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ý
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ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended December 31, 2015
OR
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¨
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TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
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For the transition period from to
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Delaware
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73-1521290
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(State or Other Jurisdiction of
Incorporation or Organization)
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(IRS Employer
Identification Number)
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14313 North May Avenue, Suite 100
Oklahoma City, Oklahoma
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73134
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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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The NASDAQ Stock Market LLC
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Page
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ITEM 1.
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ITEM 1A.
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ITEM 1B.
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ITEM 2.
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ITEM 3.
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ITEM 4.
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ITEM 5.
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ITEM 6.
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ITEM 7.
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ITEM 7A.
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ITEM 8.
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ITEM 9.
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ITEM 9A.
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ITEM 9B.
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ITEM 10.
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ITEM 11.
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ITEM 12.
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ITEM 13.
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ITEM 14.
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ITEM 15.
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ITEM 1.
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BUSINESS
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Proved Reserves
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||||||||||||||||
Field
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NRI/WI (1)
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Productive
Wells (2)
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Non-Productive
Wells
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Developed
Acreage (3)
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Gas
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Oil
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NGLs
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Total
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||||||||||||||||
Percentages
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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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MMcf
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MBbls
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MBbls
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MMcfe
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|||||||||||
Utica Shale (4)
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39.11/48.15
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306
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147.49
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3
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2.66
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36,549
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32,110
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1,558,677
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3,618
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17,736
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1,686,795
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West Cote Blanche Bay Field (5)
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80.108/100
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98
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98
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202
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202
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5,668
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5,668
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894
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2,258
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—
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14,442
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E. Hackberry Field (6)
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79.91/100
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21
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21
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124
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124
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2,910
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2,910
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316
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309
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—
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2,168
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W. Hackberry Field
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80.00/100
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5
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5
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8
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8
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1,192
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1,192
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—
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14
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—
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88
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Niobrara Formation
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38.94/46.77
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4
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2
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2
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1
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2,740
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1,370
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55
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117
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—
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758
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Bakken Formation
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1.51/1.83
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18
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0.3
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—
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—
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1,861
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163
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189
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141
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—
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1,038
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Overrides/Royalty Non-operated
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Various
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541
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0.71
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—
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—
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—
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—
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14
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1
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—
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23
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Total
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993
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274.5
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339
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337.66
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50,920
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43,413
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1,560,145
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6,458
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17,736
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1,705,312
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(1)
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Net Revenue Interest (NRI)/Working Interest (WI) for producing wells.
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(2)
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Includes two gross and net wells at WCBB that are producing intermittently.
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(3)
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Developed acres are acres spaced or assigned to productive wells. Approximately 17% of our acreage is developed acreage and has been held by production.
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(5)
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We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, we have a 40.40% non-operated working interest (29.95% NRI).
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(6)
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NRI shown is for producing wells.
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Field
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State
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Parish/County
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Acreage Working
Interest
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Overriding Royalty
Interests
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Producing
Wells
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Non-Producing
Wells
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Deer Island
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Louisiana
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Terrebonne
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3.125
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%
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—
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1
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—
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Napoleonville
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Louisiana
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Assumption
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—
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2.5
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%
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3
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—
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Crest
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Texas
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Ochiltree
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2
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%
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—
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1
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—
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Eagle City South
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Oklahoma
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Dewey
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1.04
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%
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—
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1
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—
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Fay South
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Oklahoma
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Blaine
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0.301
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%
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—
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1
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—
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Squaw Cheek
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Oklahoma
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Blaine
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0.13
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%
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—
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1
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—
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Watonga Chickasha Trend
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Oklahoma
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Canadian
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0.052
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%
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—
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1
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—
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•
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520,000 MMBtu per day of firm capacity on Dominion East Ohio, which began in 2014 and allows us to reach additional connectivity to Gulf Coast and Midwest natural gas markets;
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250,000 MMBtu per day of firm capacity on Dominion Transmission, which began in 2015 and allows us to reach additional connectivity to Midwest natural gas markets;
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•
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194,000 MMBtu per day of firm capacity on ANR Pipeline Company facilities, which began in 2014 and allows us to reach the Michigan, Chicago and Wisconsin natural gas markets;
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•
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200,000 MMBtu per day of firm capacity on Tennessee Gas Pipeline facilities, which began in 2015 and allows us to reach Gulf Coast delivery points;
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•
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275,000 MMBtu per day of firm capacity on Rockies Express Pipeline facilities, which began in 2015 and allows us to reach additional connectivity to Gulf Coast and Midwest markets;
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•
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50,000 MMBtu per day of firm capacity on Rockies Express Pipeline facilities expected to begin in 2016 allowing additional connectivity to Gulf Coast and Midwest markets;
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•
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20,000 MMBtu per day of firm capacity on Natural Gas Pipeline facilities which began in 2015 and allows us to reach Midwest markets;
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•
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50,000 MMBtu per day of firm capacity on Texas Gas Transmission facilities expected to begin in 2016 allowing additional access to Gulf Coast delivery points;
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•
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54,000 MMBtu per day of firm capacity on Texas Gas Transmission facilities expected to begin in 2017 allowing additional access to Gulf Coast delivery points;
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•
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100,000 MMBtu per day of firm capacity on Texas Eastern Transmission facilities expected to begin in 2017 allowing additional access to Midwest delivery points;
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•
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150,000 MMBtu per day of firm capacity on Energy Transfer’s Rover Pipeline facilities expected to begin in 2017 allowing additional access to Canadian, Midwest and Gulf Coast delivery points; and
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•
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100,000 MMBtu per day of firm capacity on Columbia Gulf Transmission facilities expected to begin in late 2017 allowing additional access to Gulf Coast delivery points.
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•
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the location of wells;
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•
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the method of drilling and casing wells;
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•
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the timing of construction or drilling activities, including seasonal wildlife closures;
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•
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the rates of production or “allowables”;
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the surface use and restoration of properties upon which wells are drilled;
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•
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the plugging and abandoning of wells; and
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•
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notice to, and consultation with, surface owners and other third parties.
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ITEM 1A.
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RISK FACTORS
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•
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worldwide and domestic supplies of oil and natural gas;
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•
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the level of prices, and expectations about future prices, of oil and natural gas;
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•
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the cost of exploring for, developing, producing and delivering oil and natural gas;
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the expected rates of declining current production;
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•
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the level of consumer demand;
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•
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the price and availability of alternative fuels;
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technical advances affecting energy consumption;
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•
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risks associated with operating drilling rigs;
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•
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the availability of pipeline capacity and other transportation facilities;
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•
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the price and level of foreign imports;
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•
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domestic and foreign governmental regulations and taxes;
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•
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the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
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•
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speculative trading in crude oil and natural gas derivative contracts;
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•
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political or economic instability or armed conflict in oil and natural gas producing regions, including the Middle East, Africa, South America and Russia;
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•
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the overall domestic and global economic environment; and
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•
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weather conditions, including hurricanes, and other natural disasters that can affect oil and natural gas operations over a wide area.
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•
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denial of or delay in receiving requisite regulatory approvals and/or permits;
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•
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unplanned increases in the cost of construction materials or labor;
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•
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disruptions in transportation of components or construction materials;
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•
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adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors or suppliers;
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•
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shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
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•
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market-related increases in a project's debt or equity financing costs; and
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•
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nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors.
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•
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actual prices we receive for oil and natural gas;
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•
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the amount and timing of actual production;
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•
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supply of and demand for oil and natural gas; and
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•
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changes in governmental regulations or taxation.
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•
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unusual or unexpected geological formations;
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•
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loss of drilling fluid circulation;
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•
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title problems;
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•
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facility or equipment malfunctions;
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•
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unexpected operational events;
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•
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shortages or delivery delays of equipment and services;
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•
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compliance with environmental and other governmental requirements; and
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•
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adverse weather conditions.
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•
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the timing and amount of capital expenditures;
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•
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the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;
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•
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the operator's expertise and financial resources;
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•
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approval of other participants in drilling wells;
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•
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selection of technology; and
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•
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the rate of production of the reserves.
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•
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our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to our indebtedness, and any failure to comply with the obligations under any of our debt instruments, including restrictive covenants, could result in a default under our secured revolving credit facility or the senior note indenture;
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•
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the restrictions imposed on the operation of our business by the terms of our debt agreements may hinder our ability to take advantage of strategic opportunities to grow our business;
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•
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our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, restructuring, acquisitions or general corporate purposes may be impaired, which could be exacerbated by further volatility in the credit markets;
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•
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we must use a substantial portion of our cash flow from operations to pay interest on the senior notes and our other indebtedness, which will reduce the funds available to us for operations and other purposes;
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•
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our level of indebtedness could place us at a competitive disadvantage compared to our competitors that may have proportionately less debt;
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•
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our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate may be limited;
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•
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our high level of indebtedness makes us more vulnerable to economic downturns and adverse developments in our business; and
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•
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we may be vulnerable to interest rate increases, as our borrowings under our secured revolving credit facility are at variable interest rates.
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•
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incur or guarantee additional indebtedness;
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•
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make certain investments;
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•
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declare or pay dividends or make distributions on our capital stock;
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•
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prepay subordinated indebtedness;
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•
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sell assets including capital stock of restricted subsidiaries;
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•
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agree to payment restrictions affecting our restricted subsidiaries;
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•
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consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;
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•
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enter into transactions with our affiliates;
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•
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incur liens;
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•
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engage in business other than the oil and gas business; and
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•
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designate certain of our subsidiaries as unrestricted subsidiaries.
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•
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changes in oil and natural gas prices;
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•
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changes in production levels;
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•
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changes in governmental regulations and taxes;
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•
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geopolitical developments;
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•
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the level of foreign imports of oil and natural gas; and
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•
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conditions in the oil and natural gas industry and the overall economic environment.
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ITEM 1B.
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UNRESOLVED STAFF COMMENTS
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ITEM 2.
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PROPERTIES
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•
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review and verification of historical production data, which data is based on actual production as reported by us;
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•
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verification of property ownership by our land department;
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•
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preparation of reserve estimates by our experienced reservoir engineers or under their direct supervision;
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•
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direct reporting responsibilities by our reservoir engineering department to our Chief Executive Officer;
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•
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review by our reservoir engineering department of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;
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•
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provision of quarterly updates to our board of directors regarding operational data, including production, drilling and completion activity levels and any significant changes in our reserves;
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•
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annual review by our board of directors of our year-end reserve report and year-over-year changes in our proved reserves, as well as any changes to our previously adopted development plans;
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•
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annual review and approval by our senior management and our board of directors of a multi-year development plan; and
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•
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annual review by our senior management of adjustments to our previously adopted development plan and considerations involved in making such adjustments.
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•
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review by our board of directors of changes in our previously approved development plan made by senior management and technical staff during the year, including the substitution, removal or deferral of PUD locations.
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Year Ended December 31,
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|||||||||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
|||||||||||||||||||||
|
Oil
(MBbls)
|
|
Natural
Gas
(MMcf)
|
|
Natural Gas Liquids (MBbls)
|
|
Oil
(MBbls)
|
|
Natural
Gas
(MMcf)
|
|
Natural Gas Liquids (MBbls)
|
|
Oil
(MBbls)
|
|
Natural
Gas
(MMcf)
|
|
Natural Gas Liquids (MBbls)
|
|||||||||
Proved developed
|
6,120
|
|
|
652,961
|
|
|
12,910
|
|
|
5,719
|
|
|
345,166
|
|
|
12,379
|
|
|
5,609
|
|
|
94,552
|
|
|
3,527
|
|
Proved undeveloped
|
338
|
|
|
907,184
|
|
|
4,826
|
|
|
3,778
|
|
|
373,840
|
|
|
13,889
|
|
|
2,737
|
|
|
51,894
|
|
|
2,148
|
|
Total (1)
|
6,458
|
|
|
1,560,145
|
|
|
17,736
|
|
|
9,497
|
|
|
719,006
|
|
|
26,268
|
|
|
8,346
|
|
|
146,446
|
|
|
5,675
|
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Total net proved oil and natural gas reserves (MMcfe) (1)
|
1,705,312
|
|
|
933,598
|
|
|
230,574
|
|
|||
PV-10 value (in millions) (2)
|
$
|
765.8
|
|
|
$
|
1,840.8
|
|
|
$
|
696.9
|
|
Standardized measure (in millions) (3)
|
$
|
764.3
|
|
|
$
|
1,427.2
|
|
|
$
|
578.5
|
|
(1)
|
Estimates of reserves as of year-end
2015
,
2014
and
2013
were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-
|
(2)
|
Represents present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proven reserves. The estimated future net revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on certain prevailing economic conditions. The estimated future production in our reserve reports for the years ended
December 31, 2015
,
2014
and
2013
is priced based on the 12-month unweighted arithmetic average of the first-day-of-the month price for the period January through December of the applicable year, using
$50.28
per barrel and
$2.59
per MMBtu for
2015
,
$94.99
per barrel and
$4.35
per MMBtu for
2014
and
$96.78
per barrel and
$3.67
per MMBtu for
2013
, and in each case adjusted by lease for transportation fees and regional price differentials.
|
|
December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(In thousands)
|
||||||||||
Standardized measure of discounted future net cash flows
|
$
|
764,331
|
|
|
$
|
1,427,167
|
|
|
$
|
578,466
|
|
Add: Present value of future income tax discounted at 10%
|
1,432
|
|
|
413,671
|
|
|
118,445
|
|
|||
PV-10 value
|
$
|
765,763
|
|
|
$
|
1,840,838
|
|
|
$
|
696,911
|
|
(3)
|
The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.
|
•
|
Additions of 625.9 Bcfe primarily attributable to 2015 extensions in our Utica field;
|
•
|
Conversion of approximately 81.2 Bcfe attributable to 14 PUDs into proved developed reserves;
|
•
|
Additions of 13.9 Bcfe attributable to four PUDs drilled during 2015 that were waiting on completion and pipeline connection and, as such, remain categorized as PUDs at December 31, 2015;
|
•
|
Acquisition of approximately 271.8 Bcfe in our Paloma acquisition; and
|
•
|
Downward revisions of 372.1 Bcfe due to the exclusion of PUD locations in our Southern Louisiana and Utica fields due to lower commodity prices and changes in the drilling timeline due to lower commodity prices.
|
|
2015
|
|
2014
|
|
2013
|
|
||||||
Production Volumes:
|
|
|
|
|
|
|
||||||
Oil (MBbls)
|
2,899
|
|
|
2,684
|
|
|
2,317
|
|
|
|||
Gas (MMcf)
|
156,151
|
|
|
59,318
|
|
|
8,891
|
|
|
|||
Natural gas liquids (MGal)
|
185,792
|
|
|
86,092
|
|
|
13,416
|
|
|
|||
Gas equivalents (MMcfe)
|
200,089
|
|
|
87,719
|
|
|
24,709
|
|
|
|||
Average Prices:
|
|
|
|
|
|
|
||||||
Oil (per Bbl)
|
$
|
48.91
|
|
(1)
|
$
|
92.18
|
|
(1)
|
$
|
96.74
|
|
(1)
|
Gas (per Mcf)
|
$
|
3.25
|
|
(1)
|
$
|
5.55
|
|
(1)
|
$
|
2.36
|
|
|
Natural gas liquids (per Gal)
|
$
|
0.32
|
|
(1)
|
$
|
1.09
|
|
|
$
|
1.27
|
|
|
Gas equivalents (per Mcfe)
|
$
|
3.54
|
|
|
$
|
7.65
|
|
|
$
|
10.61
|
|
|
Production Costs:
|
|
|
|
|
|
|
||||||
Average production costs (per Mcfe)
|
$
|
0.35
|
|
|
$
|
0.59
|
|
|
$
|
1.08
|
|
|
Average production taxes and midstream costs (per Mcfe)
|
$
|
0.77
|
|
|
$
|
1.01
|
|
|
$
|
1.54
|
|
|
Total production and midstream costs and production taxes (per Mcfe)
|
$
|
1.12
|
|
|
$
|
1.60
|
|
|
$
|
2.62
|
|
|
(1)
|
Includes various derivative contracts at a weighted average price of:
|
|
Per barrel
|
||
January – December 2015
|
$
|
62.36
|
|
January – December 2014
|
$
|
102.79
|
|
January – December 2013
|
$
|
100.90
|
|
|
Per MMBtu
|
||
January – December 2015
|
$
|
3.94
|
|
January – December 2014
|
$
|
4.06
|
|
January – December 2013
|
$
|
4.00
|
|
|
Per gallon
|
||
January – December 2015
|
$
|
0.48
|
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Utica Shale
|
|
|
|
|
|
||||||
Net Production
|
|
|
|
|
|
||||||
Oil (MBbls)
|
1,608
|
|
|
883
|
|
|
315
|
|
|||
Gas (MMcf)
|
155,926
|
|
|
58,919
|
|
|
8,439
|
|
|||
NGL (Mgal)
|
185,753
|
|
|
86,051
|
|
|
13,384
|
|
|||
Total (MMcfe)
|
192,108
|
|
|
76,512
|
|
|
12,238
|
|
|||
Average Sales Price:
|
|
|
|
|
|
||||||
Oil (per Bbl)
|
$
|
42.41
|
|
|
$
|
78.63
|
|
|
$
|
83.67
|
|
Gas (per Mcf)
|
$
|
3.25
|
|
|
$
|
5.56
|
|
|
$
|
2.29
|
|
NGL (per Gal)
|
$
|
0.32
|
|
|
$
|
1.09
|
|
|
$
|
1.27
|
|
Average Production Cost (per Mcfe)
|
$
|
0.25
|
|
|
$
|
0.38
|
|
|
$
|
0.59
|
|
|
NRI/WI (1)
|
|
Productive
Oil Wells (2)
|
|
Productive
Gas Wells
|
|
Non-Productive
Oil Wells
|
|
Non-Productive
Gas Wells
|
|
Developed
Acreage (3)
|
|
Undeveloped
Acreage
|
||||||||||||||||||||||||
Field
|
Percentages
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||||||||
Utica Shale (4)
|
39.11/48.15
|
|
82
|
|
|
36.96
|
|
|
224
|
|
|
110.53
|
|
|
3
|
|
|
2.66
|
|
|
—
|
|
|
—
|
|
|
36,549
|
|
|
32,110
|
|
|
203,931
|
|
|
201,469
|
|
West Cote Blanche Bay Field (5)
|
80.108/100
|
|
98
|
|
|
98
|
|
|
—
|
|
|
—
|
|
|
185
|
|
|
185
|
|
|
17
|
|
|
17
|
|
|
5,668
|
|
|
5,668
|
|
|
—
|
|
|
—
|
|
E. Hackberry Field (6)
|
79.91/100
|
|
21
|
|
|
21
|
|
|
—
|
|
|
—
|
|
|
124
|
|
|
124
|
|
|
—
|
|
|
—
|
|
|
2,910
|
|
|
2,910
|
|
|
1,206
|
|
|
1,206
|
|
W. Hackberry Field
|
80.00/100
|
|
5
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
1,192
|
|
|
1,192
|
|
|
—
|
|
|
—
|
|
Niobrara Formation (7)
|
38.94/46.77
|
|
4
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
2,740
|
|
|
1,370
|
|
|
7,415
|
|
|
3,624
|
|
Bakken Formation (8)
|
1.51/1.83
|
|
18
|
|
|
0.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,861
|
|
|
163
|
|
|
3,505
|
|
|
701
|
|
Overrides/Royalty Non-operated
|
Various
|
|
541
|
|
|
0.71
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
|
|
769
|
|
|
163.97
|
|
|
224
|
|
|
110.53
|
|
|
322
|
|
|
320.66
|
|
|
17
|
|
|
17
|
|
|
50,920
|
|
|
43,413
|
|
|
216,057
|
|
|
207,000
|
|
(1)
|
Net Revenue Interest (NRI)/Working Interest (WI).
|
(2)
|
Includes two gross and net wells at WCBB that are producing intermittently.
|
(3)
|
Developed acres are acres spaced or assigned to productive wells. Approximately 17% of our acreage is developed acreage and has been perpetuated by production.
|
(4)
|
With respect to our total undeveloped Utica Shale acreage as of
December 31, 2015
, 24%, 9%, 18%, 1% and 12% is subject to expire in 2016, 2017, 2018, 2019 and thereafter. Our Utica Shale leases generally grant us the right to extend these leases for an additional five-year period. NRI/WI is from wells that have been drilled or in which we have elected to participate. Includes 105 gross (12.03 net) gas wells and 36 gross (3.63 net) oil wells drilled by other operators on our acreage.
|
(5)
|
We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, we have a 40.40% non-operated working interest (29.95% NRI).
|
(6)
|
NRI shown is for producing wells.
|
(7)
|
The leases relating to our Niobrara Formation acreage will expire at the end of their respective primary terms unless the applicable leases are renewed or extended, we have commenced the necessary operations required by the terms of the applicable leases or we have obtained actual production from acreage subject to the applicable leases, in which event they will remain in effect until the cessation of production. Leases representing 36%, 7%, 8% and 39% of our total Niobrara undeveloped acreage are currently scheduled to expire in 2016, 2017, 2018 and 2019, respectively.
|
(8)
|
NRI/WI is from wells that have been drilled or in which we have elected to participate.
|
|
2015
|
|
2014
|
|
2013
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Recompletions:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
|
72
|
|
|
72
|
|
|
161
|
|
|
161
|
|
|
150
|
|
|
150
|
|
Dry
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
72
|
|
|
72
|
|
|
161
|
|
|
161
|
|
|
150
|
|
|
150
|
|
Development:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
|
49
|
|
|
38
|
|
|
119
|
|
|
100
|
|
|
80
|
|
|
63.8
|
|
Dry
|
—
|
|
|
—
|
|
|
7
|
|
|
6.8
|
|
|
2
|
|
|
2
|
|
Total
|
49
|
|
|
38
|
|
|
126
|
|
|
106.8
|
|
|
82
|
|
|
65.8
|
|
Exploratory:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
2.7
|
|
Dry
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
2.7
|
|
ITEM 3.
|
LEGAL PROCEEDINGS
|
ITEM 4.
|
MINE SAFETY DISCLOSURES
|
ITEM 5.
|
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
|
|
Price Range of
Common Stock
|
||||||
|
High
|
|
Low
|
||||
2014
|
|
|
|
||||
First Quarter
|
$
|
71.35
|
|
|
$
|
52.28
|
|
Second Quarter
|
75.75
|
|
|
58.90
|
|
||
Third Quarter
|
65.18
|
|
|
51.59
|
|
||
Fourth Quarter
|
56.72
|
|
|
36.56
|
|
||
2015
|
|
|
|
||||
First Quarter
|
$
|
48.60
|
|
|
$
|
35.00
|
|
Second Quarter
|
52.28
|
|
|
39.29
|
|
||
Third Quarter
|
40.59
|
|
|
28.97
|
|
||
Fourth Quarter
|
36.12
|
|
|
20.21
|
|
ITEM 6.
|
SELECTED FINANCIAL DATA
|
|
Fiscal Year Ended December 31,
|
||||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
||||||||||
|
(In thousands, except share data)
|
||||||||||||||||||
Selected Consolidated Statements of Operations Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
$
|
709,475
|
|
|
$
|
671,266
|
|
|
$
|
262,753
|
|
|
$
|
248,926
|
|
|
$
|
229,254
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating expenses
|
69,475
|
|
|
52,191
|
|
|
26,703
|
|
|
24,308
|
|
|
20,897
|
|
|||||
Production taxes
|
14,740
|
|
|
24,006
|
|
|
26,933
|
|
|
28,957
|
|
|
26,054
|
|
|||||
Midstream gathering and processing
|
138,590
|
|
|
64,467
|
|
|
11,030
|
|
|
443
|
|
|
279
|
|
|||||
Depreciation, depletion and amortization
|
337,694
|
|
|
265,431
|
|
|
118,880
|
|
|
90,749
|
|
|
62,320
|
|
|||||
Impairment of oil and gas properties
|
1,440,418
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
General and administrative
|
41,967
|
|
|
38,290
|
|
|
22,519
|
|
|
13,808
|
|
|
8,074
|
|
|||||
Accretion expense
|
820
|
|
|
761
|
|
|
717
|
|
|
698
|
|
|
666
|
|
|||||
(Gain) loss on sale of assets
|
—
|
|
|
(11
|
)
|
|
508
|
|
|
(7,300
|
)
|
|
—
|
|
|||||
|
2,043,704
|
|
|
445,135
|
|
|
207,290
|
|
|
151,663
|
|
|
118,290
|
|
|||||
(Loss) Income from Operations
|
(1,334,229
|
)
|
|
226,131
|
|
|
55,463
|
|
|
97,263
|
|
|
110,964
|
|
|||||
Other (Income) Expense:
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense
|
51,221
|
|
|
23,986
|
|
|
17,490
|
|
|
7,458
|
|
|
1,400
|
|
|||||
Interest income
|
(643
|
)
|
|
(195
|
)
|
|
(297
|
)
|
|
(72
|
)
|
|
(186
|
)
|
|||||
Litigation settlement
|
—
|
|
|
25,500
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Insurance proceeds
|
(10,015
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Gain on contribution of investments
|
—
|
|
|
(84,470
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Loss (income) from equity method investments
|
106,093
|
|
|
(139,434
|
)
|
|
(213,058
|
)
|
|
(8,322
|
)
|
|
1,418
|
|
|||||
|
146,656
|
|
|
(174,613
|
)
|
|
(195,865
|
)
|
|
(936
|
)
|
|
2,632
|
|
|||||
(Loss) Income from Continuing Operations before Income Taxes
|
(1,480,885
|
)
|
|
400,744
|
|
|
251,328
|
|
|
98,199
|
|
|
108,332
|
|
|||||
Income Tax (Benefit) Expense
|
(256,001
|
)
|
|
153,341
|
|
|
98,136
|
|
|
26,363
|
|
|
(90
|
)
|
|||||
(Loss) Income from Continuing Operations
|
(1,224,884
|
)
|
|
247,403
|
|
|
153,192
|
|
|
71,836
|
|
|
108,422
|
|
|||||
Discontinued Operations:
|
|
|
|
|
|
|
|
|
|
||||||||||
Loss on disposal of Belize properties, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
3,465
|
|
|
—
|
|
|||||
Net (Loss) Income Available to Common Stockholders
|
$
|
(1,224,884
|
)
|
|
$
|
247,403
|
|
|
$
|
153,192
|
|
|
$
|
68,371
|
|
|
$
|
108,422
|
|
Net (Loss) Income Per Common Share—Basic:
|
$
|
(12.27
|
)
|
|
$
|
2.90
|
|
|
$
|
1.98
|
|
|
$
|
1.22
|
|
|
$
|
2.22
|
|
Net (Loss) Income Per Common Share—Diluted:
|
$
|
(12.27
|
)
|
|
$
|
2.88
|
|
|
$
|
1.97
|
|
|
$
|
1.21
|
|
|
$
|
2.20
|
|
|
At December 31,
|
||||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
||||||||||
|
(In thousands)
|
||||||||||||||||||
Selected Consolidated Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
$
|
3,334,734
|
|
|
$
|
3,619,473
|
|
|
$
|
2,685,039
|
|
|
$
|
1,569,431
|
|
|
$
|
691,158
|
|
Total debt, including current maturity
|
$
|
946,263
|
|
|
$
|
703,564
|
|
|
$
|
291,090
|
|
|
$
|
290,101
|
|
|
$
|
2,283
|
|
Total liabilities
|
$
|
1,295,897
|
|
|
$
|
1,323,177
|
|
|
$
|
634,801
|
|
|
$
|
443,023
|
|
|
$
|
58,808
|
|
Stockholders’ equity
|
$
|
2,038,837
|
|
|
$
|
2,296,296
|
|
|
$
|
2,050,238
|
|
|
$
|
1,126,408
|
|
|
$
|
632,350
|
|
ITEM 7.
|
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
•
|
Production increased
128%
to approximately
200,089
MMcfe for the year ended
December 31, 2015
from approximately
87,719
MMcfe for the year ended
December 31, 2014
.
|
•
|
Oil and natural gas revenues increased
6%
to
$709.0 million
for the year ended
December 31, 2015
from
$670.8 million
for the year ended
December 31, 2014
.
|
•
|
During 2015, we spud 49 gross (38.4 net) wells, participated in an additional 25 gross (7.3 net) wells that were drilled by other operators on our Utica Shale acreage and recompleted 72 gross and net wells. Of our 49 new wells spud during 2015, ten were completed as producing wells and, at year end, 36 were in various stages of completion and three were drilling.
|
•
|
In August 2015, we acquired Paloma for a total purchase price of approximately $301.9 million. Paloma holds approximately 24,000 net nonproducing acres in the Utica Shale of Ohio.
|
•
|
On April 21, 2015, we issued 10,925,000 shares of our common stock in an underwritten public offering. The net proceeds from this equity offering were approximately $501.8 million. We used a portion of these net proceeds, together with a portion of the net proceeds from our concurrent senior notes offering described below, to repay all borrowings outstanding at that time under our senior secured revolving credit facility and to fund the acquisition of Paloma and used the remaining funds from these offerings for general corporate purposes, including the funding of a portion of our 2015 capital development plans.
|
•
|
On April 21 2015, we issued $350.0 million in aggregate principal amount of our 6.625% senior unsecured notes due 2023, resulting in net proceeds to us of $343.6 million.
|
•
|
On June 12, 2015, we issued 11,500,000 shares of our common stock in an underwritten public offering. The net proceeds from this equity offering were approximately $479.7 million. We used a portion of these net proceeds to fund the acquisition of certain acreage and other assets in the Utica Shale in Ohio from AEU, described below, and used the remaining funds for general corporate purposes, including the funding of a portion of our 2015 capital development plans.
|
•
|
On June 9, 2015, we completed the acquisition of 6,198 gross and net acres located in Belmont and Jefferson Counties, Ohio from AEU for a purchase price of approximately $68.2 million in a transaction we refer to as the Belmont/Jefferson acquisition. This acreage is located near or adjacent to the acreage included in our acquisition of Paloma. This newly acquired Belmont and Jefferson County acreage is undeveloped.
|
•
|
On June 12, 2015, we completed the acquisition of 38,965 gross (27,228 net) acres located in Monroe County, Ohio, which we refer to as the Monroe County Acreage, 14.6 MMcf per day of average net production (estimated for April 2015), 18 gross (11.3 net) drilled but uncompleted wells, an 11 mile gas gathering system and a four well pad location from AEU for a total purchase price of approximately $319.0 million, which we refer to as the Monroe Acquisition. We used a portion of the net proceeds from our June 2015 equity offering described above to fund the Monroe Acquisition. The Monroe County Acreage has a net revenue interest of approximately 84% and is approximately 85% held by production by a ten well per year drilling commitment. On June 29, 2015, we acquired an additional 4,950 gross (1,900 net) acres in Monroe County for an additional approximately $18.2 million from AEU.
|
•
|
As of
February 10, 2016
, we held leasehold interests in approximately 244,000 gross (237,000 net) acres in the Utica Shale. During 2015, we spud 49 gross (38.4 net) wells on our Utica Shale acreage and, during 2016 (through
February 10, 2016
), we had spud four gross (2.2 net) wells. As of
February 10, 2016
, one well was waiting on completion and three were still being drilled.
|
•
|
the quality and quantity of available data;
|
•
|
the interpretation of that data;
|
•
|
the accuracy of various mandated economic assumptions; and
|
•
|
the judgments of the individuals preparing the estimates.
|
|
2015
|
|
2014
|
|
2013
|
|
||||||
Production Volumes:
|
|
|
|
|
|
|
||||||
Oil (MBbls)
|
2,899
|
|
|
2,684
|
|
|
2,317
|
|
|
|||
Gas (MMcf)
|
156,151
|
|
|
59,318
|
|
|
8,891
|
|
|
|||
Natural gas liquids (MGal)
|
185,792
|
|
|
86,092
|
|
|
13,416
|
|
|
|||
Gas equivalents (MMcfe)
|
200,089
|
|
|
87,719
|
|
|
24,709
|
|
|
|||
Average Prices:
|
|
|
|
|
|
|
||||||
Oil (per Bbl)
|
$
|
48.91
|
|
(1)
|
$
|
92.18
|
|
(1)
|
$
|
96.74
|
|
(1)
|
Gas (per Mcf)
|
$
|
3.25
|
|
(1)
|
$
|
5.55
|
|
(1)
|
$
|
2.36
|
|
(1)
|
Natural gas liquids (per Gal)
|
$
|
0.32
|
|
(1)
|
$
|
1.09
|
|
|
$
|
1.27
|
|
|
Gas equivalents (per Mcfe)
|
$
|
3.54
|
|
|
$
|
7.65
|
|
|
$
|
10.61
|
|
|
Production Costs:
|
|
|
|
|
|
|
||||||
Average production costs (per Mcfe)
|
$
|
0.35
|
|
|
$
|
0.59
|
|
|
$
|
1.08
|
|
|
Average production taxes and midstream costs (per Mcfe)
|
$
|
0.77
|
|
|
$
|
1.01
|
|
|
$
|
1.54
|
|
|
Total production and midstream costs and production taxes (per Mcfe)
|
$
|
1.12
|
|
|
$
|
1.60
|
|
|
$
|
2.62
|
|
|
(1)
|
Includes various derivative contracts at a weighted average price of:
|
|
Per barrel
|
||
January – December 2015
|
$
|
62.36
|
|
January – December 2014
|
$
|
102.79
|
|
January – December 2013
|
$
|
100.90
|
|
|
Per MMBtu
|
||
January – December 2015
|
$
|
3.94
|
|
January – December 2014
|
$
|
4.06
|
|
January – December 2013
|
$
|
4.00
|
|
|
Per gallon
|
||
January – December 2015
|
$
|
0.48
|
|
|
Year Ended
December 31,
|
||||||
|
2015
|
|
2014
|
||||
Oil production volumes (MBbls)
|
2,899
|
|
|
2,684
|
|
||
Gas production volumes (MMcf)
|
156,151
|
|
|
59,318
|
|
||
Natural gas liquids production volumes (MGal)
|
185,792
|
|
|
86,092
|
|
||
Gas equivalents (MMcfe)
|
200,089
|
|
|
87,719
|
|
||
Average oil price (per Bbl)
|
$
|
48.91
|
|
|
$
|
92.18
|
|
Average gas price (per Mcf)
|
$
|
3.25
|
|
|
$
|
5.55
|
|
Average natural gas liquids (per Gal)
|
$
|
0.32
|
|
|
$
|
1.09
|
|
Gas equivalents (per Mcfe)
|
$
|
3.54
|
|
|
$
|
7.65
|
|
|
Year Ended
December 31,
|
||||||
|
2014
|
|
2013
|
||||
Oil production volumes (MBbls)
|
2,684
|
|
|
2,317
|
|
||
Gas production volumes (MMcf)
|
59,318
|
|
|
8,891
|
|
||
Natural gas liquids production volumes (MGal)
|
86,092
|
|
|
13,416
|
|
||
Gas equivalents (MMcfe)
|
87,719
|
|
|
24,709
|
|
||
Average oil price (per Bbl)
|
$
|
92.18
|
|
|
$
|
96.74
|
|
Average gas price (per Mcf)
|
$
|
5.55
|
|
|
$
|
2.36
|
|
Average natural gas liquids (per Gal)
|
$
|
1.09
|
|
|
$
|
1.27
|
|
Gas equivalents (per Mcfe)
|
$
|
7.65
|
|
|
$
|
10.61
|
|
|
Payment due by period
|
||||||||||||||||||
Contractual Obligations
|
Total
|
|
Less than 1 year
|
|
1-3 years
|
|
3-5 years
|
|
More than 5
years
|
||||||||||
|
(In thousands)
|
||||||||||||||||||
7.75% senior unsecured notes due 2020 (1)
|
$
|
830,627
|
|
|
$
|
46,500
|
|
|
$
|
93,000
|
|
|
$
|
691,127
|
|
|
$
|
—
|
|
6.625% senior unsecured notes due 2023 (2)
|
523,906
|
|
|
23,188
|
|
|
46,375
|
|
|
46,375
|
|
|
407,968
|
|
|||||
Asset retirement obligations
|
26,437
|
|
|
75
|
|
|
684
|
|
|
703
|
|
|
24,975
|
|
|||||
Employment agreements
|
1,216
|
|
|
882
|
|
|
334
|
|
|
—
|
|
|
—
|
|
|||||
Building loan (3)
|
1,653
|
|
|
179
|
|
|
1,474
|
|
|
—
|
|
|
—
|
|
|||||
Firm transportation contracts
|
3,843,274
|
|
|
145,282
|
|
|
410,307
|
|
|
459,899
|
|
|
2,827,786
|
|
|||||
Purchase obligations (4)
|
144,210
|
|
|
52,440
|
|
|
91,770
|
|
|
—
|
|
|
—
|
|
|||||
Operating leases
|
1,437
|
|
|
800
|
|
|
637
|
|
|
—
|
|
|
—
|
|
|||||
Total
|
$
|
5,372,760
|
|
|
$
|
269,346
|
|
|
$
|
644,581
|
|
|
$
|
1,198,104
|
|
|
$
|
3,260,729
|
|
(2)
|
Includes estimated interest of $23.2 million due in less than one year; $46.4 million due in 1-3 years; $46.4 million due in 3-5 years and $58.0 million due thereafter.
|
(3)
|
Does not include estimated interest of $63,000 due in less than one year and $104,000 due in 1-3 years.
|
(4)
|
The purchasing obligations reported above represent our minimum financial commitment pursuant to the terms of these contracts.
|
ITEM 7A.
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
|
Location
|
Daily Volume (Bbls/day)
|
|
Weighted
Average Price
|
|||
January 2016 - June 2016
|
ARGUS LLS
|
1,500
|
|
|
$
|
63.03
|
|
January 2016 - June 2016
|
NYMEX WTI
|
1,000
|
|
|
$
|
61.40
|
|
|
Location
|
Daily Volume (MMBtu/day)
|
|
Weighted
Average Price
|
|||
January 2016 - March 2016
|
NYMEX Henry Hub
|
415,000
|
|
|
$
|
3.56
|
|
April 2016
|
NYMEX Henry Hub
|
425,000
|
|
|
$
|
3.52
|
|
May 2016 - June 2016
|
NYMEX Henry Hub
|
355,000
|
|
|
$
|
3.42
|
|
July 2016 - September 2016
|
NYMEX Henry Hub
|
375,000
|
|
|
$
|
3.38
|
|
October 2016
|
NYMEX Henry Hub
|
405,000
|
|
|
$
|
3.33
|
|
November 2016 - December 2016
|
NYMEX Henry Hub
|
430,000
|
|
|
$
|
3.30
|
|
January 2017 - March 2017
|
NYMEX Henry Hub
|
317,500
|
|
|
$
|
3.25
|
|
April 2017 - June 2017
|
NYMEX Henry Hub
|
272,500
|
|
|
$
|
3.31
|
|
July 2017 - December 2017
|
NYMEX Henry Hub
|
210,000
|
|
|
$
|
3.12
|
|
January 2018 - December 2018
|
NYMEX Henry Hub
|
160,000
|
|
|
$
|
3.01
|
|
January 2019 - March 2019
|
NYMEX Henry Hub
|
20,000
|
|
|
$
|
3.37
|
|
|
Location
|
Daily Volume (Bbls/day)
|
|
Weighted
Average Price
|
|||
January 2016 - December 2016
|
Mont Belvieu
|
1,000
|
|
|
$
|
20.16
|
|
|
Location
|
Daily Volume (MMBtu/day)
|
|
Weighted
Average Price
|
|||
January 2016 - March 2016
|
NYMEX Henry Hub
|
75,000
|
|
|
$
|
3.25
|
|
April 2016 - December 2016
|
NYMEX Henry Hub
|
95,000
|
|
|
$
|
3.18
|
|
January 2017 - March 2017
|
NYMEX Henry Hub
|
20,000
|
|
|
$
|
2.91
|
|
|
Location
|
Daily Volume (MMBtu/day)
|
|
Weighted
Average Price |
|||
January 2016 - March 2016
|
MichCon
|
70,000
|
|
|
$
|
0.11
|
|
April 2016 - December 2016
|
MichCon
|
40,000
|
|
|
$
|
0.02
|
|
November 2016 - March 2017
|
Tetco M2
|
50,000
|
|
|
$
|
(0.59
|
)
|
ITEM 8.
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
ITEM 9.
|
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
|
ITEM 9A.
|
CONTROLS AND PROCEDURES
|
/s/ Michael G. Moore
|
|
/s/ Keri Crowell
|
||||
Name:
|
|
Michael G. Moore
|
|
Name:
|
|
Keri Crowell
|
Title:
|
|
Chief Executive Officer and President
|
|
Title:
|
|
Chief Accounting Officer
|
ITEM 9B.
|
OTHER INFORMATION
|
ITEM 10.
|
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
|
ITEM 11.
|
EXECUTIVE COMPENSATION
|
ITEM 12.
|
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
|
ITEM 13.
|
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
|
ITEM 14.
|
PRINCIPAL ACCOUNTING FEES AND SERVICES
|
ITEM 15.
|
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
|
(1)
|
Financial Statements
|
(2)
|
Financial Statement Schedules
|
(3)
|
Exhibits
|
Exhibit
Number
|
|
Description
|
|
|
|
2.1
|
|
Contribution Agreement, dated May 7, 2012, by and between the Company and Diamondback Energy, Inc. (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on May 8, 2012).
|
|
|
|
3.1
|
|
Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006).
|
|
|
|
3.2
|
|
Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 6, 2009).
|
|
|
|
3.3
|
|
Certificate of Amendment No. 2 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 23, 2013).
|
|
|
|
3.4
|
|
Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, 2006).
|
|
|
|
3.5
|
|
First Amendment to the Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 23, 2013).
|
|
|
|
3.6
|
|
Second Amendment to the Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on May 2, 2014).
|
|
|
|
4.1
|
|
Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the SEC on July 22, 2004).
|
|
|
|
4.2
|
|
Indenture, dated as of October 17, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (including the form of Gulfport Energy Corporation's 7.750% Senior Note Due November 1, 2020) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 23, 2012).
|
|
|
|
4.3
|
|
First Supplemental Indenture, dated December 21, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 2012).
|
|
|
|
4.4
|
|
Second Supplemental Indenture, dated August 18, 2014, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.3 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on August 19, 2014).
|
|
|
|
4.5
|
|
Indenture, dated as of April 21, 2015, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of the Company’s 6.625% Senior Notes due 2023) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 21, 2015).
|
|
|
4.6
|
|
Voting Rights Waiver Agreement, dated June 10, 2015, by and among Gulfport Energy Corporation, Putnam Investment Management, LLC, The Putnam Advisory Company, LLC and Putnam Fiduciary Trust Company (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on June 12, 2015)
|
|
|
|
10.1+
|
|
2013 Restated Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to the Form S-4, File No. 333-189992, filed by the Company with the SEC on July 17, 2013).
|
|
|
|
10.2+
|
|
2014 Executive Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 7, 2014).
|
|
|
|
10.3+*
|
|
Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006).
|
|
|
|
10.4+
|
|
Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to the Form 10-K, File No. 000-19514, filed by the Company with the SEC on February 28, 2014).
|
|
|
|
10.5+
|
|
Consulting Agreement, effective as of June 14, 2013, by and between the Company and Mike Liddell (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on June 19, 2013).
|
|
|
|
10.6+
|
|
Separation and Release Agreement, dated as of January 31, 2014, by and between the Company and James D. Palm (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 4, 2014).
|
|
|
|
10.7+
|
|
Amended and Restated Employment Agreement, dated as of April 29, 2015, by and between the Company and Michael G. Moore (incorporated by reference to Exhibit 10.3 to the Form 10-Q,
File No. 000-19514, filed by the Company with the SEC on May 7, 2015).
|
|
|
|
10.8+
|
|
Employment Agreement, effective as of August 11, 2014, by and between the Company and Aaron Gaydosik (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on March 19, 2015).
|
|
|
|
10.9+
|
|
Employment Agreement, effective as of April 22, 2014, by and between the Company and Ross Kirtley (incorporated by reference to Exhibit 10.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on March 19, 2015).
|
|
|
|
10.10
|
|
Amended and Restated Credit Agreement, dated as of December 27, 2013, by and among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, sole lead arranger and sole bookrunner, Amegy Bank National Association, as syndication agent, KeyBank National Association, as documentation agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on January 3, 2014).
|
|
|
|
10.11
|
|
First Amendment to Amended and Restated Credit Agreement, dated as of April 23, 2014, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, sole lead arranger and sole bookrunner, Amegy Bank National Association, as syndication agent, KeyBank National Association, as documentation agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 28, 2014).
|
|
|
|
10.12
|
|
Second Amendment to Amended and Restated Credit Agreement, dated as of November 26, 2014, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 3, 2014).
|
|
|
|
10.13
|
|
Third Amendment to Amended and Restated Credit Agreement, dated as of April 10, 2015, among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 15, 2015).
|
|
|
|
10.14
|
|
Fourth Amendment to Amended and Restated Credit Agreement, dated as of May 29, 2015, among the Company, as borrower, the Bank of Nova Scotia, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on August 7, 2015).
|
|
|
|
10.15
|
|
Fifth Amendment to Amended and Restated Credit Agreement, dated as of September 18, 2015, among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on September 24, 2015).
|
|
|
|
10.16#
|
|
Sand Supply Agreement, effective as of October 1, 2014, by and between Muskie Proppant LLC and Gulfport Energy Corporation (incorporated by reference to Exhibit 10.1 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 7, 2014).
|
|
|
|
10.17#
|
|
Amendment to Sand Supply Agreement, dated as of November 3, 2015, by and between Muskie Proppant LLC and Gulfport Energy Corporation (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 5, 2015).
|
|
|
|
10.18#
|
|
Amended and Restated Master Services Agreement, effective as of October 1, 2014, by and between Gulfport Energy Corporation and Stingray Pressure Pumping LLC (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 7, 2014).
|
|
|
|
10.19*##
|
|
Amendment to Amended and Restated Master Services Agreement, dated as of February 18, 2016 to be effective as of January 1, 2016, by and between Gulfport Energy Corporation and Stingray Pressure Pumping LLC.
|
|
|
|
10.20+
|
|
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-4, File No. 333-199905, filed by the Company with the SEC on November 6, 2014).
|
|
|
|
14
|
|
Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 14, 2006).
|
|
|
|
21*
|
|
Subsidiaries of the Registrant.
|
|
|
|
23.1*
|
|
Consent of Grant Thornton LLP.
|
|
|
|
23.2*
|
|
Consent of Ryder Scott Company.
|
|
|
|
23.3*
|
|
Consent of Netherland, Sewell & Associates, Inc.
|
|
|
|
23.4*
|
|
Consent of Grant Thornton LLP with respect to financial statements of Diamondback Energy, Inc.
|
|
|
|
31.1*
|
|
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
|
|
|
|
31.2*
|
|
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
|
|
|
|
32.1**
|
|
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
|
|
|
|
32.2**
|
|
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
|
|
|
|
99.1*
|
|
Report of Netherland, Sewell & Associates, Inc.
|
|
|
|
101.INS*
|
|
XBRL Instance Document.
|
|
|
|
101.SCH*
|
|
XBRL Taxonomy Extension Schema Document.
|
|
|
|
101.CAL*
|
|
XBRL Taxonomy Extension Calculation Linkbase Document.
|
|
|
|
101.DEF*
|
|
XBRL Taxonomy Extension Definition Linkbase Document.
|
|
|
|
101.LAB*
|
|
XBRL Taxonomy Extension Labels Linkbase Document.
|
|
|
|
101.PRE*
|
|
XBRL Taxonomy Extension Presentation Linkbase Document.
|
*
|
Filed herewith.
|
**
|
Furnished herewith, not filed.
|
+
|
Management contract, compensatory plan or arrangement.
|
#
|
Confidential treatment with respect to certain portions of this agreement was granted by the SEC which portions have been omitted and filed separately with the SEC.
|
##
|
Confidential treatment requested as to certain portions, which portions have been omitted and filed separately with the SEC.
|
GULFPORT ENERGY CORPORATION
|
||
|
|
|
By:
|
|
/s/ KERI CROWELL
|
|
|
Keri Crowell
Chief Accounting Officer
|
Date:
|
February 19, 2016
|
By:
|
|
/s/ MICHAEL G. MOORE
|
|
|
|
|
Michael G. Moore
Chief Executive Officer and President, Director
(Principal Executive Officer)
|
|
|
|
||
Date:
|
February 19, 2016
|
By:
|
|
/s/ DAVID L. HOUSTON
|
|
|
|
|
David L. Houston
Chairman of the Board and Director
|
|
|
|
||
Date:
|
February 19, 2016
|
By:
|
|
/s/ AARON GAYDOSIK
|
|
|
|
|
Aaron Gaydosik
Chief Financial Officer
(Principal Financial Officer)
|
|
|
|
|
|
Date:
|
February 19, 2016
|
By:
|
|
/s/ KERI CROWELL
|
|
|
|
|
Keri Crowell
Chief Accounting Officer
(Principal Accounting Officer)
|
|
|
|
||
Date:
|
February 19, 2016
|
By:
|
|
/s/ DONALD DILLINGHAM
|
|
|
|
|
Donald Dillingham
Director
|
|
|
|
||
Date:
|
February 19, 2016
|
By:
|
|
/s/ CRAIG GROESCHEL
|
|
|
|
|
Craig Groeschel
Director
|
|
|
|
|
|
Date:
|
February 19, 2016
|
By:
|
|
/s/ C. DOUG JOHNSON
|
|
|
|
|
C. Doug Johnson
Director
|
|
|
|
|
|
Date:
|
February 19, 2016
|
By:
|
|
/s/ BEN T. MORRIS
|
|
|
|
|
Ben T. Morris
Director
|
|
|
|
|
|
Date:
|
February 19, 2016
|
By:
|
|
/s/ SCOTT E. STRELLER
|
|
|
|
|
Scott E. Streller
Director
|
ITEM 8.
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
|
Page
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
2015 |
|
December 31,
2014 |
||||
|
(In thousands, except share data)
|
||||||
Assets
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
112,974
|
|
|
$
|
142,340
|
|
Accounts receivable—oil and gas
|
71,872
|
|
|
103,858
|
|
||
Accounts receivable—related parties
|
16
|
|
|
46
|
|
||
Prepaid expenses and other current assets
|
3,905
|
|
|
3,714
|
|
||
Short-term derivative instruments
|
142,794
|
|
|
78,391
|
|
||
Total current assets
|
331,561
|
|
|
328,349
|
|
||
Property and equipment:
|
|
|
|
||||
Oil and natural gas properties, full-cost accounting, $1,817,701 and $1,465,538 excluded from amortization in 2015 and 2014, respectively
|
5,424,342
|
|
|
3,923,154
|
|
||
Other property and equipment
|
33,171
|
|
|
18,344
|
|
||
Accumulated depletion, depreciation, amortization and impairment
|
(2,829,110
|
)
|
|
(1,050,879
|
)
|
||
Property and equipment, net
|
2,628,403
|
|
|
2,890,619
|
|
||
Other assets:
|
|
|
|
||||
Equity investments
|
242,393
|
|
|
369,581
|
|
||
Long-term derivative instruments
|
51,088
|
|
|
24,448
|
|
||
Deferred tax asset
|
74,925
|
|
|
—
|
|
||
Other assets
|
6,364
|
|
|
6,476
|
|
||
Total other assets
|
374,770
|
|
|
400,505
|
|
||
Total assets
|
$
|
3,334,734
|
|
|
$
|
3,619,473
|
|
Liabilities and Stockholders’ Equity
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable and accrued liabilities
|
$
|
265,128
|
|
|
$
|
371,410
|
|
Asset retirement obligation—current
|
75
|
|
|
75
|
|
||
Short-term derivative instruments
|
437
|
|
|
—
|
|
||
Deferred tax liability
|
50,697
|
|
|
27,070
|
|
||
Current maturities of long-term debt
|
179
|
|
|
168
|
|
||
Total current liabilities
|
316,516
|
|
|
398,723
|
|
||
Long-term derivative instrument
|
6,935
|
|
|
—
|
|
||
Asset retirement obligation—long-term
|
26,362
|
|
|
17,863
|
|
||
Deferred tax liability
|
—
|
|
|
203,195
|
|
||
Long-term debt, net of current maturities
|
946,084
|
|
|
703,396
|
|
||
Total liabilities
|
1,295,897
|
|
|
1,323,177
|
|
||
Commitments and contingencies (Notes 15 and 16)
|
|
|
|
||||
Preferred stock, $.01 par value; 5,000,000 authorized, 30,000 authorized as redeemable 12% cumulative preferred stock, Series A; 0 issued and outstanding
|
—
|
|
|
—
|
|
||
Stockholders’ equity:
|
|
|
|
||||
Common stock, $.01 par value; 200,000,000 authorized, 108,322,250 issued and outstanding in 2015 and 85,655,438 in 2014
|
1,082
|
|
|
856
|
|
||
Paid-in capital
|
2,824,303
|
|
|
1,828,602
|
|
||
Accumulated other comprehensive loss
|
(55,177
|
)
|
|
(26,675
|
)
|
||
Retained (deficit) earnings
|
(731,371
|
)
|
|
493,513
|
|
||
Total stockholders’ equity
|
2,038,837
|
|
|
2,296,296
|
|
||
Total liabilities and stockholders’ equity
|
$
|
3,334,734
|
|
|
$
|
3,619,473
|
|
|
For the Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(In thousands, except share data)
|
||||||||||
Revenues:
|
|
|
|
|
|
||||||
Gas sales
|
$
|
507,726
|
|
|
$
|
329,254
|
|
|
$
|
21,015
|
|
Oil and condensate sales
|
141,816
|
|
|
247,381
|
|
|
224,129
|
|
|||
Natural gas liquid sales
|
59,448
|
|
|
94,127
|
|
|
17,081
|
|
|||
Other income
|
485
|
|
|
504
|
|
|
528
|
|
|||
|
709,475
|
|
|
671,266
|
|
|
262,753
|
|
|||
Costs and expenses:
|
|
|
|
|
|
||||||
Lease operating expenses
|
69,475
|
|
|
52,191
|
|
|
26,703
|
|
|||
Production taxes
|
14,740
|
|
|
24,006
|
|
|
26,933
|
|
|||
Midstream gathering and processing
|
138,590
|
|
|
64,467
|
|
|
11,030
|
|
|||
Depreciation, depletion and amortization
|
337,694
|
|
|
265,431
|
|
|
118,880
|
|
|||
Impairment of oil and gas properties
|
1,440,418
|
|
|
—
|
|
|
—
|
|
|||
General and administrative
|
41,967
|
|
|
38,290
|
|
|
22,519
|
|
|||
Accretion expense
|
820
|
|
|
761
|
|
|
717
|
|
|||
(Gain) loss on sale of assets
|
—
|
|
|
(11
|
)
|
|
508
|
|
|||
|
2,043,704
|
|
|
445,135
|
|
|
207,290
|
|
|||
(LOSS) INCOME FROM OPERATIONS
|
(1,334,229
|
)
|
|
226,131
|
|
|
55,463
|
|
|||
OTHER (INCOME) EXPENSE:
|
|
|
|
|
|
||||||
Interest expense
|
51,221
|
|
|
23,986
|
|
|
17,490
|
|
|||
Interest income
|
(643
|
)
|
|
(195
|
)
|
|
(297
|
)
|
|||
Litigation settlement
|
—
|
|
|
25,500
|
|
|
—
|
|
|||
Insurance proceeds
|
(10,015
|
)
|
|
—
|
|
|
—
|
|
|||
Gain on contribution of investments
|
—
|
|
|
(84,470
|
)
|
|
—
|
|
|||
Loss (income) from equity method investments
|
106,093
|
|
|
(139,434
|
)
|
|
(213,058
|
)
|
|||
|
146,656
|
|
|
(174,613
|
)
|
|
(195,865
|
)
|
|||
(LOSS) INCOME BEFORE INCOME TAXES
|
(1,480,885
|
)
|
|
400,744
|
|
|
251,328
|
|
|||
INCOME TAX (BENEFIT) EXPENSE
|
(256,001
|
)
|
|
153,341
|
|
|
98,136
|
|
|||
NET (LOSS) INCOME
|
$
|
(1,224,884
|
)
|
|
$
|
247,403
|
|
|
$
|
153,192
|
|
NET (LOSS) INCOME PER COMMON SHARE:
|
|
|
|
|
|
||||||
Basic
|
$
|
(12.27
|
)
|
|
$
|
2.90
|
|
|
$
|
1.98
|
|
Diluted
|
$
|
(12.27
|
)
|
|
$
|
2.88
|
|
|
$
|
1.97
|
|
Weighted average common shares outstanding—Basic
|
99,792,401
|
|
|
85,445,963
|
|
|
77,375,683
|
|
|||
Weighted average common shares outstanding—Diluted
|
99,792,401
|
|
|
85,813,182
|
|
|
77,861,646
|
|
|
For the Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(In thousands)
|
||||||||||
Net (loss) income
|
$
|
(1,224,884
|
)
|
|
$
|
247,403
|
|
|
$
|
153,192
|
|
Foreign currency translation adjustment
|
(28,502
|
)
|
|
(16,894
|
)
|
|
(12,223
|
)
|
|||
Change in fair value of derivative instruments (1)
|
—
|
|
|
—
|
|
|
(4,419
|
)
|
|||
Reclassification of settled contracts (2)
|
—
|
|
|
—
|
|
|
10,290
|
|
|||
Other comprehensive loss
|
(28,502
|
)
|
|
(16,894
|
)
|
|
(6,352
|
)
|
|||
Comprehensive (loss) income
|
$
|
(1,253,386
|
)
|
|
$
|
230,509
|
|
|
$
|
146,840
|
|
|
|
|
|
|
Paid-in
Capital
|
|
Accumulated
Other
Comprehensive
Loss
|
|
Retained
Earnings (Deficit)
|
|
Total
Stockholders’
Equity
|
|||||||||||
|
Common Stock
|
|
|
|
|
|||||||||||||||||
|
Shares
|
|
Amount
|
|
|
|
|
|||||||||||||||
|
(In thousands, except share data)
|
|||||||||||||||||||||
Balance at January 1, 2013
|
67,527,386
|
|
|
$
|
674
|
|
|
$
|
1,036,245
|
|
|
$
|
(3,429
|
)
|
|
$
|
92,918
|
|
|
$
|
1,126,408
|
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
153,192
|
|
|
153,192
|
|
|||||
Other Comprehensive Loss
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,352
|
)
|
|
—
|
|
|
(6,352
|
)
|
|||||
Stock Compensation
|
—
|
|
|
—
|
|
|
10,495
|
|
|
—
|
|
|
—
|
|
|
10,495
|
|
|||||
Issuance of Common Stock in public offerings, net of related expenses
|
17,287,500
|
|
|
173
|
|
|
764,922
|
|
|
—
|
|
|
—
|
|
|
765,095
|
|
|||||
Issuance of Restricted Stock
|
237,646
|
|
|
3
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Issuance of Common Stock through exercise of options
|
125,000
|
|
|
1
|
|
|
1,399
|
|
|
—
|
|
|
—
|
|
|
1,400
|
|
|||||
Balance at December 31, 2013
|
85,177,532
|
|
|
851
|
|
|
1,813,058
|
|
|
(9,781
|
)
|
|
246,110
|
|
|
2,050,238
|
|
|||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
247,403
|
|
|
247,403
|
|
|||||
Other Comprehensive Loss
|
—
|
|
|
—
|
|
|
—
|
|
|
(16,894
|
)
|
|
—
|
|
|
(16,894
|
)
|
|||||
Stock Compensation
|
—
|
|
|
—
|
|
|
14,860
|
|
|
—
|
|
|
—
|
|
|
14,860
|
|
|||||
Issuance of Restricted Stock
|
272,665
|
|
|
3
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Issuance of Common Stock through exercise of options
|
205,241
|
|
|
2
|
|
|
687
|
|
|
—
|
|
|
—
|
|
|
689
|
|
|||||
Balance at December 31, 2014
|
85,655,438
|
|
|
856
|
|
|
1,828,602
|
|
|
(26,675
|
)
|
|
493,513
|
|
|
2,296,296
|
|
|||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,224,884
|
)
|
|
(1,224,884
|
)
|
|||||
Other Comprehensive Loss
|
—
|
|
|
—
|
|
|
—
|
|
|
(28,502
|
)
|
|
—
|
|
|
(28,502
|
)
|
|||||
Stock Compensation
|
—
|
|
|
—
|
|
|
14,359
|
|
|
—
|
|
|
—
|
|
|
14,359
|
|
|||||
Issuance of Common Stock in public offerings, net of related expenses
|
22,425,000
|
|
|
224
|
|
|
981,299
|
|
|
—
|
|
|
—
|
|
|
981,523
|
|
|||||
Issuance of Restricted Stock
|
236,812
|
|
|
2
|
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Issuance of Common Stock through exercise of options
|
5,000
|
|
|
—
|
|
|
45
|
|
|
—
|
|
|
—
|
|
|
45
|
|
|||||
Balance at December 31, 2015
|
108,322,250
|
|
|
$
|
1,082
|
|
|
$
|
2,824,303
|
|
|
$
|
(55,177
|
)
|
|
$
|
(731,371
|
)
|
|
$
|
2,038,837
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(In thousands)
|
||||||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net (loss) income
|
$
|
(1,224,884
|
)
|
|
$
|
247,403
|
|
|
$
|
153,192
|
|
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Accretion of discount—Asset Retirement Obligation
|
820
|
|
|
761
|
|
|
717
|
|
|||
Depletion, depreciation and amortization
|
337,694
|
|
|
265,431
|
|
|
118,880
|
|
|||
Impairment of oil and gas properties
|
1,440,418
|
|
|
—
|
|
|
—
|
|
|||
Stock-based compensation expense
|
8,616
|
|
|
8,916
|
|
|
6,297
|
|
|||
Loss (gain) from equity investments
|
113,120
|
|
|
(54,171
|
)
|
|
(212,714
|
)
|
|||
Gain on contribution of investments
|
—
|
|
|
(84,470
|
)
|
|
—
|
|
|||
Interest income - note receivable
|
—
|
|
|
(46
|
)
|
|
(26
|
)
|
|||
(Gain) loss on derivative instruments
|
(83,671
|
)
|
|
(121,148
|
)
|
|
18,189
|
|
|||
Deferred income tax (benefit) expense
|
(254,493
|
)
|
|
122,917
|
|
|
84,951
|
|
|||
Amortization of loan commitment fees
|
3,219
|
|
|
1,685
|
|
|
1,012
|
|
|||
Amortization of note discount and premium
|
(2,165
|
)
|
|
(533
|
)
|
|
298
|
|
|||
Changes in operating assets and liabilities:
|
|
|
|
|
|
||||||
Decrease (increase) in accounts receivable
|
31,986
|
|
|
(45,034
|
)
|
|
(33,209
|
)
|
|||
Decrease in accounts receivable—related party
|
30
|
|
|
2,571
|
|
|
32,231
|
|
|||
Increase in prepaid expenses
|
(191
|
)
|
|
(1,133
|
)
|
|
(1,075
|
)
|
|||
Increase in other assets
|
—
|
|
|
—
|
|
|
(4,523
|
)
|
|||
(Decrease) increase in accounts payable and accrued liabilities
|
(47,199
|
)
|
|
73,925
|
|
|
29,310
|
|
|||
Settlement of asset retirement obligation
|
(1,121
|
)
|
|
(7,201
|
)
|
|
(2,465
|
)
|
|||
Net cash provided by operating activities
|
322,179
|
|
|
409,873
|
|
|
191,065
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Deductions to cash held in escrow
|
8
|
|
|
8
|
|
|
8
|
|
|||
Additions to other property and equipment
|
(13,572
|
)
|
|
(7,030
|
)
|
|
(2,322
|
)
|
|||
Additions to oil and gas properties
|
(1,579,129
|
)
|
|
(1,329,277
|
)
|
|
(808,183
|
)
|
|||
Proceeds from sale of other property and equipment
|
—
|
|
|
—
|
|
|
113
|
|
|||
Proceeds from sale of oil and gas properties
|
27,998
|
|
|
4,404
|
|
|
—
|
|
|||
Repayments (advances) on note receivable to related party
|
—
|
|
|
875
|
|
|
(875
|
)
|
|||
Proceeds from sale of investments
|
—
|
|
|
258,362
|
|
|
192,737
|
|
|||
Contributions to equity method investments
|
(14,472
|
)
|
|
(63,999
|
)
|
|
(47,014
|
)
|
|||
Distributions from equity method investments
|
4,914
|
|
|
—
|
|
|
1,276
|
|
|||
Net cash used in investing activities
|
(1,574,253
|
)
|
|
(1,136,657
|
)
|
|
(664,260
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Principal payments on borrowings
|
(350,172
|
)
|
|
(115,690
|
)
|
|
(149
|
)
|
|||
Borrowings on line of credit
|
250,000
|
|
|
215,000
|
|
|
—
|
|
|||
Proceeds from bond issuance
|
350,000
|
|
|
318,000
|
|
|
—
|
|
|||
Debt issuance costs and loan commitment fees
|
(8,688
|
)
|
|
(7,831
|
)
|
|
(1,283
|
)
|
|||
Proceeds from issuance of common stock, net of offering costs and exercise of stock options
|
981,568
|
|
|
689
|
|
|
766,495
|
|
|||
Net cash provided by financing activities
|
1,222,708
|
|
|
410,168
|
|
|
765,063
|
|
|||
Net (decrease) increase in cash and cash equivalents
|
(29,366
|
)
|
|
(316,616
|
)
|
|
291,868
|
|
|||
Cash and cash equivalents at beginning of period
|
142,340
|
|
|
458,956
|
|
|
167,088
|
|
|||
Cash and cash equivalents at end of period
|
$
|
112,974
|
|
|
$
|
142,340
|
|
|
$
|
458,956
|
|
Supplemental disclosure of cash flow information:
|
|
|
|
|
|
||||||
Interest payments
|
$
|
59,736
|
|
|
$
|
28,646
|
|
|
$
|
24,280
|
|
Income tax payments
|
$
|
16,156
|
|
|
$
|
23,800
|
|
|
$
|
2,761
|
|
Supplemental disclosure of non-cash transactions:
|
|
|
|
|
|
||||||
Capitalized stock based compensation
|
$
|
5,743
|
|
|
$
|
5,944
|
|
|
$
|
4,198
|
|
Asset retirement obligation capitalized
|
$
|
8,800
|
|
|
$
|
9,295
|
|
|
$
|
3,556
|
|
Interest capitalized
|
$
|
13,580
|
|
|
$
|
9,687
|
|
|
$
|
7,132
|
|
Foreign currency translation loss on investment in Grizzly Oil Sands ULC
|
$
|
(28,502
|
)
|
|
$
|
(16,894
|
)
|
|
$
|
(12,223
|
)
|
1.
|
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
|
|
(In thousands)
|
|
|
December 31, 2012
|
$
|
2,442
|
|
December 31, 2013
|
$
|
(9,781
|
)
|
December 31, 2014
|
$
|
(26,675
|
)
|
December 31, 2015
|
$
|
(55,175
|
)
|
2.
|
ACQUISITIONS
|
|
|
(in thousands)
|
||
Consideration paid
|
|
|
||
Cash, net of purchase price adjustments
|
|
$
|
179,527
|
|
Fair value of identifiable assets acquired
|
|
|
||
Oil and natural gas properties
|
|
|
||
Proved
|
|
$
|
31,961
|
|
Unproved
|
|
6,263
|
|
|
Unevaluated
|
|
141,303
|
|
|
Fair value of net identifiable assets acquired
|
|
$
|
179,527
|
|
|
|
(In thousands)
|
||
Consideration paid
|
|
|
||
Cash, net of purchase price adjustments
|
|
$
|
405,029
|
|
Fair value of identifiable assets acquired
|
|
|
||
Oil and natural gas properties
|
|
|
||
Proved
|
|
$
|
70,804
|
|
Unevaluated
|
|
334,225
|
|
|
Fair value of net identifiable assets acquired
|
|
$
|
405,029
|
|
3.
|
PROPERTY AND EQUIPMENT
|
|
December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(In thousands)
|
||||||
Oil and natural gas properties
|
$
|
5,424,342
|
|
|
$
|
3,923,154
|
|
Office furniture and fixtures
|
12,589
|
|
|
10,752
|
|
||
Building
|
16,915
|
|
|
5,398
|
|
||
Land
|
3,667
|
|
|
2,194
|
|
||
Total property and equipment
|
5,457,513
|
|
|
3,941,498
|
|
||
Accumulated depletion, depreciation, amortization and impairment
|
(2,829,110
|
)
|
|
(1,050,879
|
)
|
||
Property and equipment, net
|
$
|
2,628,403
|
|
|
$
|
2,890,619
|
|
|
Costs Incurred in
|
||||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
|
Prior to 2013
|
|
Total
|
||||||||||
|
(in thousands)
|
||||||||||||||||||
Acquisition costs
|
$
|
621,519
|
|
|
$
|
361,167
|
|
|
$
|
273,146
|
|
|
$
|
522,872
|
|
|
$
|
1,778,704
|
|
Exploration costs
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Development costs
|
28,833
|
|
|
4,688
|
|
|
1,436
|
|
|
457
|
|
|
35,414
|
|
|||||
Capitalized interest
|
3,674
|
|
|
(2,353
|
)
|
|
2,262
|
|
|
—
|
|
|
3,583
|
|
|||||
Total oil and gas properties not subject to amortization
|
$
|
654,026
|
|
|
$
|
363,502
|
|
|
$
|
276,844
|
|
|
$
|
523,329
|
|
|
$
|
1,817,701
|
|
|
December 31, 2015
|
||
|
(In thousands)
|
||
Utica
|
$
|
1,812,256
|
|
Niobrara
|
4,932
|
|
|
Southern Louisiana
|
372
|
|
|
Bakken
|
96
|
|
|
Other
|
45
|
|
|
|
$
|
1,817,701
|
|
|
December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(In thousands)
|
||||||
Asset retirement obligation, beginning of period
|
$
|
17,938
|
|
|
$
|
15,083
|
|
Liabilities incurred
|
8,800
|
|
|
9,295
|
|
||
Liabilities settled
|
(1,121
|
)
|
|
(7,201
|
)
|
||
Accretion expense
|
820
|
|
|
761
|
|
||
Asset retirement obligation as of end of period
|
26,437
|
|
|
17,938
|
|
||
Less current portion
|
75
|
|
|
75
|
|
||
Asset retirement obligation, long-term
|
$
|
26,362
|
|
|
$
|
17,863
|
|
4.
|
EQUITY INVESTMENTS
|
|
|
|
Carrying Value
|
|
Loss (income) from equity method investments
|
|||||||||||||||
|
Approximate Ownership %
|
|
December 31,
|
|
For the Year Ended December 31,
|
|||||||||||||||
|
|
2015
|
|
2014
|
|
2015
|
2014
|
2013
|
||||||||||||
|
|
|
(In thousands)
|
|||||||||||||||||
Investment in Tatex Thailand II, LLC
|
23.5
|
%
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
189
|
|
$
|
(475
|
)
|
$
|
(343
|
)
|
Investment in Tatex Thailand III, LLC
|
17.9
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
12,408
|
|
254
|
|
|||||
Investment in Grizzly Oil Sands ULC
|
24.9999
|
%
|
|
50,645
|
|
|
180,218
|
|
|
115,544
|
|
13,159
|
|
2,999
|
|
|||||
Investment in Bison Drilling and Field Services LLC
|
—
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
213
|
|
3,533
|
|
|||||
Investment in Muskie Proppant LLC
|
—
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
371
|
|
1,975
|
|
|||||
Investment in Timber Wolf Terminals LLC
|
50.0
|
%
|
|
999
|
|
|
1,013
|
|
|
14
|
|
9
|
|
(6
|
)
|
|||||
Investment in Windsor Midstream LLC
|
22.5
|
%
|
|
27,955
|
|
|
13,505
|
|
|
(18,398
|
)
|
(477
|
)
|
(1,125
|
)
|
|||||
Investment in Stingray Pressure Pumping LLC
|
—
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
2,027
|
|
(818
|
)
|
|||||
Investment in Stingray Cementing LLC
|
50.0
|
%
|
|
2,487
|
|
|
2,647
|
|
|
147
|
|
344
|
|
93
|
|
|||||
Investment in Blackhawk Midstream LLC
|
48.5
|
%
|
|
—
|
|
|
—
|
|
|
(7,216
|
)
|
(84,787
|
)
|
673
|
|
|||||
Investment in Stingray Logistics LLC
|
—
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
(464
|
)
|
51
|
|
|||||
Investment in Diamondback Energy, Inc.
|
—
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
(79,654
|
)
|
(220,129
|
)
|
|||||
Investment in Stingray Energy Services LLC
|
50.0
|
%
|
|
5,908
|
|
|
5,718
|
|
|
557
|
|
(88
|
)
|
(215
|
)
|
|||||
Investment in Sturgeon Acquisitions LLC
|
25.0
|
%
|
|
22,769
|
|
|
22,507
|
|
|
(1,229
|
)
|
(1,819
|
)
|
—
|
|
|||||
Investment in Mammoth Energy Partners LP
|
30.5
|
%
|
|
131,630
|
|
|
143,973
|
|
|
16,485
|
|
(201
|
)
|
—
|
|
|||||
|
|
|
$
|
242,393
|
|
|
$
|
369,581
|
|
|
$
|
106,093
|
|
$
|
(139,434
|
)
|
$
|
(213,058
|
)
|
|
December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(In thousands)
|
||||||
Current assets
|
$
|
105,537
|
|
|
$
|
181,060
|
|
Noncurrent assets
|
$
|
1,293,925
|
|
|
$
|
1,306,891
|
|
Current liabilities
|
$
|
56,559
|
|
|
$
|
114,506
|
|
Noncurrent liabilities
|
$
|
155,995
|
|
|
$
|
230,062
|
|
|
December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(In thousands)
|
||||||||||
Gross revenue
|
$
|
430,729
|
|
|
$
|
390,620
|
|
|
$
|
162,401
|
|
Net (income) loss
|
$
|
(16,761
|
)
|
|
$
|
140,796
|
|
|
$
|
17,350
|
|
5.
|
OTHER ASSETS
|
|
2015
|
|
2014
|
||||
|
(In thousands)
|
||||||
Plugging and abandonment escrow account on the WCBB properties (Note 15)
|
$
|
3,089
|
|
|
$
|
3,097
|
|
Certificates of Deposit securing letter of credit
|
276
|
|
|
275
|
|
||
Prepaid drilling costs
|
58
|
|
|
483
|
|
||
Loan commitment fees
|
2,870
|
|
|
2,470
|
|
||
Deposits
|
34
|
|
|
34
|
|
||
Other
|
37
|
|
|
117
|
|
||
|
$
|
6,364
|
|
|
$
|
6,476
|
|
6.
|
LONG-TERM DEBT
|
|
2015
|
|
2014
|
||||
|
(In thousands)
|
||||||
Revolving credit agreement (1)
|
$
|
—
|
|
|
$
|
100,000
|
|
Building loans (2)
|
1,653
|
|
|
1,826
|
|
||
7.75% senior unsecured notes due 2020 (3)
|
600,000
|
|
|
600,000
|
|
||
6.625% senior unsecured notes due 2023 (4)
|
350,000
|
|
|
—
|
|
||
Net unamortized original issue premium (discount), net (5)
|
12,493
|
|
|
14,658
|
|
||
Net unamortized debt issuance costs (6)
|
(17,883
|
)
|
|
(12,920
|
)
|
||
Construction loan (7)
|
—
|
|
|
—
|
|
||
Less: current maturities of long term debt
|
(179
|
)
|
|
(168
|
)
|
||
Debt reflected as long term
|
$
|
946,084
|
|
|
$
|
703,396
|
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
(In thousands)
|
||||||||||
Cash paid for interest
|
$
|
59,736
|
|
|
$
|
28,646
|
|
|
$
|
24,270
|
|
Change in accrued interest
|
4,011
|
|
|
3,875
|
|
|
(969
|
)
|
|||
Capitalized interest
|
(13,580
|
)
|
|
(9,687
|
)
|
|
(7,132
|
)
|
|||
Amortization of loan costs
|
3,219
|
|
|
1,685
|
|
|
1,012
|
|
|||
Amortization of note discount and premium
|
(2,165
|
)
|
|
(533
|
)
|
|
298
|
|
|||
Other
|
—
|
|
|
—
|
|
|
11
|
|
|||
Total interest expense
|
$
|
51,221
|
|
|
$
|
23,986
|
|
|
$
|
17,490
|
|
7.
|
COMMON STOCK OPTIONS, RESTRICTED STOCK AND CHANGES IN CAPITALIZATION
|
8.
|
STOCK-BASED COMPENSATION
|
|
Shares
|
|
Weighted
Average
Exercise Price
per Share
|
|
Weighted
Average
Remaining
Contractual Term
|
|
Aggregate
Intrinsic
Value (In thousands)
|
||||||
Options outstanding at January 1, 2013
|
335,241
|
|
|
$
|
6.37
|
|
|
2.39
|
|
|
$
|
10,678
|
|
Granted
|
—
|
|
|
—
|
|
|
|
|
|
||||
Exercised
|
(125,000
|
)
|
|
11.20
|
|
|
|
|
4,797
|
|
|||
Forfeited/expired
|
—
|
|
|
—
|
|
|
|
|
|
||||
Options outstanding at December 31, 2013
|
210,241
|
|
|
3.50
|
|
|
1.07
|
|
|
$
|
12,538
|
|
|
Granted
|
—
|
|
|
—
|
|
|
|
|
|
||||
Exercised
|
(205,241
|
)
|
|
3.36
|
|
|
|
|
12,822
|
|
|||
Forfeited/expired
|
—
|
|
|
—
|
|
|
|
|
|
||||
Options outstanding at December 31, 2014
|
5,000
|
|
|
9.07
|
|
|
0.69
|
|
|
$
|
163
|
|
|
Granted
|
—
|
|
|
—
|
|
|
|
|
|
||||
Exercised
|
(5,000
|
)
|
|
9.07
|
|
|
|
|
124
|
|
|||
Forfeited/expired
|
—
|
|
|
—
|
|
|
|
|
|
||||
Options outstanding at December 31, 2015
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
Options exercisable at December 31, 2015
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
Number of
Unvested
Restricted Shares
|
|
Weighted
Average
Grant Date
Fair Value
|
|||
Unvested shares as of January 1, 2013
|
245,831
|
|
|
$
|
31.88
|
|
Granted
|
463,952
|
|
|
50.00
|
|
|
Vested
|
(237,646
|
)
|
|
41.79
|
|
|
Forfeited
|
(8,500
|
)
|
|
38.54
|
|
|
Unvested shares as of December 31, 2013
|
463,637
|
|
|
$
|
44.80
|
|
Granted
|
246,409
|
|
|
$
|
65.07
|
|
Vested
|
(272,665
|
)
|
|
45.76
|
|
|
Forfeited
|
(50,136
|
)
|
|
53.72
|
|
|
Unvested shares as of December 31, 2014
|
387,245
|
|
|
$
|
55.87
|
|
Granted
|
352,605
|
|
|
$
|
35.99
|
|
Vested
|
(236,812
|
)
|
|
52.39
|
|
|
Forfeited
|
(18,799
|
)
|
|
45.21
|
|
|
Unvested shares as of December 31, 2015
|
484,239
|
|
|
$
|
43.51
|
|
9.
|
FAIR VALUE OF FINANCIAL INSTRUMENTS
|
10.
|
INCOME TAXES
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
(In thousands)
|
||||||||||
Current:
|
|
|
|
|
|
||||||
State
|
$
|
(1,069
|
)
|
|
$
|
14,384
|
|
|
$
|
6,860
|
|
Federal
|
(439
|
)
|
|
16,039
|
|
|
6,325
|
|
|||
Deferred:
|
|
|
|
|
|
||||||
State
|
(14,218
|
)
|
|
4,314
|
|
|
7,385
|
|
|||
Federal
|
(240,275
|
)
|
|
118,604
|
|
|
77,566
|
|
|||
Total income tax (benefit) expense provision
|
$
|
(256,001
|
)
|
|
$
|
153,341
|
|
|
$
|
98,136
|
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
(In thousands)
|
||||||||||
(Loss) income before federal income taxes
|
$
|
(1,480,885
|
)
|
|
$
|
400,744
|
|
|
$
|
251,328
|
|
Expected income tax at statutory rate
|
(518,310
|
)
|
|
140,259
|
|
|
87,965
|
|
|||
State income taxes
|
(15,908
|
)
|
|
11,570
|
|
|
9,297
|
|
|||
Other differences
|
(420
|
)
|
|
1,512
|
|
|
874
|
|
|||
Changes in valuation allowance
|
278,637
|
|
|
—
|
|
|
—
|
|
|||
Income tax (benefit) expense recorded
|
$
|
(256,001
|
)
|
|
$
|
153,341
|
|
|
$
|
98,136
|
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
(In thousands)
|
||||||||||
Deferred tax assets:
|
|
|
|
|
|
||||||
Net operating loss carryforward
|
$
|
46,209
|
|
|
$
|
1,091
|
|
|
$
|
1,462
|
|
Oil and gas property basis difference
|
292,838
|
|
|
—
|
|
|
—
|
|
|||
FASB ASC 718 compensation expense
|
1,922
|
|
|
1,562
|
|
|
634
|
|
|||
AMT credit
|
23,629
|
|
|
24,053
|
|
|
7,968
|
|
|||
Charitable contributions carryover
|
146
|
|
|
150
|
|
|
25
|
|
|||
Unrealized loss on hedging activities
|
—
|
|
|
—
|
|
|
8,540
|
|
|||
Foreign tax credit carryforwards
|
2,074
|
|
|
2,074
|
|
|
2,074
|
|
|||
Accrued liabilities
|
—
|
|
|
1,260
|
|
|
—
|
|
|||
ARO liability
|
9,415
|
|
|
—
|
|
|
—
|
|
|||
State net operating loss carryover
|
4,344
|
|
|
2,627
|
|
|
4,408
|
|
|||
Total deferred tax assets
|
380,577
|
|
|
32,817
|
|
|
25,111
|
|
|||
Valuation allowance for deferred tax assets
|
(281,782
|
)
|
|
(3,145
|
)
|
|
(4,743
|
)
|
|||
Deferred tax assets, net of valuation allowance
|
98,795
|
|
|
29,672
|
|
|
20,368
|
|
|||
Deferred tax liabilities:
|
|
|
|
|
|
||||||
Oil and gas property basis difference
|
—
|
|
|
183,767
|
|
|
72,173
|
|
|||
Investment in pass through entities
|
7,430
|
|
|
38,315
|
|
|
8,799
|
|
|||
Non-oil and gas property basis difference
|
715
|
|
|
849
|
|
|
249
|
|
|||
Investment in nonconsolidated affiliates
|
—
|
|
|
—
|
|
|
46,495
|
|
|||
Unrealized gain on hedging activities
|
66,422
|
|
|
37,006
|
|
|
—
|
|
|||
Total deferred tax liabilities
|
74,567
|
|
|
259,937
|
|
|
127,716
|
|
|||
Net deferred tax asset (liability)
|
$
|
24,228
|
|
|
$
|
(230,265
|
)
|
|
$
|
(107,348
|
)
|
11.
|
EARNINGS PER SHARE
|
|
For the Year Ended December 31,
|
|||||||||||||||||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
|||||||||||||||||||||||||||
|
Loss
|
|
Shares
|
|
Per
Share
|
|
Income
|
|
Shares
|
|
Per
Share
|
|
Income
|
|
Shares
|
|
Per Share
|
|||||||||||||||
|
(In thousands, except share data)
|
|||||||||||||||||||||||||||||||
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Net (loss) income
|
$
|
(1,224,884
|
)
|
|
99,792,401
|
|
|
$
|
(12.27
|
)
|
|
$
|
247,403
|
|
|
85,445,963
|
|
|
$
|
2.90
|
|
|
$
|
153,192
|
|
|
77,375,683
|
|
|
$
|
1.98
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Stock options and awards
|
—
|
|
|
—
|
|
|
|
|
—
|
|
|
367,219
|
|
|
|
|
—
|
|
|
485,963
|
|
|
|
|||||||||
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Net (loss) income
|
$
|
(1,224,884
|
)
|
|
99,792,401
|
|
|
$
|
(12.27
|
)
|
|
$
|
247,403
|
|
|
85,813,182
|
|
|
$
|
2.88
|
|
|
$
|
153,192
|
|
|
77,861,646
|
|
|
$
|
1.97
|
|
12.
|
DERIVATIVE INSTRUMENTS
|
|
Location
|
Daily Volume (Bbls/day)
|
|
Weighted
Average Price
|
|||
January 2016 - June 2016
|
ARGUS LLS
|
1,500
|
|
|
$
|
63.03
|
|
January 2016 - June 2016
|
NYMEX WTI
|
1,000
|
|
|
$
|
61.40
|
|
|
Location
|
Daily Volume (MMBtu/day)
|
|
Weighted
Average Price
|
|||
January 2016 - March 2016
|
NYMEX Henry Hub
|
415,000
|
|
|
$
|
3.56
|
|
April 2016
|
NYMEX Henry Hub
|
425,000
|
|
|
$
|
3.52
|
|
May 2016 - June 2016
|
NYMEX Henry Hub
|
355,000
|
|
|
$
|
3.42
|
|
July 2016 - September 2016
|
NYMEX Henry Hub
|
375,000
|
|
|
$
|
3.38
|
|
October 2016
|
NYMEX Henry Hub
|
405,000
|
|
|
$
|
3.33
|
|
November 2016 - December 2016
|
NYMEX Henry Hub
|
430,000
|
|
|
$
|
3.30
|
|
January 2017 - March 2017
|
NYMEX Henry Hub
|
317,500
|
|
|
$
|
3.25
|
|
April 2017 - June 2017
|
NYMEX Henry Hub
|
272,500
|
|
|
$
|
3.31
|
|
July 2017 - December 2017
|
NYMEX Henry Hub
|
210,000
|
|
|
$
|
3.12
|
|
January 2018 - December 2018
|
NYMEX Henry Hub
|
160,000
|
|
|
$
|
3.01
|
|
January 2019 - March 2019
|
NYMEX Henry Hub
|
20,000
|
|
|
$
|
3.37
|
|
|
Location
|
Daily Volume (Bbls/day)
|
|
Weighted
Average Price
|
|||
January 2016 - December 2016
|
Mont Belvieu
|
1,000
|
|
|
$
|
20.16
|
|
|
Location
|
Daily Volume (MMBtu/day)
|
|
Weighted
Average Price
|
|||
January 2016 - March 2016
|
NYMEX Henry Hub
|
75,000
|
|
|
$
|
3.25
|
|
April 2016 - December 2016
|
NYMEX Henry Hub
|
95,000
|
|
|
$
|
3.18
|
|
January 2017 - March 2017
|
NYMEX Henry Hub
|
20,000
|
|
|
$
|
2.91
|
|
|
Location
|
Daily Volume (MMBtu/day)
|
|
Weighted
Average Price |
|||
January 2016 - March 2016
|
MichCon
|
70,000
|
|
|
$
|
0.11
|
|
April 2016 - December 2016
|
MichCon
|
40,000
|
|
|
$
|
0.02
|
|
November 2016 - March 2017
|
Tetco M2
|
50,000
|
|
|
$
|
(0.59
|
)
|
|
December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(In thousands)
|
||||||
Short-term derivative instruments - asset
|
$
|
142,794
|
|
|
$
|
78,391
|
|
Long-term derivative instruments - asset
|
$
|
51,088
|
|
|
$
|
24,448
|
|
Short-term derivative instruments - liability
|
$
|
437
|
|
|
$
|
—
|
|
Long-term derivative instruments - liability
|
$
|
6,935
|
|
|
$
|
—
|
|
|
Gain (loss) on derivative instruments
|
||||||||||
|
For the Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(In thousands)
|
||||||||||
Gas sales
|
$
|
72,412
|
|
|
$
|
115,324
|
|
|
$
|
(12,484
|
)
|
Oil and condensate sales
|
10,149
|
|
|
5,824
|
|
|
(5,705
|
)
|
|||
Natural gas liquids sales
|
1,110
|
|
|
—
|
|
|
—
|
|
|||
Total
|
$
|
83,671
|
|
|
$
|
121,148
|
|
|
$
|
(18,189
|
)
|
13.
|
FAIR VALUE MEASUREMENTS
|
|
December 31, 2015
|
||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||
|
(In thousands)
|
||||||||||
Assets:
|
|
|
|
|
|
||||||
Derivative Instruments
|
$
|
—
|
|
|
$
|
193,882
|
|
|
$
|
—
|
|
Liabilities:
|
|
|
|
|
|
||||||
Derivative Instruments
|
$
|
—
|
|
|
$
|
7,372
|
|
|
$
|
—
|
|
|
December 31, 2014
|
||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||
|
(In thousands)
|
||||||||||
Assets:
|
|
|
|
|
|
||||||
Derivative Instruments
|
$
|
—
|
|
|
$
|
102,839
|
|
|
$
|
—
|
|
14.
|
RELATED PARTY TRANSACTIONS
|
15.
|
COMMITMENTS
|
|
(In thousands)
|
||
2016
|
$
|
800
|
|
2017
|
583
|
|
|
2018
|
54
|
|
|
Total
|
1,437
|
|
|
For the years ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(In thousands)
|
||||||||||
Minimum rentals
|
$
|
759
|
|
|
$
|
733
|
|
|
$
|
258
|
|
Less: Sublease rentals
|
8
|
|
|
15
|
|
|
45
|
|
|||
|
$
|
751
|
|
|
$
|
718
|
|
|
$
|
213
|
|
17.
|
CONDENSED CONSOLIDATING FINANCIAL INFORMATION
|
|
December 31, 2015
|
||||||||||||||||||
|
Parent
|
|
Guarantors
|
|
Non-Guarantor
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Current assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
112,494
|
|
|
$
|
479
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
112,974
|
|
Accounts receivable - oil and gas
|
72,241
|
|
|
54
|
|
|
—
|
|
|
(423
|
)
|
|
71,872
|
|
|||||
Accounts receivable - related parties
|
16
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
16
|
|
|||||
Accounts receivable - intercompany
|
326,475
|
|
|
60
|
|
|
—
|
|
|
(326,535
|
)
|
|
—
|
|
|||||
Prepaid expenses and other current assets
|
3,905
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,905
|
|
|||||
Short-term derivative instruments
|
142,794
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
142,794
|
|
|||||
Total current assets
|
657,925
|
|
|
593
|
|
|
1
|
|
|
(326,958
|
)
|
|
331,561
|
|
|||||
Property and equipment:
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas properties, full-cost accounting
|
5,108,258
|
|
|
316,813
|
|
|
—
|
|
|
(729
|
)
|
|
5,424,342
|
|
|||||
Other property and equipment
|
33,128
|
|
|
43
|
|
|
—
|
|
|
—
|
|
|
33,171
|
|
|||||
Accumulated depletion, depreciation, amortization and impairment
|
(2,829,081
|
)
|
|
(29
|
)
|
|
—
|
|
|
—
|
|
|
(2,829,110
|
)
|
|||||
Property and equipment, net
|
2,312,305
|
|
|
316,827
|
|
|
—
|
|
|
(729
|
)
|
|
2,628,403
|
|
|||||
Other assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Equity investments and investments in subsidiaries
|
231,892
|
|
|
—
|
|
|
50,644
|
|
|
(40,143
|
)
|
|
242,393
|
|
|||||
Long-term derivative instruments
|
51,088
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
51,088
|
|
|||||
Deferred tax asset
|
74,925
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
74,925
|
|
|||||
Other assets
|
6,364
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,364
|
|
|||||
Total other assets
|
364,269
|
|
|
—
|
|
|
50,644
|
|
|
(40,143
|
)
|
|
374,770
|
|
|||||
Total assets
|
$
|
3,334,499
|
|
|
$
|
317,420
|
|
|
$
|
50,645
|
|
|
$
|
(367,830
|
)
|
|
$
|
3,334,734
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Liabilities and Stockholders' Equity
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Accounts payable and accrued liabilities
|
$
|
264,893
|
|
|
$
|
527
|
|
|
$
|
—
|
|
|
$
|
(292
|
)
|
|
$
|
265,128
|
|
Accounts payable - intercompany
|
—
|
|
|
326,541
|
|
|
124
|
|
|
(326,665
|
)
|
|
—
|
|
|||||
Asset retirement obligation - current
|
75
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
75
|
|
|||||
Short-term derivative instruments
|
437
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
437
|
|
|||||
Deferred tax liability
|
50,697
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
50,697
|
|
|||||
Current maturities of long-term debt
|
179
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
179
|
|
|||||
Total current liabilities
|
316,281
|
|
|
327,068
|
|
|
124
|
|
|
(326,957
|
)
|
|
316,516
|
|
|||||
Long-term derivative instrument
|
6,935
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,935
|
|
|||||
Asset retirement obligation - long-term
|
26,362
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
26,362
|
|
|||||
Long-term debt, net of current maturities
|
946,084
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
946,084
|
|
|||||
Total liabilities
|
1,295,662
|
|
|
327,068
|
|
|
124
|
|
|
(326,957
|
)
|
|
1,295,897
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Stockholders' equity:
|
|
|
|
|
|
|
|
|
|
||||||||||
Common stock
|
1,082
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,082
|
|
|||||
Paid-in capital
|
2,824,303
|
|
|
322
|
|
|
241,553
|
|
|
(241,875
|
)
|
|
2,824,303
|
|
|||||
Accumulated other comprehensive (loss) income
|
(55,177
|
)
|
|
—
|
|
|
(55,177
|
)
|
|
55,177
|
|
|
(55,177
|
)
|
|||||
Retained (deficit) earnings
|
(731,371
|
)
|
|
(9,970
|
)
|
|
(135,855
|
)
|
|
145,825
|
|
|
(731,371
|
)
|
|||||
Total stockholders' equity
|
2,038,837
|
|
|
(9,648
|
)
|
|
50,521
|
|
|
(40,873
|
)
|
|
2,038,837
|
|
|||||
Total liabilities and stockholders' equity
|
$
|
3,334,499
|
|
|
$
|
317,420
|
|
|
$
|
50,645
|
|
|
$
|
(367,830
|
)
|
|
$
|
3,334,734
|
|
|
December 31, 2014
|
||||||||||||||||||
|
Parent
|
|
Guarantors
|
|
Non-Guarantor
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Current assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
141,535
|
|
|
$
|
804
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
142,340
|
|
Accounts receivable - oil and gas
|
103,762
|
|
|
96
|
|
|
—
|
|
|
—
|
|
|
103,858
|
|
|||||
Accounts receivable - related parties
|
46
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46
|
|
|||||
Accounts receivable - intercompany
|
45,222
|
|
|
27
|
|
|
—
|
|
|
(45,249
|
)
|
|
—
|
|
|||||
Prepaid expenses and other current assets
|
3,714
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,714
|
|
|||||
Short-term derivative instruments
|
78,391
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
78,391
|
|
|||||
Total current assets
|
372,670
|
|
|
927
|
|
|
1
|
|
|
(45,249
|
)
|
|
328,349
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Property and equipment:
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas properties, full-cost accounting,
|
3,887,874
|
|
|
35,990
|
|
|
—
|
|
|
(710
|
)
|
|
3,923,154
|
|
|||||
Other property and equipment
|
18,301
|
|
|
43
|
|
|
—
|
|
|
—
|
|
|
18,344
|
|
|||||
Accumulated depletion, depreciation, amortization and impairment
|
(1,050,855
|
)
|
|
(24
|
)
|
|
—
|
|
|
—
|
|
|
(1,050,879
|
)
|
|||||
Property and equipment, net
|
2,855,320
|
|
|
36,009
|
|
|
—
|
|
|
(710
|
)
|
|
2,890,619
|
|
|||||
Other assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Equity investments and investments in subsidiaries
|
360,238
|
|
|
—
|
|
|
180,217
|
|
|
(170,874
|
)
|
|
369,581
|
|
|||||
Long-term derivative instruments
|
24,448
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
24,448
|
|
|||||
Other assets
|
6,476
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,476
|
|
|||||
Total other assets
|
391,162
|
|
|
—
|
|
|
180,217
|
|
|
(170,874
|
)
|
|
400,505
|
|
|||||
Total assets
|
$
|
3,619,152
|
|
|
$
|
36,936
|
|
|
$
|
180,218
|
|
|
$
|
(216,833
|
)
|
|
$
|
3,619,473
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Liabilities and Stockholders' Equity
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Accounts payable and accrued liabilities
|
$
|
371,089
|
|
|
$
|
321
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
371,410
|
|
Accounts payable - intercompany
|
—
|
|
|
45,143
|
|
|
106
|
|
|
(45,249
|
)
|
|
—
|
|
|||||
Asset retirement obligation - current
|
75
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
75
|
|
|||||
Deferred tax liability
|
27,070
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
27,070
|
|
|||||
Current maturities of long-term debt
|
168
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
168
|
|
|||||
Total current liabilities
|
398,402
|
|
|
45,464
|
|
|
106
|
|
|
(45,249
|
)
|
|
398,723
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Asset retirement obligation - long-term
|
17,863
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17,863
|
|
|||||
Deferred tax liability
|
203,195
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
203,195
|
|
|||||
Long-term debt, net of current maturities
|
703,396
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
703,396
|
|
|||||
Total liabilities
|
1,322,856
|
|
|
45,464
|
|
|
106
|
|
|
(45,249
|
)
|
|
1,323,177
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Stockholders' equity:
|
|
|
|
|
|
|
|
|
|
||||||||||
Common stock
|
856
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
856
|
|
|||||
Paid-in capital
|
1,828,602
|
|
|
322
|
|
|
227,079
|
|
|
(227,401
|
)
|
|
1,828,602
|
|
|||||
Accumulated other comprehensive (loss) income
|
(26,675
|
)
|
|
—
|
|
|
(26,675
|
)
|
|
26,675
|
|
|
(26,675
|
)
|
|||||
Retained earnings (deficit)
|
493,513
|
|
|
(8,850
|
)
|
|
(20,292
|
)
|
|
29,142
|
|
|
493,513
|
|
|||||
Total stockholders' equity
|
2,296,296
|
|
|
(8,528
|
)
|
|
180,112
|
|
|
(171,584
|
)
|
|
2,296,296
|
|
|||||
Total liabilities and stockholders' equity
|
$
|
3,619,152
|
|
|
$
|
36,936
|
|
|
$
|
180,218
|
|
|
$
|
(216,833
|
)
|
|
$
|
3,619,473
|
|
|
Year Ended December 31, 2015
|
||||||||||||||||||
|
Parent
|
|
Guarantors
|
|
Non-Guarantor
|
|
Eliminations
|
|
Consolidated
|
||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Total revenues
|
$
|
709,525
|
|
|
$
|
1,468
|
|
|
$
|
—
|
|
|
$
|
(1,518
|
)
|
|
$
|
709,475
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating expenses
|
68,632
|
|
|
843
|
|
|
—
|
|
|
—
|
|
|
69,475
|
|
|||||
Production taxes
|
14,618
|
|
|
122
|
|
|
—
|
|
|
—
|
|
|
14,740
|
|
|||||
Midstream gathering and processing
|
138,526
|
|
|
64
|
|
|
—
|
|
|
—
|
|
|
138,590
|
|
|||||
Depreciation, depletion and amortization
|
337,689
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
337,694
|
|
|||||
Impairment of oil and gas properties
|
1,440,418
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,440,418
|
|
|||||
General and administrative
|
41,892
|
|
|
55
|
|
|
20
|
|
|
—
|
|
|
41,967
|
|
|||||
Accretion expense
|
820
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
820
|
|
|||||
|
2,042,595
|
|
|
1,089
|
|
|
20
|
|
|
—
|
|
|
2,043,704
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
(LOSS) INCOME FROM OPERATIONS
|
(1,333,070
|
)
|
|
379
|
|
|
(20
|
)
|
|
(1,518
|
)
|
|
(1,334,229
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
OTHER (INCOME) EXPENSE:
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense
|
51,221
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
51,221
|
|
|||||
Interest income
|
(643
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(643
|
)
|
|||||
Insurance proceeds
|
(10,015
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(10,015
|
)
|
|||||
Loss (income) from equity method investments and investments in subsidiaries
|
107,252
|
|
|
—
|
|
|
115,544
|
|
|
(116,703
|
)
|
|
106,093
|
|
|||||
|
147,815
|
|
|
—
|
|
|
115,544
|
|
|
(116,703
|
)
|
|
146,656
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
(LOSS) INCOME BEFORE INCOME TAXES
|
(1,480,885
|
)
|
|
379
|
|
|
(115,564
|
)
|
|
115,185
|
|
|
(1,480,885
|
)
|
|||||
INCOME TAX BENEFIT
|
(256,001
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(256,001
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
NET (LOSS) INCOME
|
$
|
(1,224,884
|
)
|
|
$
|
379
|
|
|
$
|
(115,564
|
)
|
|
$
|
115,185
|
|
|
$
|
(1,224,884
|
)
|
|
Year Ended December 31, 2014
|
||||||||||||||||||
|
Parent
|
|
Guarantors
|
|
Non-Guarantor
|
|
Eliminations
|
|
Consolidated
|
||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Total revenues
|
$
|
669,067
|
|
|
$
|
2,199
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
671,266
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating expenses
|
51,238
|
|
|
953
|
|
|
—
|
|
|
—
|
|
|
52,191
|
|
|||||
Production taxes
|
23,803
|
|
|
203
|
|
|
—
|
|
|
—
|
|
|
24,006
|
|
|||||
Midstream gathering and processing
|
64,402
|
|
|
65
|
|
|
—
|
|
|
—
|
|
|
64,467
|
|
|||||
Depreciation, depletion and amortization
|
265,428
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
265,431
|
|
|||||
General and administrative
|
37,846
|
|
|
446
|
|
|
(2
|
)
|
|
—
|
|
|
38,290
|
|
|||||
Accretion expense
|
761
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
761
|
|
|||||
Gain on sale of assets
|
(11
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11
|
)
|
|||||
|
443,467
|
|
|
1,670
|
|
|
(2
|
)
|
|
—
|
|
|
445,135
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
INCOME FROM OPERATIONS
|
225,600
|
|
|
529
|
|
|
2
|
|
|
—
|
|
|
226,131
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
OTHER (INCOME) EXPENSE:
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense
|
23,986
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23,986
|
|
|||||
Interest income
|
(195
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(195
|
)
|
|||||
Litigation settlement
|
25,500
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25,500
|
|
|||||
Gain on contribution of investments
|
(84,470
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(84,470
|
)
|
|||||
(Income) loss from equity method investments and investments in subsidiaries
|
(139,965
|
)
|
|
—
|
|
|
13,159
|
|
|
(12,628
|
)
|
|
(139,434
|
)
|
|||||
|
(175,144
|
)
|
|
—
|
|
|
13,159
|
|
|
(12,628
|
)
|
|
(174,613
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
INCOME (LOSS) BEFORE INCOME TAXES
|
400,744
|
|
|
529
|
|
|
(13,157
|
)
|
|
12,628
|
|
|
400,744
|
|
|||||
INCOME TAX EXPENSE
|
153,341
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
153,341
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
NET INCOME (LOSS)
|
$
|
247,403
|
|
|
$
|
529
|
|
|
$
|
(13,157
|
)
|
|
$
|
12,628
|
|
|
$
|
247,403
|
|
|
Year Ended December 31, 2013
|
||||||||||||||||||
|
Parent
|
|
Guarantors
|
|
Non-Guarantor
|
|
Eliminations
|
|
Consolidated
|
||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Total revenues
|
$
|
261,809
|
|
|
$
|
1,517
|
|
|
$
|
—
|
|
|
$
|
(573
|
)
|
|
$
|
262,753
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating expenses
|
25,971
|
|
|
732
|
|
|
—
|
|
|
—
|
|
|
26,703
|
|
|||||
Production taxes
|
26,848
|
|
|
85
|
|
|
—
|
|
|
—
|
|
|
26,933
|
|
|||||
Midstream gathering and processing
|
10,999
|
|
|
31
|
|
|
—
|
|
|
—
|
|
|
11,030
|
|
|||||
Depreciation, depletion and amortization
|
118,878
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
118,880
|
|
|||||
General and administrative
|
22,359
|
|
|
159
|
|
|
1
|
|
|
—
|
|
|
22,519
|
|
|||||
Accretion expense
|
717
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
717
|
|
|||||
Loss on sale of assets
|
508
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
508
|
|
|||||
|
206,280
|
|
|
1,009
|
|
|
1
|
|
|
—
|
|
|
207,290
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
INCOME (LOSS) FROM OPERATIONS
|
55,529
|
|
|
508
|
|
|
(1
|
)
|
|
(573
|
)
|
|
55,463
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
OTHER (INCOME) EXPENSE:
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense
|
17,490
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17,490
|
|
|||||
Interest income
|
(297
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(297
|
)
|
|||||
(Income) loss from equity method investments and investments in subsidiaries
|
(212,992
|
)
|
|
—
|
|
|
2,999
|
|
|
(3,065
|
)
|
|
(213,058
|
)
|
|||||
|
(195,799
|
)
|
|
—
|
|
|
2,999
|
|
|
(3,065
|
)
|
|
(195,865
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
INCOME (LOSS) BEFORE INCOME TAXES
|
251,328
|
|
|
508
|
|
|
(3,000
|
)
|
|
2,492
|
|
|
251,328
|
|
|||||
INCOME TAX EXPENSE
|
98,136
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
98,136
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
NET INCOME (LOSS)
|
$
|
153,192
|
|
|
$
|
508
|
|
|
$
|
(3,000
|
)
|
|
$
|
2,492
|
|
|
$
|
153,192
|
|
|
Year Ended December 31, 2015
|
||||||||||||||||||
|
Parent
|
|
Guarantors
|
|
Non-Guarantor
|
|
Eliminations
|
|
Consolidated
|
||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Net (loss) income
|
$
|
(1,224,884
|
)
|
|
$
|
379
|
|
|
$
|
(115,564
|
)
|
|
$
|
115,185
|
|
|
$
|
(1,224,884
|
)
|
Foreign currency translation adjustment
|
(28,502
|
)
|
|
—
|
|
|
(28,502
|
)
|
|
28,502
|
|
|
(28,502
|
)
|
|||||
Other comprehensive (loss) income
|
(28,502
|
)
|
|
—
|
|
|
(28,502
|
)
|
|
28,502
|
|
|
(28,502
|
)
|
|||||
Comprehensive (loss) income
|
$
|
(1,253,386
|
)
|
|
$
|
379
|
|
|
$
|
(144,066
|
)
|
|
$
|
143,687
|
|
|
$
|
(1,253,386
|
)
|
|
Year Ended December 31, 2014
|
||||||||||||||||||
|
Parent
|
|
Guarantors
|
|
Non-Guarantor
|
|
Eliminations
|
|
Consolidated
|
||||||||||
|
|
||||||||||||||||||
Net income (loss)
|
$
|
247,403
|
|
|
$
|
529
|
|
|
$
|
(13,157
|
)
|
|
$
|
12,628
|
|
|
$
|
247,403
|
|
Foreign currency translation adjustment
|
(16,894
|
)
|
|
—
|
|
|
(16,894
|
)
|
|
16,894
|
|
|
(16,894
|
)
|
|||||
Other comprehensive (loss) income
|
(16,894
|
)
|
|
—
|
|
|
(16,894
|
)
|
|
16,894
|
|
|
(16,894
|
)
|
|||||
Comprehensive income (loss)
|
$
|
230,509
|
|
|
$
|
529
|
|
|
$
|
(30,051
|
)
|
|
$
|
29,522
|
|
|
$
|
230,509
|
|
|
Year Ended December 31, 2013
|
||||||||||||||||||
|
Parent
|
|
Guarantors
|
|
Non-Guarantor
|
|
Eliminations
|
|
Consolidated
|
||||||||||
|
|
||||||||||||||||||
Net income (loss)
|
$
|
153,192
|
|
|
$
|
508
|
|
|
$
|
(3,000
|
)
|
|
$
|
2,492
|
|
|
$
|
153,192
|
|
Foreign currency translation adjustment
|
(12,223
|
)
|
|
—
|
|
|
(12,223
|
)
|
|
12,223
|
|
|
(12,223
|
)
|
|||||
Change in fair value of derivative instruments, net of taxes
|
(4,419
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,419
|
)
|
|||||
Reclassification of settled contracts, net of taxes
|
10,290
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,290
|
|
|||||
Other comprehensive (loss) income
|
(6,352
|
)
|
|
—
|
|
|
(12,223
|
)
|
|
12,223
|
|
|
(6,352
|
)
|
|||||
Comprehensive income (loss)
|
$
|
146,840
|
|
|
$
|
508
|
|
|
$
|
(15,223
|
)
|
|
$
|
14,715
|
|
|
$
|
146,840
|
|
|
Year Ended December 31, 2015
|
||||||||||||||||||
|
Parent
|
|
Guarantors
|
|
Non-Guarantor
|
|
Eliminations
|
|
Consolidated
|
||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by (used in) operating activities
|
$
|
344,018
|
|
|
$
|
(21,839
|
)
|
|
$
|
(2
|
)
|
|
$
|
2
|
|
|
$
|
322,179
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash (used in) provided by investing activities
|
(1,595,767
|
)
|
|
21,514
|
|
|
(14,472
|
)
|
|
14,472
|
|
|
(1,574,253
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by (used in) financing activities
|
1,222,708
|
|
|
—
|
|
|
14,474
|
|
|
(14,474
|
)
|
|
1,222,708
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Net decrease in cash and cash equivalents
|
(29,041
|
)
|
|
(325
|
)
|
|
—
|
|
|
—
|
|
|
(29,366
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents at beginning of period
|
141,535
|
|
|
804
|
|
|
1
|
|
|
—
|
|
|
142,340
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents at end of period
|
$
|
112,494
|
|
|
$
|
479
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
112,974
|
|
|
Year Ended December 31, 2014
|
||||||||||||||||||
|
Parent
|
|
Guarantors
|
|
Non-Guarantor
|
|
Eliminations
|
|
Consolidated
|
||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by (used in) operating activities
|
$
|
388,177
|
|
|
$
|
21,698
|
|
|
$
|
(2
|
)
|
|
$
|
—
|
|
|
$
|
409,873
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash (used in) provided by investing activities
|
(1,108,241
|
)
|
|
(28,419
|
)
|
|
(18,799
|
)
|
|
18,802
|
|
|
(1,136,657
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by (used in) financing activities
|
410,168
|
|
|
—
|
|
|
18,802
|
|
|
(18,802
|
)
|
|
410,168
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Net (decrease) increase in cash and cash equivalents
|
(309,896
|
)
|
|
(6,721
|
)
|
|
1
|
|
|
—
|
|
|
(316,616
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents at beginning of period
|
451,431
|
|
|
7,525
|
|
|
—
|
|
|
—
|
|
|
458,956
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents at end of period
|
$
|
141,535
|
|
|
$
|
804
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
142,340
|
|
|
Year Ended December 31, 2013
|
||||||||||||||||||
|
Parent
|
|
Guarantors
|
|
Non-Guarantor
|
|
Eliminations
|
|
Consolidated
|
||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by operating activities
|
$
|
182,961
|
|
|
$
|
8,104
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
191,065
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash (used in) provided by investing activities
|
(661,886
|
)
|
|
(2,374
|
)
|
|
(33,929
|
)
|
|
33,929
|
|
|
(664,260
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by (used in) financing activities
|
765,063
|
|
|
—
|
|
|
33,929
|
|
|
(33,929
|
)
|
|
765,063
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Net increase in cash and cash equivalents
|
286,138
|
|
|
5,730
|
|
|
—
|
|
|
—
|
|
|
291,868
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents at beginning of period
|
165,293
|
|
|
1,795
|
|
|
—
|
|
|
—
|
|
|
167,088
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents at end of period
|
$
|
451,431
|
|
|
$
|
7,525
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
458,956
|
|
18.
|
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)
|
|
2015
|
|
2014
|
||||
|
(In thousands)
|
||||||
Proven properties
|
$
|
3,606,641
|
|
|
$
|
2,457,616
|
|
Unproven properties
|
1,817,701
|
|
|
1,465,538
|
|
||
|
5,424,342
|
|
|
3,923,154
|
|
||
Accumulated depreciation, depletion, amortization and impairment reserve
|
(2,820,113
|
)
|
|
(1,044,273
|
)
|
||
Net capitalized costs
|
$
|
2,604,229
|
|
|
$
|
2,878,881
|
|
|
|
|
|
||||
Equity investment in Grizzly Oil Sands ULC
|
|
|
|
||||
Proven properties
|
$
|
81,473
|
|
|
$
|
96,859
|
|
Unproven properties
|
82,388
|
|
|
103,160
|
|
||
|
163,861
|
|
|
200,019
|
|
||
Accumulated depreciation, depletion, amortization and impairment reserve
|
(1,531
|
)
|
|
(1,248
|
)
|
||
Net capitalized costs
|
$
|
162,330
|
|
|
$
|
198,771
|
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
(In thousands)
|
||||||||||
Acquisition
|
$
|
810,755
|
|
|
$
|
440,288
|
|
|
$
|
338,153
|
|
Development of proved undeveloped properties
|
642,811
|
|
|
864,511
|
|
|
408,121
|
|
|||
Exploratory
|
—
|
|
|
2,249
|
|
|
26,174
|
|
|||
Recompletions
|
13,894
|
|
|
45,658
|
|
|
44,633
|
|
|||
Capitalized asset retirement obligation
|
8,800
|
|
|
2,095
|
|
|
3,556
|
|
|||
Total
|
$
|
1,476,260
|
|
|
$
|
1,354,801
|
|
|
$
|
820,637
|
|
|
|
|
|
|
|
||||||
Equity investment in Diamondback Energy, Inc.
|
|
|
|
|
|
||||||
Acquisition
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
44,534
|
|
Development of proved undeveloped properties
|
—
|
|
|
—
|
|
|
6,369
|
|
|||
Exploratory
|
—
|
|
|
—
|
|
|
17,491
|
|
|||
Capitalized asset retirement obligation
|
—
|
|
|
—
|
|
|
50
|
|
|||
Total
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
68,444
|
|
|
|
|
|
|
|
||||||
Equity investment in Grizzly Oil Sands ULC
|
|
|
|
|
|
||||||
Acquisition
|
$
|
396
|
|
|
$
|
1,230
|
|
|
$
|
—
|
|
Development of proved undeveloped properties
|
47
|
|
|
7,107
|
|
|
—
|
|
|||
Exploratory
|
|
|
|
—
|
|
|
—
|
|
|||
Capitalized asset retirement obligation
|
282
|
|
|
1,055
|
|
|
—
|
|
|||
Total
|
$
|
725
|
|
|
$
|
9,392
|
|
|
$
|
—
|
|
|
2015
|
|
2014
|
|
2013
|
|||||||
|
(In thousands)
|
|||||||||||
Revenues
|
$
|
708,990
|
|
|
$
|
670,762
|
|
|
$
|
262,225
|
|
|
Production costs
|
(222,805
|
)
|
|
(140,664
|
)
|
|
(64,666
|
)
|
||||
Depletion
|
(335,288
|
)
|
|
(263,946
|
)
|
|
(118,118
|
)
|
||||
Impairment
|
(1,440,418
|
)
|
|
—
|
|
—
|
|
—
|
|
|||
|
(1,289,521
|
)
|
|
266,152
|
|
|
79,441
|
|
||||
Income tax (benefit) expense
|
|
|
|
|
|
|||||||
Current
|
—
|
|
|
—
|
|
|
—
|
|
||||
Deferred
|
(220,201
|
)
|
|
96,061
|
|
|
49,447
|
|
||||
|
(220,201
|
)
|
|
96,061
|
|
|
49,447
|
|
||||
Results of operations from producing activities
|
$
|
(1,069,320
|
)
|
|
$
|
170,091
|
|
|
$
|
29,994
|
|
|
Depletion per Mcf of gas equivalent (Mcfe)
|
$
|
1.68
|
|
|
$
|
3.01
|
|
|
$
|
4.78
|
|
|
|
|
|
|
|
|
|||||||
Results of Operations from equity method investment in Diamondback Energy, Inc.
|
|
|
|
|
|
|||||||
Revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
14,976
|
|
|
Production costs
|
—
|
|
|
—
|
|
|
(2,518
|
)
|
||||
Depletion
|
—
|
|
|
—
|
|
|
(4,754
|
)
|
||||
|
—
|
|
|
—
|
|
|
7,704
|
|
||||
Income tax expense
|
—
|
|
|
—
|
|
|
2,286
|
|
||||
Results of operations from producing activities
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5,418
|
|
|
|
|
|
|
|
|
|||||||
Results of Operations from equity method investment in Grizzly Oil Sands ULC
|
|
|
|
|
|
|||||||
Revenues
|
$
|
1,436
|
|
|
$
|
5,449
|
|
|
$
|
—
|
|
|
Production costs
|
(1,549
|
)
|
|
(10,113
|
)
|
|
—
|
|
||||
Depletion
|
(625
|
)
|
|
(1,195
|
)
|
|
—
|
|
||||
|
(738
|
)
|
|
(5,859
|
)
|
|
—
|
|
||||
Income tax expense
|
—
|
|
|
—
|
|
|
—
|
|
||||
Results of operations from producing activities
|
$
|
(738
|
)
|
|
$
|
(5,859
|
)
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
2015
|
|
2014
|
|
2013
|
|||||||||||||||||||||
|
Oil
|
|
Gas
|
|
NGL
|
|
Oil
|
|
Gas
|
|
NGL
|
|
Oil
|
|
Gas
|
|
NGL
|
|||||||||
|
(MBbls)
|
|
(MMcf)
|
|
(MBbls)
|
|
(MBbls)
|
|
(MMcf)
|
|
(MBbls)
|
|
(MBbls)
|
|
(MMcf)
|
|
(MBbls)
|
|||||||||
Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Beginning of the period
|
9,497
|
|
|
719,006
|
|
|
26,268
|
|
|
8,346
|
|
|
146,446
|
|
|
5,675
|
|
|
8,106
|
|
|
33,771
|
|
|
145
|
|
Purchases in oil and gas reserves in place
|
—
|
|
|
371,663
|
|
|
—
|
|
|
173
|
|
|
8,863
|
|
|
353
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Extensions and discoveries
|
2,413
|
|
|
997,057
|
|
|
5,486
|
|
|
4,975
|
|
|
629,151
|
|
|
22,594
|
|
|
2,765
|
|
|
123,597
|
|
|
5,850
|
|
Revisions of prior reserve estimates
|
(2,553
|
)
|
|
(371,430
|
)
|
|
(9,594
|
)
|
|
(1,313
|
)
|
|
(6,136
|
)
|
|
(304
|
)
|
|
(208
|
)
|
|
(2,031
|
)
|
|
—
|
|
Current production
|
(2,899
|
)
|
|
(156,151
|
)
|
|
(4,424
|
)
|
|
(2,684
|
)
|
|
(59,318
|
)
|
|
(2,050
|
)
|
|
(2,317
|
)
|
|
(8,891
|
)
|
|
(320
|
)
|
End of period
|
6,458
|
|
|
1,560,145
|
|
|
17,736
|
|
|
9,497
|
|
|
719,006
|
|
|
26,268
|
|
|
8,346
|
|
|
146,446
|
|
|
5,675
|
|
Proved developed reserves
|
6,120
|
|
|
652,961
|
|
|
12,910
|
|
|
5,719
|
|
|
345,166
|
|
|
12,379
|
|
|
5,609
|
|
|
94,552
|
|
|
3,527
|
|
Proved undeveloped reserves
|
338
|
|
|
907,184
|
|
|
4,826
|
|
|
3,778
|
|
|
373,840
|
|
|
13,889
|
|
|
2,737
|
|
|
51,894
|
|
|
2,148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Equity investment in Diamondback Energy, Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Beginning of the period
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,606
|
|
|
7,398
|
|
|
1,766
|
|
Change in ownership interest in Diamondback
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,720
|
)
|
|
(4,909
|
)
|
|
(1,171
|
)
|
Purchases in oil and gas reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
528
|
|
|
752
|
|
|
120
|
|
Extensions and discoveries
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,227
|
|
|
1,741
|
|
|
331
|
|
Revisions of prior reserve estimates
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(428
|
)
|
|
(417
|
)
|
|
(249
|
)
|
Current production
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(146
|
)
|
|
(124
|
)
|
|
(26
|
)
|
End of period
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,067
|
|
|
4,441
|
|
|
771
|
|
Proved developed reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,425
|
|
|
2,263
|
|
|
358
|
|
Proved undeveloped reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,642
|
|
|
2,178
|
|
|
413
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Equity investment in Grizzly Oil Sands ULC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Beginning of the period
|
14,558
|
|
|
—
|
|
|
—
|
|
|
13,637
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases in oil and gas reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Extensions and discoveries
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Revisions of prior reserve estimates
|
(14,530
|
)
|
|
—
|
|
|
—
|
|
|
990
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Current production
|
(28
|
)
|
|
—
|
|
|
—
|
|
|
(69
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
End of period
|
—
|
|
|
—
|
|
|
—
|
|
|
14,558
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Proved developed reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
1,632
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Proved undeveloped reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
12,926
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Year ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(In thousands)
|
||||||||||
Future cash flows
|
$
|
3,043,450
|
|
|
$
|
4,667,678
|
|
|
$
|
1,657,708
|
|
Future development and abandonment costs
|
(877,660
|
)
|
|
(719,898
|
)
|
|
(272,500
|
)
|
|||
Future production costs
|
(941,243
|
)
|
|
(880,427
|
)
|
|
(274,428
|
)
|
|||
Future production taxes
|
(58,169
|
)
|
|
(71,229
|
)
|
|
(78,647
|
)
|
|||
Future income taxes
|
(2,648
|
)
|
|
(693,154
|
)
|
|
(172,691
|
)
|
|||
Future net cash flows
|
1,163,730
|
|
|
2,302,970
|
|
|
859,442
|
|
|||
10% discount to reflect timing of cash flows
|
(399,399
|
)
|
|
(875,803
|
)
|
|
(280,976
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
764,331
|
|
|
$
|
1,427,167
|
|
|
$
|
578,466
|
|
|
|
|
|
|
|
||||||
Equity investment in Diamondback Energy, Inc. Standardized measure of discounted cash flows
|
|
|
|
|
|
||||||
Future cash flows
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
331,505
|
|
Future development and abandonment costs
|
—
|
|
|
—
|
|
|
(37,229
|
)
|
|||
Future production costs
|
—
|
|
|
—
|
|
|
(58,096
|
)
|
|||
Future production taxes
|
—
|
|
|
—
|
|
|
(22,925
|
)
|
|||
Future income taxes
|
—
|
|
|
—
|
|
|
(48,547
|
)
|
|||
Future net cash flows
|
—
|
|
|
—
|
|
|
164,708
|
|
|||
10% discount to reflect timing of cash flows
|
—
|
|
|
—
|
|
|
(94,462
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
70,246
|
|
|
|
|
|
|
|
||||||
Equity investment in Grizzly Oil Sands ULC Standardized measure of discounted cash flows
|
|
|
|
|
|
||||||
Future cash flows
|
$
|
—
|
|
|
$
|
754,720
|
|
|
$
|
—
|
|
Future development and abandonment costs
|
—
|
|
|
(205,242
|
)
|
|
—
|
|
|||
Future production costs
|
—
|
|
|
(291,988
|
)
|
|
—
|
|
|||
Future production taxes
|
—
|
|
|
—
|
|
|
—
|
|
|||
Future income taxes
|
—
|
|
|
(11,250
|
)
|
|
—
|
|
|||
Future net cash flows
|
—
|
|
|
246,240
|
|
|
—
|
|
|||
10% discount to reflect timing of cash flows
|
|
|
|
(152,494
|
)
|
|
—
|
|
|||
Standardized measure of discounted future net cash flows
|
$
|
—
|
|
|
$
|
93,746
|
|
|
$
|
—
|
|
|
Year ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(In thousands)
|
||||||||||
Sales and transfers of oil and gas produced, net of production costs
|
$
|
(486,185
|
)
|
|
$
|
(530,098
|
)
|
|
$
|
(197,559
|
)
|
Net changes in prices, production costs, and development costs
|
(1,412,181
|
)
|
|
97,716
|
|
|
65,573
|
|
|||
Acquisition of oil and gas reserves in place
|
83,340
|
|
|
14,266
|
|
|
—
|
|
|||
Extensions and discoveries
|
262,895
|
|
|
790,533
|
|
|
130,826
|
|
|||
Previously estimated development costs incurred during the period
|
117,540
|
|
|
68,227
|
|
|
43,478
|
|
|||
Revisions of previous quantity estimates, less related production costs
|
(98,162
|
)
|
|
(37,801
|
)
|
|
(3,591
|
)
|
|||
Accretion of discount
|
142,717
|
|
|
57,847
|
|
|
34,864
|
|
|||
Net changes in income taxes
|
412,240
|
|
|
(295,226
|
)
|
|
(30,239
|
)
|
|||
Change in production rates and other
|
314,960
|
|
|
683,237
|
|
|
186,473
|
|
|||
Total change in standardized measure of discounted future net cash flows
|
$
|
(662,836
|
)
|
|
$
|
848,701
|
|
|
$
|
229,825
|
|
|
|
|
|
|
|
||||||
Equity investment in Diamondback Energy, Inc. Changes in standardized measure of discounted cash flows
|
|
|
|
|
|
||||||
Change in ownership interest in Diamondback
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(52,145
|
)
|
Sales and transfers of oil and gas produced, net of production costs
|
—
|
|
|
—
|
|
|
(12,524
|
)
|
|||
Net changes in prices, production costs, and development costs
|
—
|
|
|
—
|
|
|
3,312
|
|
|||
Acquisition of oil and gas reserves in place
|
—
|
|
|
—
|
|
|
21,968
|
|
|||
Extensions and discoveries
|
—
|
|
|
—
|
|
|
39,776
|
|
|||
Previously estimated development costs incurred during the period
|
—
|
|
|
—
|
|
|
5,517
|
|
|||
Revisions of previous quantity estimates, less related production costs
|
—
|
|
|
—
|
|
|
(9,143
|
)
|
|||
Accretion of discount
|
—
|
|
|
—
|
|
|
4,175
|
|
|||
Net changes in income taxes
|
—
|
|
|
—
|
|
|
(12,137
|
)
|
|||
Change in production rates and other
|
—
|
|
|
—
|
|
|
2,862
|
|
|||
Total change in standardized measure of discounted future net cash flows
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(8,339
|
)
|
|
|
|
|
|
|
||||||
Equity investment in Grizzly Oil Sands ULC Changes in standardized measure of discounted cash flows
|
|
|
|
|
|
||||||
Sales and transfers of oil and gas produced, net of production costs
|
$
|
114
|
|
|
$
|
4,664
|
|
|
$
|
—
|
|
Net changes in prices, production costs, and development costs
|
—
|
|
|
(76,518
|
)
|
|
—
|
|
|||
Acquisition of oil and gas reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|||
Extensions and discoveries
|
—
|
|
|
7,107
|
|
|
—
|
|
|||
Previously estimated development costs incurred during the period
|
47
|
|
|
—
|
|
|
—
|
|
|||
Revisions of previous quantity estimates, less related production costs
|
(103,282
|
)
|
|
10,659
|
|
|
—
|
|
|||
Accretion of discount
|
9,375
|
|
|
14,946
|
|
|
—
|
|
|||
Net changes in income taxes
|
—
|
|
|
9,162
|
|
|
—
|
|
|||
Change in production rates and other
|
—
|
|
|
(25,738
|
)
|
|
—
|
|
|||
Total change in standardized measure of discounted future net cash flows
|
$
|
(93,746
|
)
|
|
$
|
(55,718
|
)
|
|
$
|
—
|
|
19.
|
SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
|
|
|
2015
|
||||||||||||||
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
||||||||
|
|
(In thousands)
|
||||||||||||||
Revenues
|
|
$
|
176,317
|
|
|
$
|
112,270
|
|
|
$
|
230,569
|
|
|
$
|
190,319
|
|
Income (loss) from operations
|
|
28,773
|
|
|
(21,644
|
)
|
|
(529,076
|
)
|
|
(812,282
|
)
|
||||
Income tax expense (benefit)
|
|
14,479
|
|
|
(17,214
|
)
|
|
(216,603
|
)
|
|
(36,663
|
)
|
||||
Net income (loss)
|
|
25,519
|
|
|
(31,325
|
)
|
|
(388,209
|
)
|
|
(830,869
|
)
|
||||
Income (loss) per share:
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
|
$
|
0.30
|
|
|
$
|
(0.32
|
)
|
|
$
|
(3.59
|
)
|
|
$
|
(7.67
|
)
|
Diluted
|
|
$
|
0.30
|
|
|
$
|
(0.32
|
)
|
|
$
|
(3.59
|
)
|
|
$
|
(7.67
|
)
|
|
|
|
|
|
|
|
|
|
||||||||
|
|
2014
|
||||||||||||||
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
||||||||
|
|
(In thousands)
|
||||||||||||||
Revenues
|
|
$
|
118,029
|
|
|
$
|
114,736
|
|
|
$
|
170,804
|
|
|
$
|
267,697
|
|
Income from operations
|
|
25,109
|
|
|
18,110
|
|
|
53,454
|
|
|
129,458
|
|
||||
Income tax expense
|
|
49,247
|
|
|
31,461
|
|
|
4,876
|
|
|
67,757
|
|
||||
Net income
|
|
82,558
|
|
|
47,852
|
|
|
6,920
|
|
|
110,073
|
|
||||
Income per share:
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
|
$
|
0.97
|
|
|
$
|
0.56
|
|
|
$
|
0.08
|
|
|
$
|
1.29
|
|
Diluted
|
|
$
|
0.96
|
|
|
$
|
0.56
|
|
|
$
|
0.08
|
|
|
$
|
1.28
|
|
ITEM 6.
|
EXHIBITS
|
Exhibit
Number
|
|
Description
|
|
|
|
2.1
|
|
Contribution Agreement, dated May 7, 2012, by and between the Company and Diamondback Energy, Inc. (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on May 8, 2012).
|
|
|
|
3.1
|
|
Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006).
|
|
|
|
3.2
|
|
Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 6, 2009).
|
|
|
|
3.3
|
|
Certificate of Amendment No. 2 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 23, 2013).
|
|
|
|
3.4
|
|
Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, 2006).
|
|
|
|
3.5
|
|
First Amendment to the Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 23, 2013).
|
|
|
|
3.6
|
|
Second Amendment to the Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on May 2, 2014).
|
|
|
|
4.1
|
|
Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the SEC on July 22, 2004).
|
|
|
|
4.2
|
|
Indenture, dated as of October 17, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (including the form of Gulfport Energy Corporation's 7.750% Senior Note Due November 1, 2020) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 23, 2012).
|
|
|
|
4.3
|
|
First Supplemental Indenture, dated December 21, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 2012).
|
|
|
|
4.4
|
|
Second Supplemental Indenture, dated August 18, 2014, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.3 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on August 19, 2014).
|
|
|
|
4.5
|
|
Indenture, dated as of April 21, 2015, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of the Company’s 6.625% Senior Notes due 2023) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 21, 2015).
|
|
|
|
4.6
|
|
Voting Rights Waiver Agreement, dated June 10, 2015, by and among Gulfport Energy Corporation, Putnam Investment Management, LLC, The Putnam Advisory Company, LLC and Putnam Fiduciary Trust Company (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on June 12, 2015).
|
|
|
|
10.1+
|
|
2013 Restated Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to the Form S-4, File No. 333-189992, filed by the Company with the SEC on July 17, 2013).
|
|
|
|
10.2+
|
|
2014 Executive Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 7, 2014).
|
|
|
|
10.3+
|
|
Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006).
|
|
|
|
10.4+
|
|
Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to the Form 10-K, File No. 000-19514, filed by the Company with the SEC on February 28, 2014).
|
|
|
|
10.5+
|
|
Consulting Agreement, effective as of June 14, 2013, by and between the Company and Mike Liddell (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on June 19, 2013).
|
|
|
|
10.6+
|
|
Separation and Release Agreement, dated as of January 31, 2014, by and between the Company and James D. Palm (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 4, 2014).
|
|
|
|
10.7+
|
|
Amended and Restated Employment Agreement, dated as of April 29, 2015, by and between the Company and Michael G. Moore (incorporated by reference to Exhibit 10.3 to the Form 10-Q,
File No. 000-19514, filed by the Company with the SEC on May 7, 2015).
|
|
|
|
10.8+
|
|
Employment Agreement, effective as of August 11, 2014, by and between the Company and Aaron Gaydosik (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on March 19, 2015).
|
|
|
|
10.9+
|
|
Employment Agreement, effective as of April 22, 2014, by and between the Company and Ross Kirtley (incorporated by reference to Exhibit 10.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on March 19, 2015).
|
|
|
|
10.10
|
|
Amended and Restated Credit Agreement, dated as of December 27, 2013, by and among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, sole lead arranger and sole bookrunner, Amegy Bank National Association, as syndication agent, KeyBank National Association, as documentation agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on January 3, 2014).
|
|
|
|
10.11
|
|
First Amendment to Amended and Restated Credit Agreement, dated as of April 23, 2014, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, sole lead arranger and sole bookrunner, Amegy Bank National Association, as syndication agent, KeyBank National Association, as documentation agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 28, 2014).
|
|
|
|
10.12
|
|
Second Amendment to Amended and Restated Credit Agreement, dated as of November 26, 2014, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 3, 2014).
|
|
|
|
10.13
|
|
Third Amendment to Amended and Restated Credit Agreement, dated as of April 10, 2015, among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 15, 2015).
|
|
|
|
10.14
|
|
Fourth Amendment to Amended and Restated Credit Agreement, dated as of May 29, 2015, among the Company, as borrower, the Bank of Nova Scotia, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on August 7, 2015).
|
|
|
|
10.15
|
|
Fifth Amendment to Amended and Restated Credit Agreement, dated as of September 18, 2015, among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on September 24, 2015).
|
|
|
|
10.16#
|
|
Sand Supply Agreement, effective as of October 1, 2014, by and between Muskie Proppant LLC and Gulfport Energy Corporation (incorporated by reference to Exhibit 10.1 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 7, 2014).
|
|
|
|
10.17#
|
|
Amendment to Sand Supply Agreement, dated as of November 3, 2015, by and between Muskie Proppant LLC and Gulfport Energy Corporation (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 5, 2015).
|
|
|
|
10.18#
|
|
Amended and Restated Master Services Agreement, effective as of October 1, 2014, by and between Gulfport Energy Corporation and Stingray Pressure Pumping LLC (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 7, 2014).
|
|
|
|
10.19*##
|
|
Amendment to Amended and Restated Master Services Agreement, dated as of February 18, 2016 to be effective as of January 1, 2016, by and between Gulfport Energy Corporation and Stingray Pressure Pumping LLC.
|
|
|
|
10.20+
|
|
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-4, File No. 333-199905, filed by the Company with the SEC on November 6, 2014).
|
|
|
|
14
|
|
Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 14, 2006).
|
|
|
|
21*
|
|
Subsidiaries of the Registrant.
|
|
|
|
23.1*
|
|
Consent of Grant Thornton LLP.
|
|
|
|
23.2*
|
|
Consent of Ryder Scott Company.
|
|
|
|
23.3*
|
|
Consent of Netherland, Sewell & Associates, Inc.
|
|
|
|
23.4*
|
|
Consent of Grant Thornton LLP with respect to financial statements of Diamondback Energy, Inc.
|
|
|
|
31.1*
|
|
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
|
|
|
|
31.2*
|
|
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
|
|
|
|
32.1**
|
|
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
|
|
|
|
32.2**
|
|
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
|
|
|
|
99.1*
|
|
Report of Netherland, Sewell & Associates, Inc.
|
|
|
|
101.INS*
|
|
XBRL Instance Document.
|
|
|
|
101.SCH*
|
|
XBRL Taxonomy Extension Schema Document.
|
|
|
|
101.CAL*
|
|
XBRL Taxonomy Extension Calculation Linkbase Document.
|
|
|
|
101.DEF*
|
|
XBRL Taxonomy Extension Definition Linkbase Document.
|
|
|
|
101.LAB*
|
|
XBRL Taxonomy Extension Labels Linkbase Document.
|
|
|
|
101.PRE*
|
|
XBRL Taxonomy Extension Presentation Linkbase Document.
|
*
|
Filed herewith.
|
**
|
Furnished herewith, not filed.
|
+
|
Management contract, compensatory plan or arrangement.
|
#
|
Confidential treatment with respect to certain portions of this agreement was granted by the SEC which portions have been omitted and filed separately with the SEC.
|
##
|
Confidential treatment requested as to certain portions, which portions have been omitted and filed separately with the SEC.
|
CONTRACTOR:
|
COMPANY:
|
Stingray Pressure Pumping LLC
|
Gulfport Energy Corporation
|
By:
/s/ Marc McCarthy
Name: Marc McCarthy
Title: Vice President
|
By:
/s/ Michael G. Moore
Name: Michael G. Moore
Title: Chief Executive Officer & President
|
|
|
|
Name of Subsidiary
|
|
Jurisdiction of Organization
|
|
|
|
Grizzly Holdings, Inc.
|
|
Delaware
|
Jaguar Resources LLC
|
|
Delaware
|
Puma Resources, Inc.
|
|
Delaware
|
Gator Marine, Inc.
|
|
Delaware
|
Gator Marine Ivanhoe, Inc.
|
|
Delaware
|
Westhawk Minerals LLC
|
|
Delaware
|
Gulfport Buckeye LLC
|
|
Delaware
|
|
/s/ GRANT THORNTON LLP
|
|
Oklahoma City, OK
|
February 19, 2016
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.
|
|
/s/ Michael G. Moore
|
|
Michael G. Moore
|
|
Chief Executive Officer and President
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.
|
|
/s/ Aaron Gaydosik
|
|
Aaron Gaydosik
|
|
Chief Financial Officer
|
(1)
|
the
Annual Report
on Form
10-K
of the Company for the
year
ended
December 31, 2015
(the “Report”) fully complies with the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and
|
(2)
|
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
|
/s/ Michael G. Moore
|
|
Michael G. Moore
|
|
Chief Executive Officer and President
|
(1)
|
the
Annual Report
on Form
10-K
of the Company for the
year
ended
December 31, 2015
(the “Report”) fully complies with the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and
|
(2)
|
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
|
/s/ Aaron Gaydosik
|
|
Aaron Gaydosik
|
|
Chief Financial Officer
|
|
|
Net Reserves
|
|
Future Net Revenue (M$)
|
||||||
|
|
Oil
|
|
NGL
|
|
Gas
|
|
|
|
Present Worth
|
Category
|
|
(MBBL)
|
|
(MBBL)
|
|
(MMCF)
|
|
Total
|
|
at 10%
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Producing
|
|
4,203.5
|
|
12,909.3
|
|
570,968.8
|
|
683,160.8
|
|
542,085.6
|
Proved Developed Non-Producing
|
|
1,774.8
|
|
0.0
|
|
81,789.7
|
|
123,742.9
|
|
107,332.6
|
Proved Undeveloped
|
|
337.9
|
|
4,826.2
|
|
907,183.6
|
|
354,278.6
|
|
112,591.8
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved
|
|
6,316.2
|
|
17,735.5
|
|
1,559,942.2
|
|
1,161,182.4
|
|
762,010.0
|
(i)
|
Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
|
(ii)
|
Same environment of deposition;
|
(iii)
|
Similar geological structure; and
|
(iv)
|
Same drive mechanism.
|
(i)
|
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
|
(ii)
|
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
|
(i)
|
Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
|
(ii)
|
Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
|
(iii)
|
Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
|
(iv)
|
Provide improved recovery systems.
|
(i)
|
Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
|
(ii)
|
Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
|
(iii)
|
Dry hole contributions and bottom hole contributions.
|
(iv)
|
Costs of drilling and equipping exploratory wells.
|
(v)
|
Costs of drilling exploratory-type stratigraphic test wells.
|
(i)
|
Oil and gas producing activities include:
|
(A)
|
The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
|
(B)
|
The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
|
(C)
|
The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
|
(1)
|
Lifting the oil and gas to the surface; and
|
(2)
|
Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
|
(D)
|
Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
|
a.
|
The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
|
b.
|
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
|
(ii)
|
Oil and gas producing activities do not include:
|
(A)
|
Transporting, refining, or marketing oil and gas;
|
(B)
|
Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
|
(C)
|
Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
|
(D)
|
Production of geothermal steam.
|
(i)
|
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods
|
(ii)
|
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
|
(iii)
|
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
|
(iv)
|
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
|
(v)
|
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
|
(vi)
|
Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
|
(i)
|
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
|
(ii)
|
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
|
(iii)
|
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
|
(iv)
|
See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
|
(i)
|
Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
|
(A)
|
Costs of labor to operate the wells and related equipment and facilities.
|
(B)
|
Repairs and maintenance.
|
(C)
|
Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
|
(D)
|
Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
|
(E)
|
Severance taxes.
|
(ii)
|
Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.
|
(i)
|
The area of the reservoir considered as proved includes:
|
(A)
|
The area identified by drilling and limited by fluid contacts, if any, and
|
(B)
|
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
|
(ii)
|
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
|
(iii)
|
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
|
(iv)
|
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
|
(A)
|
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
|
(B)
|
The project has been approved for development by all necessary parties and entities, including governmental entities.
|
(v)
|
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|
(ii)
|
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
|
(iii)
|
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
|