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ý
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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¨
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
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76-0466193
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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801 Louisiana, Suite 700
Houston, Texas
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77002
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(Address of principal executive offices)
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(Zip Code)
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Common Stock, par value $0.01 per share
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NYSE American
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(Title of Each Class)
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(Name of Each Exchange)
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Large accelerated filer
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¨
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Accelerated filer
|
o
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Non-accelerated filer
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¨
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Smaller reporting company
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x
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Emerging growth company
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¨
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Page
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PART I
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PART II
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PART III
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PART IV
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Items 1. and 2.
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Business and Properties
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Bbls
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Barrels of crude oil or other liquid hydrocarbons
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Bcf
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Billion cubic feet
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Bcfe
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Billion cubic feet equivalent
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Boe
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Barrel of crude oil or other liquid hydrocarbons equivalent
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MBbls
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Thousand barrels of crude oil or other liquid hydrocarbons
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Mboe
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Thousand barrels of crude oil equivalent
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Mcf
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Thousand cubic feet of natural gas
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Mcfe
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Thousand cubic feet equivalent
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MMBbls
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Million barrels of crude oil or other liquid hydrocarbons
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MMBtu
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Million British thermal units
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Mmcf
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Million cubic feet of natural gas
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Mmcfe
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Million cubic feet equivalent
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MMBoe
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Million barrels of crude oil or other liquid hydrocarbons equivalent
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NGL
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Natural gas liquids
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U.S.
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United States
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Average
Producing
Well
Working
Interest
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Producing wells at December 31, 2017
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||||
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Acreage
As of December 31, 2017
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||||||||
Field or Area
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Gross
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Net
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||||||
Tuscaloosa Marine Shale Trend
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87,635
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64,945
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65
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%
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|
40
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Haynesville Shale Trend
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50,097
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25,855
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33
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%
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91
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Eagle Ford Shale Trend
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32,430
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14,148
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|
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—
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—
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Other
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33,125
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7,323
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23
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%
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34
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Proved Reserves at December 31, 2017
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|||||||||||
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Developed
Producing
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Developed
Non-Producing
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Undeveloped
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Total
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|||||
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(dollars in thousands)
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|||||||||||
Net Proved Reserves:
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Oil (MBbls) (1)
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1,414
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|
716
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|
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—
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2,130
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Natural Gas (Mmcf)
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40,841
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12,020
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362,363
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415,224
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Mcf Natural Gas Equivalent (Mmcfe) (2)
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49,326
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16,313
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362,363
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428,002
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Estimated Future Net Cash Flows
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$
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500,504
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PV-10 (3)
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$
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264,159
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Discounted Future Income Taxes
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(3,849
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)
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Standardized Measure of Discounted Net Cash Flows (3)
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$
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260,310
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|||||
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Proved Reserves at December 31, 2016
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|||||||||||
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Developed
Producing
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Developed
Non-Producing
|
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Undeveloped
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Total
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|||||
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(dollars in thousands)
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|||||||||||
Net Proved Reserves:
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Oil (MBbls) (1)
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1,988
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|
|
827
|
|
|
—
|
|
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2,815
|
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Natural Gas (Mmcf)
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23,277
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4,266
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258,495
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286,038
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Mcf Natural Gas Equivalent (Mmcfe) (2)
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35,207
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9,225
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258,495
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302,927
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Estimated Future Net Cash Flows
|
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$
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159,824
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PV-10 (3)
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$
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57,086
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Discounted Future Income Taxes
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(164
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)
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Standardized Measure of Discounted Net Cash Flows (3)
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$
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56,922
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(1)
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Includes condensate.
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(2)
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Based on ratio of six Mcf of natural gas per Bbl of oil and per Bbl of NGLs.
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(3)
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PV-10 represents the discounted future net cash flows attributable to our proved oil and natural gas reserves before income tax, discounted at 10%. PV-10 of our total year-end proved reserves is considered a non-US GAAP financial measure as defined by the SEC. We believe that the presentation of the PV-10 is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. We further believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our reserves to other companies. See the reconciliation of our PV-10 to the standardized measure of discounted future net cash flows in the table above.
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December 31, 2017
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||||||||||
Area
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Proved
Developed
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Proved
Undeveloped
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Proved
Reserves
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% of
Total
|
||||
Tuscaloosa Marine Shale Trend
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12,704
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|
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—
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12,704
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3
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%
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Haynesville Shale Trend
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48,960
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362,363
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411,323
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96
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%
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Other
|
3,975
|
|
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—
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3,975
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|
|
1
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%
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Total
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65,639
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362,363
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428,002
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|
100
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%
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Oil
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Natural Gas
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Total
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||||||||||||
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Gross (1)
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Net (2)
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Gross (1)
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Net (2)
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Gross (1)
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Net (2)
|
||||||
Tuscaloosa Marine Shale Trend:
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||||||
Southeast Louisiana
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17
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12
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—
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—
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17
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12
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Southwest Mississippi
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23
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|
14
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—
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—
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23
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|
14
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Haynesville Shale Trend:
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East Texas
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—
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—
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6
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5
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6
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|
5
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Northwest Louisiana
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—
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—
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|
91
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|
30
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91
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|
|
30
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|
Other
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9
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|
|
1
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19
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|
5
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|
28
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|
|
6
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|
Total Productive Wells
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49
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|
|
27
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|
|
116
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|
|
40
|
|
|
165
|
|
|
67
|
|
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(1)
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Royalty and overriding interest wells that have immaterial values are excluded from the above table. As of
December 31, 2017
, only two wells with royalty-only and overriding interests-only are included.
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(2)
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Net working interest.
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|
Developed
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|
Undeveloped
|
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Total
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||||||||||||
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Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Tuscaloosa Marine Shale Trend:
|
|
|
|
|
|
|
|
|
|
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|
||||||
Southwest Mississippi
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28,369
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|
|
19,981
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|
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9,560
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|
|
5,459
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|
|
37,928
|
|
|
25,440
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Southeast Louisiana
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32,053
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|
|
21,919
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|
|
17,653
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|
|
17,586
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49,706
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|
|
39,505
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|
Haynesville Shale Trend:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
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East Texas
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12,553
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|
7,181
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|
|
212
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|
|
371
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|
|
12,765
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|
|
7,553
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Northwest Louisiana
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36,665
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|
18,362
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|
|
1,961
|
|
|
573
|
|
|
38,626
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|
|
18,935
|
|
Eagle Ford Shale Trend:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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South Texas
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11,185
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|
|
7,457
|
|
|
21,244
|
|
|
6,691
|
|
|
32,430
|
|
|
14,148
|
|
Other
|
27,195
|
|
|
6,004
|
|
|
4,637
|
|
|
686
|
|
|
31,832
|
|
|
6,690
|
|
Total
|
148,020
|
|
|
80,904
|
|
|
55,267
|
|
|
31,366
|
|
|
203,287
|
|
|
112,271
|
|
Year
|
Net Acreage
|
|
2018
|
22,492
|
|
2019
|
1,961
|
|
2020
|
8,284
|
|
2021
|
56
|
|
|
Year Ended December 31,
|
||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Development Wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
5
|
|
|
1.5
|
|
|
2
|
|
|
0.4
|
|
|
8
|
|
|
6.7
|
|
Non-Productive
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
5
|
|
|
1.5
|
|
|
2
|
|
|
0.4
|
|
|
8
|
|
|
6.7
|
|
Exploratory Wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Non-Productive
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
5
|
|
|
1.5
|
|
|
2
|
|
|
0.4
|
|
|
8
|
|
|
6.7
|
|
Non-Productive
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
5
|
|
|
1.5
|
|
|
2
|
|
|
0.4
|
|
|
8
|
|
|
6.7
|
|
|
Sales Volumes
|
|
Average Sales Prices (1)
|
|
|
|
Average
|
||||||||||||||||||||
|
Natural
Gas
Mmcf
|
|
Oil &
Condensate
MBbls
|
|
Total
Mmcfe
|
|
Natural
Gas
Mcf
|
|
Oil &
Condensate
Per Bbl
|
|
Total
Per Mcfe
|
|
% of Total Revenue
|
|
Production
Cost (2)
Per Mcfe
|
||||||||||||
For Year 2017 (Successor):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
TMS
|
—
|
|
|
302
|
|
|
1,813
|
|
|
$
|
—
|
|
|
$
|
50.86
|
|
|
$
|
8.48
|
|
|
34
|
%
|
|
$
|
3.92
|
|
Haynesville Shale Trend
|
10,303
|
|
|
—
|
|
|
10,303
|
|
|
2.88
|
|
|
—
|
|
|
2.88
|
|
|
66
|
%
|
|
0.47
|
|
||||
Other
|
20
|
|
|
2
|
|
|
34
|
|
|
5.86
|
|
|
55.67
|
|
|
7.25
|
|
|
—
|
%
|
|
3.84
|
|
||||
Total
|
10,323
|
|
|
304
|
|
|
12,150
|
|
|
$
|
2.89
|
|
|
$
|
50.90
|
|
|
$
|
3.73
|
|
|
100
|
%
|
|
$
|
1.00
|
|
For Year 2016 (Pro Forma) (4):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
TMS
|
—
|
|
|
473
|
|
|
2,837
|
|
|
$
|
—
|
|
|
$
|
40.81
|
|
|
$
|
6.80
|
|
|
34
|
%
|
|
$
|
1.98
|
|
Haynesville Shale Trend
|
5,471
|
|
|
—
|
|
|
5,471
|
|
|
1.44
|
|
|
—
|
|
|
1.44
|
|
|
66
|
%
|
|
0.48
|
|
||||
Other
|
84
|
|
|
3
|
|
|
102
|
|
|
3.00
|
|
|
39.71
|
|
|
3.65
|
|
|
—
|
%
|
|
3.69
|
|
||||
Total
|
5,555
|
|
|
476
|
|
|
8,410
|
|
|
$
|
1.47
|
|
|
$
|
40.80
|
|
|
$
|
3.28
|
|
|
100
|
%
|
|
$
|
1.02
|
|
For Year 2015 (Predecessor):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
TMS
|
—
|
|
|
883
|
|
|
5,298
|
|
|
$
|
—
|
|
|
$
|
49.60
|
|
|
$
|
8.27
|
|
|
55
|
%
|
|
$
|
1.36
|
|
Haynesville Shale Trend
|
7,018
|
|
|
—
|
|
|
7,018
|
|
|
1.67
|
|
|
—
|
|
|
1.67
|
|
|
15
|
%
|
|
0.39
|
|
||||
Eagle Ford Shale Trend (3)
|
776
|
|
|
453
|
|
|
3,494
|
|
|
2.39
|
|
|
46.30
|
|
|
6.54
|
|
|
29
|
%
|
|
1.37
|
|
||||
Other
|
190
|
|
|
—
|
|
|
190
|
|
|
3.58
|
|
|
—
|
|
|
3.58
|
|
|
1
|
%
|
|
4.55
|
|
||||
Total
|
7,984
|
|
|
1,336
|
|
|
16,000
|
|
|
$
|
1.79
|
|
|
$
|
48.50
|
|
|
$
|
4.94
|
|
|
100
|
%
|
|
$
|
0.97
|
|
|
(1)
|
Excludes the impact of commodity derivatives.
|
(2)
|
Excludes ad valorem and severance taxes.
|
(3)
|
We sold our Eagle Ford Shale Trend proved reserves and a portion of the associated leasehold on September 4, 2015.
|
(4)
|
2016 Pro Forma results is the combined Successor and Predecessor periods of 2016 as discussed earlier under “
Emergence from Voluntary Reorganization under Chapter 11 of the Bankruptcy Code
”
.
|
|
Year Ended December 31,
|
||||
|
2017
|
|
2016 (Pro Forma)
|
||
Genesis Crude Oil LP
|
20
|
%
|
|
44
|
%
|
Sunoco, Inc.
|
13
|
%
|
|
30
|
%
|
Williams Energy Resources LLC
|
29
|
%
|
|
—
|
%
|
ETC
|
15
|
%
|
|
4
|
%
|
Occidental Energy MA
|
7
|
%
|
|
13
|
%
|
Item 1A.
|
Risk Factors
|
•
|
the market prices of oil and natural gas;
|
•
|
volatility in the commodity-futures market;
|
•
|
financial market conditions and availability of capital;
|
•
|
future cash flows, credit availability and borrowings;
|
•
|
sources of funding for exploration and development;
|
•
|
our financial condition;
|
•
|
our ability to repay our debt;
|
•
|
the securities, capital or credit markets;
|
•
|
planned capital expenditures;
|
•
|
future drilling activity;
|
•
|
uncertainties about the estimated quantities of our oil and natural gas reserves;
|
•
|
production;
|
•
|
hedging arrangements;
|
•
|
litigation matters;
|
•
|
pursuit of potential future acquisition opportunities;
|
•
|
general economic conditions, either nationally or in the jurisdictions in which we are doing business;
|
•
|
legislative or regulatory changes, including retroactive royalty or production tax regimes
,
hydraulic-fracturing regulation, drilling and permitting regulations, derivatives reform, changes in state and federal corporate taxes, environmental regulation, environmental risks and liability under federal, state and foreign and local environmental laws and regulations;
|
•
|
the creditworthiness of our financial counterparties and operation partners; and
|
•
|
other factors discussed below and elsewhere in this Annual Report on Form 10-K and in our other public filings, press releases and discussions with our management.
|
•
|
worldwide and regional economic conditions impacting the supply and demand for oil and natural gas;
|
•
|
the level of global oil and natural gas exploration and production;
|
•
|
the level of global inventories;
|
•
|
prevailing prices on local price indices in the areas in which we operate and expectations about future commodity prices;
|
•
|
the extent of natural gas production associated with increased oil production;
|
•
|
the proximity, capacity, cost and availability of gathering and transportation facilities;
|
•
|
localized and global supply and demand fundamentals and transportation availability;
|
•
|
weather conditions across North America and, increasingly due to liquified natural gas, across the globe;
|
•
|
technological advances affecting energy consumption;
|
•
|
risks associated with operating drilling rigs;
|
•
|
speculative trading in commodity markets;
|
•
|
end user conservation trends;
|
•
|
petrochemical, fertilizer, ethanol, transportation supply and demand balance;
|
•
|
the price and availability of alternative fuels;
|
•
|
domestic, local and foreign governmental regulation and taxes; and
|
•
|
liquefied petroleum products supply and demand balances.
|
•
|
reductions in oil and natural gas prices;
|
•
|
inadequate capital resources;
|
•
|
limitations in the market for oil and natural gas;
|
•
|
lack of acceptable prospective acreage;
|
•
|
unexpected drilling conditions;
|
•
|
pressure or irregularities in formations;
|
•
|
equipment failures or accidents;
|
•
|
unavailability or high cost of drilling rigs, equipment or labor;
|
•
|
title problems;
|
•
|
compliance with governmental regulations;
|
•
|
mechanical difficulties; and
|
•
|
risks associated with horizontal drilling.
|
•
|
our proved reserves;
|
•
|
the volume of hydrocarbons we are able to produce from existing wells;
|
•
|
the prices at which our production is sold;
|
•
|
our ability to acquire, locate and produce new reserves;
|
•
|
the extent and levels of our derivative activities;
|
•
|
the levels of our operating expenses; and
|
•
|
our ability to borrow under our 2017 Senior Credit Facility.
|
•
|
historical production from the area compared with production from other similar producing wells;
|
•
|
the assumed effects of regulations by governmental agencies;
|
•
|
assumptions concerning future oil and natural gas prices; and
|
•
|
assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs.
|
•
|
the quantities of oil and natural gas that are ultimately recovered;
|
•
|
the production and operating costs incurred;
|
•
|
the amount and timing of future development expenditures; and
|
•
|
future oil and natural gas sales prices.
|
•
|
the amount and timing of actual production;
|
•
|
supply and demand for oil and natural gas;
|
•
|
increases or decreases in consumption; and
|
•
|
changes in governmental regulations or taxation.
|
|
Year Ended December 31,
|
||||
|
2017
|
|
2016 (Pro Forma)
|
||
Genesis Crude Oil LP
|
20
|
%
|
|
44
|
%
|
Sunoco, Inc.
|
13
|
%
|
|
30
|
%
|
Williams Energy Resources LLC
|
29
|
%
|
|
—
|
%
|
ETC
|
15
|
%
|
|
4
|
%
|
Occidental Energy MA
|
7
|
%
|
|
13
|
%
|
•
|
well blowouts;
|
•
|
cratering;
|
•
|
explosions;
|
•
|
uncontrollable flows of oil, natural gas, brine or well fluids;
|
•
|
fires;
|
•
|
formations with abnormal pressures;
|
•
|
shortages of, or delays in, obtaining water for hydraulic fracturing operations;
|
•
|
environmental hazards such as crude oil spills;
|
•
|
natural gas leaks;
|
•
|
pipeline and tank ruptures;
|
•
|
unauthorized discharges of brine, well stimulation and completion fluids or toxic gases into the environment;
|
•
|
encountering naturally occurring radioactive materials;
|
•
|
other pollution; and
|
•
|
other hazards and risks.
|
•
|
personal injury;
|
•
|
bodily injury;
|
•
|
third party property damage;
|
•
|
medical expenses;
|
•
|
legal defense costs;
|
•
|
pollution in some cases;
|
•
|
well blowouts in some cases; and
|
•
|
workers compensation.
|
•
|
key suppliers could terminate their relationship or require financial assurances or enhanced performance;
|
•
|
the ability to renew existing contracts and compete for new business may be adversely affected;
|
•
|
the ability to attract, motivate and/or retain key executives and employees may be adversely affected;
|
•
|
employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and
|
•
|
competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.
|
•
|
provide for a classified board of directors;
|
•
|
authorize our Board to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;
|
•
|
establish advance notice procedures for nominating directors or presenting matters at stockholder meetings; and
|
•
|
limit the persons who may call special meetings of stockholders.
|
Item 1B.
|
Unresolved Staff Comments
|
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
|
|
2017
|
|
2016
|
||||||||||||
|
High
|
|
Low
|
|
High
|
|
Low
|
||||||||
First Quarter
|
$
|
15.00
|
|
|
$
|
13.00
|
|
|
$
|
0.28
|
|
|
$
|
0.05
|
|
Second Quarter
|
17.25
|
|
|
10.81
|
|
|
0.08
|
|
|
0.02
|
|
||||
Third Quarter
|
14.37
|
|
|
8.20
|
|
|
0.05
|
|
|
0.01
|
|
||||
Fourth Quarter
|
11.95
|
|
|
8.96
|
|
|
14.00
|
|
|
10.75
|
|
Item 6.
|
Selected Financial Data
|
Item 7.
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
•
|
We incurred drilling or completion costs on 16 wells in the Haynesville Shale Trend. 11 gross wells are waiting completion as of December 31, 2017;
|
•
|
We ended the year with 428 Bcfe of proved oil and natural gas reserves;
|
•
|
We entered into the 2017 Senior Credit Facility with $23.3 million available at December 31, 2017;
|
•
|
We became listed on the NYSE American under the symbol “GDP”;
|
•
|
We exited 2017 with $26.0 million in cash.
|
|
Successor
|
|
Successor
|
Predecessor
|
|
Pro Forma
|
|
|
|
|
|||||||||||
|
Year Ended December 31,
|
|
October 13, to December 31, 2016
|
January 1, 2016 to October 12, 2016
|
|
Year Ended December 31,
|
|
|
|
|
|||||||||||
Summary Operating Information:
|
2017
|
|
|
|
|
2016
|
|
Variance
|
|||||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Natural gas
|
$
|
29,829
|
|
|
$
|
2,327
|
|
$
|
5,817
|
|
|
$
|
8,144
|
|
|
$
|
21,685
|
|
|
266
|
%
|
Oil and condensate
|
15,491
|
|
|
4,210
|
|
15,210
|
|
|
19,420
|
|
|
(3,929
|
)
|
|
(20
|
)%
|
|||||
Natural gas, oil and condensate
|
45,320
|
|
|
6,537
|
|
21,027
|
|
|
27,564
|
|
|
17,756
|
|
|
64
|
%
|
|||||
Net Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Natural gas (Mmcf)
|
10,323
|
|
|
1,198
|
|
4,357
|
|
|
5,555
|
|
|
4,768
|
|
|
86
|
%
|
|||||
Oil and condensate (MBbls)
|
304
|
|
|
88
|
|
388
|
|
|
476
|
|
|
(172
|
)
|
|
(36
|
)%
|
|||||
Total (Mmcfe)
|
12,150
|
|
|
1,723
|
|
6,687
|
|
|
8,410
|
|
|
3,740
|
|
|
44
|
%
|
|||||
Average daily production (Mcfe/d)
|
33,288
|
|
|
21,538
|
|
23,381
|
|
|
22,979
|
|
|
10,309
|
|
|
45
|
%
|
|||||
Average Realized Sales Price Per Unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Natural gas (per Mcf)
|
$
|
2.89
|
|
|
$
|
1.94
|
|
$
|
1.34
|
|
|
$
|
1.47
|
|
|
$
|
1.42
|
|
|
97
|
%
|
Natural gas (per Mfc) including the effect of realized gains/losses on derivatives
|
$
|
2.94
|
|
|
$
|
1.97
|
|
$
|
1.41
|
|
|
$
|
1.47
|
|
|
$
|
1.47
|
|
|
100
|
%
|
Oil and condensate (per Bbl)
|
$
|
50.90
|
|
|
$
|
47.84
|
|
$
|
39.20
|
|
|
$
|
40.80
|
|
|
$
|
10.10
|
|
|
25
|
%
|
Oil and condensate (per Bbl) including the
effect of realized gains/losses on derivatives
|
$
|
50.61
|
|
|
$
|
47.84
|
|
$
|
39.20
|
|
|
$
|
40.80
|
|
|
$
|
9.81
|
|
|
24
|
%
|
Average realized price (per Mcfe)
|
$
|
3.73
|
|
|
$
|
3.79
|
|
$
|
3.14
|
|
|
$
|
3.28
|
|
|
$
|
0.45
|
|
|
14
|
%
|
|
Successor
|
|
Successor
|
|
Predecessor
|
|
Pro Forma
|
|
|
|
|||||||||||
(in thousands)
|
Year Ended December 31,
|
|
October 13, to December 31, 2016
|
|
January 1, 2016 to October 12, 2016
|
|
Year Ended December 31,
|
|
|
|
|||||||||||
|
2017
|
|
|
|
|
|
2016
|
|
Variance
|
||||||||||||
Lease operating expenses
|
$
|
12,125
|
|
|
$
|
2,109
|
|
|
$
|
6,504
|
|
|
$
|
8,613
|
|
|
$
|
3,512
|
|
41
|
%
|
Production and other taxes
|
1,183
|
|
|
619
|
|
|
1,946
|
|
|
2,565
|
|
|
(1,382
|
)
|
(54
|
)%
|
|||||
Transportation and processing
|
6,222
|
|
|
228
|
|
|
1,265
|
|
|
*
|
|
—
|
|
—
|
%
|
||||||
Exploration
|
—
|
|
|
—
|
|
|
577
|
|
|
*
|
|
—
|
|
—
|
%
|
||||||
|
|
|
|
|
|
||||||||||||||||
|
Successor
|
|
Successor
|
|
Predecessor
|
|
Pro Forma
|
|
|
|
|||||||||||
Per Mcfe
|
Year Ended December 31,
|
|
October 13, to December 31, 2016
|
|
January 1, 2016 to October 12, 2016
|
|
Year Ended December 31,
|
|
|
|
|||||||||||
|
2017
|
|
|
|
|
|
2016
|
|
Variance
|
||||||||||||
Lease operating expenses
|
$
|
1.00
|
|
|
$
|
1.22
|
|
|
$
|
0.97
|
|
|
$
|
1.02
|
|
|
$
|
(0.02
|
)
|
(2
|
)%
|
Production and other taxes
|
0.10
|
|
|
0.36
|
|
|
0.29
|
|
|
0.30
|
|
|
(0.20
|
)
|
(67
|
)%
|
|||||
Transportation and processing
|
0.51
|
|
|
0.13
|
|
|
0.19
|
|
|
*
|
|
—
|
|
—
|
%
|
||||||
Exploration
|
—
|
|
|
—
|
|
|
0.09
|
|
|
*
|
|
—
|
|
—
|
%
|
|
Successor
|
|
Successor
|
|
Predecessor
|
||||||
(in thousands)
|
Year Ended December 31, 2017
|
|
October 13, to December 31, 2016
|
|
January 1, 2016 to October 12, 2016
|
||||||
Depreciation, depletion & amortization
|
$
|
12,125
|
|
|
$
|
1,556
|
|
|
$
|
8,276
|
|
Impairment
|
—
|
|
|
2,486
|
|
|
1,583
|
|
|||
General & administrative
|
16,696
|
|
|
2,200
|
|
|
14,474
|
|
|||
Gain on sale of assets
|
—
|
|
|
(2
|
)
|
|
(840
|
)
|
|||
|
|
|
|
||||||||
|
Successor
|
|
Successor
|
|
Predecessor
|
||||||
Per Mcfe
|
Year Ended December 31, 2017
|
|
October 13, to December 31, 2016
|
|
January 1, 2016 to October 12, 2016
|
||||||
Depreciation, depletion & amortization
|
$
|
1.00
|
|
|
$
|
0.90
|
|
|
$
|
1.24
|
|
Impairment
|
—
|
|
|
1.44
|
|
|
0.24
|
|
|||
General & administrative
|
1.37
|
|
|
1.28
|
|
|
2.16
|
|
|||
Gain on sale of assets
|
—
|
|
|
—
|
|
|
(0.13
|
)
|
|
Successor
|
|
Successor
|
|
Predecessor
|
||||||
|
Year Ended December 31, 2017
|
|
October 13, to December 31, 2016
|
|
January 1, 2016 to October 12, 2016
|
||||||
Other Income (Expense):
|
|
|
|
|
|
|
|
||||
Interest expense
|
$
|
(9,725
|
)
|
|
$
|
(1,824
|
)
|
|
$
|
(11,398
|
)
|
Interest income and other
|
1,236
|
|
|
1
|
|
|
117
|
|
|||
Gain on derivatives not designated as hedges
|
1,552
|
|
|
—
|
|
|
30
|
|
|||
Restructuring
|
—
|
|
|
—
|
|
|
(5,128
|
)
|
|||
Reorganization net gain
|
118
|
|
|
130
|
|
|
399,944
|
|
|||
Income tax benefit
|
978
|
|
|
—
|
|
|
—
|
|
|||
Average funded borrowings adjusted for debt discount
|
50,708
|
|
|
26,399
|
|
|
*
|
|
|||
Average funded borrowings
|
60,314
|
|
|
59,503
|
|
|
*
|
|
|
Successor
|
|
Successor
|
|
Predecessor
|
||||||
|
Year Ended December 31, 2017
|
|
October 13, to December 31, 2016
|
|
January 1, 2016 to October 12, 2016
|
||||||
(In thousands)
|
|
|
|
|
|
||||||
Net income (loss) (US GAAP)
|
$
|
(7,996
|
)
|
|
$
|
(4,307
|
)
|
|
$
|
369,944
|
|
Depreciation, depletion and amortization
|
12,125
|
|
|
1,556
|
|
|
8,276
|
|
|||
Income tax benefit
|
(978
|
)
|
|
—
|
|
|
—
|
|
|||
Exploration Expense
|
—
|
|
|
—
|
|
|
577
|
|
|||
Impairment
|
—
|
|
|
2,486
|
|
|
1,583
|
|
|||
Share-based compensation
|
6,863
|
|
|
240
|
|
|
3,307
|
|
|||
Interest expense
|
9,725
|
|
|
1,824
|
|
|
11,398
|
|
|||
Gain on reorganization
|
(118
|
)
|
|
(130
|
)
|
|
(399,422
|
)
|
|||
Gain on commodity derivatives not designated as hedges
|
(1,552
|
)
|
|
—
|
|
|
(30
|
)
|
|||
Net cash received (paid) in settlement of derivative instruments
|
471
|
|
|
—
|
|
|
—
|
|
|||
Other items (1)
|
(38
|
)
|
|
(3
|
)
|
|
(957
|
)
|
|||
Adjusted EBITDA/EBITDAX
|
$
|
18,502
|
|
|
$
|
1,666
|
|
|
$
|
(5,324
|
)
|
(1)
|
Other items include interest income and other, gain on sale of assets and other expense.
|
Cash flow statement information:
|
Successor
|
|
Successor
|
|
Predecessor
|
||||||
|
Year Ended December 31, 2017
|
|
October 13, to December 31, 2016
|
|
January 1, 2016 to October 12, 2016
|
||||||
Net Cash:
|
|
|
|
|
|
|
|
||||
Provided by (used in) operating activities
|
$
|
18,306
|
|
|
$
|
(4,327
|
)
|
|
$
|
(16,684
|
)
|
Used in investing activities
|
(28,200
|
)
|
|
(2,383
|
)
|
|
(3,495
|
)
|
|||
Provided by (used in) financing activities
|
(964
|
)
|
|
39,880
|
|
|
12,077
|
|
|||
Increase (decrease) in cash and cash equivalents
|
$
|
(10,858
|
)
|
|
$
|
33,170
|
|
|
$
|
(8,102
|
)
|
|
December 31, 2017
|
|
December 31, 2016
|
||||||||||||||||||||
|
Principal
|
|
Carrying
Amount |
|
Fair
Value |
|
Principal
|
|
Carrying
Amount |
|
Fair
Value |
||||||||||||
Exit Credit Facility (1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
16,651
|
|
|
$
|
16,651
|
|
|
$
|
16,651
|
|
2017 Senior Credit Facility (1)
|
16,723
|
|
|
16,723
|
|
|
16,723
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Convertible Second Lien Notes (2)
|
47,015
|
|
|
39,002
|
|
|
62,026
|
|
|
41,170
|
|
|
30,554
|
|
|
29,036
|
|
||||||
Total debt
|
$
|
63,738
|
|
|
$
|
55,725
|
|
|
$
|
78,749
|
|
|
$
|
57,821
|
|
|
$
|
47,205
|
|
|
$
|
45,687
|
|
(1)
|
The carrying amounts for the Exit Credit Facility and 2017 Senior Credit Facility represent fair value as they were fully secured.
|
(2)
|
The debt discount is being amortized using the effective interest rate method based upon a maturity date of August 30, 2019. The principal includes
$1.2 million
of paid-in-kind (PIK) interest as of December 31, 2016 and
$7.0 million
as of December 31, 2017. The carrying value includes
$10.6 million
and
$8.0 million
of unamortized debt discount at December 31, 2016 and 2017, respectively. The fair value of the notes was obtained by using a Binomial Lattice Model within Level 3 of the fair value hierarchy for the value on December 31, 2016 and utilized the last known sale price for the value on December 31, 2017.
|
|
Successor
|
|
Successor
|
|
Predecessor
|
|||||||||||||||
|
Year Ended December 31, 2017
|
|
Period from October 12, 2016 through December 31, 2016
|
|
Period from January 1, 2016 through October 12, 2016
|
|||||||||||||||
|
Interest
Expense |
|
Effective
Interest Rate |
|
Interest
Expense |
|
Effective
Interest Rate |
|
Interest
Expense |
|
Effective
Interest Rate |
|||||||||
Senior Credit Facility
|
$
|
—
|
|
|
—
|
%
|
|
$
|
—
|
|
|
—
|
%
|
|
$
|
3,342
|
|
|
*
|
|
Exit Credit Facility
|
947
|
|
|
7.1
|
%
|
|
306
|
|
|
7.3
|
%
|
|
—
|
|
|
—
|
%
|
|||
2017 Senior Credit Facility
|
244
|
|
|
7.2
|
%
|
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|||
Convertible Second Lien Notes (1)
|
8,534
|
|
|
24.1
|
%
|
|
1,518
|
|
|
24.7
|
%
|
|
—
|
|
|
—
|
%
|
|||
Obligations Canceled on the Effective Date
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|
8,010
|
|
|
*
|
|
|||
Other
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|
46
|
|
|
*
|
|
|||
Total
|
$
|
9,725
|
|
|
|
|
$
|
1,824
|
|
|
|
|
$
|
11,398
|
|
|
|
|
•
|
8.0% Second Lien Senior Secured Notes due 2018 in the principal amount of $100 million
|
•
|
8.875% Second Lien Senior Secured Notes due 2018 in the principal amount of $75 million
|
•
|
8.875% Senior Notes due 2019 in the principal amount of $116.8 million
|
•
|
5.0% Convertible Senior Notes due 2029 in the principal amount of $6.7 million
|
•
|
5.0% Convertible Senior Notes due 2032 in the principal amount of $94.2 million
|
•
|
5.0% Convertible Senior Exchange Notes due 2032 in the principal amount of $6.3 million
|
•
|
3.25% Convertible Senior Notes Due 2026 in the principal amount of $0.4 million
|
|
Payment due by Period
|
||||||||||||||||||||||||
|
Note
|
|
Total
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
and After |
||||||||||||
Debt
|
5
|
|
$
|
75,387
|
|
|
$
|
—
|
|
|
$
|
58,664
|
|
|
$
|
—
|
|
|
$
|
16,723
|
|
|
$
|
—
|
|
Office space leases
|
|
|
5,103
|
|
|
1,510
|
|
|
1,540
|
|
|
1,540
|
|
|
513
|
|
|
—
|
|
||||||
Operations contracts
|
|
|
871
|
|
|
836
|
|
|
20
|
|
|
15
|
|
|
—
|
|
|
—
|
|
||||||
Total contractual obligations (1)
|
|
|
$
|
81,361
|
|
|
$
|
2,346
|
|
|
$
|
60,224
|
|
|
$
|
1,555
|
|
|
$
|
17,236
|
|
|
$
|
—
|
|
|
(1)
|
This table does not include the estimated liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $3.4 million as of December 31, 2017. We record a separate liability for the asset retirement obligations. See
Note 4—Asset Retirement Obligation
in the
Notes to Consolidated Financial Statements in “Item 8—Financial Statements and Supplementary Data”
of this Annual Report on Form 10-K
.
|
Item 7A.
|
Quantitative and Qualitative Disclosures About Market Risk
|
Item 8.
|
Financial Statements and Supplementary Data
|
|
|
Page
|
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
|
December 31,
2017 |
|
December 31,
2016 |
||||
ASSETS
|
|
|
|
|
|||
CURRENT ASSETS:
|
|
|
|
|
|||
Cash and cash equivalents
|
$
|
25,992
|
|
|
$
|
36,850
|
|
Accounts receivable, trade and other, net of allowance
|
1,371
|
|
|
1,998
|
|
||
Accrued oil and natural gas revenue
|
4,958
|
|
|
3,142
|
|
||
Fair value of oil and natural gas derivatives
|
2,034
|
|
|
—
|
|
||
Inventory
|
2,521
|
|
|
4,125
|
|
||
Prepaid expenses and other
|
1,614
|
|
|
755
|
|
||
Total current assets
|
38,490
|
|
|
46,870
|
|
||
PROPERTY AND EQUIPMENT:
|
|
|
|
|
|||
Unevaluated properties
|
5,984
|
|
|
24,206
|
|
||
Oil and gas properties (full cost method)
|
120,333
|
|
|
60,936
|
|
||
Furniture, fixtures and equipment
|
1,039
|
|
|
984
|
|
||
|
127,356
|
|
|
86,126
|
|
||
Less: Accumulated depletion, depreciation and amortization
|
(15,899
|
)
|
|
(4,006
|
)
|
||
Net property and equipment
|
111,457
|
|
|
82,120
|
|
||
Fair value of oil and natural gas derivatives
|
566
|
|
|
—
|
|
||
Deferred tax asset
|
937
|
|
|
—
|
|
||
Other
|
691
|
|
|
322
|
|
||
TOTAL ASSETS
|
$
|
152,141
|
|
|
$
|
129,312
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|||
CURRENT LIABILITIES:
|
|
|
|
|
|||
Accounts payable
|
$
|
17,204
|
|
|
$
|
14,392
|
|
Accrued liabilities
|
18,075
|
|
|
3,882
|
|
||
Fair value of oil and natural gas derivatives
|
1,002
|
|
|
—
|
|
||
Total current liabilities
|
36,281
|
|
|
18,274
|
|
||
Long term debt, net
|
55,725
|
|
|
47,205
|
|
||
Accrued abandonment cost
|
3,367
|
|
|
2,933
|
|
||
Fair value of oil and natural gas derivatives
|
517
|
|
|
—
|
|
||
Total liabilities
|
95,890
|
|
|
68,412
|
|
||
Commitments and contingencies (See Note 10)
|
|
|
|
|
|
||
STOCKHOLDERS’ EQUITY:
|
|
|
|
|
|||
Successor Preferred stock: 10,000,000 shares $1.00 par value authorized, and none issued and outstanding
|
—
|
|
|
—
|
|
||
Successor Common stock: $0.01 par value, 75,000,000 shares authorized, and 10,770,962 and 9,108,826 shares issued and outstanding as of December 31, 2017 and 2016, respectively
|
108
|
|
|
91
|
|
||
Additional paid in capital
|
68,446
|
|
|
65,116
|
|
||
Accumulated deficit
|
(12,303
|
)
|
|
(4,307
|
)
|
||
Total stockholders’ equity
|
56,251
|
|
|
60,900
|
|
||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
|
$
|
152,141
|
|
|
$
|
129,312
|
|
|
Successor
|
|
Successor
|
|
Predecessor
|
||||||
|
Year ended December 31, 2017
|
|
Period from October 13, 2016 to December 31, 2016
|
|
Period ended October 12, 2016
|
||||||
REVENUES:
|
|
|
|
|
|
|
|||||
Oil and natural gas revenues
|
$
|
45,320
|
|
|
$
|
6,537
|
|
|
$
|
21,027
|
|
Other
|
833
|
|
|
45
|
|
|
(341
|
)
|
|||
|
46,153
|
|
|
6,582
|
|
|
20,686
|
|
|||
OPERATING EXPENSES:
|
|
|
|
|
|
|
|||||
Lease operating expense
|
12,125
|
|
|
2,109
|
|
|
6,504
|
|
|||
Production and other taxes
|
1,183
|
|
|
619
|
|
|
1,946
|
|
|||
Transportation and processing
|
6,222
|
|
|
228
|
|
|
1,265
|
|
|||
Depreciation, depletion and amortization
|
12,125
|
|
|
1,556
|
|
|
8,276
|
|
|||
Exploration
|
—
|
|
|
—
|
|
|
577
|
|
|||
Impairment
|
—
|
|
|
2,486
|
|
|
1,583
|
|
|||
General and administrative
|
16,696
|
|
|
2,200
|
|
|
14,474
|
|
|||
Gain on sale of assets
|
—
|
|
|
(2
|
)
|
|
(840
|
)
|
|||
Other
|
(43
|
)
|
|
—
|
|
|
—
|
|
|||
|
48,308
|
|
|
9,196
|
|
|
33,785
|
|
|||
Operating loss
|
(2,155
|
)
|
|
(2,614
|
)
|
|
(13,099
|
)
|
|||
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
|
|||||
Interest expense
|
(9,725
|
)
|
|
(1,824
|
)
|
|
(11,398
|
)
|
|||
Interest income and other
|
1,236
|
|
|
1
|
|
|
117
|
|
|||
Gain on derivatives not designated as hedges
|
1,552
|
|
|
—
|
|
|
30
|
|
|||
Restructuring
|
—
|
|
|
—
|
|
|
(5,128
|
)
|
|||
|
(6,937
|
)
|
|
(1,823
|
)
|
|
(16,379
|
)
|
|||
|
|
|
|
|
|
||||||
Reorganization items, net
|
118
|
|
|
130
|
|
|
399,422
|
|
|||
|
|
|
|
|
|
||||||
Income (loss) before income taxes
|
(8,974
|
)
|
|
(4,307
|
)
|
|
369,944
|
|
|||
Income tax benefit
|
978
|
|
|
—
|
|
|
—
|
|
|||
Net income (loss)
|
(7,996
|
)
|
|
(4,307
|
)
|
|
369,944
|
|
|||
Preferred stock, net
|
—
|
|
|
—
|
|
|
11,237
|
|
|||
Net income (loss) applicable to common stock
|
$
|
(7,996
|
)
|
|
$
|
(4,307
|
)
|
|
$
|
358,707
|
|
PER COMMON SHARE
|
|
|
|
|
|
|
|||||
Net income (loss) applicable to common stock—basic
|
$
|
(0.80
|
)
|
|
$
|
(0.60
|
)
|
|
$
|
4.64
|
|
Net income (loss) applicable to common stock—diluted
|
$
|
(0.80
|
)
|
|
$
|
(0.60
|
)
|
|
$
|
3.69
|
|
Weighted average common shares outstanding—basic
|
9,975
|
|
|
7,184
|
|
|
77,236
|
|
|||
Weighted average common shares outstanding—diluted
|
9,975
|
|
|
7,184
|
|
|
98,369
|
|
|
Successor
|
|
Successor
|
|
Predecessor
|
||||||
|
Year ended December 31, 2017
|
|
October 13, to December 31, 2016
|
|
January 1, 2016 to October 12, 2016
|
||||||
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|||
Net income (loss)
|
$
|
(7,996
|
)
|
|
$
|
(4,307
|
)
|
|
$
|
369,944
|
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
|
|
|
|
|
|
|
|
|
|||
Depletion, depreciation and amortization
|
12,125
|
|
|
1,556
|
|
|
8,276
|
|
|||
Deferred income taxes
|
(937
|
)
|
|
—
|
|
|
—
|
|
|||
(Gain) on derivatives not designated as hedges
|
(1,552
|
)
|
|
—
|
|
|
(30
|
)
|
|||
Net cash received in settlement of derivative instruments
|
471
|
|
|
—
|
|
|
—
|
|
|||
Impairment
|
—
|
|
|
2,486
|
|
|
1,583
|
|
|||
Embedded derivative
|
—
|
|
|
—
|
|
|
(5,538
|
)
|
|||
Amortization of leasehold costs
|
—
|
|
|
—
|
|
|
67
|
|
|||
Share-based compensation (non-cash)
|
6,863
|
|
|
240
|
|
|
3,307
|
|
|||
Gain on sale of assets
|
—
|
|
|
—
|
|
|
(840
|
)
|
|||
Amortization of finance cost and debt discount
|
8,534
|
|
|
1,518
|
|
|
7,425
|
|
|||
Reorganization items
|
(1
|
)
|
|
(6,658
|
)
|
|
(410,875
|
)
|
|||
Gain from material transfers
|
(367
|
)
|
|
—
|
|
|
—
|
|
|||
Amortization of transportation obligation
|
—
|
|
|
—
|
|
|
156
|
|
|||
Change in assets and liabilities:
|
|
|
|
|
|
|
|
|
|||
Accounts receivable, trade and other, net of allowance
|
627
|
|
|
(1,408
|
)
|
|
724
|
|
|||
Accrued oil and natural gas revenue
|
(1,816
|
)
|
|
1,065
|
|
|
(786
|
)
|
|||
Inventory
|
—
|
|
|
—
|
|
|
(265
|
)
|
|||
Prepaid expenses and other
|
(881
|
)
|
|
(66
|
)
|
|
811
|
|
|||
Accounts payable
|
1,888
|
|
|
1,631
|
|
|
(4,332
|
)
|
|||
Accrued liabilities
|
1,348
|
|
|
(384
|
)
|
|
13,689
|
|
|||
Net cash provided by (used in) operating activities
|
18,306
|
|
|
(4,327
|
)
|
|
(16,684
|
)
|
|||
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|||
Capital expenditures
|
(28,763
|
)
|
|
(3,232
|
)
|
|
(3,789
|
)
|
|||
Proceeds from sale of assets
|
563
|
|
|
849
|
|
|
294
|
|
|||
Net cash used in investing activities
|
(28,200
|
)
|
|
(2,383
|
)
|
|
(3,495
|
)
|
|||
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|||
Principal payments of bank borrowings
|
(16,651
|
)
|
|
(23,742
|
)
|
|
—
|
|
|||
Proceeds from bank borrowings
|
16,723
|
|
|
—
|
|
|
13,000
|
|
|||
Proceeds from equity offering, net of issuance costs
|
—
|
|
|
23,622
|
|
|
—
|
|
|||
Proceeds from Second Lien Notes
|
—
|
|
|
40,000
|
|
|
—
|
|
|||
Note conversions
|
—
|
|
|
—
|
|
|
(804
|
)
|
|||
Debt issuance costs
|
(694
|
)
|
|
—
|
|
|
(114
|
)
|
|||
Issuance cost, net
|
(342
|
)
|
|
—
|
|
|
—
|
|
|||
Other
|
—
|
|
|
—
|
|
|
(5
|
)
|
|||
Net cash provided by (used in) financing activities
|
(964
|
)
|
|
39,880
|
|
|
12,077
|
|
|||
Increase (decrease) in cash and cash equivalents
|
(10,858
|
)
|
|
33,170
|
|
|
(8,102
|
)
|
|||
Cash and cash equivalents, beginning of period
|
36,850
|
|
|
3,680
|
|
|
11,782
|
|
|||
Cash and cash equivalents, end of period
|
$
|
25,992
|
|
|
$
|
36,850
|
|
|
$
|
3,680
|
|
Supplemental disclosures of cash flow information:
|
|
|
|
|
|
|
|
|
|||
Cash paid during the year for interest
|
$
|
1,228
|
|
|
$
|
498
|
|
|
$
|
1,656
|
|
Cash paid during the year for taxes
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Increase (decrease) in non-cash capital expenditures
|
$
|
9,863
|
|
|
$
|
556
|
|
|
$
|
(836
|
)
|
|
Preferred
Stock |
|
Common
Stock |
|
Additional
Paid-in |
|
Treasury
Stock |
|
Retained
Earnings/ |
|
Total
Stockholders’ |
|||||||||||||||||||||
Predecessor Company
|
Shares
|
|
Value
|
|
Shares
|
|
Value
|
|
Capital
|
|
Shares
|
|
Value
|
|
(Deficit)
|
|
Equity/(Deficit)
|
|||||||||||||||
Balance at December 31, 2015
|
1,502
|
|
|
$
|
1,502
|
|
|
63,910
|
|
|
$
|
12,782
|
|
|
$
|
1,069,673
|
|
|
(173
|
)
|
|
$
|
(41
|
)
|
|
$
|
(1,492,001
|
)
|
|
$
|
(408,085
|
)
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
369,944
|
|
|
369,944
|
|
||||||
Preferred stock dividends
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,112
|
|
|
4,112
|
|
||||||
Preferred stock conversion
|
(9
|
)
|
|
(9
|
)
|
|
6,102
|
|
|
1,220
|
|
|
(5,322
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,111
|
)
|
||||||
Share-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,115
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,115
|
|
||||||
Warrant issuance
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
403
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
403
|
|
||||||
Equity offering
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Director shares issued
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Treasury stock activity
|
—
|
|
|
—
|
|
|
146
|
|
|
29
|
|
|
(29
|
)
|
|
(47
|
)
|
|
(5
|
)
|
|
—
|
|
|
(5
|
)
|
||||||
Convertible note issuance
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Note conversions
|
—
|
|
|
—
|
|
|
9,818
|
|
|
1,964
|
|
|
29,663
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
31,627
|
|
||||||
Balance at October 12, 2016
|
1,493
|
|
|
$
|
1,493
|
|
|
79,976
|
|
|
$
|
15,995
|
|
|
$
|
1,100,503
|
|
|
(220
|
)
|
|
$
|
(46
|
)
|
|
$
|
(1,117,945
|
)
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Cancellation of predecessor equity
|
(1,493
|
)
|
|
(1,493
|
)
|
|
(79,976
|
)
|
|
(15,995
|
)
|
|
(1,100,503
|
)
|
|
221
|
|
|
46
|
|
|
1,117,945
|
|
|
—
|
|
||||||
Balance at October 12, 2016 Predecessor
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Successor Company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Issuance of common stock and warrants
|
—
|
|
|
—
|
|
|
6,836
|
|
|
68
|
|
|
30,312
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
30,380
|
|
||||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,307
|
)
|
|
(4,307
|
)
|
||||||
Share-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
240
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
240
|
|
||||||
Second Lien warrants and conversion
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,964
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,964
|
|
||||||
Equity offering
|
—
|
|
|
—
|
|
|
2,273
|
|
|
23
|
|
|
23,727
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23,750
|
|
||||||
Issuance cost
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(127
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(127
|
)
|
||||||
Balance at December 31, 2016 Successor
|
—
|
|
|
$
|
—
|
|
|
9,109
|
|
|
$
|
91
|
|
|
$
|
65,116
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
(4,307
|
)
|
|
$
|
60,900
|
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,996
|
)
|
|
(7,996
|
)
|
||||||
Share-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,458
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,458
|
|
||||||
Restricted stock vesting
|
—
|
|
|
—
|
|
|
232
|
|
|
2
|
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Second Lien warrants and conversion
|
—
|
|
|
—
|
|
|
1,430
|
|
|
15
|
|
|
(158
|
)
|
|
(1
|
)
|
|
(7
|
)
|
|
—
|
|
|
(150
|
)
|
||||||
Issuance cost
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(37
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(37
|
)
|
||||||
Treasury stock activity
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(931
|
)
|
|
1
|
|
|
7
|
|
|
—
|
|
|
(924
|
)
|
||||||
Balance at December 31, 2017 Successor
|
—
|
|
|
$
|
—
|
|
|
10,771
|
|
|
$
|
108
|
|
|
$
|
68,446
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
(12,303
|
)
|
|
$
|
56,251
|
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
Trade Payables
|
$
|
4,092
|
|
|
$
|
2,357
|
|
Revenue Payables
|
10,692
|
|
|
10,943
|
|
||
Prepayments from Partners
|
2,193
|
|
|
966
|
|
||
Other
|
227
|
|
|
126
|
|
||
Total Accounts Payable
|
$
|
17,204
|
|
|
$
|
14,392
|
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
Accrued capital expenditures
|
$
|
10,511
|
|
|
$
|
648
|
|
Accrued lease operating expense
|
786
|
|
|
547
|
|
||
Accrued production and other taxes
|
449
|
|
|
552
|
|
||
Accrued transportation and gathering
|
1,130
|
|
|
70
|
|
||
Accrued performance bonus
|
3,869
|
|
|
—
|
|
||
Accrued interest
|
244
|
|
|
278
|
|
||
Accrued office lease
|
696
|
|
|
99
|
|
||
Accrued reorganization costs
|
168
|
|
|
1,235
|
|
||
Accrued general and administrative expense and other
|
222
|
|
|
453
|
|
||
|
$
|
18,075
|
|
|
$
|
3,882
|
|
•
|
Level 1 Inputs- unadjusted quoted market prices in active markets for identical assets or liabilities. We have no Level 1 instruments;
|
•
|
Level 2 Inputs- quotes that are derived principally from or corroborated by observable market data. Included in this Level are our Exit Credit Facility and commodity derivatives whose fair values are based on third-party quotes or available interest rate information and commodity pricing data obtained from third party pricing sources and our creditworthiness or that of our counterparties; and
|
•
|
Level 3 Inputs- unobservable inputs for the asset or liability, such as discounted cash flow models or valuations, based on our various assumptions and future commodity prices. Included in this Level would be our initial measurement of asset retirement obligations.
|
|
Year Ended December 31,
|
||||
|
2017
|
|
2016 (Pro Forma)
|
||
Genesis Crude Oil LP
|
20
|
%
|
|
44
|
%
|
Sunoco, Inc.
|
13
|
%
|
|
30
|
%
|
Williams Energy Resources LLC
|
29
|
%
|
|
—
|
%
|
ETC
|
15
|
%
|
|
4
|
%
|
Occidental Energy MA
|
7
|
%
|
|
13
|
%
|
1.
|
Each holder of an allowed priority claim (other than a priority tax claim or administrative claim) received either: (a) cash equal to the full allowed amount of its claim or (b) such other treatment as may otherwise be agreed to by such holder, the Debtors, the holders of at least
50%
in principal amount of the Second Lien Notes (the “Majority Consenting Noteholders”), and the purchasers of the new Convertible Second Lien Notes (“New 2L Notes Purchasers”);
|
2.
|
Each holder of a secured claim (other than a priority tax claim, Senior Credit Facility claim, or Second Lien Notes claim) received, at the Debtors’ election and with the consent of the Majority Consenting Noteholders, either: (a) cash equal to the full allowed amount of its claim, (b) reinstatement of such holder’s claim, (c) the return or abandonment of the collateral securing such claim to such holder, or (d) such other treatment as may otherwise be agreed to by such holder, the Debtors, the Majority Consenting Noteholders, and the New 2L Notes Purchasers;
|
3.
|
The Senior Credit Facility claims were paid cash in an amount sufficient to reduce the Senior Credit Facility claims to a balance of
$20.0 million
while the remaining
$20.0 million
owed was to be refinanced into a new senior secured term loan credit facility;
|
4.
|
The Second Lien Notes claims were deemed allowed in the aggregate amount of
$175.0 million
of principal plus accrued and unpaid interest through the Petition Date. Except to the extent a holder of a Second Lien Note claim agreed in writing to less favorable treatment, in full and final satisfaction, settlement, release, and discharge of, and in exchange for, each Second Lien Notes claim, each holder of a Second Lien Notes claim received their pro rata share of
98%
of the new equity interests in the reorganized company (the “New Equity Interests”), subject to dilution on account of (i) the management incentive plan, (ii) the potential conversion of the Convertible Second Lien Notes, (iii) the warrants granted to the New 2L Notes Purchasers, and (iv) the out-of-the-money warrants equal to an aggregate of up to
10%
of the New Equity Interests with a maturity of
10
years and an equity strike price equal to
$230.0 million
;
|
5.
|
Holders of unsecured notes claims received, pro rata with holders of other general unsecured claims, their pro rata share of the out-of-the-money warrants equal to an aggregate of up to
10%
of the New Equity Interests with a maturity of
10
years and an equity strike price equal to
$230.0 million
; plus its pro rata share of
2%
of the New Equity Interests that are subject to dilution on account of (i) the management incentive plan, (ii) the potential conversion of the Convertible Second Lien Notes, (iii) the warrants granted to the New 2L Notes Purchasers, and (iv) the out-of-the money warrants equal to an aggregate of up to
10%
of the New Equity Interests with a maturity of
10
years and an equity strike price equal of
$230.0 million
;
|
6.
|
Holders of allowed general unsecured claims had the option to elect on their ballot to (a) receive, pro rata with holders of unsecured notes claims, its pro rata share of the out-of-the-money warrants equal to an aggregate of up to
10%
of the New Equity Interests with a maturity of
10
years and an equity strike price equal to
$230.0 million
; plus its pro rata share of
2%
of the New Equity Interests that are subject to dilution on account of (i) the management incentive plan, (ii) the potential conversion of the Convertible Second Lien Notes, (iii) the warrants granted to the New 2L Notes Purchasers, and (iv) the out-of-the-money warrants equal to an aggregate of up to
10%
of the New Equity Interests with a maturity of
10
years and an equity strike price equal to
$230.0 million
, or (b) treat its allowed general unsecured claim as a convenience class claim by releasing any claims in excess of
$10,000
;
|
7.
|
Holders of convenience class claims received either: (a) cash equal to the full allowed amount of such holder’s claim or (b) such lesser treatment as may otherwise be agreed to by such holder, the Debtors, the Majority Consenting Noteholders and the New 2L Notes Purchasers;
|
8.
|
Equity interests in the Subsidiary were canceled and extinguished without further notice to, approval of, or action by any entity, and each holder of an equity interest in the Subsidiary did not receive any distribution or retain any property on account of such equity interest in the Subsidiary. Equity interests in the Company were canceled and extinguished without further notice to, approval of, or action by any entity, and each holder of an equity interest in the Company did not receive any distribution or retain any property on account of such equity interest in the Company.
|
|
|
October 12, 2016
|
||
Current assets
|
|
$
|
28,216
|
|
Oil & gas properties
|
|
|
||
Proved Reserves
|
|
37,200
|
|
|
Undeveloped acreage
|
|
41,570
|
|
|
Asset Retirement Obligation
|
|
2,896
|
|
|
Materials inventory
|
|
4,125
|
|
|
Tangible personal & real property
|
|
984
|
|
|
Goodwill
|
|
9
|
|
|
Total asset value
|
|
$
|
115,000
|
|
Balance sheet reclass (current assets)
|
|
18,201
|
|
|
Total successor assets
|
|
$
|
96,799
|
|
8.0% Second Lien Senior Secured Notes due 2018
|
$
|
100,000
|
|
8.875% Second Lien Senior Secured Notes due 2018
|
75,000
|
|
|
8.875% Senior Notes due 2019
|
116,828
|
|
|
3.25% Convertible Senior Notes due 2026
|
429
|
|
|
5.0% Convertible Senior Notes due 2029
|
6,692
|
|
|
5.0% Convertible Senior Notes due 2032
|
99,238
|
|
|
5.0% Convertible Exchange Senior Notes due 2032
|
6,305
|
|
|
Accrued interest
|
17,161
|
|
|
Accounts payable and accrued liabilities
|
4,596
|
|
|
Liabilities Subject to compromise at October 12, 2016
|
426,249
|
|
|
Fair value of equity in Successor Company
|
30,381
|
|
|
Gain on settlement of Liabilities subject to compromise
|
$
|
395,868
|
|
2.
|
Reflects the cancellation of the Predecessor Company Preferred and Common Stock and associated Additional Paid in Capital.
|
3.
|
Reflects the issuance of
5.8 million
shares of common stock to the Second Lien Noteholders,
0.1 million
shares of common stock to the unsecured debt holders, and an issued
1.0 million
common shares under the Management Incentive Plan. Additionally, the unsecured debt holders were issued warrants to purchase
1.3 million
shares of common stock valued at
$2.5 million
.
|
Gain on settlement of Liabilities subject to compromise
|
$
|
395,868
|
|
Cancellation of Predecessor Company equity
|
(1,513,814
|
)
|
|
Net impact to accumulated deficit
|
$
|
(1,117,946
|
)
|
|
Predecessor
Company October 12 2016 |
|
Fresh Start Adjustments
|
|
Successor Company October 13, 2016
|
||||||
Oil and Gas Properties
|
|
|
|
|
|
||||||
Oil & gas properties (successful efforts method)
|
$
|
868,703
|
|
|
$
|
(868,703
|
)
|
|
$
|
—
|
|
Unproved properties (successful efforts method)
|
107,318
|
|
|
(107,318
|
)
|
|
—
|
|
|||
Proved properties (Full Cost Method)
|
—
|
|
|
40,104
|
|
|
40,104
|
|
|||
Unproved properties ( Full Cost Method)
|
—
|
|
|
41,570
|
|
|
41,570
|
|
|||
Total Oil and Gas Properties
|
976,021
|
|
|
(894,347
|
)
|
|
81,674
|
|
|||
Less: Accumulated depletion and impairments
|
(912,252
|
)
|
|
912,252
|
|
|
—
|
|
|||
Net Oil and Gas Properties
|
63,769
|
|
|
17,905
|
|
|
81,674
|
|
|||
|
|
|
|
|
|
||||||
Furniture, Fixtures and other equipment
|
7,302
|
|
|
(6,318
|
)
|
|
984
|
|
|||
Less: Accumulated depreciation
|
(6,869
|
)
|
|
6,869
|
|
|
—
|
|
|||
Net Furniture, Fixtures and other equipment
|
433
|
|
|
551
|
|
|
984
|
|
|||
Net Oil and Gas Properties, Furniture, and fixtures and accumulated depreciation
|
$
|
64,202
|
|
|
$
|
18,456
|
|
|
$
|
82,658
|
|
7.
|
Reorganization Items represent items directly related to the Chapter 11 bankruptcy filing and implementation of the Plan of Reorganization and are classified as Gain on reorganization, net in the Consolidated Statement of Operations. The following table summarizes the reorganization items (in thousands):
|
|
|
Successor
|
|
Predecessor
|
||||
|
|
|
|
|
||||
|
|
Period from October 13, 2016 through
December 31, 2016 |
|
Period from January 1, 2016 through
October 12, 2016 |
||||
Gain on settlement of liabilities subject to compromise
|
|
$
|
—
|
|
|
$
|
(395,868
|
)
|
Gain on Fresh start adjustments
|
|
—
|
|
|
(19,504
|
)
|
||
Professional fees and adjustments to debt
|
|
(130
|
)
|
|
15,950
|
|
||
Gain on Reorganization items, net
|
|
$
|
(130
|
)
|
|
$
|
(399,422
|
)
|
•
|
Volatility factor
- The volatility factor represents the extent to which the market price of the Company's common stock price is expected to fluctuate between the grant date and the end of the performance period.
|
•
|
Dividend yield
- The dividend yield on the Company's common stock is assumed to be zero since the Company does not currently pay dividends and does not anticipate paying dividends in the future.
|
•
|
Risk-free interest rate
- The risk-free interest rate is based upon the yield of US Treasuries with a three year term.
|
•
|
Expected term
- The expected term represents the period of time that the PSU's will be outstanding, which is the grant date to the end of the performance period, or three years.
|
|
2017
|
||
Number of simulations
|
100,000
|
|
|
Grant date price
|
$
|
9.82
|
|
Volatility factor
|
57
|
%
|
|
Dividend yield
|
—
|
|
|
Risk-free interest rate
|
1.92
|
%
|
|
Expected term (in years)
|
3
|
|
|
Year Ended December 31,
|
||||||
2016 Long Term Incentive Plan
|
2017
|
|
2016
|
||||
RSU expense - employees
|
$
|
3,636
|
|
|
$
|
187
|
|
PSU expense
|
84
|
|
|
—
|
|
||
RSU expense - directors
|
738
|
|
|
53
|
|
||
Total share-based compensation:
|
$
|
4,458
|
|
|
$
|
240
|
|
2016 Long Term Incentive Plan
|
Number of Units
|
|
Weighted Average Grant-Date Fair Value
|
|
Total Value (thousands)
|
|||||||||||||||||||||||||||
|
RSU
|
|
PSU
|
|
Total
|
|
RSU
|
|
PSU
|
|
Total
|
|
RSU
|
|
PSU
|
|
Total
|
|||||||||||||||
Unvested at October 12, 2016
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Granted
|
1,859,570
|
|
|
—
|
|
|
1,859,570
|
|
|
7.72
|
|
|
—
|
|
|
7.72
|
|
|
14,365
|
|
|
—
|
|
|
14,365
|
|
||||||
Vested
|
(726,904
|
)
|
|
—
|
|
|
(726,904
|
)
|
|
4.05
|
|
|
—
|
|
|
4.05
|
|
|
(2,944
|
)
|
|
—
|
|
|
(2,944
|
)
|
||||||
Forfeited
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Unvested at December 31, 2016
|
1,132,666
|
|
|
—
|
|
|
1,132,666
|
|
|
$
|
10.08
|
|
|
$
|
—
|
|
|
$
|
10.08
|
|
|
$
|
11,421
|
|
|
$
|
—
|
|
|
$
|
11,421
|
|
Granted
|
476,054
|
|
|
402,679
|
|
|
878,733
|
|
|
9.93
|
|
|
15.29
|
|
|
12.38
|
|
|
4,726
|
|
|
6,157
|
|
|
10,882
|
|
||||||
Vested
|
(413,436
|
)
|
|
—
|
|
|
(413,436
|
)
|
|
10.28
|
|
|
—
|
|
|
10.28
|
|
|
(4,213
|
)
|
|
—
|
|
|
(4,213
|
)
|
||||||
Forfeited
|
(23,931
|
)
|
|
—
|
|
|
(23,931
|
)
|
|
12.00
|
|
|
—
|
|
|
12.00
|
|
|
(287
|
)
|
|
—
|
|
|
(287
|
)
|
||||||
Unvested at December 31, 2017
|
1,171,353
|
|
|
402,679
|
|
|
1,574,032
|
|
|
$
|
9.91
|
|
|
$
|
15.29
|
|
|
$
|
11.29
|
|
|
$
|
11,646
|
|
|
$
|
6,157
|
|
|
$
|
17,803
|
|
2016 Long Term Incentive Plan
|
Unrecognized compensation costs
|
|
Weighted Average years to recognition
|
|||||||||||||||
|
(thousands)
|
|
(years)
|
|||||||||||||||
|
RSU
|
|
PSU
|
|
Total
|
|
RSU
|
|
PSU
|
|
Total
|
|||||||
December 31, 2017
|
$
|
11,248
|
|
|
$
|
6,070
|
|
|
$
|
17,318
|
|
|
2.23
|
|
2.96
|
|
|
2.47
|
December 31, 2016
|
11,181
|
|
|
—
|
|
|
11,181
|
|
|
2.77
|
|
—
|
|
|
2.77
|
2006 Long Term Incentive Plan
|
2016
|
||
Restricted stock expense
|
$
|
3,307
|
|
Stock option expense
|
—
|
|
|
Director stock expense
|
—
|
|
|
Total share-based compensation:
|
$
|
3,307
|
|
|
Successor
|
|
Successor
|
|
Predecessor
|
||||||
|
Year Ended December 31, 2017
|
|
October 13, 2016 to December 31, 2016
|
|
January 1, 2016 to October 12, 2016
|
||||||
Beginning balance
|
$
|
2,933
|
|
|
$
|
2,897
|
|
|
$
|
3,728
|
|
Liabilities incurred
|
132
|
|
|
—
|
|
|
—
|
|
|||
Revisions in estimated liabilities (1)
|
71
|
|
|
—
|
|
|
—
|
|
|||
Liabilities settled
|
—
|
|
|
—
|
|
|
—
|
|
|||
Accretion expense
|
231
|
|
|
36
|
|
|
216
|
|
|||
Dispositions
|
—
|
|
|
—
|
|
|
—
|
|
|||
Ending balance
|
$
|
3,367
|
|
|
$
|
2,933
|
|
|
$
|
3,944
|
|
Current liability
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
83
|
|
Long term liability
|
$
|
3,367
|
|
|
$
|
2,933
|
|
|
$
|
3,861
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||||||||||||||||||
|
Principal
|
|
Carrying
Amount |
|
Fair
Value |
|
Principal
|
|
Carrying
Amount (5) |
|
Fair
Value (1) |
||||||||||||
Exit Credit Facility (1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
16,651
|
|
|
$
|
16,651
|
|
|
$
|
16,651
|
|
2017 Senior Credit Facility (1)
|
16,723
|
|
|
16,723
|
|
|
16,723
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Convertible Second Lien Notes (2)
|
47,015
|
|
|
39,002
|
|
|
62,026
|
|
|
41,170
|
|
|
30,554
|
|
|
29,036
|
|
||||||
Total debt
|
$
|
63,738
|
|
|
$
|
55,725
|
|
|
$
|
78,749
|
|
|
$
|
57,821
|
|
|
$
|
47,205
|
|
|
$
|
45,687
|
|
|
(1)
|
The carrying amount for the Exit Credit and 2017 Senior Credit Facility represents fair value as it was fully secured.
|
(2)
|
The debt discount is being amortized using the effective interest rate method based upon a maturity date of August 30, 2019. The principal includes
$1.2 million
of paid-in-kind (PIK) interest as of December 31, 2016 and
$7.0 million
as of December 31, 2017. The carrying value includes
$10.6 million
and
$8.0 million
of unamortized debt discount at December 31, 2016 and 2017, respectively. The fair value of the notes was obtained by using a Binomial Lattice Model within Level 3 of the fair value hierarchy for the value on December 31, 2016 and utilized the last known sale price for the value on December 31, 2017.
|
|
Successor
|
|
Successor
|
|
Predecessor
|
|||||||||||||||
|
Year Ended December 31, 2017
|
|
Period from October 12, 2016 through December 31, 2016
|
|
Period from January 1, 2016 through October 12, 2016
|
|||||||||||||||
|
Interest
Expense
|
|
Effective
Interest
Rate
|
|
Interest
Expense
|
|
Effective
Interest
Rate
|
|
Interest
Expense
|
|
Effective
Interest
Rate
|
|||||||||
Senior Credit Facility
|
$
|
—
|
|
|
—
|
%
|
|
$
|
—
|
|
|
—
|
%
|
|
$
|
3,342
|
|
|
*
|
|
Exit Credit Facility
|
947
|
|
|
7.1
|
%
|
|
306
|
|
|
7.3
|
%
|
|
—
|
|
|
—
|
%
|
|||
2017 Senior Credit Facility
|
244
|
|
|
7.2
|
%
|
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|||
Convertible Second Lien Notes (1)
|
8,534
|
|
|
24.1
|
%
|
|
1,518
|
|
|
24.7
|
%
|
|
—
|
|
|
—
|
%
|
|||
Obligations Canceled on the Effective Date
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|
8,010
|
|
|
*
|
|
|||
Other
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|
46
|
|
|
*
|
|
|||
Total
|
$
|
9,725
|
|
|
|
|
$
|
1,824
|
|
|
|
|
$
|
11,398
|
|
|
|
|
•
|
8.0%
Second Lien Senior Secured Notes due 2018 in the principal amount of
$100.0 million
|
•
|
8.875%
Second Lien Senior Secured Notes due 2018 in the principal amount of
$75.0 million
|
•
|
8.875%
Senior Notes due 2019 in the principal amount of
$116.8 million
|
•
|
5.0%
Convertible Senior Notes due 2029 in the principal amount of
$6.7 million
|
•
|
5.0%
Convertible Senior Notes due 2032 in the principal amount of
$94.2 million
|
•
|
5.0%
Convertible Senior Exchange Notes due 2032 in the principal amount of
$6.3 million
|
•
|
3.25%
Convertible Senior Notes Due 2026 in the principal amount of
$0.4 million
|
|
Successor
|
|
Successor
|
|
Predecessor
|
||||||
|
Year Ended December 31, 2017
|
|
Period from October 13, 2016 through December 31, 2016
|
|
Period from January 1, 2016 through October 12, 2016
|
||||||
|
(Amounts in thousands, except per share data)
|
||||||||||
Basic and Diluted loss per share:
|
|
|
|
|
|
|
|||||
Net loss applicable to common stock
|
$
|
(7,996
|
)
|
|
$
|
(4,307
|
)
|
|
$
|
358,707
|
|
Weighted-average shares of common stock outstanding
|
9,975
|
|
|
7,184
|
|
|
77,236
|
|
|||
Basic income (loss) per share
|
$
|
(0.80
|
)
|
|
$
|
(0.60
|
)
|
|
$
|
4.64
|
|
|
|
|
|
|
|
|
|||||
Diluted income (loss) per share
|
|
|
|
|
|
|
|||||
Net income (loss) applicable to common stock
|
$
|
(7,996
|
)
|
|
$
|
(4,307
|
)
|
|
$
|
358,707
|
|
Dividends on convertible preferred stock
|
—
|
|
|
—
|
|
|
2,990
|
|
|||
Interest, discount, accretion and amortization of loan cost on 5% 2029 senior convertible notes, net of tax
|
—
|
|
|
—
|
|
|
63
|
|
|||
Interest, discount, accretion and amortization of loan cost on 5% 2032 senior convertible notes, net of tax
|
—
|
|
|
—
|
|
|
1,548
|
|
|||
Interest, discount, accretion and amortization of loan cost on 5% 2032 Exchange Notes due 2032, net of tax
|
—
|
|
|
—
|
|
|
28
|
|
|||
Interest, discount, accretion and amortization of loan cost on 3.25% senior convertible notes, net of tax
|
—
|
|
|
—
|
|
|
3
|
|
|||
Diluted net income (loss)
|
$
|
(7,996
|
)
|
|
$
|
(4,307
|
)
|
|
$
|
363,339
|
|
Weighted-average shares of common stock outstanding
|
9,975
|
|
|
7,184
|
|
|
77,236
|
|
|||
Common shares issuable upon assumed conversion of convertible preferred stock or dividends paid.
|
—
|
|
|
—
|
|
|
14,966
|
|
|||
Common shares issuable upon assumed conversion of the 2026 Notes, 2029 Notes, 2032 Notes and 2032 Exchange Notes or interest paid.
|
—
|
|
|
—
|
|
|
5,911
|
|
|||
Common shares issuable on assumed conversion of restricted stock, stock warrants and employee stock options were not included in the computation of diluted loss per common share.
|
—
|
|
|
—
|
|
|
256
|
|
|||
Weighted-average diluted shares outstanding
|
9,975
|
|
|
7,184
|
|
|
98,369
|
|
|||
Diluted income (loss) per share (1) (2) (3) (4)
|
$
|
(0.80
|
)
|
|
$
|
(0.60
|
)
|
|
$
|
3.69
|
|
(1) Common shares issuable upon conversion of the Convertible Second Lien Notes were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive.
|
1,875
|
|
|
1,875
|
|
|
—
|
|
|||
(2) Common shares issuable upon conversion of the Convertible Second Lien Notes associated warrants and unsecured claim holders were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive.
|
2,459
|
|
|
3,789
|
|
|
—
|
|
|||
(3) Common shares issuable on assumed conversion of restricted stock were not included in the computation of diluted loss per common share since their inclusion would have been anti-dilutive.
|
243
|
|
|
24
|
|
|
—
|
|
|
Successor
|
|
Successor
|
|
Predecessor
|
||||||
|
Year Ended December 31, 2017
|
|
October 13, 2016
to December 31, 2016 |
|
January 1, 2016
to October 12, 2016 |
||||||
Current tax expense (benefit)
|
|
|
|
|
|
|
|
||||
Federal
|
$
|
(41
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
State
|
—
|
|
|
—
|
|
|
—
|
|
|||
Total current tax expense (benefit)
|
(41
|
)
|
|
—
|
|
|
—
|
|
|||
Deferred tax expense (benefit)
|
|
|
|
|
|
||||||
Federal
|
(937
|
)
|
|
—
|
|
|
—
|
|
|||
State
|
—
|
|
|
—
|
|
|
—
|
|
|||
Total deferred tax expense (benefit)
|
(937
|
)
|
|
—
|
|
|
—
|
|
|||
Total tax expense (benefit)
|
$
|
(978
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Successor
|
|
Successor
|
|
Predecessor
|
||||||
|
Year Ended December 31, 2017
|
|
October 13, 2016
to December 31, 2016 |
|
January 1, 2016
to October 12, 2016 |
||||||
Income tax expense (benefit)
|
|
|
|
|
|
|
|
||||
Tax at U.S. statutory income tax
|
$
|
(3,141
|
)
|
|
$
|
(1,508
|
)
|
|
$
|
129,481
|
|
Book restructuring gain
|
—
|
|
|
—
|
|
|
(146,770
|
)
|
|||
Remeasurement due to Tax Cuts and Jobs Act
|
41,175
|
|
|
—
|
|
|
—
|
|
|||
Valuation allowance for remeasurement and changes relating to the Tax Cuts and Jobs Act
|
(42,112
|
)
|
|
—
|
|
|
—
|
|
|||
Other valuation allowance
|
5,474
|
|
|
1,055
|
|
|
(5,003
|
)
|
|||
State income taxes-net of federal benefit
|
(861
|
)
|
|
(111
|
)
|
|
16,985
|
|
|||
Nondeductible expenses and other
|
(1,513
|
)
|
|
564
|
|
|
5,307
|
|
|||
Total income tax expense (benefit)
|
$
|
(978
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
Non-current deferred tax assets:
|
|
|
|
|
|
||
Operating loss carry-forwards
|
$
|
27,136
|
|
|
$
|
3,033
|
|
State Tax NOL and Credits
|
8,060
|
|
|
1,320
|
|
||
Statutory depletion carry-forward
|
4,221
|
|
|
7,035
|
|
||
AMT tax credit carry-forward
|
1,008
|
|
|
1,052
|
|
||
Compensation
|
1,170
|
|
|
244
|
|
||
Contingent liabilities and other
|
298
|
|
|
508
|
|
||
Derivative financial instruments
|
—
|
|
|
—
|
|
||
Debt discount
|
173
|
|
|
—
|
|
||
Property and equipment
|
45,809
|
|
|
112,274
|
|
||
Total gross noncurrent deferred tax assets
|
87,875
|
|
|
125,466
|
|
||
Less valuation allowance
|
(86,711
|
)
|
|
(125,164
|
)
|
||
Net noncurrent deferred tax assets
|
1,164
|
|
|
302
|
|
||
Noncurrent deferred tax liabilities:
|
|
|
|
|
|
||
Bond discount
|
—
|
|
|
(302
|
)
|
||
Derivatives
|
(227
|
)
|
|
—
|
|
||
Total non-current deferred tax liabilities
|
(227
|
)
|
|
(302
|
)
|
||
Net non-current deferred tax asset
|
$
|
937
|
|
|
$
|
—
|
|
|
Successor
|
|
Successor
|
|
Predecessor
|
||||||
Oil and Natural Gas Derivatives (in thousands)
|
Year Ended December 31, 2017
|
|
October 13, 2016 to December 31, 2016
|
|
January 1, 2016 to October 12, 2016
|
||||||
Gain on commodity derivatives not designated as hedges, settled
|
$
|
471
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Gain on commodity derivatives not designated as hedges, not settled
|
1,081
|
|
|
—
|
|
|
30
|
|
|||
Total gain on commodity derivatives not designated as hedges
|
$
|
1,552
|
|
|
$
|
—
|
|
|
$
|
30
|
|
Contract Type
|
Daily
Volume |
|
Total
Volume |
|
Fixed Price
|
|
December 31, 2017
|
||||||
Crude Oil swaps (Bbls)
|
|
|
|
|
|
|
|
|
|
|
|||
2019
|
312
|
|
|
114,025
|
|
|
$
|
51.80
|
|
|
$
|
(517
|
)
|
2018
|
375
|
|
|
136,800
|
|
|
$
|
51.80
|
|
|
(1,002
|
)
|
|
Total Oil
|
|
|
|
|
|
|
|
|
|
(1,519
|
)
|
||
Natural gas swaps and calls (MMBtu)
|
|
|
|
|
|
|
|
|
|
|
|
||
2019
|
14,034
|
|
|
5,122,500
|
|
|
$
|
3.03
|
|
|
566
|
|
|
2018
|
30,641
|
|
|
11,184,000
|
|
|
$2.985-$3.033
|
|
|
2,034
|
|
||
Total Natural Gas
|
|
|
|
|
|
|
|
|
|
2,600
|
|
||
Total Oil and Natural Gas
|
|
|
|
|
|
|
$
|
1,081
|
|
|
December 31, 2017 Fair Value Measurements Using
|
||||||||||||||
Description
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Current Assets Commodity Derivatives
|
$
|
—
|
|
|
$
|
2,034
|
|
|
$
|
—
|
|
|
$
|
2,034
|
|
Non-current Assets Commodity Derivatives
|
—
|
|
|
566
|
|
|
—
|
|
|
566
|
|
||||
Current Liabilities Commodity Derivatives
|
—
|
|
|
(1,002
|
)
|
|
—
|
|
|
(1,002
|
)
|
||||
Non-current Liabilities Commodity Derivatives
|
—
|
|
|
(517
|
)
|
|
—
|
|
|
(517
|
)
|
||||
Total
|
$
|
—
|
|
|
$
|
1,081
|
|
|
$
|
—
|
|
|
$
|
1,081
|
|
|
Payment due by Period
|
||||||||||||||||||||||||
|
Note
|
|
Total
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
and After |
||||||||||||
Debt
|
5
|
|
$
|
75,387
|
|
|
$
|
—
|
|
|
$
|
58,664
|
|
|
$
|
—
|
|
|
$
|
16,723
|
|
|
$
|
—
|
|
Office space leases
|
|
|
5,103
|
|
|
1,510
|
|
|
1,540
|
|
|
1,540
|
|
|
513
|
|
|
—
|
|
||||||
Operations contracts
|
|
|
871
|
|
|
836
|
|
|
20
|
|
|
15
|
|
|
—
|
|
|
—
|
|
||||||
Total contractual obligations (1)
|
|
|
$
|
81,361
|
|
|
$
|
2,346
|
|
|
$
|
60,224
|
|
|
$
|
1,555
|
|
|
$
|
17,236
|
|
|
$
|
—
|
|
(1)
|
This table does not include the estimated liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of
$3.4 million
as of December 31, 2017. We record a separate liability for the asset retirement obligations. See Note 4.
|
|
Full Cost Accounting Method
|
|
Full Cost Accounting Method
|
|
Successful Efforts Accounting Method
|
||||||
|
Successor
|
|
Successor
|
|
Predecessor
|
||||||
|
Year Ended December 31, 2017
|
|
October 13, 2016 through December 31, 2016
|
|
January 1, 2016 to October 12, 2016
|
||||||
Proved properties
|
$
|
120,333
|
|
|
$
|
61,040
|
|
|
$
|
868,703
|
|
Unproved properties
|
5,984
|
|
|
24,102
|
|
|
107,318
|
|
|||
|
126,317
|
|
|
85,142
|
|
|
976,021
|
|
|||
Less: accumulated depreciation, depletion and amortization
|
(15,632
|
)
|
|
(3,954
|
)
|
|
(912,252
|
)
|
|||
Net oil and natural gas properties
|
$
|
110,685
|
|
|
$
|
81,188
|
|
|
$
|
63,769
|
|
|
Full Cost Accounting Method
|
|
Full Cost Accounting Method
|
|
Successful Efforts Accounting Method
|
||||||
|
Successor
|
|
Successor
|
|
Predecessor
|
||||||
|
Year Ended December 31, 2017
|
|
October 13, 2016 through December 31, 2016
|
|
January 1, 2016 to October 12, 2016
|
||||||
Property Acquisition
|
|
|
|
|
|
|
|
|
|||
Unproved
|
$
|
527
|
|
|
$
|
33
|
|
|
$
|
450
|
|
Proved
|
—
|
|
|
—
|
|
|
—
|
|
|||
Exploration
|
—
|
|
|
—
|
|
|
498
|
|
|||
Development (1)
|
$
|
41,148
|
|
|
$
|
4,284
|
|
|
$
|
1,560
|
|
Total (2)
|
$
|
41,675
|
|
|
$
|
4,317
|
|
|
$
|
2,508
|
|
|
(1)
|
Includes asset retirement costs of
$0.2 million
in
2017
and
zero
in
2016
.
|
(2)
|
Substantially all the costs incurred in the Successor periods related to the Haynesville Shale Trend and the majority of the cost incurred in the 2016 Predecessor period related the Tuscaloosa Marine Shale Trend.
|
|
Natural Gas (Mmcf)
|
|
Oil, Condensate and NGLs (MBbls)
|
||||||||||||||
|
2017
|
|
2016
|
|
2015
|
|
2017
|
|
2016
|
|
2015
|
||||||
Net proved reserves at beginning of period
|
286,038
|
|
|
31,851
|
|
|
104,832
|
|
|
2,815
|
|
|
3,834
|
|
|
28,143
|
|
Revisions of previous estimates (1)
|
106,639
|
|
|
(4,426
|
)
|
|
(62,437
|
)
|
|
(381
|
)
|
|
(543
|
)
|
|
(15,737
|
)
|
Extensions, discoveries and improved recovery (2)
|
32,871
|
|
|
264,166
|
|
|
6,196
|
|
|
—
|
|
|
—
|
|
|
1,207
|
|
Purchases of minerals in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sales of minerals in place
|
—
|
|
|
2
|
|
|
(8,073
|
)
|
|
—
|
|
|
—
|
|
|
(8,551
|
)
|
Production
|
(10,324
|
)
|
|
(5,555
|
)
|
|
(8,667
|
)
|
|
(304
|
)
|
|
(476
|
)
|
|
(1,228
|
)
|
Net proved reserves at end of period
|
415,224
|
|
|
286,038
|
|
|
31,851
|
|
|
2,130
|
|
|
2,815
|
|
|
3,834
|
|
Net proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
21,872
|
|
|
31,851
|
|
|
60,708
|
|
|
2,815
|
|
|
3,834
|
|
|
10,719
|
|
End of period
|
52,861
|
|
|
21,872
|
|
|
31,851
|
|
|
2,130
|
|
|
2,815
|
|
|
3,834
|
|
Net proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
264,166
|
|
|
—
|
|
|
44,124
|
|
|
—
|
|
|
—
|
|
|
17,424
|
|
End of period
|
362,363
|
|
|
264,166
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Natural Gas Equivalents (Mmcfe)
|
|||||||
|
2017
|
|
2016
|
|
2015
|
|||
Net proved reserves at beginning of period
|
302,927
|
|
|
54,852
|
|
|
273,690
|
|
Revisions of previous estimates (1)
|
104,354
|
|
|
(7,683
|
)
|
|
(156,858
|
)
|
Extensions, discoveries and improved recovery (2)
|
32,871
|
|
|
264,166
|
|
|
13,440
|
|
Purchases of minerals in place
|
—
|
|
|
—
|
|
|
—
|
|
Sales of minerals in place (3)
|
—
|
|
|
2
|
|
|
(59,382
|
)
|
Production
|
(12,150
|
)
|
|
(8,410
|
)
|
|
(16,038
|
)
|
Net proved reserves at end of period
|
428,002
|
|
|
302,927
|
|
|
54,852
|
|
Net proved developed reserves:
|
|
|
|
|
|
|
|
|
Beginning of period
|
44,432
|
|
|
54,852
|
|
|
125,022
|
|
End of period
|
65,639
|
|
|
44,432
|
|
|
54,852
|
|
Net proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
Beginning of period
|
258,495
|
|
|
—
|
|
|
148,668
|
|
End of period
|
362,363
|
|
|
258,495
|
|
|
—
|
|
|
(1)
|
Revision of previous estimates in 2017 were positive due to the application of both experience and ever improving technology in drilling and completing Haynesville Shale natural gas wells. Well production performance has improved by drilling longer laterals, increasing both the number of frac stages and the amount of sand used in each frac stage. Revisions of previous estimates in 2016 were negative, primarily due to increases in our operating expenditures and other tax rates. Revisions of previous estimates in 2015 were negative, primarily due to the transfer of undeveloped volumes out of the proved category.
|
(2)
|
Extensions and discoveries were positive on an overall basis in all three periods presented, primarily related to our drilling activity on in the TMS in 2015. In 2016 we recognized a
264.2
Mmcfe gain reflecting our successful drilling results on our Haynesville Shale Trend Properties which continued into 2017.
|
(3)
|
In 2015, we sold approximately
59.4
MMBoe attributed to the sale of producing properties in the Eagle Ford Shale Trend located in south Texas.
|
|
2017
|
|
2016
|
|
2015
|
||||||
Future revenues
|
$
|
1,260,490
|
|
|
$
|
595,745
|
|
|
$
|
245,411
|
|
Future lease operating expenses and production taxes
|
(430,048
|
)
|
|
(213,030
|
)
|
|
(130,455
|
)
|
|||
Future development costs (1)
|
(329,938
|
)
|
|
(222,892
|
)
|
|
(20,146
|
)
|
|||
Future income tax expense
|
(17,113
|
)
|
|
(456
|
)
|
|
—
|
|
|||
Future net cash flows
|
483,391
|
|
|
159,367
|
|
|
94,810
|
|
|||
10% annual discount for estimated timing of cash flows
|
(223,081
|
)
|
|
(102,445
|
)
|
|
(24,915
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
260,310
|
|
|
$
|
56,922
|
|
|
$
|
69,895
|
|
Index price used to calculate reserves (2)
|
|
|
|
|
|
|
|
|
|||
Natural gas (per Mcf)
|
$2.98
|
|
$2.48
|
|
$2.58
|
||||||
Oil (per Bbl)
|
$51.34
|
|
$42.75
|
|
$50.28
|
|
(1)
|
Includes cumulative asset retirement obligations of
$7.2 million
and
$10.3 million
in
2017
and
2016
, respectively.
|
(2)
|
These index prices, used to estimate our reserves at these dates, are before deducting or adding applicable transportation and quality differentials on a well-by-well basis.
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Balance, beginning of year
|
$
|
56,922
|
|
|
$
|
69,895
|
|
|
$
|
644,736
|
|
Net changes in prices and production costs related to future production
|
113,319
|
|
|
(20,442
|
)
|
|
(535,696
|
)
|
|||
Sales and transfers of oil and natural gas produced, net of production costs
|
(32,012
|
)
|
|
(15,826
|
)
|
|
(58,917
|
)
|
|||
Net change due to revisions in quantity estimates
|
107,499
|
|
|
(8,630
|
)
|
|
(132,832
|
)
|
|||
Net change due to extensions, discoveries and improved recovery
|
8,970
|
|
|
25,638
|
|
|
24,895
|
|
|||
Net change due to purchases and sales of minerals in place
|
—
|
|
|
648
|
|
|
(158,391
|
)
|
|||
Changes in future development costs
|
(59,560
|
)
|
|
2,102
|
|
|
324,624
|
|
|||
Previously estimated development cost incurred in period
|
8,114
|
|
|
—
|
|
|
—
|
|
|||
Net change in income taxes
|
(3,686
|
)
|
|
(164
|
)
|
|
5,848
|
|
|||
Accretion of discount
|
5,709
|
|
|
6,990
|
|
|
65,058
|
|
|||
Change in production rates (timing) and other
|
55,035
|
|
|
(3,289
|
)
|
|
(109,430
|
)
|
|||
Net increase (decrease) in standardized measures
|
203,388
|
|
|
(12,973
|
)
|
|
(574,841
|
)
|
|||
Balance, end of year
|
$
|
260,310
|
|
|
$
|
56,922
|
|
|
$
|
69,895
|
|
Item 9.
|
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
|
Item 9A.
|
Controls and Procedures
|
Item 9B.
|
Other Information
|
Item 10.
|
Directors, Executive Officers and Corporate Governance
|
Name
|
|
Age
|
|
Position
|
Walter G. “Gil” Goodrich
|
|
59
|
|
Chairman of the Board of Directors, Chief Executive Officer and Director
|
Robert C. Turnham, Jr.
|
|
60
|
|
President, Chief Operating Officer and Director
|
Mark E. Ferchau
|
|
63
|
|
Executive Vice President
|
Michael J. Killelea
|
|
55
|
|
Executive Vice President, General Counsel and Corporate Secretary
|
Robert T. Barker
|
|
67
|
|
Senior Vice President, Controller and Chief Financial Officer
|
Ronald F. Coleman
|
|
63
|
|
Director
|
Steven J. Pully
|
|
58
|
|
Director
|
K. Adam Leight
|
|
61
|
|
Director
|
Timothy D. Leuliette
|
|
68
|
|
Director
|
Thomas M. Souers
|
|
64
|
|
Director
|
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, Financial Statement Schedules
|
2.1
|
|
2.2
|
|
3.1
|
|
3.2
|
|
4.1
|
|
4.2
|
|
10.1
|
|
10.2
|
|
10.3
|
|
10.4
|
|
10.5
|
10.6
|
|
10.7
|
|
10.8
|
|
10.9
|
|
10.10
|
|
10.11
|
|
10.12
|
|
10.13
|
|
10.14†
|
|
10.15†
|
|
10.16†
|
|
10.17†
|
|
10.18†
|
|
10.19†
|
|
10.20†
|
|
10.21†
|
|
10.22†
|
10.23†
|
|
10.24†
|
|
10.25†
|
|
12.1*
|
|
12.2*
|
|
21
|
Subsidiary of the Registrant:
|
|
Goodrich Petroleum Company L.L.C. - Organized in the State of Louisiana.
|
23.1*
|
|
23.2*
|
|
23.3*
|
|
23.4*
|
|
31.1*
|
|
31.2*
|
|
32.1**
|
|
32.2**
|
|
99.1*
|
|
99.2*
|
|
101.INS*
|
XBRL Instance Document
|
101.SCH*
|
XBRL Schema Document
|
101.CAL*
|
XBRL Calculation Linkbase Document
|
101.LAB*
|
XBRL Labels Linkbase Document
|
101.PRE*
|
XBRL Presentation Linkbase Document
|
101.DEF*
|
XBRL Definition Linkbase Document
|
*
|
Filed herewith.
|
**
|
Furnished herewith.
|
†
|
Denotes management contract or compensatory plan or arrangement.
|
|
GOODRICH PETROLEUM CORPORATION
|
||
|
|
|
|
|
By:
|
|
/s/ WALTER G. GOODRICH
|
|
|
|
Walter G. Goodrich
Chief Executive Officer
|
Signature
|
|
Title
|
/s/ WALTER G. GOODRICH
|
|
Chairman, Chief Executive Officer and Director (Principal Executive Officer)
|
Walter G. Goodrich
|
|
|
/S/ ROBERT C. TURNHAM, JR.
|
|
President, Chief Operating Officer and Director
|
Robert C. Turnham, Jr.
|
|
|
/S/ ROBERT T. BARKER
|
|
Senior Vice President, Controller, Chief Accounting Officer and Chief Financial Officer
|
Robert T. Barker
|
|
|
/S/ RONALD COLEMAN
|
|
Director
|
Ronald Coleman
|
|
|
/S/ ADAM LEIGHT
|
|
Director
|
Adam Leight
|
|
|
/S/ TIM LEULIETTE
|
|
Director
|
Tim Leuliette
|
|
|
/S/ STEVEN J. PULLY
|
|
Director
|
Steven J. Pully
|
|
|
/S/ TOM SOUERS
|
|
Director
|
Tom Souers
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|||||||||||||||||
Successor
|
Successor
|
Predecessor
|
Year Ended December 31,
|
|||||||||||||||||||||
|
|
Year Ended December 31, 2017
|
|
October 13, 2016 to December 31, 2016
|
|
January 1, 2016 to October 12, 2016
|
2015
|
2014
|
2013
|
|||||||||||||||
Earnings:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Income (loss) before income taxes
|
|
$
|
(8,974
|
)
|
|
$
|
(4,307
|
)
|
|
$
|
369,944
|
|
|
$
|
(479,424
|
)
|
|
$
|
(353,136
|
)
|
|
$
|
(95,186
|
)
|
Plus: fixed charges
|
|
9,725
|
|
|
1,824
|
|
|
11,398
|
|
|
54,807
|
|
|
47,829
|
|
|
51,187
|
|
||||||
Earnings available for fixed charges
|
|
751
|
|
|
(2,483)
|
|
|
381,342
|
|
|
(424,617)
|
|
|
(305,307)
|
|
|
(43,999)
|
|
||||||
Fixed Charges:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Interest expense
|
|
9,725
|
|
|
1,824
|
|
|
11,398
|
|
|
54,807
|
|
|
47,829
|
|
|
51,187
|
|
||||||
Total fixed charges
|
|
9,725
|
|
|
1,824
|
|
|
11,398
|
|
|
54,807
|
|
|
47,829
|
|
|
51,187
|
|
||||||
Ratio of Earnings to Fixed Charges
|
|
0.08
|
|
|
(a)
|
|
33.46
|
|
|
(b)
|
|
(c)
|
|
(d)
|
|
(a)
|
Successor Company earnings for the year ended December 31, 2016 were inadequate to cover fixed charges. The coverage deficiency was $4.3 million.
|
(b)
|
Predecessor Company earnings for the year ended December 31, 2015 were inadequate to cover fixed charges. The coverage deficiency was $479.4 million.
|
(c)
|
Predecessor Company earnings for the year ended December 31, 2014 were inadequate to cover fixed charges. The coverage deficiency was $353.1 million.
|
(d)
|
Predecessor Company earnings for the year ended December 31, 2013 were inadequate to cover fixed charges. The coverage deficiency was $95.2 million.
|
|
|
|
|
|
|
|
Predecessor
|
|||||||||||||||||
Successor
|
Successor
|
Predecessor
|
Year Ended December 31,
|
|||||||||||||||||||||
|
|
Year Ended December 31, 2017
|
|
October 13, 2016 to December 31, 2016
|
|
January 1, 2016 to October 12, 2016
|
2015
|
2014
|
2013
|
|||||||||||||||
Earnings:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Income (loss) before income taxes
|
|
$
|
(8,974
|
)
|
|
$
|
(4,307
|
)
|
|
$
|
369,944
|
|
|
$
|
(479,424
|
)
|
|
$
|
(353,136
|
)
|
|
$
|
(95,186
|
)
|
Plus: fixed charges
|
|
9,725
|
|
|
1,824
|
|
|
11,398
|
|
|
54,807
|
|
|
47,829
|
|
|
51,187
|
|
||||||
Preference securities dividends
|
|
-
|
|
|
-
|
|
|
4,112
|
|
|
(25,325)
|
|
|
(29,722)
|
|
|
(18,604)
|
|
||||||
Earnings available for fixed charges
|
|
751
|
|
|
(2,483)
|
|
|
385,454
|
|
|
(449,942)
|
|
|
(335,029)
|
|
|
(62,603)
|
|
||||||
Fixed Charges:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Interest expense
|
|
9,725
|
|
|
1,824
|
|
|
11,398
|
|
|
54,807
|
|
|
47,829
|
|
|
51,187
|
|
||||||
Preference securities dividends
|
|
-
|
|
|
-
|
|
|
(4,112)
|
|
|
25,325
|
|
|
29,722
|
|
|
18,604
|
|
||||||
Total fixed charges
|
|
9,725
|
|
|
1,824
|
|
|
7,286
|
|
|
80,132
|
|
|
77,551
|
|
|
69,791
|
|
||||||
Ratio of Earnings to Fixed Charges and Preference Securities Dividends
|
|
0.08
|
|
|
(a)
|
|
52.90
|
|
|
(b)
|
|
(c)
|
|
(d)
|
|
(a)
|
Successor Company Earnings as of December 31, 2016 were inadequate to cover fixed charges and preference securities dividends. The coverage deficiency was $4.3 million.
|
(b)
|
Predecessor Company Earnings for the year ended December 31, 2015 were inadequate to cover fixed charges and preference securities dividends. The coverage deficiency was $530.1 million.
|
(c)
|
Predecessor Company Earnings for the year ended December 31, 2014 were inadequate to cover fixed charges and preference securities dividends. The coverage deficiency was $412.6 million.
|
NETHERLAND SEWELL & ASSOCIATES, INC.
|
|
|
|
By:
|
/s/ J. Carter Henson, Jr.
|
|
J. Carter Henson, Jr., P.E.
Senior Vice President
|
TBPE REGISTERED ENGINEERING
|
FIRM F-1580
|
FAX (713) 651-0849
|
|
1100 LOUISIANA STREET SUITE 4600
|
HOUSTON, TEXAS 77002-5294
|
TELEPHONE (713) 651-9191
|
1.
|
Registration Statement (Form S-8 333-221429) pertaining to the 2016 Long Term Incentive Plan of Goodrich Petroleum Corporation,
|
2.
|
Registration Statement (Form S-3 333-217675) pertaining to the registration of securities Goodrich Petroleum Corporation may offer and sell not to exceed $250 million,
|
3.
|
Registration Statement (Form S-1 No. 333-216015) pertaining to Common Stock, 13.50% Convertible Second Lien Senior Secured Notes due 2019, related Warrants and Common Stock upon conversion,
|
4.
|
Registration Statement (Form S-8 No. 333-214080) pertaining to the 2016 Long Term Incentive Plan of Goodrich Petroleum Corporation,
|
5.
|
Registration Statement (Form S-1 No. 333-215051) pertaining to the registration of Common Stock issued pursuant to the Plan of Reorganization pertaining to Goodrich Petroleum Corporation Common Stock.
|
/s/ Ryder Scott Company, L.P.
|
RYDER SCOTT COMPANY, L.P.
|
TBPE Firm Registration No. F-1580
|
1.
|
I have reviewed this annual report on Form 10-K of Goodrich Petroleum Corporation (the “registrant”);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
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 subsidiary, 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
|
5.
|
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control 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 control over financial reporting.
|
Date: March 2, 2018
|
/s/ Walter G. Goodrich
|
Walter G. Goodrich
|
Chief Executive Officer
|
1.
|
I have reviewed this annual report on Form 10-K of Goodrich Petroleum Corporation;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
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 subsidiary, 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
|
5.
|
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control 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 control over financial reporting.
|
Date: March 2, 2018
|
/s/ Robert T. Barker
|
Robert T. Barker
|
Senior Vice President, Controller, Chief Accounting Officer and Chief Financial Officer
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; 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/ Walter G. Goodrich
|
Walter G. Goodrich
|
Chief Executive Officer
|
March 2, 2018
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; 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/ Robert T. Barker
|
Robert T. Barker
|
Senior Vice President, Controller, Chief Accounting Officer and Chief Financial Officer
|
March 2, 2018
|
|
|
|
Exhibit 99.1
|
|
|
|
|
|
|
|
|
|
|
Chaiman & CEO
|
|
|
Executive Committee
|
C.H. (Scott) Rees III
|
|
|
|
Robert C. Barg
|
Mike K. Norton
|
President & COO
|
|
P. Scott Frost
|
Dan Paul Smith
|
Danny D. Simmons
|
|
|
John G. Hattner
|
Joseph J . Spellman
|
Executive VP
|
|
|
J. Carter Henson, Jr
|
Daniel T. Walker
|
G. Lance Binder
|
|
|
|
|
|
|
|
|
Net Reserves
|
|
Future Net Revenue (M$)
|
||||
|
|
Oil
|
|
Gas
|
|
|
|
Present Worth
|
Category
|
|
(MBBL)
|
|
(MMCF)
|
|
Total
|
|
at 10%
|
|
|
|
|
|
|
|
|
|
Proved Developed Producing
|
|
12.4
|
|
40,840.9
|
|
54,464.0
|
|
37,804.2
|
Proved Developed Non-Producing
|
|
0.0
|
|
12,020.1
|
|
23,921.8
|
|
16,820.9
|
Proved Undeveloped
|
|
0.0
|
|
362,363.4
|
|
385,501.9
|
|
185,751.1
|
|
|
|
|
|
|
|
|
|
Total Proved
|
|
12.4
|
|
415,224.4
|
|
463,887.6
|
|
240,376.1
|
2100 Ross Avenue, Suite 2200 • Dallas, Texas 75201 • PH: 214-969-5401 • Fax: 214-969-5411
|
|
info@nsai-petro.com
|
1301 McKinney Street, Suite 3200 • Houston, Texas 77010 • PH: 713-654-4950 • Fax: 713-654-4951
|
|
netherlandsewell.com
|
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
|
Sincerely,
|
|
|
|
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
||
Texas Registered Engineering Firm F-2699
|
||
|
|
|
|
|
|
|
/s/ C.H. (Scott) Rees III
|
|
By:
|
|
|
|
C.H. (Scott) Rees III, P.E.
|
|
|
Chairman and Chief Executive Officer
|
|
|
|
|
|
/s/ J. Carter Henson, Jr.
|
|
|
/s/ Mike K. Norton
|
||
By:
|
|
|
|
By:
|
|
|
|
J. Carter Henson, Jr., P.E. 73964
|
|
|
Mike K. Norton, P.G. 441
|
||
|
Senior Vice President
|
|
|
Senior Vice President
|
||
|
|
|
|
|
|
|
Date Signed: February 2, 2018
|
|
Date Signed: February 2, 2018
|
||||
|
|
|
|
|||
JCH:LRG
|
|
|
|
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
|
(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.
|
Supplemental definitions from the 2007 Petroleum Resources Management System:
Developed Producing Reserves - Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves - Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new 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.
|
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:
a.
Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b.
Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
a.
Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
b.
Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
c.
Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
d.
Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
e.
Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
f.
Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.
|
(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.
|
From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects - such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations - by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:
The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
The company's historical record at completing development of comparable long-term projects;
The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).
|
(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.
|
/s/ Miles R. Palke
|
Miles R Palke, P.E.
|
TBPE License No. 94894
|
Managing Senior Vice President
|
RYDER SCOTT COMPANY, L.P.
|
TBPE Firm Registration No. F-1580
|
|
|
|
|
|
|
|
TBPE REGISTERED ENGINEERING FIRM F-1580
|
|
|
|
FAX (713) 651-0849
|
|
1100 LOUISIANA SUITE 4600
|
|
HOUSTON, TEXAS 77002-5294
|
|
TELEPHONE (713) 651-9191
|
SUITE 600, 1015 4TH STREET, S.W.
|
|
CALGARY, ALBERTA T2R 1J4
|
|
TEL (403) 262-2799
|
|
FAX (403) 262-2790
|
621 17TH STREET, SUITE 1550
|
|
DENVER, COLORADO 80293-1501
|
|
TEL (303) 623-9147
|
|
FAX (303) 623-4258
|
SEC PARAMETERS
|
Estimated Net Reserves and Income Data
|
Certain Leasehold Interests of
|
Goodrich Petroleum Corporation
|
As of December 31, 2017
|
|
|
Proved
|
||||||||||
|
|
Developed
|
|
Total
|
||||||||
|
|
Producing
|
|
Non-Producing
|
|
Proved
|
||||||
Net Remaining Reserves
|
|
|
|
|
|
|
||||||
Oil/Condensate – Mbbl
|
|
1,402
|
|
|
715
|
|
|
2,117
|
|
|||
|
|
|
|
|
|
|
||||||
Income Data ($M)
|
|
|
|
|
|
|
||||||
Future Gross Revenue
|
|
|
$63,892
|
|
|
|
$33,074
|
|
|
|
$96,966
|
|
Deductions
|
|
40,589
|
|
|
19,761
|
|
|
60,350
|
|
|||
Future Net Income (FNI)
|
|
|
$23,303
|
|
|
$
|
13,313
|
|
|
$
|
36,616
|
|
|
|
|
|
|
|
|
||||||
Discounted FNI @ 10%
|
|
|
$16,782
|
|
|
$
|
7,001
|
|
|
$
|
23,783
|
|
|
|
Discounted Future Net Income ($M)
|
||
|
|
As of December 31, 2017
|
||
Discount Rate
|
|
Total
|
|
|
Percent
|
|
Proved
|
|
|
|
|
|
|
|
9
|
|
$24,648
|
|
|
15
|
|
$20,249
|
|
|
20
|
|
$17,657
|
|
|
25
|
|
$15,678
|
|
Very truly yours,
|
|
RYDER SCOTT COMPANY, L.P.
|
TBPE Firm Registration No. F-1580
|
|
/s/ Miles R. Palke
|
|
Miles R. Palke, P.E.
|
TBPE License No. 94894
|
Managing Senior Vice President
|
|
(1)
|
completion intervals which are open at the time of the estimate, but which have not started producing;
|
(2)
|
wells which were shut-in for market conditions or pipeline connections; or
|
(3)
|
wells not capable of production for mechanical reasons.
|
(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.
|