Delaware
(State of Incorporation)
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20-3940661
(I.R.S. Employer Identification No.)
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575 North Dairy Ashford, Suite 1200
Houston, Texas 77079
(281) 874-2700
(Address and telephone number of principal executive offices)
Securities registered pursuant to Section 12(b) of the Act:
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Title of Class
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Exchanges on Which Registered:
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Common Stock, par value $.01 per share
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New York Stock Exchange
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Yes
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o
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No
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þ
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Yes
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o
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No
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þ
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Yes
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þ
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No
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o
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Yes
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þ
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No
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o
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o
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Yes
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o
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No
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þ
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Part I
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Page
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Items 1 & 2
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Business and Properties
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Item 1A.
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Risk Factors
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Item 1B.
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Unresolved Staff Comments
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Item 3.
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Legal Proceedings
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Item 4.
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Mine Safety Disclosures
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Part II
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Item 5.
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Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
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Item 6.
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Selected Financial Data
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Item 7.
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Management's Discussion and Analysis of Financial Condition and Results of Operations
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Item 7A.
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Quantitative and Qualitative Disclosures About Market Risk
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Item 8.
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Financial Statements and Supplementary Data
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Item 9.
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Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
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Item 9A.
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Controls and Procedures
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Item 9B.
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Other Information
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Part III
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Item 10.
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Directors, Executive Officers and Corporate Governance
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Item 11.
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Executive Compensation
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Item 12.
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Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters
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Item 13.
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Certain Relationships and Related Transactions, and Director Independence
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Item 14.
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Principal Accountant Fees and Services
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Part IV
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Item 15.
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Exhibits and Financial Statement Schedules
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•
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Leverage technical expertise to efficiently develop our extensive drilling inventory of high rate of return Eagle Ford shale drilling locations
. Our technical team has an average of over 25 years of experience and has drilled over 200 horizontal wells in the Eagle Ford which we believe gives us a technical advantage when developing and organically expanding our asset base. We leverage this advantage in our existing asset base to create highly efficient drilling and completion operations. Focusing solely on the Eagle Ford play allows us to use our operating, technical and regional expertise to interpret geological and operating trends, enhance production rates and maximize well recovery. We are focused on enhancing asset value through utilizing cost-effective technology to locate the highest quality intervals to drill and complete oil and gas wells. We have optimized our drilling techniques which have shortened our drill times and allowed us steer our laterals to target a narrow high quality interval of the lower Eagle Ford. We have also enhanced fracture stimulation design using more pounds of proppant and tighter fracture stage spacing while continuing to lower well costs. These factors have further enhanced the return profile of our drilling and completion operations. In 2018, we plan to invest between $245 and $265 million on our Eagle Ford operations to drill 32 net (38 gross) horizontal wells. The 2018 drilling program represents approximately 5% of the total inventory of 667 horizontal wells we have identified across our position.
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•
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Operate our properties as a low-cost producer.
We believe our concentrated acreage position in the Eagle Ford and our experience as an operator of essentially all of our properties enables us to apply drilling and completion techniques and economies of scale that improve returns. Operating control allows us to manage pace of development, timing, and associated annual capital expenditures. Furthermore, we are able to achieve lower operating costs through concentrated infrastructure and field operations. In addition, our concentrated acreage positions allow the Company to drill multiple wells from a single pad while optimizing lateral lengths. Pad drilling reduces facilities costs and consolidates surface level operations. Our operational control is critical to us being able to transfer successful drilling and completion techniques and cost cutting initiatives from one field to another. Finally, we will continue to leverage our proximity to end user markets of natural gas which gives us the ability to lower transportation costs relative to other basins and enhance returns to shareholders.
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•
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Continue to pursue strategic opportunities to further expand our core position in the Eagle Ford.
We continue to take advantage of opportunities to expand our core positions through leasing and bolt-on acquisitions as evidenced by the approximate 36,500 acres we acquired
during 2017 which represented a 59% increase over our acreage position at year end 2016. We plan to strategically target certain areas of the Eagle Ford where our technical experience and successful drilling results can be replicated and expanded. Our Eagle Ford portfolio provides us with a multi-decade growth platform that continues to improve in response to our successful drilling program. We believe we have the extensive basin-wide experience that gives us a competitive advantage in locating both strategic acquisitions and ground-floor leasing opportunities to expand our core acreage position in the future.
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•
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Maintain our financial flexibility and strong liquidity profile.
We are committed to preserving our financial flexibility and are focused on continued growth in a disciplined manner. We have historically funded our capital program by using a combination of internally generated cash flows and funds available on our Credit Facility. As of December 31, 2017, the Company had approximately $260 million of liquidity, which we believe provides us with a sufficient amount of liquidity to execute on our 2018 development plan and opportunistically acquire or lease additional acreage even with modest changes in the commodity environment. Our Credit Facility and Senior Secured Second Lien Notes, maturing in April 2022 and December 2024, respectively, are our only stated debt maturities.
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•
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Manage risk exposure.
We utilize a disciplined hedging program to limit our exposure to volatility in commodity prices and achieve a more predictable level of cash flows to support current and future capital expenditure plans. Our multi-year hedging program also hedges to limit our basis differential to Henry Hub pricing. We take a systematic approach to hedging and consistently add hedges to our portfolio at prices that ensure adequate rates of returns on our drilling program. As of December 31, 2017 we had approximately 53% of total production volumes hedged for full year 2018 using the mid-point of production guidance of 175 to 195 Mmcfe/d.
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•
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Extensive inventory of high rate of return drilling locations with high degree of operational control.
We have developed a significant inventory of future drilling locations, primarily in our well-established gas position in the Eagle Ford. As of December 31, 2017, we had approximately 100,000 net acres in the Eagle Ford and roughly 667 horizontal drilling locations. Approximately 55% of our estimated proved reserves at December 31, 2017 were undeveloped. We operate essentially all of our proved reserves and have an average working interest of approximately 92% across our identified locations. These factors provide us with a high level of control over our operations, allowing us to manage our development drilling schedule, utilize pad drilling where applicable, and implement leading edge modern completion techniques. We plan to continue to deliver production, reserve and cash flow growth by developing our extensive inventory of low-risk drilling locations in a disciplined manner.
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•
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Balanced portfolio mix of proved producing assets and low-risk development with significant upside from newer areas.
Our average daily production for the full year 2017 was 153.8 MMfce/d and our proved developed reserves were 458 Bcfe representing approximately
$470 million
of PV-10. Our portfolio of properties and our 2018 capital plan couples this strong base of production and reserves with low risk in-fill drilling in our Fasken Area where we plan to drill 13 net wells in 2018. We have identified a total of 156 drilling locations in this area prospective for the lower and upper Eagle Ford and Austin Chalk. In addition, our plan allows us to capture the significant upside associated with our recent success in our newer Oro Grande Area. In 2017, we successfully drilled two wells in Oro Grande and in 2018 we plan to drill an additional 5 net wells in this area. This area is comprised of a blocky and contiguous 24,884 net acres where we have identified 104 additional drilling locations. We believe that our balanced portfolio and development approach allow us to deliver low-risk production and reserve growth and expose shareholders to significant upside and organic inventory expansion.
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•
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Proximity to Demand Centers.
Our assets are positioned in one of the most economically advantaged natural gas regions of North America. Our proximity to the Gulf Coast affords us much lower natural gas basis differentials and meaningfully
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•
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Experienced and proven technical team.
We employ
17
oil and gas technical professionals, including geophysicists, geologists, drilling production and reservoir engineers, and other oil and gas professionals who have an average of approximately
25
years of experience in their technical fields. Our senior technical team has come from a number of large and successful organizations. Our technical team is focused on utilizing modern completion techniques to increase our EUR per 1,000 feet of lateral length and maximizing our per-well returns. Our enhanced completion designs include tighter fracture stage spacing as well as higher proppant loadings and intensity. Additionally, we rely on advanced technologies, such as micro-seismic analysis, to better define geologic risk and enhance the results of our drilling efforts. Due to these efforts, we have drilled 27 out of the top 50 natural gas wells in the Eagle Ford based on first year cumulative production based on data as of January 1, 2018. We continually apply our extensive in-house experience and current technologies to benefit our drilling and production operations.
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•
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Proven low cost operator with blocky and contiguous acreage.
Our core acreage positions are blocky and contiguous in nature which allows us to continue to lower per unit costs through drilling longer laterals, utilizing pad drilling, consolidating in-field infrastructure, and efficiently sourcing materials through our rigorous procurement strategies. We believe the nature of our positions and our operational improvements and efficiencies will allow us to continue to successfully mitigate service cost inflation as activity increases. Additionally, we continually seek to optimize our production operations with the objective of reducing our operating costs through efficient well management. Finally, our significant operational control, as well as our manageable leasehold drilling obligations, provide us the flexibility to control our costs as we transition to a development mode across our portfolio.
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•
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Strong balance sheet and liquidity profile.
As of December 31, 2017, the Company had approximately $260 million of liquidity, which we believe provides us with a sufficient amount of liquidity to execute on our 2018 development plan and opportunistically acquire or lease additional acreage even with modest changes in the commodity environment. Our Credit Facility and Senior Secured Second Lien Notes, maturing in April 2022 and December 2024, respectively, are our only debt maturities. As of December 31, 2017, we had $73 million drawn on our $330 million Credit Facility.
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Fields
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Acreage
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2017 Production (MMcfe/d)
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% Gas
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2017 Wells Drilled
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2017 Wells Completed
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|||||
Artesia
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12,811
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20,256
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44
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%
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7
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|
7
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AWP
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42,566
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35,628
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53
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%
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2
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2
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Fasken
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7,718
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92,518
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100
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%
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6
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10
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Other
(1)
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37,026
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5,392
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|
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96
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%
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|
3
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|
|
3
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Total
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100,121
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153,794
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82
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%
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|
18
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|
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22
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Fields
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Proved Developed Reserves (MMcfe)
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Proved Undeveloped Reserves
(MMcfe)
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Total Proved Reserves
(MMcfe)
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% of Total Proved Reserves
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Oil and
NGLs as % of Proved Reserves
|
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Total
Production (Mcfe)
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||||||
Artesia
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64.5
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|
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62.5
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|
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127.0
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12.4
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%
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53.7
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%
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7,393.4
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AWP Eagle Ford
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75.1
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229.3
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|
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304.4
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29.7
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%
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33.2
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%
|
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8,910.0
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AWP Olmos
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29.9
|
|
|
—
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|
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29.9
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|
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2.9
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%
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40.4
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%
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4,094.3
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Fasken
|
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267.9
|
|
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243.0
|
|
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510.9
|
|
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49.9
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%
|
|
—
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%
|
|
33,769.2
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Other
(1)
|
|
20.8
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|
|
31.3
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|
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52.2
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5.1
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%
|
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0.4
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%
|
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1,968.0
|
|
Total
|
|
458.2
|
|
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566.2
|
|
|
1,024.4
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|
|
100.0
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%
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17.7
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%
|
|
56,134.9
|
|
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As of December 31,
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||||||||||
(in millions)
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2017
|
|
2016
|
|
2015
|
||||||
PV-10 Value
|
$
|
805
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|
|
$
|
442
|
|
|
$
|
374
|
|
Less: Future income taxes (discounted at 10%)
|
73
|
|
|
35
|
|
|
—
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|||
Standardized Measure of Discounted Future Net Cash Flows
|
$
|
732
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|
|
$
|
407
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|
|
$
|
374
|
|
Estimated Proved Natural Gas, Oil and NGL Reserves
|
|
As of December 31,
|
||||||||||
|
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2017
|
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2016
|
|
2015
|
||||||
Natural gas reserves (MMcf):
|
|
|
|
|
|
|
||||||
Proved developed
|
|
377,506
|
|
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312,125
|
|
|
238,356
|
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|||
Proved undeveloped
(3)
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|
465,230
|
|
|
314,664
|
|
|
73,332
|
|
|||
Total
|
|
842,736
|
|
|
626,789
|
|
|
311,688
|
|
|||
Oil reserves (MBbl):
|
|
|
|
|
|
|
||||||
Proved developed
|
|
5,027
|
|
|
4,513
|
|
|
10,109
|
|
|||
Proved undeveloped
(3)
|
|
2,133
|
|
|
1,265
|
|
|
—
|
|
|||
Total
|
|
7,160
|
|
|
5,778
|
|
|
10,109
|
|
|||
NGL reserves (MBbl):
|
|
|
|
|
|
|
||||||
Proved developed
|
|
8,431
|
|
|
6,505
|
|
|
6,500
|
|
|||
Proved undeveloped
(3)
|
|
14,690
|
|
|
7,209
|
|
|
1,716
|
|
|||
Total
|
|
23,121
|
|
|
13,714
|
|
|
8,216
|
|
|||
|
|
|
|
|
|
|
||||||
Total Estimated Reserves (MMcfe)
(1)(3)
|
|
1,024,422
|
|
|
743,742
|
|
|
421,638
|
|
|||
|
|
|
|
|
|
|
||||||
Standardized Measure of Discounted Future Net Cash Flows (in millions)
(2)
|
|
$
|
732
|
|
|
$
|
407
|
|
|
$
|
374
|
|
|
|
|
|
|
|
|
||||||
PV-10 by reserve category
|
|
|
|
|
|
|
||||||
Proved developed
|
|
$
|
470
|
|
|
$
|
252
|
|
|
$
|
321
|
|
Proved undeveloped
|
|
335
|
|
|
190
|
|
|
53
|
|
|||
Total PV-10 Value
(2)
|
|
$
|
805
|
|
|
$
|
442
|
|
|
$
|
374
|
|
Year Added
|
|
Volume
(MMcfe)
|
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% of PUD
Volumes
|
|
2017
|
|
313.5
|
|
55
|
%
|
2016
(1)
|
|
252.7
|
|
45
|
%
|
2015
|
|
0.0
|
|
—
|
%
|
2014
|
|
0.0
|
|
—
|
%
|
2013
|
|
0.0
|
|
—
|
%
|
Total
|
|
566.2
|
|
100
|
%
|
|
Oil Wells
|
|
Gas Wells
|
|
Total
Wells
(1)
|
|||
December 31, 2017
|
|
|
|
|
|
|||
Gross
|
166
|
|
|
543
|
|
|
709
|
|
Net
|
161.7
|
|
|
500
|
|
|
661.7
|
|
December 31, 2016
|
|
|
|
|
|
|||
Gross
|
175
|
|
|
604
|
|
|
779
|
|
Net
|
172.1
|
|
|
558.7
|
|
|
730.8
|
|
December 31, 2015
|
|
|
|
|
|
|||
Gross
|
327
|
|
|
729
|
|
|
1,056
|
|
Net
|
308.9
|
|
|
682.7
|
|
|
991.6
|
|
(1)
|
Excludes 8, 9 and 48 service wells in
2017, 2016 and 2015
.
|
|
Developed
|
|
Undeveloped
|
||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||
Texas
(1)
|
57,357
|
|
|
53,650
|
|
|
71,973
|
|
|
62,110
|
|
Colorado
(2)
|
—
|
|
|
—
|
|
|
21,922
|
|
|
20,997
|
|
Louisiana
|
5,084
|
|
|
4,775
|
|
|
4,920
|
|
|
4,478
|
|
Wyoming
|
—
|
|
|
—
|
|
|
3,013
|
|
|
1,442
|
|
Total
|
62,441
|
|
|
58,425
|
|
|
101,828
|
|
|
89,027
|
|
(1)
|
The Company's total acreage in Eagle Ford includes 112,804 gross and 100,121 net acres.
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(2)
|
The Company's leasehold acreage in Colorado is scheduled to expire in 2018. The Company has no plans to extend these leases and plans to let them expire.
|
|
|
|
|
Gross Wells
|
|
Net Wells
|
||||||||||||||
Year
|
|
Type of Well
|
|
Total
|
|
Producing
|
|
Dry
|
|
Total
|
|
Producing
|
|
Dry
|
||||||
2017
|
|
Exploratory
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Development
|
|
27
|
|
|
27
|
|
|
—
|
|
|
22.0
|
|
|
22.0
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
2016
|
|
Exploratory
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Development
|
|
8
|
|
|
8
|
|
|
—
|
|
|
5.1
|
|
|
5.1
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
2015
|
|
Exploratory
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Development
|
|
24
|
|
|
24
|
|
|
—
|
|
|
17.1
|
|
|
17.1
|
|
|
—
|
|
|
Successor
|
|
|
Predecessor
|
||||||||
Sellers greater than 10%
|
Year Ended December 31, 2017
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31, 2015
|
||||
Kinder Morgan
|
48
|
%
|
|
38
|
%
|
|
|
20
|
%
|
|
27
|
%
|
Plains Marketing
(1)
|
—
|
%
|
|
14
|
%
|
|
|
14
|
%
|
|
18
|
%
|
Howard Energy
(1)
|
—
|
%
|
|
—
|
%
|
|
|
11
|
%
|
|
13
|
%
|
Southcross Energy
(1)
|
—
|
%
|
|
—
|
%
|
|
|
11
|
%
|
|
—
|
%
|
Shell
(1)
|
—
|
%
|
|
15
|
%
|
|
|
19
|
%
|
|
16
|
%
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
|
Year Ended December 31, 2017
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31, 2015
|
||||||||
All Fields
|
|
|
|
|
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||
Net Sales Volume:
|
|
|
|
|
|
|
|
|
|
||||||||
Oil (MBbls)
|
|
685
|
|
|
786
|
|
|
|
522
|
|
|
2,406
|
|
||||
Natural Gas Liquids (MBbls)
|
|
1,046
|
|
|
727
|
|
|
|
380
|
|
|
1,433
|
|
||||
Natural gas (MMcf)
|
|
45,751
|
|
|
29,109
|
|
|
|
11,431
|
|
|
43,839
|
|
||||
Total (MMcfe)
|
|
56,135
|
|
|
38,190
|
|
|
|
16,842
|
|
|
66,877
|
|
||||
|
|
|
|
|
|
|
|
|
|
||||||||
Average Sales Price:
|
|
|
|
|
|
|
|
|
|
||||||||
Oil (Per Bbl)
|
|
$
|
50.98
|
|
|
$
|
44.79
|
|
|
|
$
|
31.43
|
|
|
$
|
47.11
|
|
Natural Gas Liquids (Per Bbl)
|
|
$
|
21.61
|
|
|
$
|
16.39
|
|
|
|
$
|
11.04
|
|
|
$
|
14.54
|
|
Natural gas (Per Mcf)
|
|
$
|
3.03
|
|
|
$
|
2.55
|
|
|
|
$
|
1.96
|
|
|
$
|
2.56
|
|
Total (Per Mcfe)
|
|
$
|
3.49
|
|
|
$
|
3.18
|
|
|
|
$
|
2.55
|
|
|
$
|
3.68
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Average Production Cost (Per Mcfe sold)
(1)
|
|
$
|
0.74
|
|
|
$
|
1.00
|
|
|
|
$
|
1.26
|
|
|
$
|
1.38
|
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
|
Year Ended December 31, 2017
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31, 2015
|
||||||||
Fasken
|
|
|
|
|
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||
Net Sales Volume:
|
|
|
|
|
|
|
|
|
|
||||||||
Natural Gas Liquids (MBbls)
|
|
2
|
|
|
1
|
|
|
|
1
|
|
|
2
|
|
||||
Natural gas (MMcf)
(1)
|
|
33,757
|
|
|
20,762
|
|
|
|
7,274
|
|
|
28,598
|
|
||||
Total (MMcfe)
|
|
33,769
|
|
|
20,770
|
|
|
|
7,277
|
|
|
28,611
|
|
||||
|
|
|
|
|
|
|
|
|
|
||||||||
Average Sales Price:
|
|
|
|
|
|
|
|
|
|
||||||||
Natural Gas Liquids (Per Bbl)
|
|
$
|
18.13
|
|
|
$
|
14.09
|
|
|
|
$
|
3.87
|
|
|
$
|
16.65
|
|
Natural gas (Per Mcf)
|
|
$
|
3.02
|
|
|
$
|
2.55
|
|
|
|
$
|
1.96
|
|
|
$
|
2.53
|
|
Total (Per Mcfe)
|
|
$
|
3.02
|
|
|
$
|
2.55
|
|
|
|
$
|
1.96
|
|
|
$
|
2.53
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Average Production Cost (Per Mcfe sold)
(2)
|
|
$
|
0.59
|
|
|
$
|
0.56
|
|
|
|
$
|
0.58
|
|
|
$
|
0.53
|
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
|
Year Ended December 31, 2017
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31, 2015
|
||||||||
AWP
|
|
|
|
|
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||
Net Sales Volume:
|
|
|
|
|
|
|
|
|
|
||||||||
Oil (MBbls)
|
|
427
|
|
|
388
|
|
|
|
206
|
|
|
1,047
|
|
||||
Natural Gas Liquids (MBbls)
|
|
598
|
|
|
519
|
|
|
|
235
|
|
|
843
|
|
||||
Natural gas (MMcf)
(1)
|
|
6,857
|
|
|
6,438
|
|
|
|
3,061
|
|
|
10,372
|
|
||||
Total (MMcfe)
|
|
13,004
|
|
|
11,878
|
|
|
|
5,704
|
|
|
21,711
|
|
||||
|
|
|
|
|
|
|
|
|
|
||||||||
Average Sales Price:
|
|
|
|
|
|
|
|
|
|
||||||||
Oil (Per Bbl)
|
|
$
|
50.40
|
|
|
$
|
44.54
|
|
|
|
$
|
30.07
|
|
|
$
|
45.37
|
|
Natural Gas Liquids (Per Bbl)
|
|
$
|
20.87
|
|
|
$
|
16.32
|
|
|
|
$
|
11.31
|
|
|
$
|
14.79
|
|
Natural gas (Per Mcf)
|
|
$
|
3.09
|
|
|
$
|
2.59
|
|
|
|
$
|
1.90
|
|
|
$
|
2.62
|
|
Total (Per Mcfe)
|
|
$
|
4.25
|
|
|
$
|
3.57
|
|
|
|
$
|
2.57
|
|
|
$
|
4.01
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Average Production Cost (Per Mcfe sold)
(2)
|
|
$
|
1.25
|
|
|
$
|
1.03
|
|
|
|
$
|
1.31
|
|
|
$
|
1.44
|
|
•
|
the Clean Air Act (“CAA”), which restricts the emission of air pollutants from many sources, imposes various pre-construction, monitoring, and reporting requirements, which the EPA has relied upon as authority for adopting climate change regulatory initiatives relating to greenhouse gas emissions (“GHGs”);
|
•
|
the Federal Water Pollution Control Act, also known as the federal Clean Water Act, which regulates discharges of pollutants from facilities to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States;
|
•
|
the Comprehensive Environmental Response, Compensation and Liability Act of 1980, which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;
|
•
|
the Resource Conservation and Recovery Act (“RCRA”), which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes;
|
•
|
the Oil Pollution Act of 1990, which subjects owners and operators of vessels, onshore facilities, and pipelines, as well as lessees or permittees of areas in which offshore facilities are located, to liability for removal costs and damages arising from an oil spill in waters of the United States;
|
•
|
the Safe Drinking Water Act (“SDWA”), which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and controlling the injection of waste fluids into below-ground formations that may adversely affect drinking water sources;
|
•
|
the Emergency Planning and Community Right-to-Know Act, which requires facilities to implement a safety hazard communication program and disseminate information to employees, local emergency planning committees, and response departments on toxic chemical uses and inventories;
|
•
|
the Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures;
|
•
|
the Endangered Species Act, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas; and
|
•
|
the National Environmental Policy Act, which requires federal agencies to evaluate major agency actions having the potential to impact the environment and that may require the preparation of environmental assessments and more detailed environmental impact statements that may be made available for public review and comment.
|
•
|
domestic and foreign supplies of oil and natural gas;
|
•
|
price and quantity of foreign imports of oil and natural gas;
|
•
|
actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil and natural gas price and production controls;
|
•
|
level of consumer product demand, including as a result of competition from alternative energy sources;
|
•
|
level of global oil and natural gas exploration and production activity;
|
•
|
domestic and foreign governmental regulations;
|
•
|
stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and natural gas;
|
•
|
level of global oil and natural gas inventories;
|
•
|
political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America, Africa and Russia;
|
•
|
weather conditions;
|
•
|
technological advances affecting oil and natural gas production and consumption;
|
•
|
overall U.S. and global economic conditions; and
|
•
|
price and availability of alternative fuels.
|
•
|
sell assets, including equity interests in our subsidiaries;
|
•
|
redeem our debt;
|
•
|
make investments;
|
•
|
incur or guarantee additional indebtedness;
|
•
|
create or incur certain liens;
|
•
|
make certain acquisitions and investments;
|
•
|
redeem or prepay other debt;
|
•
|
enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
|
•
|
consolidate, merge or transfer all or substantially all of our assets;
|
•
|
engage in transactions with affiliates;
|
•
|
create unrestricted subsidiaries;
|
•
|
enter into swap agreements beyond certain maximum thresholds;
|
•
|
enter into sale and leaseback transactions; and
|
•
|
engage in certain business activities.
|
•
|
would not be required to lend any additional amounts to us;
|
•
|
could elect to declare all borrowings or notes outstanding, together with accrued and unpaid interest and fees, to be due and payable;
|
•
|
may have the ability to require us to apply all of our available cash to repay these borrowings or notes; or
|
•
|
may prevent us from making debt service payments under our other agreements.
|
•
|
hurricanes, tropical storms or other natural disasters;
|
•
|
environmental hazards, such as natural gas leaks, oil and produced water spills, pipeline or tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
|
•
|
abnormally pressured formations;
|
•
|
mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
|
•
|
fires and explosions; and
|
•
|
personal injuries and death.
|
•
|
the sale or other disposition of assets of the Company or any of its subsidiaries, in any single transaction or series of related transactions, with a fair market value in the aggregate in excess of $75 million, other than certain intercompany ordinary course transactions;
|
•
|
any sale, recapitalization, liquidation, dissolution, winding up, bankruptcy event, reorganization, consolidation, or merger of the Company or any of its subsidiaries;
|
•
|
issuing or repurchasing any shares of our common stock or other equity securities (or securities convertible into or exercisable for equity securities) in an amount that is in the aggregate in excess of $5 million, other than pursuant to employee benefit and incentive plans (including certain repurchases of capital stock to satisfy withholding or similar taxes in connection with any exercise of equity rights) and the issuance of shares of common stock upon exercise of our outstanding warrants;
|
•
|
incurring any indebtedness for borrowed money (including through capital leases, the issuance of debt securities or the guarantee of indebtedness of another person or entity), in any single transaction or series of related transactions, that is in the aggregate in excess of $75 million other than indebtedness incurred to refinance indebtedness issued for less than $75 million, intercompany indebtedness, and certain other obligations incurred in the ordinary course of business;
|
•
|
entering into any proposed transaction or series of related transactions involving a “Change of Control” of the Company (for purposes of this provision, “Change of Control” shall mean any transaction resulting in any person or group (as such terms are defined in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934) acquiring “beneficial ownership” (as defined in Rules 13d-3 and 13d-5 under the Securities Exchange Act of 1934) of more than 50% of the total outstanding equity interests of the Company (measured by voting power rather than number of shares);
|
•
|
entering into or consummating any material acquisition of businesses, companies or assets (whether through sales or leases) or joint ventures, in any single transaction or series of related transactions, in the aggregate in excess of $75 million;
|
•
|
increasing or decreasing the size of the Board;
|
•
|
amending the Certificate of Incorporation or the Bylaws of the Company; or
|
•
|
entering into any arrangements or transactions with affiliates of the Company.
|
•
|
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;
|
•
|
provide SVP and certain other institutional stockholders the right to nominate up to four of our directors;
|
•
|
limit the persons who may call special meetings of stockholders; and
|
•
|
provide veto rights to certain stockholders as detailed in our Charter, including any transaction that may constitute a change of control, as defined in the Charter.
|
|
2017
|
|
2016
|
|||||
|
First Quarter
|
Second Quarter
|
Third Quarter
|
Fourth Quarter
|
|
Period of April 23, 2016 through June 30, 2016
|
Third Quarter
|
Fourth Quarter
|
Low
|
$25.50
|
$24.00
|
$19.89
|
$21.53
|
|
$22.00
|
$24.40
|
$26.77
|
High
|
$34.00
|
$31.33
|
$27.05
|
$29.99
|
|
$26.10
|
$31.00
|
$35.70
|
Period
|
|
Total Number
of Shares
Purchased
|
|
Average Price
Paid Per Share
|
|
Total Number of
Shares Purchased as
Part of Publicly
Announced Plans
or Programs
|
|
Approximate Dollar
Value of Shares that
May Yet Be Purchased
Under the Plans or
Programs
(in thousands)
|
|||||
October 1 - 31, 2017
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$---
|
|
November 1- 30, 2017
|
|
7,212
|
|
|
$
|
22.06
|
|
|
—
|
|
|
—
|
|
December 1 - 31, 2017
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
|
7,212
|
|
|
$
|
22.06
|
|
|
—
|
|
|
$---
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||||||
(data in thousands except per share, price and well amounts)
|
Year Ended December 31, 2017
|
April 23, 2016 - December 31, 2016
|
|
|
January 1, 2016 - April 22, 2016
|
Years Ended December 31,
|
||||||||||||||
|
|
|
2015
|
2014
|
2013
|
|||||||||||||||
|
|
|
|
|
|
|
|
|
||||||||||||
Oil and Gas Sales
|
$
|
195,910
|
|
$
|
121,386
|
|
|
|
$
|
43,027
|
|
$
|
246,270
|
|
$
|
547,790
|
|
$
|
585,229
|
|
Income (Loss) Before Income Taxes
|
$
|
70,017
|
|
$
|
(156,288
|
)
|
|
|
$
|
851,611
|
|
$
|
(1,734,514
|
)
|
$
|
(433,470
|
)
|
$
|
198
|
|
Net Income (Loss)
|
$
|
71,971
|
|
$
|
(156,288
|
)
|
|
|
$
|
851,611
|
|
$
|
(1,653,971
|
)
|
$
|
(283,427
|
)
|
$
|
(2,442
|
)
|
Net Cash Provided by (Used in) Operating Activities
|
$
|
107,838
|
|
$
|
47,427
|
|
|
|
$
|
(41,466
|
)
|
$
|
42,274
|
|
$
|
306,371
|
|
$
|
311,447
|
|
Per Share and Share Data
|
|
|
|
|
|
|
|
|
||||||||||||
Weighted Average Shares Outstanding - Basic
|
11,453
|
|
10,013
|
|
|
|
44,692
|
|
44,463
|
|
43,795
|
|
43,331
|
|
||||||
Earnings (loss) per Share - Basic
|
$
|
6.28
|
|
$
|
(15.61
|
)
|
|
|
$
|
19.06
|
|
$
|
(37.20
|
)
|
$
|
(6.47
|
)
|
$
|
(0.06
|
)
|
Earnings (loss) per Share - Diluted
|
$
|
6.25
|
|
$
|
(15.61
|
)
|
|
|
$
|
18.64
|
|
$
|
(37.20
|
)
|
$
|
(6.47
|
)
|
$
|
(0.06
|
)
|
|
|
|
|
|
|
|
|
|
||||||||||||
Production (Bcfe equivalent)
|
56.1
|
|
38.2
|
|
|
|
16.8
|
|
66.9
|
|
69.6
|
|
68.4
|
|
||||||
|
|
|
|
|
|
|
|
|
||||||||||||
Average Sales Price
(1)
|
|
|
|
|
|
|
|
|
||||||||||||
Natural Gas (per Mcf produced)
|
$
|
3.03
|
|
$
|
2.55
|
|
|
|
$
|
1.96
|
|
$
|
2.56
|
|
$
|
4.36
|
|
$
|
3.66
|
|
Natural Gas Liquids (per barrel)
|
$
|
21.61
|
|
$
|
16.39
|
|
|
|
$
|
11.04
|
|
$
|
14.54
|
|
$
|
31.83
|
|
$
|
31.39
|
|
Oil (per barrel)
|
$
|
50.98
|
|
$
|
44.79
|
|
|
|
$
|
31.43
|
|
$
|
47.11
|
|
$
|
92.74
|
|
$
|
103.42
|
|
Mcfe Equivalent
|
$
|
3.49
|
|
$
|
3.18
|
|
|
|
$
|
2.55
|
|
$
|
3.68
|
|
$
|
7.87
|
|
$
|
8.72
|
|
|
Successor
|
|
|
Predecessor
|
|||||||||||||
|
December 31,
|
|
|
December 31,
|
|||||||||||||
Balance Sheet Data
|
2017
|
2016
|
|
|
2015
|
2014
|
2013
|
||||||||||
Assets
|
|
|
|
|
|
|
|
||||||||||
Current Assets
|
$
|
42,569
|
|
$
|
21,479
|
|
|
|
$
|
61,847
|
|
$
|
64,669
|
|
$
|
92,489
|
|
Property & Equipment, Net of Accumulated Depreciation, Depletion, Amortization and Impairment
|
495,397
|
|
347,195
|
|
|
|
457,903
|
|
2,095,037
|
|
2,588,817
|
|
|||||
Total Assets
|
551,270
|
|
377,299
|
|
|
|
524,998
|
|
2,173,347
|
|
2,698,505
|
|
|||||
Liabilities
|
|
|
|
|
|
|
|
||||||||||
Current Liabilities
(1)
|
75,497
|
|
79,124
|
|
|
|
333,053
|
|
148,919
|
|
176,033
|
|
|||||
Long-Term Debt
(1)
|
265,325
|
|
198,000
|
|
|
|
—
|
|
1,074,534
|
|
1,142,368
|
|
|||||
Total Liabilities
|
357,812
|
|
301,244
|
|
|
|
1,377,722
|
|
1,378,969
|
|
1,633,155
|
|
|||||
Stockholders' Equity (Deficit)
|
$
|
193,458
|
|
$
|
76,055
|
|
|
|
$
|
(852,724
|
)
|
$
|
794,378
|
|
$
|
1,065,350
|
|
|
|
|
|
|
|
|
|
||||||||||
Shares Outstanding at Year-End
|
11,571
|
|
10,054
|
|
|
|
44,592
|
|
43,918
|
|
43,402
|
|
|||||
Book Value per Share at Year-End
|
$
|
16.72
|
|
$
|
7.56
|
|
|
|
$
|
(19.12
|
)
|
$
|
18.09
|
|
$
|
24.55
|
|
|
|
|
|
|
|
|
|
||||||||||
Additional Information
|
|
|
|
|
|
|
|
||||||||||
Producing Wells
|
|
|
|
|
|
|
|
||||||||||
SilverBow Operated
|
694
|
|
774
|
|
|
|
1,030
|
|
1,040
|
|
1,039
|
|
|||||
Outside Operated
|
15
|
|
5
|
|
|
|
26
|
|
25
|
|
25
|
|
|||||
Total Producing Wells
|
709
|
|
779
|
|
|
|
1,056
|
|
1,065
|
|
1,064
|
|
|||||
Wells Drilled (Gross)
|
25
|
|
7
|
|
|
|
24
|
|
36
|
|
48
|
|
|||||
|
|
|
|
|
|
|
|
||||||||||
Proved Reserves
|
|
|
|
|
|
|
|
||||||||||
Natural Gas (Bcf)
(2)
|
842.7
|
|
626.8
|
|
|
|
311.7
|
|
686.7
|
|
815.1
|
|
|||||
Oil Reserves (MBoe)
(2)
|
7.2
|
|
5.8
|
|
|
|
10.1
|
|
49.7
|
|
53.0
|
|
|||||
NGL Reserves (MBoe)
(2)
|
23.1
|
|
13.7
|
|
|
|
8.2
|
|
29.7
|
|
30.4
|
|
|||||
Total Proved Reserves (MMcfe equivalent)
|
1,024.4
|
|
744.0
|
|
|
|
421.6
|
|
1,163.0
|
|
1,315.2
|
|
Fields
|
|
Acreage
|
|
2017 Production (MMcfe/d)
|
|
% Gas
|
|
2017 Wells Drilled
|
|
2017 Wells Completed
|
|||||
Artesia
|
|
12,811
|
|
|
20,256
|
|
|
44
|
%
|
|
7
|
|
|
7
|
|
AWP
|
|
42,566
|
|
|
35,628
|
|
|
53
|
%
|
|
2
|
|
|
2
|
|
Fasken
|
|
7,718
|
|
|
92,518
|
|
|
100
|
%
|
|
6
|
|
|
10
|
|
Other
(1)
|
|
37,026
|
|
|
5,392
|
|
|
96
|
%
|
|
3
|
|
|
3
|
|
Total
|
|
100,121
|
|
|
153,794
|
|
|
82
|
%
|
|
18
|
|
|
22
|
|
•
|
a ratio of total debt to EBITDA, as defined in the Credit Agreement, for the most recently completed four fiscal quarters, not to exceed 4.0 to 1.0 as of the last day of each fiscal quarter; and
|
•
|
a current ratio, as defined in the Credit Agreement, and which includes in the numerator available borrowings undrawn under the borrowing base, of not less than 1.0 to 1.0 as of the last day of each fiscal quarter.
|
•
|
Revenues and net income (loss):
The Company's oil and gas revenues were
$195.9 million
for the
year ended December 31, 2017
(successor) and
$121.4 million
and
$43.0 million
for the
period of April 23, 2016 through December 31, 2016 (successor)
and the
period of January 1, 2016 through April 22, 2016 (predecessor)
, respectively. Revenues were higher primarily due to overall higher commodity pricing as well as higher natural gas production, partially offset by lower oil and NGL production. The Company's net income of
$72.0 million
for the
year ended December 31, 2017
(successor) was primarily due to higher commodity pricing along with lower operating expenses
while
the net loss of
$156.3 million
in the
period of April 23, 2016 through December 31, 2016 (successor)
was primarily due to the
$133.5 million
non-cash write-down of our oil and gas properties and losses on derivative instruments of $19.7 million and
the net income of
$851.6 million
in the
period of January 1, 2016 through April 22, 2016 (predecessor)
was primarily due to the gain on reorganization adjustments as part of our emergence from bankruptcy.
|
•
|
Capital expenditures:
The Company's capital expenditures on a cash basis were
$193.0 million
for the
year ended December 31, 2017
(successor) compared to
$45.7 million
and
$24.5 million
in the
period of April 23, 2016 through December 31, 2016 (successor)
and the
period of January 1, 2016 through April 22, 2016 (predecessor)
, respectively. The expenditures for the
year ended December 31, 2017
(successor), were primarily driven by development activity in our Fasken, AWP, Artesia and Oro Grande fields in Eagle Ford. Capital expenditures in the
period of April 23, 2016 through December 31, 2016 (successor)
were focused on drilling and completion activities in our Fasken field. These expenditures were funded by operating cash flows and proceeds from property dispositions. Expenditures for the
period of January 1, 2016 through April 22, 2016 (predecessor)
, were primarily devoted to completion of wells in South Texas that were drilled in 2015. These expenditures were funded by cash flows and borrowings under our DIP Credit Facility.
|
•
|
Working capital:
The Company had a working capital deficit of
$32.9 million
at
December 31, 2017
and a deficit of
$57.6 million
at
December 31, 2016
. The working capital computation does not include available liquidity through our Credit Facility.
|
•
|
Cash Flows:
For the
year ended December 31, 2017
(successor) the Company generated cash from Operating Activities of
$107.8 million
, of which
$0.7 million
was attributable to changes in working capital. Cash used for property additions was
$193.0 million
. This included
$9.9 million
attributable to a net increase of capital related payables and accrued costs. The Company’s net payments on the revolving Credit Facility were
$125.0 million
which includes the pay down on Credit Facility borrowings with proceeds from the Second Lien.
|
|
2018
|
2019
|
2020
|
2021
|
2022
|
Thereafter
|
Total
|
||||||||||||||
Non-cancelable operating leases
(1)
|
$
|
4,622
|
|
$
|
698
|
|
$
|
627
|
|
$
|
263
|
|
$
|
—
|
|
$
|
—
|
|
$
|
6,210
|
|
Asset retirement obligation
(2)
|
2,109
|
|
873
|
|
635
|
|
130
|
|
78
|
|
6,960
|
|
10,785
|
|
|||||||
Drilling, Completion and Geoscience Contracts
|
4,082
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
4,082
|
|
|||||||
Gas transportation and Processing
(3)
|
6,816
|
|
8,410
|
|
7,479
|
|
325
|
|
—
|
|
—
|
|
23,030
|
|
|||||||
Interest Cost
(4)
|
22,415
|
|
22,498
|
|
22,589
|
|
22,690
|
|
20,410
|
|
38,304
|
|
148,906
|
|
|||||||
Long-Term Debt
|
—
|
|
—
|
|
—
|
|
—
|
|
73,000
|
|
200,000
|
|
273,000
|
|
|||||||
Executive severance agreements
|
1,552
|
|
554
|
|
—
|
|
—
|
|
—
|
|
—
|
|
2,106
|
|
|||||||
Other contractual commitments
(5)
|
11,250
|
|
5,000
|
|
—
|
|
—
|
|
—
|
|
—
|
|
16,250
|
|
|||||||
Total
|
$
|
52,846
|
|
$
|
38,033
|
|
$
|
31,330
|
|
$
|
23,408
|
|
$
|
93,488
|
|
$
|
245,264
|
|
$
|
484,369
|
|
Fields
|
|
Oil and Gas Sales (In Millions)
|
|||||||||||||||
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
|
Year Ended December 31, 2017
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31, 2015
|
||||||||
Artesia
|
|
$
|
33.2
|
|
|
$
|
9.9
|
|
|
|
$
|
3.5
|
|
|
$
|
19.3
|
|
AWP
|
|
55.2
|
|
|
42.4
|
|
|
|
14.7
|
|
|
87.1
|
|
||||
Fasken
|
|
101.8
|
|
|
53.0
|
|
|
|
14.3
|
|
|
72.1
|
|
||||
Other
(1)
|
|
5.7
|
|
|
16.1
|
|
|
|
10.5
|
|
|
67.8
|
|
||||
Total
|
|
$
|
195.9
|
|
|
$
|
121.4
|
|
|
|
$
|
43.0
|
|
|
$
|
246.3
|
|
Fields
|
|
Net Oil and Gas Production Volumes (Mcfe)
|
|||||||||||||
|
|
Successor
|
|
|
Predecessor
|
||||||||||
|
|
|
|
(a)
|
|
|
(b)
|
(a) + (b)
|
|
|
|||||
|
|
Year Ended December 31, 2017
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
Year Ended December 31, 2016
|
|
Year Ended December 31, 2015
|
|||||
Artesia
|
|
7,393
|
|
|
2,904
|
|
|
|
1,542
|
|
4,446
|
|
|
6,288
|
|
AWP
|
|
13,004
|
|
|
11,880
|
|
|
|
5,706
|
|
17,586
|
|
|
21,708
|
|
Fasken
|
|
33,769
|
|
|
20,772
|
|
|
|
7,278
|
|
28,050
|
|
|
28,614
|
|
Other
(1)
|
|
1,969
|
|
|
2,634
|
|
|
|
2,316
|
|
4,950
|
|
|
10,266
|
|
Total
|
|
56,135
|
|
|
38,190
|
|
|
|
16,842
|
|
55,032
|
|
|
66,876
|
|
•
|
Price variances that had a
$44.6 million
favorable
impact on sales, with an
increase
of
$29.3 million
due to the
27%
increase
in natural gas prices received, an
increase
of
$7.9 million
due to the
29%
increase
in oil prices received and an
increase
of
$7.4 million
due to the
48%
increase
in NGL prices received.
|
•
|
Volume variances that had a
$13.1 million
unfavorable
impact on sales, with a
$24.6 million
decrease
due to the
0.6 million
Bbl
decrease
in oil production volumes, a
$12.4 million
increase
due to the
5.2
Bcf
increase
in natural gas production volumes and a
$0.9 million
decrease
due to the
0.1 million
Bbl
decrease
in NGL production volumes.
|
•
|
Price variances that had a $17.0 million unfavorable impact on sales, with a decrease of $10.0 million due to the 16% decrease in oil prices received and a decrease of $7.0 million due to the 7% decrease in natural gas prices.
|
•
|
Volume variances that had a $64.9 million unfavorable impact on sales, with a $51.7 million decrease due to the 1.1 million Bbl decrease in oil production volumes, an $8.4 million decrease due to the 3.3 Bcf decrease in natural gas production volumes and a $4.7 million decrease due to the 0.3 million Bbl decrease in NGL production volumes.
|
|
Production Volume
|
|
Average Price
|
||||||||||
|
Oil
|
|
NGL
|
|
Gas
|
|
Combined
|
|
Oil
|
|
NGL
|
|
Gas
|
|
(MBbl)
|
|
(MBbl)
|
|
(Bcf)
|
|
(Bcfe)
|
|
(Bbl)
|
|
(Bbl)
|
|
(Mcf)
|
2017 (Successor)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
146
|
|
204
|
|
10.1
|
|
12.2
|
|
$49.26
|
|
$20.33
|
|
$3.07
|
Second Quarter
|
139
|
|
228
|
|
11.1
|
|
13.3
|
|
$46.82
|
|
$18.49
|
|
$3.16
|
Third Quarter
|
170
|
|
267
|
|
11.7
|
|
14.3
|
|
$46.93
|
|
$21.67
|
|
$3.01
|
Fourth Quarter
|
229
|
|
347
|
|
12.8
|
|
16.3
|
|
$57.64
|
|
$24.37
|
|
$2.88
|
Total
|
684
|
|
1,046
|
|
45.7
|
|
56.1
|
|
$50.98
|
|
$21.61
|
|
$3.03
|
2016 (Successor)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April 23 - June 30
|
254
|
|
246
|
|
8.1
|
|
11.1
|
|
$44.35
|
|
$14.15
|
|
$1.97
|
Third Quarter
|
292
|
|
255
|
|
11.5
|
|
14.8
|
|
$43.27
|
|
$16.38
|
|
$2.71
|
Fourth Quarter
|
240
|
|
226
|
|
9.5
|
|
12.3
|
|
$47.10
|
|
$18.84
|
|
$2.86
|
Total
|
786
|
|
727
|
|
29.1
|
|
38.2
|
|
$44.79
|
|
$16.39
|
|
$2.55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 (Predecessor)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
427
|
|
310
|
|
9.2
|
|
13.6
|
|
$30.07
|
|
$10.83
|
|
$1.98
|
April 1 - April 22
|
95
|
|
70
|
|
2.2
|
|
3.2
|
|
$37.49
|
|
$11.96
|
|
$1.90
|
Total
|
522
|
|
380
|
|
11.4
|
|
16.8
|
|
$31.43
|
|
$11.04
|
|
$1.96
|
2015 (Predecessor)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
685
|
|
426
|
|
10.7
|
|
17.4
|
|
$45.10
|
|
$16.09
|
|
$2.76
|
Second Quarter
|
628
|
|
366
|
|
10.4
|
|
16.4
|
|
$56.65
|
|
$15.18
|
|
$2.61
|
Third Quarter
|
581
|
|
344
|
|
10.8
|
|
16.4
|
|
$45.24
|
|
$12.94
|
|
$2.70
|
Fourth Quarter
|
511
|
|
297
|
|
11.9
|
|
16.7
|
|
$40.22
|
|
$13.38
|
|
$2.20
|
Total
|
2,405
|
|
1,433
|
|
43.8
|
|
66.9
|
|
$47.11
|
|
$14.54
|
|
$2.56
|
|
Successor
|
|
|
Predecessor
|
||||||||||
Costs and Expenses
|
Year Ended December 31, 2017
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
Year Ended December 31, 2015
|
||||||||
General and administrative, net
|
$
|
30,000
|
|
$
|
22,538
|
|
|
|
$
|
9,245
|
|
$
|
42,611
|
|
Depreciation, depletion, and amortization
|
46,933
|
|
36,436
|
|
|
|
20,439
|
|
177,512
|
|
||||
Accretion of asset retirement obligation
|
2,322
|
|
2,878
|
|
|
|
1,610
|
|
5,572
|
|
||||
Lease operating cost
|
21,908
|
|
25,777
|
|
|
|
14,933
|
|
70,188
|
|
||||
Transportation and gas processing
|
19,360
|
|
13,038
|
|
|
|
6,090
|
|
21,741
|
|
||||
Severance and other taxes
|
8,205
|
|
6,713
|
|
|
|
3,917
|
|
17,090
|
|
||||
Interest expense, net
|
15,070
|
|
15,310
|
|
|
|
13,347
|
|
75,870
|
|
||||
Write-down of oil and gas properties
|
—
|
|
133,496
|
|
|
|
77,732
|
|
1,562,086
|
|
||||
Reorganization items, net
|
—
|
|
1,639
|
|
|
|
(956,142
|
)
|
6,565
|
|
||||
Total Costs and Expenses
|
$
|
143,798
|
|
$
|
257,825
|
|
|
|
$
|
(808,829
|
)
|
$
|
1,979,235
|
|
•
|
Depreciation, depletion, amortization;
|
•
|
Accretion of asset retirement obligations;
|
•
|
Interest expense;
|
•
|
Impairment of oil and natural gas properties;
|
•
|
Reorganization items;
|
•
|
Net losses (gains) on commodity derivative contracts;
|
•
|
Amounts collected (paid) for commodity derivative contracts held to settlement;
|
•
|
Income tax expense or (benefit); and
|
•
|
Share-based compensation expense.
|
•
|
the approximately $906 million of indebtedness outstanding on account of the Company’s senior notes, the $75 million drawn under the Company's DIP Credit Agreement (described below) and certain other unsecured claims were exchanged for 88.5% of the post-emergence Company’s common stock;
|
•
|
the lenders under the DIP Credit Agreement (as defined and more fully described below) received a backstop fee consisting of 7.5% of the post-emergence Company’s common stock which was not included in the 88.5% distributed to creditors;
|
•
|
the Company’s pre-petition common stock was canceled and the previous shareholders received 4% of the post-emergence Company’s common stock and warrants to purchase up to 30% of the reorganized Company's equity;
|
•
|
the warrants (each for up to 15% of the reorganized Company's equity), are exercisable at prices that represent a substantial increase from the value at emergence, as follows:
|
Issue Date
|
Expiration Date
|
Shares
|
Strike Price
|
April 22, 2016
|
April 22, 2019
|
2,142,857
|
$80.00
|
April 22, 2016
|
April 22, 2020
|
2,142,857
|
$86.18
|
•
|
claims of other creditors were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditors;
|
•
|
the Company entered into a registration rights agreement to provide customary registration rights to certain holders of the Company’s post-emergence common stock who, together with their affiliates received upon emergence 5% or more of the outstanding common stock of the Company;
|
•
|
the Company sold (effective April 15, 2016) a portion of its interest in its Central Louisiana fields known as Burr Ferry and South Bearhead Creek to Texegy LLC, for net proceeds of approximately $46.9 million including deposits received prior to the closing date; and
|
•
|
the Company's previous credit facility (the "Prior First Lien Credit Facility") was terminated and a new senior secured credit facility (defined herein as "Credit Facility") was established. For more information refer to Note 4 of the accompanying consolidated financial statements in this Form 10-K.
|
Item 8. Financial Statements and Supplementary Data
|
Page
|
|
|
|
|
Management's Report on Internal Control Over Financial Reporting
|
||
|
|
|
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
|
||
|
|
|
Reports of Independent Registered Public Accounting Firms on Consolidated Financial Statements
|
||
|
|
|
Consolidated Balance Sheets
|
||
|
|
|
Consolidated Statements of Operations
|
||
|
|
|
Consolidated Statements of Stockholders' Equity (Deficit)
|
||
|
|
|
Consolidated Statements of Cash Flows
|
||
|
|
|
Notes to Consolidated Financial Statements
|
||
|
|
|
Supplementary Information
|
|
Successor
|
||||||
|
December 31, 2017
|
|
December 31, 2016
|
||||
ASSETS
|
|
|
|
||||
Current Assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
7,806
|
|
|
$
|
303
|
|
Accounts receivable, net
|
27,263
|
|
|
17,490
|
|
||
Fair value of commodity derivatives
|
5,148
|
|
|
458
|
|
||
Other current assets
|
2,352
|
|
|
3,228
|
|
||
Total Current Assets
|
42,569
|
|
|
21,479
|
|
||
|
|
|
|
||||
Property and Equipment:
|
|
|
|
|
|
||
Property and Equipment, Full Cost Method, including $50,377 and $33,354 of unproved property costs not being amortized
|
712,166
|
|
|
517,074
|
|
||
Less – Accumulated depreciation, depletion, amortization and impairment
|
(216,769
|
)
|
|
(169,879
|
)
|
||
Property and Equipment, Net
|
495,397
|
|
|
347,195
|
|
||
Other Long-Term Assets
|
13,304
|
|
|
8,625
|
|
||
Total Assets
|
$
|
551,270
|
|
|
$
|
377,299
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
||
Current Liabilities:
|
|
|
|
|
|
||
Accounts payable and accrued liabilities
|
$
|
44,437
|
|
|
$
|
40,434
|
|
Fair value of commodity derivatives
|
5,075
|
|
|
15,823
|
|
||
Accrued capital costs
|
10,883
|
|
|
11,954
|
|
||
Accrued interest
|
2,106
|
|
|
1,721
|
|
||
Undistributed oil and gas revenues
|
12,996
|
|
|
9,192
|
|
||
Total Current Liabilities
|
75,497
|
|
|
79,124
|
|
||
|
|
|
|
||||
Long-term debt
|
265,325
|
|
|
198,000
|
|
||
Asset retirement obligations
|
8,678
|
|
|
22,291
|
|
||
Other long-term liabilities
|
8,312
|
|
|
1,829
|
|
||
|
|
|
|
||||
Commitments and Contingencies (Note 6)
|
—
|
|
|
—
|
|
||
|
|
|
|
||||
Stockholders' Equity:
|
|
|
|
|
|
||
Preferred stock, $.01 par value, 10,000,000 shares authorized, none issued
|
—
|
|
|
—
|
|
||
Common stock, $.01 par value, 40,000,000 shares authorized, 11,621,385 and 10,076,059 shares issued and 11,570,621 and 10,053,574 shares outstanding
|
116
|
|
|
101
|
|
||
Additional paid-in capital
|
279,111
|
|
|
232,917
|
|
||
Treasury stock held, at cost, 50,764 and 22,485 shares
|
(1,452
|
)
|
|
(675
|
)
|
||
Retained earnings (Accumulated deficit)
|
(84,317
|
)
|
|
(156,288
|
)
|
||
Total Stockholders’ Equity
|
193,458
|
|
|
76,055
|
|
||
Total Liabilities and Stockholders’ Equity
|
$
|
551,270
|
|
|
$
|
377,299
|
|
|
|
|
|
||||
See accompanying Notes to Consolidated Financial Statements.
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended December 31, 2017
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31, 2015
|
||||||||
Revenues:
|
|
|
|
|
|
|
|
|
||||||||
Oil and gas sales
|
$
|
195,910
|
|
|
$
|
121,386
|
|
|
|
$
|
43,027
|
|
|
$
|
246,270
|
|
|
|
|
|
|
|
|
|
|
||||||||
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
||||||
General and administrative, net
|
30,000
|
|
|
22,538
|
|
|
|
9,245
|
|
|
42,611
|
|
||||
Depreciation, depletion, and amortization
|
46,933
|
|
|
36,436
|
|
|
|
20,439
|
|
|
177,512
|
|
||||
Accretion of asset retirement obligations
|
2,322
|
|
|
2,878
|
|
|
|
1,610
|
|
|
5,572
|
|
||||
Lease operating expense
|
21,908
|
|
|
25,777
|
|
|
|
14,933
|
|
|
70,188
|
|
||||
Transportation and gas processing
|
19,360
|
|
|
13,038
|
|
|
|
6,090
|
|
|
21,741
|
|
||||
Severance and other taxes
|
8,205
|
|
|
6,713
|
|
|
|
3,917
|
|
|
17,090
|
|
||||
Write-down of oil and gas properties
|
—
|
|
|
133,496
|
|
|
|
77,732
|
|
|
1,562,086
|
|
||||
Total Operating Expenses
|
128,728
|
|
|
240,876
|
|
|
|
133,966
|
|
|
1,896,800
|
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Operating Income (Loss)
|
67,182
|
|
|
(119,490
|
)
|
|
|
(90,939
|
)
|
|
(1,650,530
|
)
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Non-Operating Income (Expense)
|
|
|
|
|
|
|
|
|
||||||||
Net gain (loss) on commodity derivatives
|
17,913
|
|
|
(19,677
|
)
|
|
|
—
|
|
|
186
|
|
||||
Interest expense, net
|
(15,070
|
)
|
|
(15,310
|
)
|
|
|
(13,347
|
)
|
|
(75,870
|
)
|
||||
Reorganization items
|
—
|
|
|
(1,639
|
)
|
|
|
956,142
|
|
|
(6,565
|
)
|
||||
Other income (expense), net
|
(8
|
)
|
|
(172
|
)
|
|
|
(245
|
)
|
|
(1,735
|
)
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Income (Loss) Before Income Taxes
|
70,017
|
|
|
(156,288
|
)
|
|
|
851,611
|
|
|
(1,734,514
|
)
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Income Tax Benefit
|
(1,954
|
)
|
|
—
|
|
|
|
—
|
|
|
(80,543
|
)
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Net Income (Loss)
|
$
|
71,971
|
|
|
$
|
(156,288
|
)
|
|
|
$
|
851,611
|
|
|
$
|
(1,653,971
|
)
|
|
|
|
|
|
|
|
|
|
||||||||
Per Share Amounts:
|
|
|
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
|
|
||||||||
Basic: Net Income (Loss)
|
$
|
6.28
|
|
|
$
|
(15.61
|
)
|
|
|
$
|
19.06
|
|
|
$
|
(37.20
|
)
|
|
|
|
|
|
|
|
|
|
||||||||
Diluted: Net Income (Loss)
|
$
|
6.25
|
|
|
$
|
(15.61
|
)
|
|
|
$
|
18.64
|
|
|
$
|
(37.20
|
)
|
|
|
|
|
|
|
|
|
|
||||||||
Weighted Average Shares Outstanding - Basic
|
11,453
|
|
|
10,013
|
|
|
|
44,692
|
|
|
44,463
|
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Weighted Average Shares Outstanding - Diluted
|
11,514
|
|
|
10,013
|
|
|
|
45,697
|
|
|
44,463
|
|
||||
|
|
|
|
|
|
|
|
|
||||||||
See accompanying Notes to Consolidated Financial Statements.
|
|
Common Stock
|
|
Additional Paid-in Capital
|
|
Treasury Stock
|
|
Retained Earnings (Deficit)
|
|
Total
|
||||||||||
Balance, December 31, 2014 (Predecessor)
|
$
|
444
|
|
|
$
|
771,972
|
|
|
$
|
(9,855
|
)
|
|
$
|
31,817
|
|
|
$
|
794,378
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Stock issued for benefit plans (352,476 shares)
|
—
|
|
|
(1,714
|
)
|
|
7,518
|
|
|
(4,885
|
)
|
|
919
|
|
|||||
Purchase of treasury shares (70,437 shares)
|
—
|
|
|
—
|
|
|
(154
|
)
|
|
—
|
|
|
(154
|
)
|
|||||
Employee stock purchase plan (87,629 shares)
|
1
|
|
|
301
|
|
|
—
|
|
|
—
|
|
|
302
|
|
|||||
Issuance of restricted stock (304,166 shares)
|
3
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Share-based compensation
|
—
|
|
|
5,802
|
|
|
—
|
|
|
—
|
|
|
5,802
|
|
|||||
Net Loss
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,653,971
|
)
|
|
(1,653,971
|
)
|
|||||
Balance, December 31, 2015 (Predecessor)
|
$
|
448
|
|
|
$
|
776,358
|
|
|
$
|
(2,491
|
)
|
|
$
|
(1,627,039
|
)
|
|
$
|
(852,724
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Purchase of treasury shares (65,170 shares)
|
—
|
|
|
—
|
|
|
(5
|
)
|
|
—
|
|
|
(5
|
)
|
|||||
Issuance of restricted stock (229,690 shares)
|
2
|
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Share-based compensation
|
—
|
|
|
1,118
|
|
|
—
|
|
|
—
|
|
|
1,118
|
|
|||||
Net Income
|
—
|
|
|
—
|
|
|
—
|
|
|
851,611
|
|
|
851,611
|
|
|||||
Balance, April 22, 2016 (Predecessor)
|
$
|
450
|
|
|
$
|
777,474
|
|
|
$
|
(2,496
|
)
|
|
$
|
(775,428
|
)
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cancellation of Predecessor equity
|
(450
|
)
|
|
(777,474
|
)
|
|
2,496
|
|
|
775,428
|
|
|
—
|
|
|||||
Balance, April 22, 2016 (Predecessor)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Issuance of Successor common stock & warrants
|
100
|
|
|
229,299
|
|
|
—
|
|
|
—
|
|
|
229,399
|
|
|||||
Balance, April 22, 2016 (Successor)
|
$
|
100
|
|
|
$
|
229,299
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
229,399
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Purchase of treasury shares (22,485 shares)
|
—
|
|
|
—
|
|
|
(675
|
)
|
|
—
|
|
|
(675
|
)
|
|||||
Issuance of restricted stock (76,058 shares)
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Share-based compensation
|
—
|
|
|
3,618
|
|
|
—
|
|
|
—
|
|
|
3,618
|
|
|||||
Net Loss
|
—
|
|
|
—
|
|
|
—
|
|
|
(156,288
|
)
|
|
(156,288
|
)
|
|||||
Balance, December 31, 2016 (Successor)
|
$
|
101
|
|
|
$
|
232,917
|
|
|
$
|
(675
|
)
|
|
$
|
(156,288
|
)
|
|
$
|
76,055
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Purchase of treasury shares (28,279 shares)
|
—
|
|
|
—
|
|
|
(777
|
)
|
|
—
|
|
|
(777
|
)
|
|||||
Issuance of common stock (1,403,508 shares)
|
14
|
|
|
39,166
|
|
|
—
|
|
|
—
|
|
|
39,180
|
|
|||||
Issuance of restricted stock (141,818 shares)
|
1
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Share-based compensation
|
—
|
|
|
7,029
|
|
|
—
|
|
|
—
|
|
|
7,029
|
|
|||||
Net Income
|
—
|
|
|
—
|
|
|
—
|
|
|
71,971
|
|
|
71,971
|
|
|||||
Balance, December 31, 2017 (Successor)
|
$
|
116
|
|
|
$
|
279,111
|
|
|
$
|
(1,452
|
)
|
|
$
|
(84,317
|
)
|
|
$
|
193,458
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
See accompanying Notes to Consolidated Financial Statements.
|
|
Successor
|
|
|
Predecessor
|
|||||||||||
|
Year Ended December 31, 2017
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31, 2015
|
||||||||
Cash Flows from Operating Activities:
|
|
|
|
|
|
|
|
||||||||
Net income (loss)
|
$
|
71,971
|
|
$
|
(156,288
|
)
|
|
|
$
|
851,611
|
|
|
$
|
(1,653,971
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities-
|
|
|
|
|
|
|
|
|
|
||||||
Write-down of oil and gas properties
|
—
|
|
133,496
|
|
|
|
77,732
|
|
|
1,562,086
|
|
||||
Depreciation, depletion, and amortization
|
46,933
|
|
36,436
|
|
|
|
20,439
|
|
|
177,512
|
|
||||
Accretion of asset retirement obligation
|
2,322
|
|
2,878
|
|
|
|
1,610
|
|
|
5,572
|
|
||||
Deferred income tax benefit
|
—
|
|
—
|
|
|
|
—
|
|
|
(80,133
|
)
|
||||
Share-based compensation expense
|
6,849
|
|
3,618
|
|
|
|
886
|
|
|
4,435
|
|
||||
Loss (gain) on derivatives
|
(17,913
|
)
|
19,676
|
|
|
|
—
|
|
|
(186
|
)
|
||||
Cash settlements (paid) received on derivatives
|
(1,411
|
)
|
(1,928
|
)
|
|
|
—
|
|
|
2,544
|
|
||||
Settlements of asset retirement obligations
|
(2,335
|
)
|
(2,993
|
)
|
|
|
(848
|
)
|
|
—
|
|
||||
Write-down of debt issuance cost
|
2,676
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||
Reorganization items (non-cash)
|
—
|
|
—
|
|
|
|
(977,696
|
)
|
|
6,565
|
|
||||
Other
|
(559
|
)
|
1,351
|
|
|
|
229
|
|
|
(3,189
|
)
|
||||
Change in operating assets and liabilities-
|
|
|
|
|
|
|
|
|
|
||||||
(Increase) decrease in accounts receivable and other assets
|
(7,169
|
)
|
16,812
|
|
|
|
(5,474
|
)
|
|
26,747
|
|
||||
Increase (decrease) in accounts payable and accrued liabilities
|
6,089
|
|
(6,689
|
)
|
|
|
(9,647
|
)
|
|
(15,003
|
)
|
||||
Increase (decrease) in income taxes payable
|
—
|
|
—
|
|
|
|
—
|
|
|
(435
|
)
|
||||
Increase (decrease) in accrued interest
|
385
|
|
1,058
|
|
|
|
(308
|
)
|
|
9,730
|
|
||||
Net Cash Provided by (Used in) Operating Activities
|
107,838
|
|
47,427
|
|
|
|
(41,466
|
)
|
|
42,274
|
|
||||
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
||||||
Additions to property and equipment
|
(192,982
|
)
|
(45,671
|
)
|
|
|
(24,530
|
)
|
|
(139,688
|
)
|
||||
Acquisition of producing properties
|
(9,426
|
)
|
—
|
|
|
|
—
|
|
|
—
|
|
||||
Proceeds from the sale of property and equipment
|
702
|
|
45,985
|
|
|
|
48,661
|
|
|
1,164
|
|
||||
Net Cash Provided by (Used in) Investing Activities
|
(201,706
|
)
|
314
|
|
|
|
24,131
|
|
|
(138,524
|
)
|
||||
Cash Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
|
||||||
Proceeds from long-term debt issuances
|
198,000
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||
Proceeds from bank borrowings
|
404,700
|
|
84,000
|
|
|
|
328,000
|
|
|
281,100
|
|
||||
Payments of bank borrowings
|
(529,700
|
)
|
(139,000
|
)
|
|
|
(324,900
|
)
|
|
(153,500
|
)
|
||||
Net proceeds from issuances of common stock
|
39,179
|
|
—
|
|
|
|
—
|
|
|
302
|
|
||||
Purchase of treasury shares
|
(777
|
)
|
(675
|
)
|
|
|
(4
|
)
|
|
(154
|
)
|
||||
Payments of debt issuance costs
|
(10,031
|
)
|
(502
|
)
|
|
|
(6,482
|
)
|
|
(2,444
|
)
|
||||
Net Cash Provided by (Used in) Financing Activities
|
101,371
|
|
(56,177
|
)
|
|
|
(3,386
|
)
|
|
125,304
|
|
||||
|
|
|
|
|
|
|
|
||||||||
Net Increase (Decrease) in Cash and Cash Equivalents
|
7,503
|
|
(8,436
|
)
|
|
|
(20,721
|
)
|
|
29,054
|
|
||||
Cash and Cash Equivalents at Beginning of Period
|
303
|
|
8,739
|
|
|
|
29,460
|
|
|
406
|
|
||||
Cash and Cash Equivalents at End of Period
|
$
|
7,806
|
|
$
|
303
|
|
|
|
$
|
8,739
|
|
|
$
|
29,460
|
|
|
|
|
|
|
|
|
|
||||||||
Supplemental Disclosures of Cash Flows Information:
|
|
|
|
|
|
|
|
|
|
||||||
Cash paid during period for interest, net of amounts capitalized
|
$
|
10,428
|
|
$
|
12,517
|
|
|
|
$
|
10,367
|
|
|
$
|
63,132
|
|
Cash paid during period for income taxes
|
$
|
—
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
450
|
|
Cash paid for reorganization items
|
$
|
—
|
|
$
|
12,929
|
|
|
|
$
|
15,643
|
|
|
$
|
—
|
|
Changes in capital accounts payable and capital accruals
|
$
|
9,894
|
|
$
|
(6,265
|
)
|
|
|
$
|
1,843
|
|
|
$
|
(27,611
|
)
|
Changes in other long-term liabilities for capital expenditures
|
$
|
5,000
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
See accompanying Notes to Consolidated Financial Statements.
|
•
|
the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows there-from, and the ceiling test impairment calculation,
|
•
|
estimates related to the collectability of accounts receivable and the credit worthiness of our customers,
|
•
|
estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf,
|
•
|
estimates of future costs to develop and produce reserves,
|
•
|
accruals related to oil and gas sales, capital expenditures and lease operating expenses,
|
•
|
estimates in the calculation of share-based compensation expense,
|
•
|
estimates of our ownership in properties prior to final division of interest determination,
|
•
|
the estimated future cost and timing of asset retirement obligations,
|
•
|
estimates made in our income tax calculations,
|
•
|
estimates in the calculation of the fair value of commodity derivative assets and liabilities,
|
•
|
estimates in the assessment of current litigation claims against the Company,
|
•
|
estimates in amounts due with respect to open state regulatory audits, and
|
•
|
the estimates of reorganization value, enterprise value and fair value of assets and liabilities upon emergence from bankruptcy and application of fresh start accounting.
|
|
Successor
|
|||||
|
December 31,
2017 |
December 31,
2016 |
||||
Property and Equipment
|
|
|
||||
Proved oil and gas properties
|
$
|
658,519
|
|
$
|
480,499
|
|
Unproved oil and gas properties
|
50,377
|
|
33,354
|
|
||
Furniture, fixtures, and other equipment
|
3,270
|
|
3,221
|
|
||
Less – Accumulated depreciation, depletion, amortization and impairment
|
(216,769
|
)
|
(169,879
|
)
|
||
Property and Equipment, Net
|
$
|
495,397
|
|
$
|
347,195
|
|
|
Successor
|
|||||
|
December 31,
2017 |
December 31,
2016 |
||||
Trade accounts payable
|
$
|
20,884
|
|
$
|
12,372
|
|
Accrued operating expenses
|
3,490
|
|
2,990
|
|
||
Accrued compensation costs
|
5,334
|
|
4,730
|
|
||
Asset retirement obligations – current portion
|
2,109
|
|
9,965
|
|
||
Accrued non-income based taxes
|
3,898
|
|
3,937
|
|
||
Accrued corporate and legal fees
|
2,784
|
|
3,075
|
|
||
Other payables
|
5,938
|
|
3,365
|
|
||
Total Accounts payable and accrued liabilities
|
$
|
44,437
|
|
$
|
40,434
|
|
|
Successor
|
|
|
Predecessor
|
||||||||
Sellers greater than 10%
|
Year Ended December 31, 2017
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31, 2015
|
||||
Kinder Morgan
|
48
|
%
|
|
38
|
%
|
|
|
20
|
%
|
|
27
|
%
|
Plains Marketing
(1)
|
—
|
%
|
|
14
|
%
|
|
|
14
|
%
|
|
18
|
%
|
Howard Energy
(1)
|
—
|
%
|
|
—
|
%
|
|
|
11
|
%
|
|
13
|
%
|
Southcross Energy
(1)
|
—
|
%
|
|
—
|
%
|
|
|
11
|
%
|
|
—
|
%
|
Shell
(1)
|
—
|
%
|
|
15
|
%
|
|
|
19
|
%
|
|
16
|
%
|
|
Successor Year Ended December 31, 2017
|
|
Successor from April 23, 2016 through December 31, 2016
|
||||||||||||||||||
|
Net Income (Loss)
|
|
Shares
|
|
Per Share
Amount |
|
Net Income (Loss)
|
|
Shares
|
|
Per Share
Amount |
||||||||||
Basic EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Net Income (Loss) and Share Amounts
|
$
|
71,971
|
|
|
11,453
|
|
|
$
|
6.28
|
|
|
$
|
(156,288
|
)
|
|
10,013
|
|
|
$
|
(15.61
|
)
|
Dilutive Securities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Restricted Stock Awards
|
|
|
6
|
|
|
|
|
|
|
—
|
|
|
|
|
|||||||
Restricted Stock Units Awards
|
|
|
—
|
|
|
|
|
|
|
—
|
|
|
|
||||||||
Stock Option Awards
|
|
|
55
|
|
|
|
|
|
|
—
|
|
|
|
|
|||||||
Diluted EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Net Income (Loss) and Assumed Share Conversions
|
$
|
71,971
|
|
|
11,514
|
|
|
$
|
6.25
|
|
|
$
|
(156,288
|
)
|
|
10,013
|
|
|
$
|
(15.61
|
)
|
|
Predecessor from January 1, 2016 through April 22, 2016
|
|
Predecessor Year Ended December 31, 2015
|
||||||||||||||||||
|
Net Income (Loss)
|
|
Shares
|
|
Per Share
Amount |
|
Net Income (Loss)
|
|
Shares
|
|
Per Share
Amount |
||||||||||
Basic EPS:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net Income (Loss) and Share Amounts
|
$
|
851,611
|
|
|
44,692
|
|
|
$
|
19.06
|
|
|
$
|
(1,653,971
|
)
|
|
44,463
|
|
|
$
|
(37.20
|
)
|
Dilutive Securities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Restricted Stock Awards
|
|
|
1,005
|
|
|
|
|
|
|
—
|
|
|
|
||||||||
Restricted Stock Unit Awards
|
|
|
—
|
|
|
|
|
|
|
—
|
|
|
|
||||||||
Stock Option Awards
|
|
|
—
|
|
|
|
|
|
|
—
|
|
|
|
||||||||
Diluted EPS:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net Income (Loss) and Assumed Share Conversions
|
$
|
851,611
|
|
|
45,697
|
|
|
$
|
18.64
|
|
|
$
|
(1,653,971
|
)
|
|
44,463
|
|
|
$
|
(37.20
|
)
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended December 31, 2017
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31, 2015
|
||||||||
|
|
|
|
|
||||||||||||
Income (Loss) Before Income Taxes
|
$
|
70,017
|
|
|
$
|
(156,288
|
)
|
|
|
$
|
851,611
|
|
|
$
|
(1,734,514
|
)
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended December 31, 2017
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31, 2015
|
||||||||
|
|
|
|
|
||||||||||||
Current
|
$
|
(1,954
|
)
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
(410
|
)
|
Deferred
|
—
|
|
|
—
|
|
|
|
—
|
|
|
(80,133
|
)
|
||||
Total
|
$
|
(1,954
|
)
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
(80,543
|
)
|
|
Successor
|
|
|
Predecessor
|
||||||||
|
Year Ended December 31, 2017
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31, 2015
|
||||
|
|
|
|
|
||||||||
Federal Statutory Rate
|
35.0
|
%
|
|
35.0
|
%
|
|
|
35.0
|
%
|
|
35.0
|
%
|
State tax provisions (benefits), net of federal benefits
|
1.6
|
%
|
|
0.9
|
%
|
|
|
0.9
|
%
|
|
1.0
|
%
|
Reorganization Adjustments
|
—
|
%
|
|
—
|
%
|
|
|
(1.8
|
)%
|
|
—
|
%
|
Expiration/Write-off of NOL Carryovers
|
13.9
|
%
|
|
(74.9
|
)%
|
|
|
—
|
%
|
|
—
|
%
|
Change in Enacted Tax Rates
|
55.6
|
%
|
|
—
|
%
|
|
|
—
|
%
|
|
—
|
%
|
Executive Compensation Limitation
|
0.6
|
%
|
|
—
|
%
|
|
|
—
|
%
|
|
—
|
%
|
Other, net
|
2.3
|
%
|
|
0.2
|
%
|
|
|
1.0
|
%
|
|
(0.1
|
)%
|
Valuation allowance adjustments
|
(111.8
|
)%
|
|
38.9
|
%
|
|
|
(35.1
|
)%
|
|
(31.3
|
)%
|
Effective rate
|
(2.8
|
)%
|
|
—
|
%
|
|
|
—
|
%
|
|
4.6
|
%
|
|
Successor
|
||||||
|
Year Ended December 31, 2017
|
|
Year Ended December 31, 2016
|
||||
Deferred tax assets:
|
|
|
|
||||
Federal net operating loss (“NOL”) carryovers
|
$
|
58,438
|
|
|
$
|
40,104
|
|
Oil and gas exploration and development costs
|
—
|
|
|
71,292
|
|
||
Alternative minimum tax credits
|
138
|
|
|
2,092
|
|
||
Other Carryover Items
|
619
|
|
|
1,107
|
|
||
Asset Retirement Obligations
|
2,329
|
|
|
11,447
|
|
||
Derivative Contracts
|
29
|
|
|
5,802
|
|
||
Unrealized share-based compensation
|
872
|
|
|
648
|
|
||
Other
|
2,190
|
|
|
4,164
|
|
||
Valuation allowance
|
(58,398
|
)
|
|
(136,656
|
)
|
||
Total deferred tax assets
|
$
|
6,217
|
|
|
$
|
—
|
|
|
|
|
|
||||
Deferred tax liabilities:
|
|
|
|
||||
Oil and gas exploration and development costs
|
$
|
(6,054
|
)
|
|
$
|
—
|
|
Other
|
(163
|
)
|
|
—
|
|
||
Total deferred tax liabilities
|
(6,217
|
)
|
|
—
|
|
||
|
|
|
|
||||
Net deferred tax liabilities
|
$
|
—
|
|
|
$
|
—
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
Bank Borrowings
(1)
|
$
|
73,000
|
|
|
$
|
198,000
|
|
Second Lien Notes due 2024
|
200,000
|
|
|
—
|
|
||
|
273,000
|
|
|
198,000
|
|
||
Unamortized discount on Second Lien Notes due 2024
|
(1,992
|
)
|
|
—
|
|
||
Unamortized debt issuance cost on Second Lien Notes due 2024
|
(5,683
|
)
|
|
—
|
|
||
Total Long-Term Debt
|
$
|
265,325
|
|
|
$
|
198,000
|
|
•
|
a ratio of total debt to EBITDA, as defined in the Credit Agreement, for the most recently completed four fiscal quarters, not to exceed
4.0
to 1.0 as of the last day of each fiscal quarter; and
|
•
|
a current ratio, as defined in the Credit Agreement and which includes in the numerator available borrowings undrawn under the borrowing base, of not less than
1.0
to 1.0 as of the last day of each fiscal quarter.
|
Oil Derivative Swaps
(NYMEX WTI Settlements) |
Total Volumes (Bbls)
|
|
Weighted Average Price
|
|||
2018 Contracts
|
|
|
|
|||
1Q18
|
151,000
|
|
|
$
|
52.80
|
|
2Q18
|
140,400
|
|
|
$
|
52.57
|
|
3Q18
|
130,400
|
|
|
$
|
52.40
|
|
4Q18
|
122,800
|
|
|
$
|
52.23
|
|
|
|
|
|
|||
2019 Contracts
|
|
|
|
|||
1Q19
|
97,200
|
|
|
$
|
52.40
|
|
2Q19
|
92,700
|
|
|
$
|
52.32
|
|
3Q19
|
88,500
|
|
|
$
|
52.39
|
|
4Q19
|
84,500
|
|
|
$
|
52.30
|
|
|
|
|
|
|||
2020 Contracts
|
|
|
|
|||
1Q20
|
51,000
|
|
|
$
|
51.49
|
|
2Q20
|
49,250
|
|
|
$
|
51.46
|
|
3Q20
|
47,500
|
|
|
$
|
51.42
|
|
4Q20
|
46,500
|
|
|
$
|
51.40
|
|
Natural Gas Derivative Swaps
(NYMEX Henry Hub Settlements) |
Total Volumes (MMBtu)
|
|
Weighted Average Price
|
|||
|
|
|
|
|||
2018 Contracts
|
|
|
|
|||
1Q18
|
5,238,000
|
|
|
$
|
3.42
|
|
2Q18
|
8,245,000
|
|
|
$
|
2.86
|
|
3Q18
|
8,014,000
|
|
|
$
|
2.88
|
|
4Q18
|
7,976,000
|
|
|
$
|
2.96
|
|
|
|
|
|
|||
2019 Contracts
|
|
|
|
|||
1Q19
|
6,016,000
|
|
|
$
|
3.07
|
|
2Q19
|
6,060,000
|
|
|
$
|
2.83
|
|
3Q19
|
5,550,000
|
|
|
$
|
2.84
|
|
4Q19
|
5,966,000
|
|
|
$
|
2.84
|
|
|
|
|
|
|||
2020 Contracts
|
|
|
|
|||
1Q20
|
5,370,000
|
|
|
$
|
2.83
|
|
2Q20
|
1,170,000
|
|
|
$
|
2.86
|
|
3Q20
|
1,170,000
|
|
|
$
|
2.86
|
|
4Q20
|
1,170,000
|
|
|
$
|
2.86
|
|
NGL Derivative Swaps
(OPIS Settlements) |
Total Volumes (Bbls)
|
|
Weighted Average Price
|
|||
2018 Contracts
|
|
|
|
|||
1Q18
|
126,000
|
|
|
$
|
24.78
|
|
2Q18
|
118,200
|
|
|
$
|
24.78
|
|
3Q18
|
112,200
|
|
|
$
|
24.78
|
|
4Q18
|
148,200
|
|
|
$
|
24.78
|
|
Natural Gas Basis Derivative Swaps
(East Texas Houston Ship Channel Settlements) |
Total Volumes (MMBtu)
|
|
Weighted Average Price
|
|||
2018 Contracts
|
|
|
|
|||
1Q18
|
5,105,000
|
|
|
$
|
(0.11
|
)
|
2Q18
|
6,795,000
|
|
|
$
|
(0.04
|
)
|
3Q18
|
3,020,000
|
|
|
$
|
(0.03
|
)
|
4Q18
|
2,730,000
|
|
|
$
|
(0.09
|
)
|
|
|
|
|
|||
2019 Contracts
|
|
|
|
|||
1Q19
|
750,000
|
|
|
$
|
(0.11
|
)
|
Oil Basis Derivative Swaps
(NYMEX WTI and Argus Settlements) |
Total Volumes (Bbls)
|
|
Weighted Average Price
|
|||
2018 Contracts
|
|
|
|
|||
1Q18
|
20,000
|
|
|
$
|
4.06
|
|
2Q18
|
30,000
|
|
|
$
|
4.06
|
|
3Q18
|
30,000
|
|
|
$
|
4.06
|
|
4Q18
|
30,000
|
|
|
$
|
4.06
|
|
|
Stock Option Valuation Assumptions
|
||
Expected Dividend
|
—
|
|
|
Expected volatility
|
70.3
|
%
|
|
Risk-free interest rate
|
1.99
|
%
|
|
Expected life of stock option awards (in years)
|
5.7
|
|
|
Grant-date market value
|
$
|
27.71
|
|
Grant-date fair value
|
$
|
17.09
|
|
|
Shares
|
|
Wtd. Avg.
Exer. Price
|
|||
|
|
|
|
|||
Options outstanding, beginning of period (successor)
|
105,811
|
|
|
$
|
23.25
|
|
Options granted
|
428,974
|
|
|
$
|
27.71
|
|
Options forfeited
|
(26,055
|
)
|
|
$
|
26.96
|
|
Options canceled
|
—
|
|
|
$
|
—
|
|
Options exercised
|
—
|
|
|
$
|
—
|
|
Options outstanding, end of period (successor)
|
508,730
|
|
|
$
|
26.82
|
|
Options exercisable, end of period (successor)
|
112,338
|
|
|
$
|
25.47
|
|
|
Shares
|
|
Wtd. Avg.
Grant Price |
|||
Restricted units outstanding, beginning of period (successor)
|
178,847
|
|
|
$
|
23.25
|
|
Restricted stock units granted
|
326,532
|
|
|
$
|
28.21
|
|
Restricted stock units forfeited
|
(16,821
|
)
|
|
$
|
26.41
|
|
Restricted stock units vested
|
(141,818
|
)
|
|
$
|
25.15
|
|
Restricted stock units outstanding, end of period (successor)
|
346,740
|
|
|
$
|
26.99
|
|
|
Fair Value Measurements at
|
||||||||||||||
(in millions)
|
Total
|
|
Quoted Prices in
Active markets for
Identical Assets
(Level 1)
|
|
Significant Other
Observable Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
||||||||
December 31, 2017
|
|
|
|
|
|
|
|
||||||||
Assets
|
|
|
|
|
|
|
|
||||||||
Natural Gas Derivatives
|
$
|
7.2
|
|
|
$
|
—
|
|
|
$
|
7.2
|
|
|
$
|
—
|
|
Natural Gas Basis Derivatives
|
$
|
0.3
|
|
|
$
|
—
|
|
|
$
|
0.3
|
|
|
$
|
—
|
|
NGL Derivatives
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
—
|
|
Liabilities
|
|
|
|
|
|
|
|
||||||||
Natural Gas Derivatives
|
$
|
1.3
|
|
|
$
|
—
|
|
|
$
|
1.3
|
|
|
$
|
—
|
|
Natural Gas Basis Derivatives
|
$
|
0.3
|
|
|
$
|
—
|
|
|
$
|
0.3
|
|
|
$
|
—
|
|
Oil Derivatives
|
$
|
5.2
|
|
|
$
|
—
|
|
|
$
|
5.2
|
|
|
$
|
—
|
|
Oil Basis Derivatives
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
—
|
|
NGL Derivatives
|
$
|
0.9
|
|
|
$
|
—
|
|
|
$
|
0.9
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
||||||||
December 31, 2016
|
|
|
|
|
|
|
|
||||||||
Assets
|
|
|
|
|
|
|
|
||||||||
Natural Gas Basis Derivatives
|
$
|
0.4
|
|
|
$
|
—
|
|
|
$
|
0.4
|
|
|
$
|
—
|
|
Liabilities
|
|
|
|
|
|
|
|
||||||||
Natural Gas Derivatives
|
$
|
13.7
|
|
|
$
|
—
|
|
|
$
|
13.7
|
|
|
$
|
—
|
|
Natural Gas Basis Derivatives
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
—
|
|
Oil Derivatives
|
$
|
3.0
|
|
|
$
|
—
|
|
|
$
|
3.0
|
|
|
$
|
—
|
|
Asset Retirement Obligations as of December 31, 2015
|
$
|
63,555
|
|
Accretion expense
|
1,610
|
|
|
Liabilities incurred for new wells and facilities construction
|
1
|
|
|
Reductions due to sold wells and facilities
|
(6,545
|
)
|
|
Reductions due to plugged wells and facilities
|
(85
|
)
|
|
Revisions in estimates
|
488
|
|
|
Asset Retirement Obligations as of April 22, 2016 (Predecessor)
|
$
|
59,024
|
|
Fair value fresh start adjustment
|
5,216
|
|
|
|
|
||
|
|
||
Asset Retirement Obligation as of April 22, 2016 (Successor)
|
$
|
64,240
|
|
Accretion expense
|
2,878
|
|
|
Liabilities incurred for new wells and facilities construction
|
34
|
|
|
Reductions due to sold wells and facilities
|
(42,857
|
)
|
|
Reductions due to plugged wells and facilities
|
(916
|
)
|
|
Revisions in estimates
|
8,877
|
|
|
Asset Retirement Obligations as of December 31, 2016 (Successor)
|
$
|
32,256
|
|
Accretion expense
|
2,322
|
|
|
Liabilities incurred for new wells and facilities construction
|
253
|
|
|
Reductions due to sold wells and facilities
|
(21,466
|
)
|
|
Reductions due to plugged wells and facilities
|
(2,366
|
)
|
|
Revisions in estimates
|
(212
|
)
|
|
Asset Retirement Obligations as of December 31, 2017 (Successor)
|
$
|
10,787
|
|
•
|
the approximately
$906 million
of indebtedness outstanding on account of the Company’s senior notes,
$75 million
in borrowings under the Company's DIP Credit Agreement (described below) and certain other unsecured claims were exchanged for
88.5%
of the post-emergence Company’s common stock;
|
•
|
the lenders under the DIP Credit Agreement (as defined and more fully described below) received an additional backstop fee consisting of
7.5%
of the post-emergence Company’s common stock;
|
•
|
the Company’s pre-petition common stock was canceled and the current shareholders received
4%
of the post-emergence Company’s common stock and warrants to purchase up to
30%
of the reorganized Company's equity. See Note 13 of these consolidated financial statements for more information;
|
•
|
claims of other creditors were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditors;
|
•
|
the Company entered into a registration rights agreement to provide customary registration rights to certain holders of the Company’s post-emergence common stock who, together with their affiliates received upon emergence
5%
or more of the outstanding common stock of the Company;
|
•
|
the Company sold (effective April 15, 2016) a portion of its interest in its Central Louisiana fields known as Burr Ferry and South Bearhead Creek to Texegy LLC, for net proceeds of approximately
$46.9 million
including deposits received prior to the closing date; and
|
•
|
the Company's previous credit facility (the "Prior First Lien Credit Facility") was terminated and a new senior secured credit facility (defined herein as "Credit Facility") with an initial
$320 million
borrowing base was established. For more information refer to Note 4 of these consolidated financial statements.
|
|
April 22, 2016
|
||
Enterprise Value
|
$
|
473,660
|
|
Plus: Cash and cash equivalents
|
8,739
|
|
|
Less: Fair value of debt
|
(253,000
|
)
|
|
Less: Fair value of warrants
|
(14,967
|
)
|
|
Fair value of Successor common stock
|
$
|
214,432
|
|
|
|
||
Shares outstanding at April 22, 2016
|
10,000
|
|
|
|
|
||
Per share value
|
$
|
21.44
|
|
|
April 22, 2016
|
||
Enterprise Value
|
$
|
473,660
|
|
Plus: Cash and cash equivalents
|
8,739
|
|
|
Plus: Other working capital liabilities
|
73,318
|
|
|
Plus: Other long-term liabilities
|
58,992
|
|
|
Reorganization value of Successor assets
|
$
|
614,709
|
|
|
Predecessor Company
|
|
Reorganization Adjustments
|
|
Fresh Start Adjustments
|
|
Successor Company
|
||||||||
ASSETS
|
|
|
|
|
|
|
|
||||||||
Current Assets:
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
57,599
|
|
|
$
|
(48,860
|
)
|
(1)
|
$
|
—
|
|
|
$
|
8,739
|
|
Accounts receivable
|
34,278
|
|
|
(597
|
)
|
(2)
|
—
|
|
|
33,681
|
|
||||
Other current assets
|
3,503
|
|
|
—
|
|
|
—
|
|
|
3,503
|
|
||||
Total current assets
|
95,380
|
|
|
(49,457
|
)
|
|
—
|
|
|
45,923
|
|
||||
Property and equipment
|
6,007,326
|
|
|
—
|
|
|
(5,448,759
|
)
|
(12)
|
558,567
|
|
||||
Less - accumulated depreciation, depletion and amortization
|
(5,676,252
|
)
|
|
—
|
|
|
5,676,252
|
|
(12)
|
—
|
|
||||
Property and equipment, net
|
331,074
|
|
|
—
|
|
|
227,493
|
|
|
558,567
|
|
||||
Other Long-Term Assets
|
4,629
|
|
|
6,388
|
|
(3)
|
(798
|
)
|
(13)
|
10,219
|
|
||||
Total Assets
|
$
|
431,083
|
|
|
$
|
(43,069
|
)
|
|
$
|
226,695
|
|
|
$
|
614,709
|
|
|
Predecessor Company
|
|
Reorganization Adjustments
|
|
Fresh Start Adjustments
|
|
Successor Company
|
|||||||||
LIABILITIES AND STOCKHOLDERS' EQUITY
|
|
|
|
|
|
|
|
|||||||||
Current Liabilities:
|
|
|
|
|
|
|
|
|||||||||
Accounts payable and accrued liabilities
|
$
|
64,324
|
|
|
$
|
(4,666
|
)
|
(4)
|
$
|
(885
|
)
|
(14
|
)
|
$
|
58,773
|
|
Accrued capital costs
|
5,410
|
|
|
—
|
|
|
—
|
|
|
5,410
|
|
|||||
Accrued interest
|
768
|
|
|
(104
|
)
|
(5)
|
—
|
|
|
664
|
|
|||||
Undistributed oil and gas revenues
|
8,471
|
|
|
—
|
|
|
—
|
|
|
8,471
|
|
|||||
Current portion of debt
|
364,500
|
|
|
(364,500
|
)
|
(6)
|
—
|
|
|
—
|
|
|||||
Total current liabilities
|
443,473
|
|
|
(369,270
|
)
|
|
(885
|
)
|
|
73,318
|
|
|||||
|
|
|
|
|
|
|
|
|||||||||
Long-Term Debt
|
—
|
|
|
253,000
|
|
(7)
|
—
|
|
|
253,000
|
|
|||||
Asset retirement obligation
|
51,800
|
|
|
—
|
|
|
6,101
|
|
(14
|
)
|
57,901
|
|
||||
Other long-term liabilities
|
2,124
|
|
|
—
|
|
|
(1,033
|
)
|
(15
|
)
|
1,091
|
|
||||
Liabilities subject to compromise
|
911,381
|
|
|
(911,381
|
)
|
(8)
|
—
|
|
|
—
|
|
|||||
Total Liabilities
|
1,408,778
|
|
|
(1,027,651
|
)
|
|
4,183
|
|
|
385,310
|
|
|||||
Stockholders' Equity:
|
|
|
|
|
|
|
|
|||||||||
Preferred stock
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Common stock (Predecessor)
|
450
|
|
|
(450
|
)
|
(9)
|
—
|
|
|
—
|
|
|||||
Common stock (Successor)
|
—
|
|
|
100
|
|
(10)
|
—
|
|
|
100
|
|
|||||
Additional paid-in capital (Predecessor)
|
777,475
|
|
|
(777,475
|
)
|
(9)
|
—
|
|
|
—
|
|
|||||
Additional paid-in capital (Successor)
|
—
|
|
|
229,299
|
|
(10)
|
—
|
|
|
229,299
|
|
|||||
Treasury stock held at cost
|
(2,496
|
)
|
|
2,496
|
|
(9)
|
—
|
|
|
—
|
|
|||||
Retained earnings (accumulated deficit)
|
(1,753,124
|
)
|
|
1,530,612
|
|
(11)
|
222,512
|
|
(16
|
)
|
—
|
|
||||
Total Stockholders' Equity (Deficit)
|
(977,695
|
)
|
|
984,582
|
|
|
222,512
|
|
|
229,399
|
|
|||||
Total Liabilities and Stockholders' Equity
|
$
|
431,083
|
|
|
$
|
(43,069
|
)
|
|
$
|
226,695
|
|
|
$
|
614,709
|
|
1.
|
Reflects the net cash payments recorded as of the Effective Date from implementation of the Plan (in thousands):
|
Sources:
|
|
||
Net proceeds from Credit Facility
|
253,000
|
|
|
Total Sources
|
$
|
253,000
|
|
Uses:
|
|
||
Repayment of Prior First Lien Credit Facility
|
289,500
|
|
|
Debt issuance costs
|
6,482
|
|
|
Predecessor accounts payable paid upon emergence
|
5,878
|
|
|
Total Uses
|
$
|
301,860
|
|
Net Uses
|
$
|
(48,860
|
)
|
2.
|
Reflects the impairment of a short-term leasehold improvement build-out receivable for
$0.6 million
that will no longer be reimbursed by the building lessor as the Company's office lease contract was rejected as part of the bankruptcy.
|
3.
|
Reflects the capitalization of debt issuance costs on the Credit Facility for
$7.0 million
, of which
$6.5 million
was paid on emergence and
$0.5 million
included in accounts payable and accrued liabilities and paid in the subsequent month, as well as the write-off of a long-term leasehold improvement build-out receivable for
$0.6 million
relating to an office lease contract that was rejected in connection with the bankruptcy.
|
4.
|
Reflects the settlement of predecessor accounts payable of
$5.2 million
partially offset by accrued debt issuance costs of
$0.5 million
.
|
5.
|
Reflects the settlement of accrued interest on the Company's DIP Credit Agreement which was equitized upon emergence.
|
6.
|
On the Effective Date, the Company repaid in full all borrowings outstanding of
$289.5 million
under the Prior First Lien Credit Facility. In addition the Company equitized the outstanding DIP Credit Agreement borrowings of
$75 million
via the issuance of equity valued at
$142.3 million
.
|
7.
|
Reflects the
$253 million
in new borrowings under the Credit Facility.
|
8.
|
Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands):
|
|
|
||
7.125% senior notes due 2017
|
$
|
250,000
|
|
8.875% senior notes due 2020
|
225,000
|
|
|
7.875% senior notes due 2022
|
400,000
|
|
|
Accrued interest
|
30,043
|
|
|
Accounts payable and accrued liabilities
|
1,713
|
|
|
Other long-term liabilities
|
4,625
|
|
|
Liabilities subject to compromise of the Predecessor Company (LSTC)
|
911,381
|
|
|
Fair value of equity issued to former holders of the senior notes of the Predecessor
|
(47,443
|
)
|
|
Gain on settlement of Liabilities subject to compromise
|
$
|
863,938
|
|
9.
|
Reflects the cancellation of the Predecessor Company equity to retained earnings.
|
10.
|
Reflects the issuance of
10.0 million
shares of common stock at a per share price of
$21.44
and
4.3 million
warrants to purchase up to
30%
of the reorganized Company's equity valued at
$15.0 million
with an average per unit value of
$3.49
. Former holders of the senior notes and certain unsecured creditors were issued
8.85 million
shares of common stock while the Backstop
|
11.
|
Reflects the cumulative impact of the reorganization adjustments discussed above (in thousands):
|
|
|
||
Gain on settlement of Liabilities subject to compromise
|
$
|
863,938
|
|
Fair value of equity issued in excess of DIP principal
|
(67,329
|
)
|
|
Fair value of equity and warrants issued to Predecessor stockholders
|
(23,544
|
)
|
|
Fair value of equity issued to DIP lenders for backstop fee
|
(16,082
|
)
|
|
Other reorganization adjustments
|
(1,800
|
)
|
|
Cancellation of Predecessor Company equity
|
775,429
|
|
|
Net impact to accumulated deficit
|
$
|
1,530,612
|
|
12.
|
The following table summarizes the fair value adjustment on our oil and gas properties and accumulated depletion, depreciation and amortization (in thousands):
|
|
Predecessor Company
|
Fresh Start Adjustments
|
Successor Company
|
||||||
Oil and Gas Properties
|
|
|
|
||||||
Proved properties
|
$
|
5,951,016
|
|
$
|
(5,441,655
|
)
|
$
|
509,361
|
|
Unproved properties
|
12,057
|
|
33,448
|
|
45,505
|
|
|||
Total Oil and Gas Properties
|
5,963,073
|
|
(5,408,207
|
)
|
554,866
|
|
|||
Less - Accumulated depletion and impairments
|
(5,638,741
|
)
|
5,638,741
|
|
—
|
|
|||
Net Oil and Gas Properties
|
324,332
|
|
230,534
|
|
554,866
|
|
|||
|
|
|
|
||||||
Furniture, Fixtures, and other equipment
|
44,252
|
|
(40,551
|
)
|
3,701
|
|
|||
Less - Accumulated depreciation
|
(37,510
|
)
|
37,510
|
|
—
|
|
|||
Net Furniture, Fixtures and other equipment
|
$
|
6,742
|
|
$
|
(3,041
|
)
|
$
|
3,701
|
|
Net Oil and Gas Properties, Furniture and fixtures and accumulated depreciation
|
$
|
331,074
|
|
$
|
227,493
|
|
$
|
558,567
|
|
13.
|
Reflects the adjustment of other non-current assets to fair value.
|
14.
|
Reflects the current and long-term portion of the Company’s asset retirement obligation computed in accordance with ASC 410-20, applying the appropriate discount rate to future costs as of the emergence date.
|
15.
|
Reflects the adjustment of other non-current liabilities to fair value.
|
16.
|
Reflects the cumulative impact of fresh start adjustments as discussed above.
|
|
Successor
|
|
|
Predecessor
|
Predecessor
|
||||||
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
Year Ended December 31, 2015
|
||||||
Gain on settlement of liabilities subject to compromise
|
$
|
—
|
|
|
|
$
|
(863,938
|
)
|
$
|
—
|
|
Fair value of equity issued in excess of DIP principal
|
—
|
|
|
|
67,329
|
|
—
|
|
|||
Fresh start adjustments
|
—
|
|
|
|
(222,512
|
)
|
—
|
|
|||
Reorganization legal and professional fees and expenses
|
1,598
|
|
|
|
25,573
|
|
—
|
|
|||
Fair value of equity issued to DIP lenders for backstop fee
|
—
|
|
|
|
16,082
|
|
—
|
|
|||
Write-off of debt issuance costs, including premium and discount on senior notes
|
—
|
|
|
|
—
|
|
6,565
|
|
|||
Other reorganization items
|
41
|
|
|
|
21,324
|
|
—
|
|
|||
(Gain) Loss on Reorganization items, net
|
$
|
1,639
|
|
|
|
$
|
(956,142
|
)
|
$
|
6,565
|
|
|
Total
|
||
December 31, 2017
|
|
||
Proved oil and gas properties
|
$
|
658,519
|
|
Unproved oil and gas properties
|
50,377
|
|
|
|
708,896
|
|
|
Accumulated depreciation, depletion, amortization and impairment
|
(215,480
|
)
|
|
Net capitalized costs
|
$
|
493,416
|
|
|
|
||
December 31, 2016
|
|
||
Proved oil and gas properties
|
$
|
480,499
|
|
Unproved oil and gas properties
|
33,354
|
|
|
|
513,853
|
|
|
Accumulated depreciation, depletion, amortization and impairment
|
(169,335
|
)
|
|
Net capitalized costs
|
$
|
344,518
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended December 31, 2017
|
|
Period from April 23, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through April 22, 2016
|
|
Year Ended December 31, 2015
|
||||||||
|
|
|
|
|||||||||||||
Lease acquisitions and prospect costs
|
$
|
44,569
|
|
|
$
|
6,466
|
|
|
|
$
|
2,695
|
|
|
$
|
28,571
|
|
Exploration
|
—
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||
Development
(1) (3)
|
149,293
|
|
|
40,908
|
|
|
|
24,082
|
|
|
74,948
|
|
||||
Acquisition of property
|
9,426
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||
Total acquisition, exploration, and development
(2)
|
$
|
203,288
|
|
|
$
|
47,374
|
|
|
|
$
|
26,777
|
|
|
$
|
103,519
|
|
Estimates of Proved Reserves
|
Total
|
|
Natural Gas
|
|
Oil
|
|
NGL
|
||||
|
(Mcfe)
|
|
(Mcf)
|
|
(Bbls)
|
|
(Bbls)
|
||||
Proved reserves as of December 31, 2015
|
421,638,060
|
|
|
311,688,398
|
|
|
10,108,833
|
|
|
8,216,111
|
|
Extensions, discoveries, and other additions
(3)
|
92,804,898
|
|
|
92,804,900
|
|
|
—
|
|
|
—
|
|
Revisions of previous estimates
(1)
|
326,679,690
|
|
|
270,749,891
|
|
|
1,821,443
|
|
|
7,500,190
|
|
Sales of minerals in place
(4)
|
(42,349,578
|
)
|
|
(7,915,022
|
)
|
|
(4,844,064
|
)
|
|
(895,030
|
)
|
Production
|
(55,031,868
|
)
|
|
(40,539,807
|
)
|
|
(1,308,521
|
)
|
|
(1,106,822
|
)
|
|
|
|
|
|
|
|
|
||||
Proved reserves as of December 31, 2016
|
743,741,202
|
|
|
626,788,360
|
|
|
5,777,691
|
|
|
13,714,449
|
|
Extensions, discoveries, and other additions
(3)
|
317,023,521
|
|
|
250,063,107
|
|
|
2,054,571
|
|
|
9,105,498
|
|
Revisions of previous estimates
(1)
|
(8,747,628
|
)
|
|
(8,711,753
|
)
|
|
29,178
|
|
|
(34,045
|
)
|
Purchases of minerals in place
|
33,405,229
|
|
|
23,499,391
|
|
|
51,275
|
|
|
1,599,698
|
|
Sales of minerals in place
(4)
|
(4,866,078
|
)
|
|
(3,158,892
|
)
|
|
(68,350
|
)
|
|
(216,181
|
)
|
Production
|
(56,134,862
|
)
|
|
(45,745,137
|
)
|
|
(684,670
|
)
|
|
(1,048,063
|
)
|
|
|
|
|
|
|
|
|
||||
Proved reserves as of December 31, 2017
|
1,024,421,384
|
|
|
842,735,076
|
|
|
7,159,695
|
|
|
23,121,356
|
|
|
|
|
|
|
|
|
|
||||
Proved developed reserves
(2)
:
|
|
|
|
|
|
|
|
||||
December 31, 2015
|
338,005,854
|
|
|
238,355,707
|
|
|
10,108,833
|
|
|
6,499,524
|
|
December 31, 2016
|
378,233,832
|
|
|
312,125,091
|
|
|
4,512,842
|
|
|
6,505,282
|
|
December 31, 2017
|
458,252,677
|
|
|
377,504,768
|
|
|
5,026,398
|
|
|
8,431,587
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves
|
|
|
|
|
|
|
|
||||
December 31, 2015
|
83,632,206
|
|
|
73,332,691
|
|
|
—
|
|
|
1,716,587
|
|
December 31, 2016
|
365,507,610
|
|
|
314,663,510
|
|
|
1,264,849
|
|
|
7,209,167
|
|
December 31, 2017
|
566,168,707
|
|
|
465,230,305
|
|
|
2,133,297
|
|
|
14,689,769
|
|
|
As of December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Future gross revenues
|
$
|
3,319,101
|
|
|
$
|
1,980,642
|
|
|
$
|
1,434,931
|
|
Future production costs
|
(1,027,860
|
)
|
|
(750,823
|
)
|
|
(688,427
|
)
|
|||
Future development costs
(1)
|
(529,088
|
)
|
|
(365,064
|
)
|
|
(280,252
|
)
|
|||
Future net cash flows before income taxes
|
1,762,153
|
|
|
864,755
|
|
|
466,252
|
|
|||
Future income taxes
|
(237,396
|
)
|
|
(88,775
|
)
|
|
(297
|
)
|
|||
Future net cash flows after income taxes
|
1,524,757
|
|
|
775,980
|
|
|
465,955
|
|
|||
Discount at 10% per annum
|
(793,230
|
)
|
|
(368,987
|
)
|
|
(92,190
|
)
|
|||
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
|
$
|
731,527
|
|
|
$
|
406,993
|
|
|
$
|
373,765
|
|
|
2017
|
|
2016
|
|
2015
|
||||||
Beginning balance
|
$
|
406,993
|
|
|
$
|
373,765
|
|
|
$
|
1,651,674
|
|
|
|
|
|
|
|
||||||
Revisions to reserves proved in prior years:
|
|
|
|
|
|
||||||
Net changes in prices, net of production costs
|
204,445
|
|
|
(46,553
|
)
|
|
(2,018,065
|
)
|
|||
Net changes in future development costs
|
35,735
|
|
|
(152,600
|
)
|
|
817,324
|
|
|||
Net changes due to revisions in quantity estimates
|
(8,926
|
)
|
|
264,124
|
|
|
(599,342
|
)
|
|||
Accretion of discount
|
44,193
|
|
|
33,327
|
|
|
194,326
|
|
|||
Other
|
27,056
|
|
|
28,888
|
|
|
119,483
|
|
|||
Total revisions
|
302,503
|
|
|
127,186
|
|
|
(1,486,274
|
)
|
|||
|
|
|
|
|
|
||||||
New field discoveries and extensions, net of future production and development costs
|
121,117
|
|
|
75,034
|
|
|
3,025
|
|
|||
Purchase of reserves
|
11,491
|
|
|
—
|
|
|
—
|
|
|||
Sales of minerals in place
|
(1,953
|
)
|
|
(76,327
|
)
|
|
—
|
|
|||
Sales of oil and gas produced, net of production costs
|
(146,471
|
)
|
|
(93,945
|
)
|
|
(137,251
|
)
|
|||
Previously estimated development costs incurred
|
75,968
|
|
|
36,218
|
|
|
51,149
|
|
|||
Net change in income taxes
|
(38,121
|
)
|
|
(34,938
|
)
|
|
291,442
|
|
|||
Net change in standardized measure of discounted future net cash flows
|
324,534
|
|
|
33,228
|
|
|
(1,277,909
|
)
|
|||
Ending balance
|
$
|
731,527
|
|
|
$
|
406,993
|
|
|
$
|
373,765
|
|
|
Oil and Gas Sales
|
|
Net Income (Loss) Before Taxes
|
|
Net Income (Loss)
|
|
Basic EPS
|
|
Diluted EPS
|
||||||||||
2017 (Successor)
|
|
|
|
|
|
|
|
|
|
||||||||||
First
|
$
|
42,412
|
|
|
$
|
17,710
|
|
|
$
|
17,710
|
|
|
$
|
1.58
|
|
|
$
|
1.57
|
|
Second
|
45,785
|
|
|
16,241
|
|
|
16,241
|
|
|
1.41
|
|
|
1.41
|
|
|||||
Third
|
49,019
|
|
|
12,884
|
|
|
12,884
|
|
|
1.12
|
|
|
1.12
|
|
|||||
Fourth
|
58,694
|
|
|
23,182
|
|
|
25,136
|
|
|
2.17
|
|
|
2.17
|
|
|||||
Total
|
$
|
195,910
|
|
|
$
|
70,017
|
|
|
$
|
71,971
|
|
|
$
|
6.28
|
|
|
$
|
6.25
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
January 1 - April 22, 2016 (Predecessor)
|
|
|
|
|
|
|
|
|
|
||||||||||
First
(1)
|
$
|
34,367
|
|
|
$
|
(108,303
|
)
|
|
$
|
(108,303
|
)
|
|
$
|
(2.42
|
)
|
|
$
|
(2.42
|
)
|
April 1 - April 22, 2016
|
8,660
|
|
|
959,914
|
|
|
959,914
|
|
|
21.45
|
|
|
21.03
|
|
|||||
Total
|
$
|
43,027
|
|
|
$
|
851,611
|
|
|
$
|
851,611
|
|
|
$
|
19.06
|
|
|
$
|
18.64
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
April 23 - December 31, 2016 (Successor)
|
|
|
|
|
|
|
|
|
|
||||||||||
April 23 - June 30, 2016
(1)
|
$
|
30,581
|
|
|
$
|
(149,601
|
)
|
|
$
|
(149,601
|
)
|
|
$
|
(14.96
|
)
|
|
$
|
(14.96
|
)
|
Third
|
47,959
|
|
|
394
|
|
|
394
|
|
|
0.04
|
|
|
0.04
|
|
|||||
Fourth
|
42,846
|
|
|
(7,081
|
)
|
|
(7,081
|
)
|
|
(0.71
|
)
|
|
(0.71
|
)
|
|||||
Total
|
$
|
121,386
|
|
|
$
|
(156,288
|
)
|
|
$
|
(156,288
|
)
|
|
$
|
(15.61
|
)
|
|
$
|
(15.61
|
)
|
Management's Report on Internal Control Over Financial Reporting
|
|
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
|
|
Reports of Independent Registered Public Accounting Firms
|
|
Consolidated Balance Sheets
|
|
Consolidated Statements of Operations
|
|
Consolidated Statements of Stockholders' Equity (Deficit)
|
|
Consolidated Statements of Cash Flows
|
|
Notes to Consolidated Financial Statements
|
3.1
|
|
|
|
3.2
|
|
|
|
4.1
|
|
|
|
4.2
|
|
|
|
4.3
|
|
|
|
4.4
|
|
|
|
10.1
|
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10.2*
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10.3
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10.4
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10.5
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10.6
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10.7
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10.8+
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10.9+
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10.10+
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10.11+
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10.12+
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10.13+
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10.14+
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10.15+
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10.16+
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10.17+
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10.18+
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10.19+
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10.20+
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10.21+
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10.22+
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10.23+
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10.24+
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10.25+
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10.26+
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10.27+
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10.28+*
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16
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21 *
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23.1 *
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23.2 *
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23.3*
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31.1 *
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31.2*
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32*
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99.1*
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101.INS*
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XBRL Instance Document
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101.SCH*
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XBRL Schema Document
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101.CAL*
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XBRL Calculation Linkbase Document
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101.LAB*
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XBRL Label Linkbase Document
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101.PRE*
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XBRL Presentation Linkbase Document
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101.DEF*
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XBRL Definition Linkbase Document
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SILVERBOW RESOURCES, INC.
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By: /s/ Sean C. Woolverton
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Sean C. Woolverton
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Chief Executive Officer
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Signatures
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Title
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Date
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/s/ Sean C. Woolverton
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Chief Executive Officer
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March 1, 2018
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Sean C. Woolverton
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Executive Vice President
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/s/ G. Gleeson Van Riet
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and Chief Financial Officer
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March 1, 2018
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G. Gleeson Van Riet
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/s/ Gary G. Buchta
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Controller
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March 1, 2018
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Gary G. Buchta
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Chairman of the Board
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/s/Marcus C. Rowland
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Director
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March 1, 2018
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Marcus C. Rowland
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/s/ Michael Duginski
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Director
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March 1, 2018
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Michael Duginski
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/s/ Gabriel L. Ellisor
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Director
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March 1, 2018
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Gabriel L. Ellisor
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/s/ David Geenberg
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Director
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March 1, 2018
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David Geenberg
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/s/ Christoph O. Majeske
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Director
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March 1, 2018
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Christoph O. Majeske
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/s/ Charles W. Wampler
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Director
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March 1, 2018
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Charles W. Wampler
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(i)
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the Borrower incurs the Proposed Debt Incurrence within the Incurrence Window,
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(ii)
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the aggregate principal amount of the Proposed Debt Incurrence is within the Incurrence Range, and
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(iii)
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the Proposed Debt Incurrence constitutes (A) Permitted Second Lien Debt if the Proposed Debt Incurrence is secured and (B) Permitted Unsecured Debt if the Proposed Debt Incurrence is unsecured.
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BORROWER:
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SILVERBOW RESOURCES, INC.
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GUARANTOR:
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SILVERBOW RESOURCES OPERATING, LLC
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GUARANTOR:
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SILVERBOW RESOURCES USA, INC.
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LENDER:
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COMPASS BANK
, as a Lender
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LENDER:
|
SUNTRUST BANK
, as a Lender
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LENDER:
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Canadian Imperial Bank of Commerce, New
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LENDER:
|
FIFTH THIRD BANK
, as a Lender
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LENDER:
|
BRANCH BANKING AND TRUST
, as a Lender
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LENDER:
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COMERCIA BANK
, as a Lender
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LENDER:
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Credit Suisse AG, Cayman Islands Branch
, as a
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LENDER:
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KeyBank, National Association
, as a Lender
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LENDER:
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Associated Bank, N.A.
, as a Lender
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LENDER:
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Whitney Bank
, as a Lender
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Name of Lender
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Applicable Percentage
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Maximum Credit Amount
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JPMORGAN CHASE BANK, N.A.
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10.67567567333330%
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$64,054,054.04
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COMPASS BANK
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9.18918919000000%
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$55,135,135.14
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SUNTRUST BANK
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9.18918919000000%
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$55,135,135.14
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BOKF, N.A. DBA BANK OF TEXAS
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9.18918919000000%
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$55,135,135.14
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CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK BRANCH
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9.18918919000000%
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$55,135,135.14
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FIFTH THIRD BANK
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9.18918919000000%
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$55,135,135.14
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BRANCH BANKING AND TRUST COMPANY
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8.37837837833334%
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$50,270,270.27
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COMERICA BANK
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8.37837837833334%
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$50,270,270.27
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CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH
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8.37837837833334%
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$50,270,270.27
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KEYBANK N.A.
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7.43243243166667%
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$44,594,594.59
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ASSOCIATED BANK, N.A.
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5.40540540500000%
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$32,432,432.43
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WHITNEY BANK
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5.40540540500000%
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$32,432,432.43
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TOTAL
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100.00000000000000%
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$600,000,000.00
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SILVERBOW RESOURCES, INC.
525 N. Dairy Ashford, Ste. 1200
Houston, TX 77079
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By:
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_____________________
_____________________
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H.J. GRUY AND ASSOCIATES, INC.
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By:
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/
s
/
Marilyn Wilson
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Marilyn Wilson, P.E.
President and Chief Executive Officer
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1.
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I have reviewed this Annual Report on Form 10-K for the period ended December 31, 2017, of SilverBow Resources, Inc. (the "registrant");
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2.
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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;
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3.
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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;
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4.
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The registrant's other certifying officer 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:
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(a)
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Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
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(b)
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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;
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(c)
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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
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(d)
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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
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5.
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The registrant's other certifying officer 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):
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(a)
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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
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(b)
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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.
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Date:
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March 1, 2018
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/s/Sean C. Woolverton
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|
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Sean C. Woolverton
Chief Executive Officer
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1.
|
I have reviewed this Annual Report on Form 10-K for the period ended December 31, 2017, of SilverBow Resources, Inc. (the "registrant");
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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;
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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;
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4.
|
The registrant's other certifying officer 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:
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(a)
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Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
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(b)
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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;
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(c)
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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
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(d)
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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
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5.
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The registrant's other certifying officer 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):
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(a)
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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
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(b)
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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.
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Date:
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March 1, 2018
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/s/ G. Gleeson Van Riet
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G. Gleeson Van Riet Executive Vice President and Chief Financial Officer
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1.
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The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
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2.
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The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Swift.
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Date:
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March 1, 2018
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/s/ Sean C. Woolverton
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|
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Sean C. Woolverton
Chief Executive Officer
|
Date:
|
March 1, 2018
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/s/ G. Gleeson Van Riet
|
|
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G. Gleeson Van Riet
Executive Financial President and Chief Financial Officer
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Proved Reserves
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|||||||||||||
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|||||||
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Estimated
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Estimated
|
||||||||||
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Net Reserves
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Future Net Cash Flow
|
||||||||||
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Natural
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Discounted
|
|||||||
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Oil
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Gas
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Gas Liquids
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Not
|
at 10 Percent
|
|||||||
|
(Barrels)
|
(Mcf)
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(Barrels)
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Discounted
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Per Year
|
|||||||
Proved Producing
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4,865,173
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372,091,939
|
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8,050,637
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$
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898,445,093
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$
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470,752,668
|
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Proved Nonproducing
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161,225
|
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5,412,830
|
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380,950
|
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$
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14,129,113
|
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$
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6,367,990
|
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Proved Undeveloped
|
2,133,297
|
|
465,230,305
|
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14,689,769
|
|
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$
|
924,542,197
|
|
$
|
334,616,313
|
|
|
|
|
|
|
|
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|||||||
Total Proved
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7,159,695
|
|
842,735,074
|
|
23,121,356
|
|
|
$
|
1,837,116,403
|
|
$
|
811,736,971
|
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1.
|
I am President of H.J. Gruy and Associates, Inc, and I am the engineer responsible for the estimates of reserves, future production, and future income determined by H.J. Gruy and Associates, Inc. and preparation of the reserves report for Swift Energy Company effective December 31, 2017, and dated January 26, 2018, attached herewith.
|
2.
|
I hold a Bachelor of Science Degree in Petroleum Engineering from Texas A&M University, and I am a Licensed Professional Engineer in the State of Texas, License Number 59498. I am a member of the Society of Petroleum Engineers, and I am a past President and member of the Society of Petroleum Evaluation Engineers. I have over 30 years of experience in the evaluation of oil and gas reserves.
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3.
|
Based on my educational and professional background, I meet or exceed the professional qualifications as a Reserves Estimator presented in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers.
|