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Section 1: 10-K (2017 10-K)

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 2017

Commission File Number 1-8754
392412102_sbowlogoa04.jpg
SILVERBOW RESOURCES, INC.
(Exact Name of Registrant as Specified in Its Charter)
Delaware
(State of Incorporation)
20-3940661
(I.R.S. Employer Identification No.)
 
 
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:

Title of Class
Exchanges on Which Registered:
Common Stock, par value $.01 per share
New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes
o
No
þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.
Yes
o
No
þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days.
Yes
þ
No
o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes
þ
No
o


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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definition of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
o
 
Accelerated filer
þ
 
Non-accelerated filer
 o
 
Smaller reporting company
 o
Emerging Growth Company
o
 
 
 
 
 
 
 
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
o
 
 
 
 
 
 
 
 
 
 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes
o
No
þ

The aggregate public float of common equity held by non-affiliates computed by reference to the price at which the common equity was last sold as quoted on the New York Stock Exchange as of June 30, 2017, the last business day of June 2017, was approximately $86,619,851.

The number of shares of common stock outstanding as of February 26, 2018 was 11,616,482.

Explanatory Note

SilverBow Resources, Inc. was formerly known as Swift Energy Company. On May 5, 2017, through amendments to its Certificate of Incorporation and Bylaws, Swift Energy Company changed its name to SilverBow Resources, Inc. Additionally, SilverBow Resources, Inc. began trading on the New York Stock Exchange (“NYSE”) under the ticker symbol “SBOW” on May 5, 2017.




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Form 10-K
SilverBow Resources, Inc. and Subsidiaries

10-K Part and Item No.
Part I
 
Page
 
 
 
Items 1 & 2
Business and Properties
 
 
 
Item 1A.
Risk Factors
 17
 
 
 
Item 1B.
Unresolved Staff Comments
 
 
 
Item 3.
Legal Proceedings
 
 
 
Item 4.
Mine Safety Disclosures
 
 
 
Part II
 
 
 
 
 
Item 5.
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
 
 
Item 6.
Selected Financial Data
 
 
 
Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
 
 
 
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
 
 
 
Item 8.
Financial Statements and Supplementary Data
 
 
 
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
 
 
 
Item 9A.
Controls and Procedures
 
 
 
Item 9B.
Other Information
 
 
 
Part III
 
 
 
 
 
Item 10.
Directors, Executive Officers and Corporate Governance
 
 
 
Item 11.
Executive Compensation
 
 
 
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters
 
 
 
Item 13.
Certain Relationships and Related Transactions, and Director Independence
 
 
 
Item 14.
Principal Accountant Fees and Services
 
 
 
Part IV
 
 
 
 
 
Item 15.
Exhibits and Financial Statement Schedules




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Items 1 and 2. Business and Properties

As used in this Annual Report on Form 10-K, unless the context otherwise requires or indicates, references to “SilverBow Resources,” “the Company,” “we,” “our,” “ours” and “us” refer to SilverBow Resources, Inc. See pages 29 and 30 for explanations of abbreviations and terms used herein.

Overview

SilverBow Resources is a growth oriented independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford Shale located in South Texas where we have assembled over 100,000 net acres across five operating areas. Our acreage positions in each of our operating areas are highly contiguous and designed for optimal and efficient horizontal well development. We have built a balanced portfolio of properties with a significant base of current production and reserves coupled with low-risk development drilling opportunities and meaningful upside from newer areas. We produced an average of 177 MMcfe per day during the fourth quarter of 2017 and had proved reserves of 1,024 MMcfe (82% natural gas) with a PV-10 of $805 million as of December 31, 2017. PV-10 Value is a non-GAAP measure, see the section titled “Oil and Natural Gas Reserves” of this Form 10-K for a reconciliation of this non-GAAP measure to the standardized measure of discounted future net cash flows, the most directly comparable GAAP measure.
 
Being a committed and long-term operator in South Texas, the Company possesses a significant understanding of the reservoir characteristics, geology, landowners, and competitive landscape in the region. We leverage this in-depth knowledge to continue to assemble high quality drilling inventory while continuously enhancing our operations to maximize returns on capital invested.

We have transformed the Company from a conventional, Louisiana shallow water producer to a focused Eagle Ford player. Over the last few years we have successfully renegotiated midstream contracts, moved our headquarters to west Houston, and reduced headcount over 50% since 2015. These initiatives have resulted in a reduction of per unit G&A from $0.64/Mcfe at year end 2015 to $0.53/Mcfe at year end 2017, a 17% reduction. We expect to continue improving our G&A metrics as we execute on our strategic growth program. We continue to refine our portfolio, including the sale of certain AWP Olmos wells on March 1, 2018. This strategic divestiture allows us to better leverage existing personnel while lowering field-level costs on a per unit basis. We believe there are other opportunities to continue streamlining our business to extract value for our shareholders.

Emergence from Voluntary Reorganization under Chapter 11 Proceedings

On December 31, 2015, we and eight of our U.S. subsidiaries (the "Chapter 11 Subsidiaries") filed voluntary petitions seeking relief under Chapter 11 of Title 11 of the U.S. Bankruptcy Code (the "Bankruptcy Code") in the U.S. Bankruptcy Court for the District of Delaware under the caption In re Swift Energy Company, et al (Case No. 15-12670). The Company and the Chapter 11 Subsidiaries received bankruptcy court confirmation of their joint plan of reorganization (the "Plan") on March 31, 2016, and subsequently emerged from bankruptcy on April 22, 2016 (the "Effective Date"). References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to April 22, 2016. References to “Predecessor” or “Predecessor Company” refer to the financial position and results of operations of the Company prior to and including April 22, 2016. For a further description of these matters, see Notes 12 and 13 in our Consolidated Financial Statements in this Form 10-K.

Business Strategies

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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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.

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.

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.

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.

Our Competitive Strengths

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.

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.

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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higher price realizations when compared to other natural gas plays, such as those in the Marcellus and the Utica. For instance, in 2017 our average natural gas basis differentials to NYMEX were $0.07/Mcfe discount vs. $0.87 Mcfe discount at Dominion in the northeastern natural gas markets. Additionally, our assets are in close proximity to the largest and highest growth natural gas and NGL demand centers, including increasing LNG exports, natural gas exports to Mexico and industrial, petrochemical, and power demand in the Gulf Coast markets.

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.

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.

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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Property Overview

Our operations are focused in three fields located in the Eagle Ford Shale trend of South Texas. The following table sets forth information regarding our Eagle Ford fields in 2017.

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

(1) Other includes Oro Grande, Uno Mas and non-core properties.

The following table sets forth information regarding our 2017 year-end proved reserves of 1,024.4 MMcfe and production of 56.1 Bcfe by area:
Fields
 
Proved Developed Reserves (MMcfe)
 
Proved Undeveloped Reserves
(MMcfe)
 
Total Proved Reserves
(MMcfe)
 
% of Total Proved Reserves
 
Oil and
NGLs as % of Proved Reserves
 
Total
Production (Mcfe)
Artesia
 
64.5

 
62.5

 
127.0

 
12.4
%
 
53.7
%
 
7,393.4

AWP Eagle Ford
 
75.1

 
229.3

 
304.4

 
29.7
%
 
33.2
%
 
8,910.0

AWP Olmos
 
29.9

 

 
29.9

 
2.9
%
 
40.4
%
 
4,094.3

Fasken
 
267.9

 
243.0

 
510.9

 
49.9
%
 
%
 
33,769.2

Other (1)
 
20.8

 
31.3

 
52.2

 
5.1
%
 
0.4
%
 
1,968.0

Total
 
458.2

 
566.2

 
1,024.4

 
100.0
%
 
17.7
%
 
56,134.9

(1) Other includes Oro Grande, Uno Mas and non-core properties.

Oil and Natural Gas Reserves

The following tables present information regarding proved reserves of oil and natural gas attributable to our interests in producing properties as of December 31, 2017, 2016 and 2015. The information set forth in the tables regarding reserves is based on proved reserves reports prepared in accordance with SEC rules. H.J. Gruy and Associates, Inc., independent petroleum engineers, prepared our proved reserves report as of December 31, 2017 and 2016 and audited 99% of our proved reserves as of December 31, 2015. Our 2015 reserves report was prepared internally under the supervision of our Chief Reservoir Engineer. The 2015 reserves audit by H.J. Gruy and Associates conformed to the meaning of the term “reserves audit” as presented in Regulation S-K, Item 1202. Reserve data used for interim reporting periods were prepared internally and was not audited.

The reserves estimation process involves members of the reserves and evaluation department who report to the Chief Reservoir Engineer. The staff includes engineers whose duty is to prepare estimates of reserves in accordance with the Commission's rules, regulations and guidelines. This team worked closely with H. J. Gruy and Associates to ensure the accuracy and completeness of the data utilized for the preparation of the 2017 and 2016 reserve reports. All information from our secure engineering database as well as geographic maps, well logs, production tests and other pertinent data were provided to H.J. Gruy and Associates.

The Chief Reservoir Engineer supervises this process with multiple levels of review and reconciliation of reserve estimates to ensure they conform to SEC guidelines. Reserves data are also reported to and reviewed by senior management quarterly. The Board of Directors review the reserve data periodically and the independent Board members meet with H.J. Gruy and Associates, Inc. in executive sessions at least annually.

The technical person at H.J. Gruy and Associates, Inc. primarily responsible for overseeing preparation of the 2017 and 2016 reserves report and the audits of prior year reports is a Licensed Professional Engineer, holds a degree in petroleum engineering, is past Chairman of the Gulf Coast Section of the Society of Petroleum Engineers, is past President of the Society of Petroleum Evaluation Engineers, and has over 30 years of experience in preparing reserves reports and overseeing reserves audits.


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Our Chief Reservoir Engineer, the primary technical person responsible for overseeing the preparation of our 2017 and 2016 reserve estimates, holds a bachelor's degree in geology, is a member of the Society of Petroleum Engineers and the Society of Professional Well Log Analysts, and has over 25 years of experience in petrophysical analysis, reservoir engineering, and reserves estimation.

Estimates of future net revenues from our proved reserves, Standardized Measure and PV-10 (PV-10 is a non-GAAP measure defined below), as of December 31, 2017, 2016 and 2015 are made in accordance with SEC criteria, which is based on the preceding 12-months' average adjusted price after differentials based on closing prices on the first business day of each month, (excluding the effects of hedging) and are held constant for that year's reserves calculation throughout the life of the properties, except where such guidelines permit alternate treatment, including, in the case of natural gas contracts, the use of fixed and determinable contractual price escalations. We have interests in certain tracts that are estimated to have additional hydrocarbon reserves that cannot be classified as proved and are not reflected in the following tables.

The following prices are used to estimate our SEC proved reserve volumes, year-end Standardized Measure and PV-10. The 12-month 2017 average adjusted prices after differentials were $2.95 per Mcf of natural gas, $50.38 per barrel of oil, and $20.32 per barrel of NGL, compared to $2.43 per Mcf of natural gas, $41.07 per barrel of oil, and $16.13 per barrel of NGL for 2016 and $2.61 per Mcf of natural gas, $49.58 per barrel of oil, and $14.64 per barrel of NGL for 2015.

As noted above, PV-10 Value is a non-GAAP measure. The most directly comparable GAAP measure to the PV-10 Value is the Standardized Measure. We believe the PV-10 Value is a useful supplemental disclosure to the Standardized Measure because the PV-10 Value is a widely used measure within the industry and is commonly used by securities analysts, banks and credit rating agencies to evaluate the value of proved reserves on a comparative basis across companies or specific properties without regard to the owner's income tax position. We use the PV-10 Value for comparison against our debt balances, to evaluate properties that are bought and sold and to assess the potential return on investment in our oil and gas properties. PV-10 Value is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for any GAAP measure. Our PV-10 Value and the Standardized Measure do not purport to represent the fair value of our proved oil and natural gas reserves.

The following table provides a reconciliation between the Standardized Measure (the most directly comparable financial measure calculated in accordance with U.S. GAAP) and PV-10 Value of the Company's proved reserves.
 
As of December 31,
(in millions)
2017
 
2016
 
2015
PV-10 Value
$
805

 
$
442

 
$
374

Less: Future income taxes (discounted at 10%)
73

 
35

 

Standardized Measure of Discounted Future Net Cash Flows
$
732

 
$
407

 
$
374


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The following tables set forth estimates of future net revenues presented on the basis of unescalated prices and costs in accordance with criteria prescribed by the SEC and presented on a Standardized Measure and PV-10 basis as of December 31, 2017, 2016 and 2015. Operating costs, development costs, asset retirement obligation costs, and certain production-related taxes were deducted in arriving at the estimated future net revenues.

At December 31, 2017, we had estimated proved reserves of 1,024.4 MMcfe with a Standardized Measure of $732 million and PV-10 Value of $805 million. This is an increase of approximately 281 MMcfe from our year-end 2016 proved reserves quantities primarily due to drilling and an expanded development plan. Our total proved reserves at December 31, 2017 were approximately 4% crude oil, 82% natural gas, and 14% NGLs, while 45% of our total proved reserves were developed. All of our proved reserves are located in Texas. The following amounts shown in MMcfe below are based on an oil conversion factor of 1 Boe to 6 Mcf:
Estimated Proved Natural Gas, Oil and NGL Reserves
 
As of December 31,
 
 
2017
 
2016
 
2015
Natural gas reserves (MMcf):
 
 
 
 
 
 
   Proved developed
 
377,506

 
312,125

 
238,356

   Proved undeveloped (3)
 
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


(1) The reserve volumes exclude natural gas consumed in operations.
(2) The Standardized Measure and PV-10 Values as of December 31, 2017, 2016 and 2015 are net of $7.1 million, $33.1 million and $57.8 million of plugging and abandonment costs, respectively.
(3) The increase in 2016 reserves volumes was primarily due to rebooking of proved undeveloped reserves that we removed in 2015 due to uncertainty about available financing. The increase in 2017 was primarily attributable to extensions added based on drilling results and leasing of adjacent acreage.

Proved reserves are estimates of hydrocarbons to be recovered in the future. Reserves estimation is a subjective process of estimating the sizes of underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserves reports of other engineers might differ from the reports contained herein. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Future prices received for the sale of oil and natural gas may be different from those used in preparing these reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. There can be no assurance that these estimates are accurate predictions of the present value of future net cash flows from oil and natural gas reserves.



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Proved Undeveloped Reserves

The following table sets forth the aging of our proved undeveloped reserves as of December 31, 2017:
Year Added
 
Volume
(MMcfe)
 
% 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
%
(1) The Company did not carry proved undeveloped reserves forward through bankruptcy except for locations that were converted to developed reserves early in 2016, therefore all proved undeveloped reserves as of December 31, 2016 were 2016 additions.

During 2017, our proved undeveloped reserves increased by approximately 200.7 MMcfe primarily due to additions of undeveloped reserves in our AWP and Oro Grande fields, partially offset by 2016 undeveloped reserves which were converted to proved developed reserves during 2017. We also incurred approximately $89.5 million in capital expenditures during the year which resulted in the conversion of 115.5 MMcfe of our December 31, 2016 proved undeveloped reserves to proved developed reserves, primarily in the Fasken field.

The PV-10 Value from our proved undeveloped reserves was $335 million at December 31, 2017, which was approximately 42% of our total PV-10 Value of $805 million. The PV-10 Value of our proved undeveloped reserves, by year of booking was 54% in 2017 and 46% in 2016.

Sensitivity of Reserves to Pricing

As of December 31, 2017, a 5% increase in natural gas pricing would increase our total estimated proved reserves by approximately 2.5 MMcfe and would increase the PV-10 Value by approximately $57.6 million. Similarly, a 5% decrease in natural gas pricing would decrease our total estimated proved reserves by approximately 2.7 MMcfe and would decrease the PV-10 Value by approximately $57.2 million.

As of December 31, 2017, a 5% increase in oil and NGL pricing would increase our total estimated proved reserves of 1,024.4 MMcfe by approximately 1.8 MMcfe, and would increase the PV-10 Value of $805 million by approximately $19.5 million. Similarly, a 5% decrease in oil and NGL pricing would decrease our total estimated proved reserves by approximately 1.9 MMcfe and would decrease the PV-10 Value by approximately $19.4 million.



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Oil and Gas Wells

The following table sets forth the total gross and net wells in which we owned an interest at the following dates:
 
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.

Oil and Gas Acreage

The following table sets forth the developed and undeveloped leasehold acreage held by us at December 31, 2017:
 
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.
(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.

As of December 31, 2017, SilverBow Resources' net undeveloped acreage subject to expiration over the next three years, if not renewed, is approximately 25% in 2018, 2% in 2019 and 7% in 2020. In most cases, acreage scheduled to expire can be held through drilling operations or we can exercise extension options. As of February 28, 2018, 3,387 net undeveloped acres, primarily in Colorado, have expired during 2018. The exploration potential of all undeveloped acreage is fully evaluated before expiration. In each fiscal year where undeveloped acreage is subject to expiration (except for Colorado acreage) our intent is to reduce the expirations through either development or extensions, if we believe it is commercially advantageous to do so.


11




Drilling and Other Exploratory and Development Activities

The following table sets forth the results of our drilling and completion activities during the years ended December 31, 2017, 2016 and 2015:
 
 
 
 
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

 


Recent Activities

As of December 31, 2017, we were in the process of drilling six wells in our Fasken field where we have a 64% working interest. These wells were completed in the first quarter of 2018.

Operations

We generally seek to be the operator of the wells in which we have a significant economic interest. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or other oil field services equipment used for drilling or maintaining wells on properties we operate. Independent contractors supervised by us provide this equipment and personnel. We employ drilling, production, and reservoir engineers, geologists, and other specialists who work to improve production rates, increase reserves, and lower the cost of operating our oil and natural gas properties.

Operations on our oil and natural gas properties are customarily accounted for in accordance with Council of Petroleum Accountants Societies' guidelines. We charge a monthly per-well supervision fee to the wells we operate including our wells in which we own up to a 100% working interest. Supervision fees vary widely depending on the geographic location and depth of the well and whether the well produces oil or natural gas. The fees for these activities in 2017 totaled $4.7 million and ranged from $125 to $1,301 per well per month.


12




Marketing of Production

We typically sell our oil and natural gas production at market prices near the wellhead or at a central point after gathering and/or processing. We usually sell our natural gas in the spot market on a monthly basis, while we sell our oil at prevailing market prices. We do not refine any oil we produce. For the year ended December 31, 2017 (successor), the period of April 23, 2016 through December 31, 2016 (successor), the period of January 1, 2016 through April 22, 2016 (predecessor) and the year ended December 31, 2015 (predecessor) parties which accounted for approximately 10% or more of our total oil and gas receipts were as follows:

 
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
%
(1) Less than 10% for the year ended December 31, 2017 (successor).

We have gas processing and gathering agreements with Southcross Energy for a majority of our natural gas production in the AWP area. Oil production is transported to market by truck and sold at prevailing market prices.

We have a gas gathering agreement with Howard Energy providing for the transportation of our Eagle Ford production on the pipeline from Fasken to Kinder Morgan Texas Pipeline or Eagle Ford Midstream, where it is sold at prices tied to monthly and daily natural gas price indices. At Fasken, we also have a connection with the Navarro gathering system into which we may deliver natural gas from time to time.

We have an agreement with Eagle Ford Gathering LLC that provides for the gathering and processing for almost all of our natural gas production in the Artesia Wells area. Natural gas in the area can also be delivered to the Targa (formerly Atlas) system for processing and transportation to downstream markets. In the Artesia Wells area, our oil production is sold at prevailing market prices and transported to market by truck.

The prices in the tables below do not include the effects of hedging. Quarterly prices are detailed under “Results of Operations – Revenues” in “Management's Discussion and Analysis of Financial Condition and Results of Operations” in this Form 10-K.


13




The following table summarizes sales volumes, sales prices, and production cost information for our net oil, NGL and natural gas production for the year ended December 31, 2017 (successor), the period of April 23, 2016 through December 31, 2016 (successor), the period of January 1, 2016 through April 22, 2016 (predecessor) and the year ended December 31, 2015 (predecessor).



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


(1) Average production cost includes lease operating costs, transportation and gas processing costs but excludes severance and ad valorem taxes.

The following table provides a summary of our sales volumes, average sales prices, and average production costs for our fields with proved reserves greater than 15% of total proved reserves. These fields account for approximately 83% of the Company's proved reserves based on total MMcfe as of December 31, 2017:
 
 
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


(1) Excludes natural gas consumed in operations.
(2) Average production cost includes lease operating costs, transportation and gas processing costs but excludes severance and ad valorem taxes.


14




 
 
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


(1) Excludes natural gas consumed in operations.
(2) Average production cost includes lease operating costs, transportation and gas processing costs but excludes severance and ad valorem taxes.


Risk Management

Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and natural gas, including blowouts, pipe failure, casing collapse, fires, and adverse weather conditions, each of which could result in severe damage to or destruction of oil and natural gas wells, production facilities or other property, or individual injuries. The oil and natural gas exploration business is also subject to environmental hazards, such as oil spills, natural gas leaks, and ruptures and discharges of toxic substances or gases that could expose us to substantial liability due to pollution and other environmental damage. We maintain comprehensive insurance coverage, including general liability insurance, operators extra expense insurance, and property damage insurance. Our standing Insurable Risk Advisory Team, which includes individuals from operations, drilling, facilities, legal, HSE and finance meets regularly to evaluate risks, review property values, review and monitor claims, review market conditions and assist with the selection of coverages. We believe that our insurance is adequate and customary for companies of a similar size engaged in comparable operations, but if a significant accident or other event occurs that is uninsured or not fully covered by insurance, it could adversely affect us. Refer to “Item 1A. Risk Factors” of this Form 10-K for more details and for discussion of other risks.

Commodity Risk

The oil and gas industry is affected by the volatility of commodity prices. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. The Company has derivative instruments in place to protect a significant portion of our production against declines in oil and natural gas prices through the fourth quarter of 2020. For additional discussion related to our price-risk policy, refer to Note 5 of the consolidated financial statements in this Form 10-K.

Competition

We operate in a highly competitive environment, competing with major integrated and independent energy companies for desirable oil and natural gas properties, as well as for equipment, labor, and materials required to develop and operate such properties. Many of these competitors have financial and technological resources substantially greater than ours. The market for oil and natural gas properties is highly competitive and we may lack technological information or expertise available to other bidders. We may incur higher costs or be unable to acquire and develop desirable properties at costs we consider reasonable because of this competition. Our ability to replace and expand our reserve base depends on our continued ability to attract and retain quality personnel and identify and acquire suitable producing properties and prospects for future drilling and acquisition.


15




Environmental and Occupational Health and Safety Matters

Our business operations are subject to numerous federal, state and local environmental and occupational health and safety laws and regulations. Numerous governmental entities, including the U.S. Environmental Protection Agency (“EPA”), the U.S. Occupational Safety and Health Administration ("OSHA") and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. These laws and regulations may, among other things (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; (v) impose specific safety and health criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and completion activities.

The more significant of these existing environmental and occupational health and safety laws and regulations include the following U.S. laws and regulations, as amended from time to time:

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.

These U.S. laws and regulations, as well as state counterparts, generally restrict the level of pollutants emitted to ambient air, discharges to surface water, and disposals or other releases to surface and below-ground soils and ground water. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the permitting, development or expansion of projects; and the issuance of injunctions restricting or prohibiting some or all of our activities in a particular area. Additionally, multiple environmental laws provide for citizen suits, which allow environmental organizations to act in place of the government and sue operators for alleged violations of environmental law. See Risk Factors under Part I, Item 1A of this Form 10‑K for further discussion on hydraulic fracturing; ozone standards, induced seismicity; climate change; and other regulations relating to environmental protection. The ultimate

16




financial impact arising from environmental laws and regulations is neither clearly known nor determinable as existing standards are subject to change and new standards continue to evolve.

Many states, including Texas where we conduct operations, also have, or are developing, similar environmental and occupational health and safety laws and regulations governing many of these same types of activities. While the legal requirements imposed under state law may be similar in form to federal laws and regulations, in some cases the actual implementation of these requirements may impose additional, or more stringent, conditions or controls that can significantly alter or delay the permitting, development or expansion of a project or substantially increase the cost of doing business. In addition, environmental and occupational health and safety laws and regulations, including new or amended legal requirements that may arise in the future to address potential environmental or worker health and safety concerns, are expected to continue to have an increasing impact on our operations.

We have incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with environmental and occupational health and safety laws and regulations. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operational results.

Employees

As of December 31, 2017, the Company employed 87 people. None of our employees were represented by a union and relations with employees are considered to be good.

Facilities

At December 31, 2017, we occupied approximately 34,275 square feet of office space at 575 N. Dairy Ashford Road, Houston, Texas. For discussion regarding the term and obligations of this sub-lease refer to Note 6 of the consolidated financial statements in this Form 10-K.

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, amendments to those reports, changes in and stock ownership of our directors and executive officers, together with other documents filed with the Securities and Exchange Commission under the Securities Exchange Act can be accessed free of charge on our web site at www.sbow.com as soon as reasonably practicable after we electronically file these reports with the SEC. All exhibits and supplemental schedules to these reports are available free of charge through the SEC web site at www.sec.gov. In addition, we have adopted a Code of Ethics for Senior Financial Officers and the Principal Executive Officers. We have posted this Code of Ethics on our website, where we also intend to post any waivers from or amendments to this Code of Ethics.



17




Item 1A. Risk Factors

Risks Related to the Business:

Oil and natural gas prices are volatile, and a substantial or extended decline in oil and natural gas prices would adversely affect our financial results and impede our growth.

Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future. For example, during 2017 the WTI crude oil crude oil and Henry Hub natural gas spot prices ranged from approximately $42 to $60 per barrel and $2.44 to $3.71 per MMBtu, respectively. As of December 31, 2017, the spot market price for WTI was $60.46 while the spot market price for natural gas was $2.95. Prices for oil and natural gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:

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.

Our financial condition, revenues, profitability and the carrying value of our properties depend upon the prevailing prices and demand for oil and natural gas. Any sustained periods of low prices for oil and natural gas are likely to materially and adversely affect our financial position, the quantities of oil and natural gas reserves that we can economically produce, our cash flow available for capital expenditures and our ability to access funds through the capital markets, if they are available at all.

Insufficient capital could lead to declines in our cash flow or in our oil and natural gas reserves, or a loss of properties.

The oil and natural gas industry is capital intensive. Our 2018 capital expenditure budget, including expenditures for leasehold acquisitions, drilling and infrastructure and fulfillment of abandonment obligations is expected to be in the range of $245 million and $265 million. We had approximately $219.5 million of capital expenditures in 2017. Cash flow from operations is a principal source of our financing of our future capital expenditures. Insufficient cash flow from operations and inability to access capital could lead to losing leases that require us to drill new wells in order to maintain the lease. Lower liquidity and other capital constraints may make it difficult to drill those wells prior to the lease expiration dates, which could result in our losing reserves and production.

Our Credit Facilities, as defined below, contain operating and financial restrictions that may restrict our business and financing activities.

Our Credit Facilities include (i) that certain amended and restated senior secured revolving credit facility among the Company, as borrower, JPMorgan Chase Bank, N.A., as administrative agent and the lenders party thereto (defined herein as the “Credit Facility”) and (ii) that certain note purchase agreement among the Company, as issuer, U.S. Bank National Association, as agent and collateral agent and the holders party thereto (the “Second Lien”, together with the Credit Facility, our “Credit Facilities”). Our Credit Facilities contain a number of restrictive covenants that impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:

sell assets, including equity interests in our subsidiaries;
redeem our debt;
make investments;

18




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.

As a result of these covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.

Our ability to comply with some of the covenants and restrictions contained in our Credit Facilities may be affected by events beyond our control. If market or other economic conditions deteriorate or if oil and natural gas prices remain at their current level for an extended period of time or were to decline, our ability to comply with these covenants may be impaired. A failure to comply with the covenants, ratios or tests in our Credit Facilities or any future indebtedness could result in an event of default under our Credit Facilities or our future indebtedness, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations.

If an event of default under either of our Credit Facilities occurs and remains uncured, the lenders or holders under the applicable Credit Facility:

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.

In addition, our obligations under the Credit Facilities are collateralized by perfected first and second priority liens and security interests on substantially all of our assets, including mortgage liens on oil and natural gas properties having at least 85% of the PV-9 of the borrowing base properties (with respect to the Credit Facility) or the oil and gas properties constituting proved reserves as set forth in the most recent reserve report (with respect to the Second Lien), and if we are unable to repay our indebtedness under the Credit Facilities, the lenders could seek to foreclose on our assets.

Most of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

We own leasehold interests in areas not currently held by production. Unless production in paying quantities is established or we exercise an extension option on units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties.  We have leases on 22,126 net acres that could potentially expire during fiscal year 2018, representing approximately 25% of our net undeveloped acreage. Additionally, we have leases on 20,997 net acres in Colorado that are scheduled to expire in 2018. We have no plans to extend the leases for the Colorado acreage and plan to let them expire.

Our drilling plans for areas not currently held by production are subject to change based upon various factors.  Many of these factors are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.  On our acreage that we do not operate, we have less control over the timing of drilling; therefore, there is additional risk of expirations occurring in those sections.

If low commodity prices continue for an extended period, our liquidity would be significantly reduced.

We continue to have substantial capital needs following our emergence from bankruptcy, including in connection with our existing secured indebtedness and the continued development of our operations. As a result, we will need additional capital in the future to fund our operations, implement our business plan and fulfill our abandonment obligations. An extended period of low

19




commodity prices would substantially reduce our cash flows and would likely reduce liquidity to a level that would make it increasingly difficult to operate our business.

We have written down the carrying values on our oil and natural gas properties in 2015 and 2016 and could incur additional write-downs in the future.

The SEC accounting rules require that on a quarterly basis we review the carrying value of our oil and natural gas properties for possible write-down or impairment (the "ceiling test"). Any capital costs in excess of the ceiling amount must be permanently written down. For the period of April 23, 2016 through December 31, 2016 (successor), period of January 1, 2016 through April 22, 2016 (predecessor), and the year ended December 31, 2015 (predecessor), we reported non-cash write-downs on a before-tax basis of, $133.5 million, $77.7 million and $1.6 billion ($1.5 billion after-tax) respectively, on our oil and natural gas properties. There was no write-down for the year ended December 31, 2017 (successor). If oil and natural gas prices decline in the future, we could be required to record additional non-cash write-downs of our oil and gas properties. Refer to Note 1 of the consolidated financial statements in this Form 10-K for further discussion of the ceiling test calculation.

Estimates of proved reserves are uncertain, and revenues from production may vary significantly from expectations.

The quantities and values of our proved reserves included in our 2017 estimates of proved reserves are only estimates and subject to numerous uncertainties. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation. These estimates depend on assumptions regarding quantities and production rates of recoverable oil and natural gas reserves, future prices for oil and natural gas, timing and amounts of development expenditures and operating expenses, all of which will vary from those assumed in our estimates. If the variances in these assumptions are significant, many of which are based upon extrinsic events we cannot control, they could significantly affect these estimates and could result in the actual amounts of oil and natural gas ultimately recovered and future net cash flows being materially different from the estimates in our reserves reports. These estimates may not accurately predict the present value of future net cash flows from our oil and natural gas reserves.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect the Company’s production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand or other proppant and chemical additives under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. The Company uses hydraulic fracturing techniques in certain of its operations. Hydraulic fracturing typically is regulated by state oil and gas commissions or similar state agencies, but several federal agencies have conducted studies or asserted regulatory authority over certain aspects of the process. For example, in December 2016, the U.S. Environmental Protection Agency (“EPA”) released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some circumstances. Additionally, in 2014, the EPA asserted regulatory authority pursuant to the Safe Drinking Water Act’s (“SDWA”) Underground Injection Control (“UIC”) program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. The EPA also issued final federal Clean Air Act (“CAA”) regulations in 2012 and in June 2016 governing performance standards, including standards for the capture of air emissions released during oil and natural gas hydraulic fracturing. Moreover, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants and, in 2014, published an Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the federal Bureau of Land Management (“BLM”) published a final rule in March 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands. However, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule, the BLM appealed the decision to the U.S. Circuit Court of Appeals in July 2016, the appellate court issued a ruling in September 2017 to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the 2015 rule in response to the BLM’s issuance of a proposed rulemaking to rescind the 2015 rule and, in December 2017, the BLM published a final rule rescinding the March 2015 rule. In January 2018, litigation challenging the BLM’s rescission of the 2015 rule was brought in federal court.

The U.S. Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. In addition, certain states, including Texas, have adopted, and other states are considering adopting legal requirements that could impose new or more stringent permitting, public disclosure, or well construction requirements on hydraulic fracturing activities. States could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York. Local governments also may seek to adopt ordinances

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within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where the Company operates the Company could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to added delays for our operations or increased operating costs in our production of oil and natural gas. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells, which could have a material adverse effect on our business or results of operations.

Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.

Our operations include the need of water for use in oil and natural gas exploration and production activities. The Company’s access to water may be limited due to reasons such as prolonged drought, private third party competition for water in localized areas, or the Company’s inability to acquire or maintain water sourcing permits or other rights. In addition, some state and local governmental authorities have begun to monitor or restrict the use of water subject to their jurisdiction for hydraulic fracturing to ensure adequate local water supply. Any such decrease in the availability of water could adversely affect the Company’s business and financial condition and operations. Moreover, any inability by the Company to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact the Company’s exploration and production operations and have a corresponding adverse effect on the Company’s business and financial condition.

Federal or state legislative and regulatory initiatives related to induced seismicity could result in operating restrictions or delays that could adversely affect the Company’s production of oil and natural gas.

Operations associated with our production and development activities generate drilling muds, produced waters and other waste streams, some of which may be disposed of by means of injection into underground wells situated in non-producing subsurface formations. These disposal wells are regulated pursuant to the UIC program established under the SDWA and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for construction and operation of such disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern relates to recent seismic events near underground disposal wells used for the disposal by injection of produced water or certain other oilfield fluids resulting from oil and natural gas activities. When caused by human activity, such events are called induced seismicity. Developing research suggests that the link between seismic activity and produced water disposal may vary by region, and that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or may have been, the likely cause of induced seismicity. In March 2016, the United States Geological Survey identified Texas, where the Company conducts operations, as well as Oklahoma, Kansas, Colorado, New Mexico, and Arkansas as the states with the most significant hazards from induced seismicity.

In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma has issued rules for produced water disposal wells that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, is developing and implementing plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. The Texas Railroad Commission has adopted similar rules for the permitting of produced water disposal wells. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells in connection with Company activities to dispose of produced water and certain other oilfield fluids. Increased regulation and attention given to induced seismicity also could lead to greater opposition, including litigation, to oil and natural gas activities utilizing injection wells for waste disposal. Any one or more of these developments may result in the Company having to limit disposal well volumes, disposal rates or locations, or require third party disposal well operators the Company may engage to dispose of produced water generated by Company activities to shut down disposal wells, which development could adversely affect the Company’s production or result in the Company incurring increased costs and delays with respect to Company operations.

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Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas the Company produces.

Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of greenhouse gases (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.

At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has determined that emissions of GHGs present an endangerment to public health and the environment and has adopted regulations under existing provisions of the CAA that establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from large stationary sources that are already potential sources of significant, or criteria, pollutant emissions. The Company’s operations could become subject to these permitting requirements and be required to install "best available control technology" to limit emissions of GHGs from any new or significantly modified facilities that the Company may seek to construct in the future if they would otherwise emit large volumes of GHGs as well as criteria pollutants from such sources. The EPA has also adopted rules requiring the reporting of GHG emissions on an annual basis from specified GHG emission sources in the United States, including onshore and offshore oil and gas production facilities, which may include certain Company operations. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines, and in January 2016, the EPA proposed additional revisions to leak detection methodology to align the reporting rules with the New Source Performance Standards (“NSPS”).

Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published NSPS, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and VOC emissions. These Subpart OOOOa standards will expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors and imposing leak detection and repair requirements for natural gas compressor and booster stations. However, in June 2017, the EPA published a proposed rule to stay certain portions of the June 2016 standards for two years and re-evaluate the entirety of the 2016 standards but the EPA has not yet published a final rule and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. In another example, the BLM published a final rule in November 2016 that imposes requirements to reduce methane emissions from venting, flaring, and leaking on federal and Indian lands. However, in December 2017, the BLM published a final rule that temporarily suspends or delays certain requirements contained in the November 2016 final rule until January 17, 2019. The suspension of the November 2016 final rule is being challenged in court. These rules, should they remain in effect, and any other new methane emission standards imposed on the oil and natural gas sector could result in increased costs to our operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that proposed an agreement requiring member countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020 (the "Paris Agreement"). While this international agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions. The Paris Agreement was signed by the United States in April 2016 and entered into force in November 2016. However, in August 2017, the U.S. State Department informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.

The adoption and implementation of any international, federal or state legislation or regulations that requires reporting of GHGs or otherwise restricts emissions of GHGs from the Company’s equipment and operations could require the Company to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements, including the imposition of a carbon tax, which one or more developments could have an adverse effect on the Company’s business, financial condition and results of operations. Moreover, such new legislation or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for oil and gas, which could reduce the demand for, or lower the value of, the oil and natural gas the Company produces. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production or

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midstream activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time.

Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on the Company’s operations. At this time, the Company has not developed a comprehensive plan to address the legal, economic, social, or physical impacts of climate change on the Company’s operations.

A worldwide financial downturn or negative credit market conditions may have lasting effects on our liquidity, business and financial condition that we cannot control or predict.

Global economic conditions may adversely affect the financial viability of and increase the credit risk associated with our purchasers, suppliers, insurers, and commodity derivative counterparties to perform under the terms of contracts or financial arrangements we have with them. Although we have heightened our level of scrutiny of our contractual counterparties, our assessment of the risk of non-performance by various parties is subject to sudden swings in the financial and credit markets. This same crisis may adversely impact insurers and their ability to pay current and future insurance claims that we may have.

Our future access to capital could be limited due to tightening credit markets that could affect our ability to fund our future capital projects. In addition, long-term restriction upon or freezing of the capital markets and legislation related to financial and banking reform may affect short-term or long-term liquidity.

Our oil and natural gas exploration and production business involves high risks and we may suffer uninsured losses.

These risks include blowouts, explosions, adverse weather effects and pollution and other environmental damage, any of which could result in substantial losses to the Company due to injury or loss of life, damage to or destruction of wells, production facilities or other property, clean-up responsibilities, regulatory investigations and penalties and suspension of operations. Although the Company currently maintains insurance coverage that it considers reasonable and that is similar to that maintained by comparable companies in the oil and natural gas industry, it is not fully insured against certain of these risks, such as business interruption, either because such insurance is not available or because of the high premium costs and deductibles associated with obtaining and carrying such insurance.

Drilling wells is speculative and capital intensive.

Developing and exploring properties for oil and natural gas requires significant capital expenditures and involves a high degree of financial risk, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. The budgeted costs of drilling, completing, and operating wells are often exceeded and can increase significantly when drilling costs rise. Drilling may be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages, and mechanical difficulties. Moreover, the successful drilling or completion of an oil or natural gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition, or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

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.


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Any of these risks could adversely affect our ability to conduct operations or result in substantial losses. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect our financial condition.

Pollution and property contamination arising from the Company’s operations and the nearby operations of other oil and natural gas operators could expose the Company to significant costs and liabilities.

The performance of the Company’s operations may result in significant environmental costs and liabilities as a result of handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater or other fluid discharges related to operations, and due to historical industry operations and waste disposal practices. Spills or other unauthorized releases of regulated substances by or resulting from the Company’s operations, or the nearby operations of other oil and natural gas operators, could expose the Company to material losses, expenditures and liabilities under environmental laws and regulations. Certain of these laws may impose strict liability, which means that in some situations the Company could be exposed to liability as a result of the Company’s conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Neighboring landowners and other third parties may file claims against the Company for personal injury or property damage allegedly caused by the release of pollutants into the environment. Moreover, environmental laws and regulations generally have become more stringent in recent years and are expected to continue to do so, which could result in the occurrence of delays or cancellation in the permitting or performance of new or expanded projects, or more stringent or costly well drilling, construction, completion or water management activities or waste handling, storage, transport, disposal or cleanup requirements. Any one or more of such developments could require the Company to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on the oil and natural gas exploration and production industry in general in addition to the Company’s own results of operations, competitive position or financial condition. The Company may not be able to recover some or any of its costs with respect to such developments from insurance.

Government regulation of the Company’s activities could adversely affect the Company and its operations.

The oil and natural gas business is subject to extensive governmental regulation under which, among other things, rates of production from oil and natural gas wells may be regulated. Governmental regulation also may affect the market for the Company’s production and operations. Costs of compliance with governmental regulation are significant, and the cost of compliance with new and emerging laws and regulations and the incurrence of associated liabilities could adversely affect the results of the Company. We cannot predict the timing or impact of new or changed laws, regulations, or permit requirements or changes in the ways that such laws, regulations, or permit requirements are enforced, interpreted or administered.  For example, various governmental agencies, including the EPA and analogous state agencies, the BLM, and the Federal Energy Regulatory Commission can enact or change, begin to force compliance with, or otherwise modify their enforcement, interpretation or administration of, certain regulations that could adversely affect the Company.

The Company’s operations are subject to environmental and worker safety and health laws and regulations that may expose the Company to significant costs and liabilities and could delay the pace or restrict the scope of the Company’s operations.

The Company’s oil and natural gas exploration, production and development operations are subject to stringent federal, state and local laws and regulations governing worker safety and health, the release or disposal of materials into the environment or otherwise relating to environmental protection. Numerous governmental entities, including the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations, which may require the Company to take actions resulting in costly capital and operating expenditures at its wells and properties. These laws and regulations may restrict or affect the Company’s business in many ways, including applying specific health and safety criteria addressing worker protection, requiring the acquisition of a permit before drilling or other regulated activities commence, restricting the types, quantities and concentration of substances that can be released into the environment, limiting or prohibiting construction or drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and imposing substantial liabilities for pollution resulting from the Company’s operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigative, remedial or corrective action obligations, the occurrence of delays in the permitting or development or expansion of projects, and the issuance of orders enjoining performance of some or all of the Company’s operations in a particular area.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and changes in environmental laws and regulations or re-interpretation of enforcement policies may result in increased costs and liabilities, delays or restrictions in the Company’s operations. For example, during October 2015, the EPA issued a final rule lowering the National Ambient Air Quality Standard for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA published a final rule in November 2017 that issued area designations with respect to ground-

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level ozone for approximately 85% of the U.S. counties as either “attainment/unclassifiable” or “unclassifiable” and is expected to issue non-attainment designations for the remaining areas of the U.S. not addressed under the November 2017 final rule in the first half of 2018. In a second example, in June 2015, the EPA and U.S. Army Corps of Engineers (“Corps”) published a final rule that attempted to clarify federal jurisdiction under the Clean Water Act over waters of the United States, including wetlands, but legal challenges to this rule followed. The 2015 rule was stayed nationwide to determine whether federal district or appellate courts had jurisdiction to hear cases in the matter and, in January 2017, the U.S. Supreme Court agreed to hear the case. The EPA and Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule, announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction, and published a proposed rule in November 2017 specifying that the contested June 2015 rule would not take effect until two years after the November 2017 proposed rule was finalized and published in the Federal Register. Recently, on January 22, 2018, the U.S. Supreme Court issued a decision finding that jurisdiction resides with the federal district courts; consequently, while implementation of the 2015 rule currently remains stayed, the previously-filed district court cases will be allowed to proceed. As a result of these recent developments, future implementation of the June 2015 rule is uncertain at this time. Any expansion to the Federal Water Pollution Control Act jurisdiction in areas where Company’s operations are conducted could, among other things, require installation of new emission controls on some of the Company’s equipment, result in longer permitting timelines, and increase the Company’s capital expenditures and operating costs, which could adversely impact the Company’s business. In a third example, in response to a lawsuit filed in the U.S. District Court for the District of Columbia by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its Resource Conservation and Recovery Act (“RCRA”) Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in the Company’s costs to manage and dispose of wastes generated from its operations, which could effect on the Company’s operations and financial position. The Company may be unable to pass on increased compliance costs arising out of its activities as a result of these developments to its customers.

The Endangered Species Act and other restrictions intended to protect certain species of wildlife govern our oil and natural gas operations, which constraints could have an adverse impact on our ability to expand some of our existing operations or limit our ability to explore for and develop new oil and natural gas wells.

The federal Endangered Species Act (“ESA”) and comparable state laws and other regulatory initiatives restrict activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migrating birds under the federal Migratory Bird Treaty Act. Some of our operations may be located in or near areas that are designated as habitat for endangered or threatened species and, in these areas, we may be obligated to develop and implement plans to avoid potential adverse effects to protected species and their habitats, and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to our drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. Moreover, as a result of one or more settlements approved by the U.S. Fish and Wildlife Service, the agency is required to make determinations on the listing of numerous species as endangered or threatened under the ESA pursuant to specific timelines. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures, time delays or limitations on our exploration and production activities, which costs, delays or limitations could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

Enactment of executive, legislative or regulatory proposals under consideration could negatively affect our business.

Numerous executive, legislative and regulatory proposals affecting the oil and natural gas industry have been introduced, are anticipated to be introduced, or are otherwise under consideration, by the President, Congress, state legislatures and various federal and state agencies. Among these proposals are: (1) proposed legislation (none of which has passed) to repeal various tax deductions available to oil and natural gas producers as discussed in more detail below and (2) the Pipeline Safety, Regulatory Certainty, and Job Creation Act enacted in 2011, which increases penalties, grants new authority to impose damage prevention and incident notification requirements, and directs the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) to prescribe minimum safety standards for CO2 pipelines.

The foregoing described proposals, including other applicable proposals, could affect our operations and the costs thereof. The trend toward stricter standards, increased oversight and regulation and more extensive permit requirements, along with any future laws and regulations, could result in increased costs or additional operating restrictions which could have an effect on the

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Company, its operations, the demand for oil and natural gas, or the prices at which it can be sold. However, until such legislation or regulations are enacted or adopted into law and thereafter implemented, it is not possible to gauge their impact on our future operations or our results of operations and financial condition.

Recently enacted changes to the U.S. federal tax laws could adversely affect our financial position, results of operations and cash flows.

Legislation recently enacted in Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, made significant changes to U.S. tax laws. The Tax Cuts and Jobs Act (i) eliminates the deduction for certain domestic production activities, (ii) imposes new limitations on the utilization of net operating losses, (iii) eliminates the exception under Section 162(m) for qualified performance-based compensation, (iv) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense, which may impact the taxation of oil and natural gas companies. While past legislative proposals have included changes to certain key U.S. federal income tax provisions currently available to oil and natural gas companies, including (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures, these specific changes are not included in the Tax Cuts and Jobs Act. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. This legislation or any future similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to natural gas and oil exploration and production. We continue to examine the impact the Tax Cuts and Jobs Act may have on us, and it could have an adverse effect on our financial position, results of operations and cash flows.

Our ability to deduct interest expense incurred in our business may be limited.

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion.

Our ability to deduct compensation paid to certain employees may be limited.

Section 162(m) of the Code limits our ability to deduct certain compensation paid to covered employees (i.e., individuals currently serving or who have previously served, at any point after December 31, 2016, as the Chief Executive Officer, Chief Financial Officer and the three other highest compensated officers of the Company). Previously, Section 162(m) provided an exception for certain qualified performance-based compensation; however, the Tax Cuts and Jobs Act eliminates this exception (other than for compensation provided under certain grandfathered arrangements), and as a result, our ability to deduct certain amounts paid to our covered employees may be limited.

Legal proceedings could result in liability affecting our results of operations.

Most oil and natural gas companies, such as us, are involved in various legal proceedings, such as title, royalty, environmental or contractual disputes, in the ordinary course of business. We defend ourselves vigorously in all such matters, if appropriate.

Because we maintain a portfolio of assets in the various areas in which we operate, the complexity and types of legal proceedings with which we may become involved may vary, and we could incur significant legal and support expenses in different jurisdictions. If we are not able to successfully defend ourselves, there could be a delay or even halt in our exploration, development or production activities or other business plans, resulting in a reduction in reserves, loss of production and reduced cash flows. Legal proceedings could result in a substantial liability. In addition, legal proceedings distract management and other personnel from their primary responsibilities.

A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.

Our business has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain of our exploration, development and production activities. We depend on digital technology to estimate quantities of oil and natural gas reserves, process and record financial and operating data, analyze seismic and drilling information and in many other activities related to our business. Our technologies, systems and networks may become the target of cyber-attacks or information security breaches that could result in the disruption of our business operations, damage to our properties and/or injuries. For example,

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unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our drilling or production operations.

To date we are not aware of any material losses relating to cyber-attacks, however there can be no assurance that we will not suffer such losses in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any cyber vulnerabilities.

Our financial results are not comparable to our historical financial information prior to our emergence from bankruptcy as a result of the implementation of the plan of reorganization and the transactions contemplated thereby and our adoption of fresh start accounting.

Upon our emergence from bankruptcy in 2016, we adopted fresh start accounting. Accordingly, our financial conditions and results of operations subsequent to emergence from bankruptcy are not comparable to the financial condition or results of operations reflected in the Company’s historical financial statements prior to our emergence from bankruptcy. Investors may find it more difficult to analyze the performance of the Company due to the limited comparable historical financial information.

There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.

Funds associated with Strategic Value Partners LLC, ("SVP") and DW Partners, LP (“DW”) currently own approximately 38.9% and 14.4%, respectively, of our outstanding common stock. SVP currently has a right to nominate two of our directors under our director nominating agreement. DW, together with other former noteholders who received our common stock pursuant to our plan of reorganization, collectively hold the current right to nominate two additional directors. Our current board is limited to seven directors under the terms of the director nomination agreement. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, that, in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. Furthermore, we have entered into a director nomination agreement with each of SVP, DW and other former holders of our senior notes that provides for certain continuing nomination rights subject to conditions on share ownership. In addition, our significant concentration of share ownership may adversely affect the trading price of our common shares because investors may perceive disadvantages in owning shares in companies with significant stockholders.

We do not expect to pay dividends in the near future.

We do not anticipate that cash dividends or other distributions will be paid with respect to our common stock in the foreseeable future. In addition, restrictive covenants in certain debt instruments to which we are, or may be, a party, may limit our ability to pay dividends or for us to receive dividends from our operating companies, any of which may negatively impact the trading price of our common stock.

A small number of institutional investors controls a significant percentage of our voting power and possess negative control or veto rights with respect to certain proposed Company transactions

A small group of institutional investors, who are parties to our director nomination agreement currently, beneficially own a percentage majority of our issued and outstanding common stock. Consequently, such investors are able to strongly influence all matters that require approval by our stockholders, including the election and removal of directors, changes to our organizational documents and approval of acquisition offers and other significant corporate transactions. This concentration of ownership limits our other stockholders’ ability to influence corporate matters. In addition, the institutional holders that are parties to the director nomination agreement possess negative control or veto rights under the Company’s Certificate of Incorporation with respect to certain transactions the Company may propose to undertake for so long as such parties collectively hold 50% or more of the Company’s issued and outstanding shares of common stock. Such parties are entitled to notice of certain proposed transactions which may be vetoed if such parties who collectively hold at least 50% of the issued and outstanding shares of common stock object to such action. These veto rights of the parties to the director nomination agreement apply to the following transactions:

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;

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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.

Certain provisions of our certificate of incorporation and our bylaws may make it difficult for stockholders to change the composition of our Board and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.

Certain provisions of our Certificate of Incorporation (the “Charter”) and our Bylaws and our existing director nomination agreement may have the effect of delaying or preventing changes in control if our Board determines that such changes in control are not in the best interests of the Company and our stockholders. The provisions in our Charter and Bylaws and our existing director nomination agreement include, among other things, those that:

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.

While these provisions have the effect of encouraging persons seeking to acquire control of the Company to negotiate with our Board, they could enable the Board to hinder or frustrate a transaction that some, or a majority, of the stockholders may believe to be in their best interests and, in that case, may prevent or discourage attempts to remove and replace incumbent directors. These provisions may frustrate or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our Board, which is responsible for appointing the members of our management. Furthermore, we have entered into a director nomination agreement with each of SVP, DW and other former holders of our senior notes that provides for certain continuing nomination rights subject to conditions on share ownership.



28




Item 1B. Unresolved Staff Comments

None.

Glossary of Abbreviations and Terms

The following abbreviations and terms have the indicated meanings when used in this report:

ASC - Accounting Standards Codification.
Bankruptcy Code - Refers to title 11 of the United States Code.
Bankruptcy Court - Refers to the United States Bankruptcy Court for the District of Delaware.
Bar Date - Refers to the deadline, set by the Bankruptcy Court, by which certain creditors must file proofs of claims in order to receive any distribution under the Plan.
Bbl - Barrel or barrels of oil.
Bcf - Billion cubic feet of natural gas.
Bcfe - Billion cubic feet of natural gas equivalent (see Mcfe).
Boe - Barrels of oil equivalent.
Chapter 11 - Means chapter 11 of the Bankruptcy Code.
Completion - Preparation of a well bore and installation of permanent equipment for production of oil, natural gas or NGLs or, in the case of a dry well, reporting to the appropriate authority that the well has been abandoned.
Condensate - Liquid hydrocarbons that are found in natural gas wells and condense when brought to the well surface. Condensate is used synonymously with oil.
Differential - An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Developed Oil and Gas Reserves - Oil and natural gas reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods.
Development Well - A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry Well - An exploratory or development well that is not a producing well.
Effective Date - The Company's date of emergence from bankruptcy April 22, 2016.
Exploratory Well - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.
FASB - The Financial Accounting Standards Board.
Field - An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
Gross Acre - An acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
Gross Well - A well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.
MBbl - Thousand barrels of oil.
MBoe - Thousand barrels of oil equivalent.
Mcf - Thousand cubic feet of natural gas.
Mcfe - Thousand cubic feet of natural gas equivalent, which is determined using the ratio of one barrel of oil, condensate, or natural gas liquids to 6 Mcf of natural gas.
MMBbl - Million barrels of oil.
MMBtu - Million British thermal units, which is a heating equivalent measure for natural gas and is an alternate measure of natural gas reserves, as opposed to Mcf, which is strictly a measure of natural gas volumes. Typically, prices quoted for natural gas are designated as price per MMBtu, the same basis on which natural gas is contracted for sale.
MMcf - Million cubic feet of natural gas.
MMcfe - Million cubic feet of natural gas equivalent (see Mcfe).
Net Acre - A net acre is deemed to exist when the sum of fractional working interests owned in gross acres equals one. The number of net acres is the sum of fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
Net Well - A net well is deemed to exist when the sum of fractional working interests owned in gross wells equals one. The number of net wells is the sum of fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.
NGL - Natural gas liquid.
NYMEX - The New York Mercantile Exchange.
Producing Well - An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

29




Proved Oil and Gas Reserves - Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. For reserves calculations economic conditions include prices based on either the preceding 12-months' average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements.
Proved Undeveloped (PUD) Locations - A location containing proved undeveloped reserves.
PV-10 Value - The estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%. These amounts are calculated net of estimated production costs and future development costs, using prices based on either the preceding 12-months' average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements, without escalation and without giving effect to non-property related expenses, such as general and administrative expenses, debt service, future income tax expense, or depreciation, depletion, and amortization. PV-10 Value is a non-GAAP measure and its use is explained under “Item 1& 2. Business and Properties - Oil and Natural Gas Reserves” above in this Form 10-K.
Reserves -  Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. 
Reservoir -  A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Spot Market Price - The cash market price without reduction for expected quality, transportation and demand adjustments.
Standardized Measure - The present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing economic conditions). Future income taxes are calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and natural gas operations. Sales prices were prepared using average hydrocarbon prices equal to the unweighted arithmetic average of hydrocarbon prices on the first day of each month within the 12-month period preceding the reporting date (except for consideration of price changes to the extent provided by contractual arrangements).
Undeveloped Oil and Gas Reserves - Oil and natural gas reserves of any category that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
WTI - West Texas Intermediate.

Item 3. Legal Proceedings

In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as operator of oil and natural gas wells. In our opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.

Item 4. Mine Safety Disclosures

Not Applicable.



30




PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Successor Common Stock, year ended December 31, 2017 and the period of April 23, 2016 through December 31, 2016

The trading price of our common stock prior to our emergence from bankruptcy is not comparable to our successor Company and therefore excluded from the table below. Our common stock, was quoted on the OTCQX Market under the symbol “SWTF” from April 23, 2016 through May 4, 2017. On May 5, 2017 our common stock began trading on the New York Stock Exchange under the symbol “SBOW”. The high and low quarterly closing sale prices for the common stock for the year ended December 31, 2017 and the period of April 23, 2016 through December 31, 2016 were as follows:
 
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

The high and low closing sale prices for the common stock reported on the OTCQX Market for the period of April 23, 2016 through May 4, 2017 were $35.70 and $22.00, respectively. The high and low closing sale prices for the common stock reported on the New York Stock Exchange for the period of May 5, 2017 through December 31, 2017 were $31.33 and $19.89, respectively.

Since inception, no cash dividends have been declared on our common stock. Cash dividends are restricted under the terms of our credit agreements.

We had approximately 103 stockholders of record as of December 31, 2017.

Stock Repurchase Table

The following table summarizes repurchases of our common stock during the fourth quarter of 2017, all of which were shares withheld from employees to satisfy tax obligations arising upon the vesting of restricted shares:
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

 

 
$---


Equity Compensation Plan Information

For information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2017 see Note 7 of the consolidated financial statements included in this Form 10-K.



31




Item 6. Selected Financial Data
 
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

(1) These prices do not include the effects of our hedging activities which were recorded in “Net gain (loss) on commodity derivatives” on the consolidated statements of operations included in this Form 10-K.

32




 
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

(1) Reduction in Long-Term Debt is due to reclassifications of (a) the Company's senior notes to Liabilities Subject to Compromise and (b) borrowings under the Prior First Lien Credit Facility to Current Liabilities in 2015, both as a result of the bankruptcy filing.
(2) Reserves decreased during 2015 due to the impact of lower commodity prices and uncertainties surrounding the availability of the financing that would be necessary to develop our proved undeveloped reserves, due in part to our bankruptcy filing.



33




Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion and analysis in conjunction with our financial information and our audited consolidated financial statements and accompanying notes for the year ended December 31, 2017 (successor), the period of April 23, 2016 through December 31, 2016 (successor), the period of January 1, 2016 through April 22, 2016 (predecessor) and the year ended December 31, 2015 (predecessor) included in this Form 10-K. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 53 of this report.


As discussed in Notes 12 and 13 to the consolidated financial statements included herein, the Company applied fresh start accounting upon emergence from bankruptcy on April 22, 2016, at which time it became a new entity for financial reporting purposes. The effects of the Plan of Reorganization (described below) and the application of fresh start accounting were reflected in our consolidated financial statements as of April 22, 2016 and the related adjustments thereto were recorded in our consolidated statements of operations as reorganization items for the period April 1, 2016 to April 22, 2016 (predecessor). References to the Successor relate to the Company on and subsequent to the Effective Date. References to Predecessor refer to the Company prior to the Effective Date.

Company Overview

SilverBow Resources is a growth oriented independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford Shale located in South Texas where we have assembled over 100,000 net acres across five operating areas. Our acreage positions in each of our operating areas are highly contiguous and designed for optimal and efficient horizontal well development. We have built a balanced portfolio of properties with a significant base of current production and reserves coupled with low-risk development drilling opportunities and meaningful upside from newer areas. We produced an average 177 MMcfe per day during the fourth quarter of 2017 and had proved reserves of 1,024 MMcfe (82% natural gas) with a PV-10 of $805 million as of December 31, 2017. PV-10 Value is a non-GAAP measure, see the section titled “Oil and Natural Gas Reserves” of this Form 10-K for a reconciliation of this non-GAAP measure to the standardized measure of discounted future net cash flows, the most directly comparable GAAP measure.
 
Being a committed and long-term operator in South Texas, the Company possesses a significant understanding of the reservoir characteristics, geology, landowners, and competitive landscape in the region. We leverage this in-depth knowledge to continue to assemble high quality drilling inventory while continuously enhancing our operations to maximize returns on capital invested.

We have transformed the Company from a conventional, Louisiana shallow water producer to a focused Eagle Ford player. Over the last few years we have successfully renegotiated midstream contracts, moved our headquarters to west Houston, and reduced headcount over 50% since 2015. These initiatives have resulted in a reduction of per unit G&A from $0.64/Mcfe at year end 2015 to $0.53/Mcfe at year end 2017, a 17% reduction. We expect to continue improving our G&A metrics as we execute on our strategic growth program. We continue to refine our portfolio, including the sale of AWP Olmos wells on March 1, 2018. This strategic divestiture allows us to better leverage existing personnel while lowering field-level costs on a per unit basis. We believe there are other opportunities to continue streamlining our business to extract value for our shareholders.

Operational Results

The Company continues to optimize completion techniques in order to enhance well performance across its portfolio, including optimized landing points, frac designs, and the expanded use of diverters and scale inhibitors. The following table and discussion outlines our drilling and completion schedule for 2017 and our initial plans for 2018:
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

(1) Other includes Oro Grande, Uno Mas and other non-core properties.


34




In Fasken, the Company tested an optimized new completion design in the Upper Eagle Ford in mid-2017 with encouraging results. As a result, the Company drilled a six well pad in late 2017 that was completed in the first quarter of 2018 which included three Upper Eagle Ford wells and three lower Eagle Ford wells. The Company plans to drill six net Upper Eagle Ford wells and seven net Lower Eagle Ford wells in 2018. In 2017, the Company added 2,520 net acres near Fasken.

In Oro Grande where the Company holds just under 25,000 net acres, the Company drilled and completed two assessment wells during 2017; the NMC 1H and NMC 2H. The NMC 1H had cumulative production of 0.9 Bcfe after 90 producing days, while the NMC 2H had cumulative production of 0.8 Bcfe after 90 producing days. Based upon the results of these two initial wells in this acreage block, the Company plans on drilling and completing five additional net wells in Oro Grande during 2018.

The Company returned to Artesia for the first time since 2013 in the second and third quarters to deploy the newest generation of drilling and completion technology. Earlier wells in this area were drilled without the benefit of processed and evaluated 3D seismic, target window identification, and modern completion design tied to longer laterals. The Company completed seven wells in northern Artesia in 2017, with lateral lengths ranging from 6,000 feet to 11,000 feet in accordance with lease configurations. Drilling costs averaged $2.0 million per well for the seven wells drilled in Artesia during the second and third quarters, a decrease of 38% from our 2013 drilling program. Likewise, the average completion cost per stage of $0.1 million decreased 33% despite increasing proppant volumes by 62% compared to our average completions in 2013. The Company is currently leasing acreage in the northern portion of Artesia to increase the amount of high quality inventory where future capital will be deployed.

In AWP, SilverBow drilled and completed two gas wells in 2017, the Bracken 21H and 22H, which utilized 300 foot frac stage spacing and 1,500 pounds of proppant per foot of lateral. The Company continues to optimize its development of the AWP area to provide higher recovery efficiencies and enhanced economic returns. These objectives will be achieved through reservoir pressure management practices and optimized spacing and drilling sequencing between parent and child wells. During 2017, the Company acquired roughly 21,000 acres in AWP. The Company continues to acquire bolt-on acreage in this area to further enhance efficiencies and returns while leveraging existing infrastructure. The Company plans on drilling seven net wells in this area in 2018, including two net wells in the Company’s oily acreage in Northern AWP.

On November 6, 2017 the Company purchased the non-operating working interest of two joint interest partners in certain wells and leases in AWP Field. The value of these assets are concentrated in proved oil and gas reserves. This purchase constitutes a business combination. The acquisition cost of this interest was $9.4 million. Additionally, the Company assumed asset retirement obligations of $0.2 million.

Strategic dispositions: Effective July 31, 2017, the Company disposed of its Wheeler assets in South Texas. This package represented 117 wellbores in the Company’s AWP Olmos area. We received net proceeds of $0.7 million and the buyer assumed approximately $0.5 million of plugging and abandonment liability. No gain or loss was recorded on the sale of this property.

Effective December 22, 2017, we closed the sale of the Company's wellbores and facilities of our Bay De Chene field located in Louisiana. The contract price of $16.3 million will be paid by the Company, as seller. The payments will be funded over time, through an escrow account, with funds being released as plugging and abandonment work is performed and certified to meet state requirements. The buyer assumed approximately $20.9 million of plugging and abandonment liability with no gain or loss recorded on the sale of this property. Of the $16.3 million, during the first quarter of 2018 approximately $6.0 million was released in the first quarter of 2018 for completion of initial post-closing requirements. The remaining $10 million will be funded as the abandonment work is completed and certified. Based on the available information, it is unlikely that more than half of the $10 million allocation will be funded before the end of 2018. Accordingly, the initial allocation of the accrued liability will be $11.3 million as a current liability and $5 million as a non-current liability.

Additionally, subsequent to the year ended December 31, 2017, the Company executed a definitive purchase and sale agreement to divest certain wells in its AWP Olmos field for $28.8 million plus the assumption by the buyer of $6.2 million of asset retirement obligations. This transaction closed on March 1, 2018 and has an effective date of January 1, 2018. These assets are located in McMullen County, Texas and include roughly 491 wells with total proved reserves of 28 Bcfe (100% proved developed) as of December 31, 2017. Full year 2017 production from these properties was approximately 9.5 Mmcfe/d (57% natural gas). Cash proceeds from the sale will be used to repay outstanding borrowings under the Company’s Credit Facility. The Company anticipates that its borrowing base will remain unchanged at $330 million after closing this transaction and will be reviewed as normal during its regularly scheduled Spring redetermination.

2017 cost reduction initiatives: We continue to focus on cost efficient operations and took additional actions in 2017 to reduce operating and overhead costs. These initiatives include field staff reductions, intermittent production of marginal properties,

35




disposition of uneconomic and higher cost properties, full utilization of existing facilities, elimination of redundant equipment and replacement of rental equipment with company-owned equipment. We have also improved each step in the process of drilling and completing a well. Our procurement team takes a diligent and systematic approach to reducing the total delivered costs of purchased services by examining costs at their most detailed level. Services are commonly sourced directly from the suppliers. This has led to a significant reduction in our overall lease operating expenses at the field level. For example, our South Texas lease operating expenses were $0.40 per million cubic feet of natural gas equivalent (“Mcfe”) for the full year 2017 compared to $0.96 per MMcfe in 2013.

Additionally, our significant operational control, as well as our manageable leasehold obligations, provide us the flexibility to control our costs as we transition to a development mode across our portfolio. At the corporate level, we have also undergone additional staff reductions, reduced the square footage of leased office space and are taking additional steps to further reduce overhead costs. This has led to a decline in our net cash general and administrative costs of $23.2 million in 2017 compared to $35.3 million in 2015.

We have continued to maintain a safe working environment while implementing these cost-reduction efforts. Our corporate total recordable incident rate (“TRIR”) declined from 1.8 incidents per 200,000 work hours in 2016 to 0.2 in 2017.

Management Changes

The Company announced the appointment of Sean Woolverton as Chief Executive Officer, effective March 1, 2017. He also serves as a member of the Board of Directors. Mr. Woolverton succeeded the Company’s interim Chief Executive Officer, Bob Banks, who continued to serve at the Company until his departure on November 3, 2017. Mr. Woolverton was previously the Chief Operating Officer of Samson Resources Company, which he joined in November 2013. From 2007 to 2013, Mr. Woolverton held a series of positions of increasing responsibility at Chesapeake Energy Corporation, a public independent exploration and development oil and natural gas company, including Vice President of its Southern Appalachia business unit. Prior to joining Chesapeake Energy Corporation, Mr. Woolverton worked for Encana Corporation, a North American oil and natural gas producer, where he oversaw its Fort Worth Basin development and shale exploration teams in North Texas. Earlier in his career, Mr. Woolverton worked for Burlington Resources in multiple engineering and management roles. Mr. Woolverton received his Bachelor of Science degree in Petroleum Engineering from Montana Tech.

The Company announced the appointment of Gleeson Van Riet as Executive Vice President and Chief Financial Officer, effective March 20, 2017. Mr. Van Riet succeeded Alton Heckaman, who announced his retirement in August 2016. Mr. Van Riet was previously the Chief Financial Officer of Sanchez Energy Corporation where he held a series of positions of increasing responsibility from April 2013 to March 2016. Mr. Van Riet has over 20 years of finance experience and previously worked as an investment banker with Credit Suisse and Donaldson, Lufkin & Jenrette in London and Los Angeles. Mr. Van Riet earned a dual B.A. and B.S. from the University of Pennsylvania and an MBA from the Harvard Business School.

The Company announced the appointment of Chris Abundis as Senior Vice President and General Counsel, effective March 22, 2017. From April 2016 to March 2017, Mr. Abundis was Vice President, General Counsel and Secretary for the Company. He has also served the Board of Directors as Secretary of the Company, a position that he has held since August 2012. From February 2007 to August 2012, Mr. Abundis served as Assistant Secretary of the Company and has provided legal consultation in corporate governance, securities law and other corporate related matters in progressive positions of responsibility including Senior Counsel, Counsel and Associate Corporate Counsel. Mr. Abundis received a Bachelor of Business Administration and Master of Science in Accounting from Texas A&M University and a Juris Doctor from South Texas College of Law.

The Company announced the appointment of Steven W. Adam as Executive Vice President and Chief Operating Officer, effective November 6, 2017, succeeding Robert J. Banks. Steve Adam was previously the Senior Vice President of Operations of Sanchez Oil & Gas where he held a series of positions of increasing responsibility from April 2013 to July 2017. Mr. Adam has over 40 years of upstream exploration and production and petroleum services experience with both major and independent companies. His unconventional resource management experiences have been with Occidental Petroleum and most recently with Sanchez Oil & Gas. Mr. Adam received his Bachelor of Science degree in Chemical Engineering from Montana State University, Master of Business Administration from Pepperdine University and Advanced Management Certificate from the University of California - Berkeley.


36




Leasing Activity

The Company expanded its Eagle Ford shale footprint by over 50% in 2017, through a combination of grassroots leasing and strategically acquiring bolt-on producing acreage. The Company spent approximately $50 million on acquiring over 35,000 acres, primarily throughout the gas and rich gas windows of the Eagle Ford shale. Specifically, the Company added approximately 21,463 acres at AWP in McMullen County, 9,548 acres at Uno Mas in Live Oak County, 3,066 acres at Artesia in La Salle County, and 2,520 acres at Fasken in Webb County.


2017 Liquidity and Capital Resources

Our primary use of cash flow has been to fund capital expenditures to develop our oil and gas properties. As of December 31, 2017, the Company’s liquidity consisted of approximately $7.8 million of cash-on-hand and $253.6 million in available borrowings (calculated as $257 million of borrowing availability less $3.4 million in letters of credit) on our $330 million borrowing base. Management believes the Company has sufficient liquidity to meet its obligations for at least the next twelve months and execute our long-term development plans.

Revolving Credit Facility and Prior First Lien Credit Agreement. Upon emergence from bankruptcy the Company entered into a Senior Secured Revolving Credit Agreement among the Company as borrower, JPMorgan Chase Bank, National Association as administrative agent, and certain lenders party thereto. On April 19, 2017, the Company amended and restated the Senior Secured Revolving Credit Agreement by entering into a First Amended and Restated Senior Secured Revolving Credit Agreement (the “Credit Agreement”) among the Company as borrower, JPMorgan Chase Bank, N.A. as administrative agent, and certain lenders that are a party thereto, which provides for revolving loans of up to the borrowing base then in effect (the “Credit Facility”). The Credit Facility matures on April 19, 2022. The maximum credit amount under the Credit Facility is currently $600 million with a borrowing base of $330 million. The borrowing base is scheduled to be redetermined in May and November of each calendar year and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt.  Additionally, each of the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations.  The amount of the borrowing base is determined by the lenders in their discretion and consistent with their oil and gas lending criteria at the time of the relevant redetermination. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to $25 million, which reduce the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit.

Interest under the Credit Facility accrues at the Company’s option either at an Alternative Base Rate plus the applicable margin (“ABR Loans”) or the LIBOR Rate plus the applicable margin (“Eurodollar Loans”).  The applicable margin ranges from 1.75% to 2.75% for ABR Loans and 2.75% to 3.75% for Eurodollar Loans.  The Alternate Base Rate and LIBOR Rate are defined, and the applicable margins are set forth, in the Credit Agreement. Undrawn amounts under the Credit Facility are subject to a 0.50% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto.

The obligations under the Credit Agreement are secured, subject to certain exceptions, by a first priority lien on substantially all assets of the Company and certain of its subsidiaries, including a first priority lien on properties attributed with at least 85% of estimated proved reserves of the Company and its subsidiaries.

The Credit Agreement contains the following financial covenants:

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.

Additionally, the Credit Agreement contains certain representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts.  The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable.


37




We are in compliance with the covenants as of December 31, 2017 and expect to be in compliance with the covenants under the Credit Agreement during the next twelve months. Maintaining or increasing our borrowing base under our Credit Facility is dependent upon many factors, including commodities pricing, our hedge positions and our ability to raise capital to drill wells to replace produced reserves.

Senior Secured Second Lien Notes. On December 15, 2017, the Company entered into a note purchase agreement for Senior Secured Second Lien Notes (the “Second Lien”) among the Company as issuer, U.S. Bank National Association as agent and collateral agent (the “Second Lien Agent”), and certain holders that are a party thereto, and issued notes in an initial principal amount of $200 million, with a $2.0 million discount, for net proceeds of $198.0 million (the “Second Lien Facility”). The Company has the ability, subject to the satisfaction of certain conditions (including compliance with the Asset Coverage Ratio described below and the agreement of the holders to purchase such additional notes), to issue additional notes in a principal amount not to exceed $100 million. The Second Lien matures on December 15, 2024.

Interest under the Second Lien is payable quarterly and accrues at LIBOR plus 7.5%; provided that if LIBOR ceases to be available, the Second Lien provides for a mechanism to use ABR (an alternate base rate) plus 6.5% as the applicable interest rate. The definitions of LIBOR and ABR are set forth in the Second Lien. To the extent that a payment, insolvency or, at the holders’ election, another default exists and is continuing, all amounts outstanding under the Second Lien will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. Additionally, to the extent the Company were to default on the Second Lien, this would potentially trigger a cross-default on our Credit Facility.

The Company has the right, to the extent permitted under the Credit Facility and subject to the terms and conditions of the Second Lien, to optionally prepay the notes issued pursuant to the Second Lien, subject to the following repayment fees: during years one and two, a customary “make-whole” amount (which is equal to the present value of the remaining interest payments through the twenty-four month anniversary of the issuance of the Second Lien, discounted at a rate equal to the Treasury Rate plus 50 basis points) plus 2.0% of the principal amount of the notes repaid; during year three, 2.0% of the principal amount of the notes being prepaid; during year four, 1.0% of the principal amount of the notes being prepaid; and thereafter, no premium. Additionally, the Second Lien contains customary mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and incurrences of certain debt, subject to, in certain circumstances, reinvestment periods. Management has deemed the probability of mandatory prepayment due to default is remote.

The obligations under the Second Lien are secured, subject to certain exceptions and other permitted liens (including the liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit Facility, and mortgage lien on substantially all assets of the Company and certain of its subsidiaries, including a mortgage lien on oil and gas properties attributed with at least 85% of estimated PV-9 of proved reserves of the Company and its subsidiaries and 85% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions provided by the Administrative Agent of the Credit Facility.

The Second Lien contains an Asset Coverage Ratio, which is only tested (i) as a condition to issue additional notes and (ii) in connection with certain asset sales in order to determine whether the proceeds of such asset sale must be applied as a prepayment of the notes and includes in the numerator the PV-10 (defined below), based on forward strip pricing, plus the swap mark-to-market value of the commodity derivative contracts of the Company and its restricted subsidiaries and in the denominator the total net indebtedness of the Company and its restricted subsidiaries, of not less than 1.25 to 1.0 as of each date of determination (the “Asset Coverage Ratio Requirement”). PV-10 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%.

The Second Lien also contains a financial covenant measuring the ratio of total net debt to EBITDA, as defined in the purchase agreement, for the most recently completed four fiscal quarters, not to exceed 4.5 to 1.0 as of the last day of each fiscal quarter.

The Second Lien contains certain customary representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Second Lien contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Second Lien Facility to be immediately due and payable.

The debt was issued at a 1% discount of $2.0 million and the Company incurred $5.7 million in debt issuance costs. As of December 31, 2017, net amounts recorded for the Second Lien were $192.3 million, net of unamortized debt discount and debt issuance costs.


38




2017 Private Placement of Common Stock. Effective January 25, 2017 the Company entered into an agreement to sell approximately 1.4 million shares of its Common Stock in a private placement at a price of $28.50 per share, which resulted in approximately $40.0 million in gross proceeds. The shares were sold to select institutional accredited investors and proceeds were primarily used to repay Credit Facility borrowings.



39




Summary of 2017 Financial Results

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.

For the period of April 23, 2016 through December 31, 2016 (successor) the Company generated cash from Operating Activities of $47.4 million, of which $11.2 million was attributable to changes in working capital. Additionally, we realized $46.0 million in net proceeds from asset sales during this period. Cash used for property additions was $45.7 million. This included $6.3 million attributable to net pay-down of capital related payables and accrued cost as the Company paid a significant portion of the well completion costs from earlier in the year during this period. The Company’s net payments on the revolving Credit Facility were $55.0 million for this period.

For the period of January 1, 2016 through April 22, 2016 (predecessor) (which included the impact of cash transactions occurring upon emergence from bankruptcy) the Company’s operating cash flow deficit was $41.5 million, of which $15.4 million was attributable to working capital changes. During this period the Company incurred $25.6 million in legal and professional fees related to its bankruptcy and reorganization activities. While the Company paid $24.5 million for capital expenditures, it realized $48.7 million from asset sales (primarily from the sales of properties in Central Louisiana) and received $75 million in proceeds from its DIP Credit Facility. It utilized $71.9 million to pay down its Prior First Lien Credit Facility from $324.9 million to $253.0 million prior to emergence from bankruptcy. The remaining $253.0 million was refinanced with the Company’s new Credit Facility. The Company also paid $10.4 million for interest during the period and $6.5 million for debt issuance costs associated with obtaining the new Credit Facility.




40




Contractual Commitments and Obligations

Our contractual commitments for the next five years and thereafter are shown below as of December 31, 2017 (in thousands):
 
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


(1) We signed a new sub-lease on our corporate headquarters commencing on January 1, 2017. For additional discussion regarding the terms and obligations of this lease refer to Note 6 of the consolidated financial statements in this Form 10-K.
(2) Amounts shown by year are the net present value at December 31, 2017.
(3) Amounts shown represent fees for the minimum delivery obligations. Any amount of transportation utilized in excess of the minimum will reduce future year obligations.
(4) Interest is estimated using the weighted average interest rate during the quarter ended December 31, 2017 on our Credit Facility of 4.7%, see Note 4 of these consolidated financial statements in this Form 10-K. Actual interest rate is variable over the term of the facility.
(5) Obligation under Bay De Chene sales contract.

As of December 31, 2017, we had no off-balance sheet arrangements requiring disclosure pursuant to article 303(a) of Regulation S-K.

Proved Oil and Gas Reserves

During 2017, our reserves increased by approximately 280.7 MMcfe due to increases in our natural gas reserves primarily from our AWP, Fasken and Oro Grande fields. As of December 31, 2017, 45% of our total proved reserves were proved developed, compared with 51% at year-end 2016 and 80% at year-end 2015.

At December 31, 2017, our proved reserves were 1,024.4 MMcfe with a Standardized Measure of $732 million, which is an increase of approximately $327 million, or 80%, from the prior year-end levels. In 2017, our proved natural gas reserves increased 215.9 MMcf, or 34%, while our proved oil reserves increased 1.4 MMBbl, or 24%, and our NGL reserves increased 9.4 MMBbl, or 69%, for a total equivalent increase of 280.7 MMcfe, or 38%.

We have added proved reserves primarily through our drilling activities, including 317.0 MMcfe added in 2017. We obtained reasonable certainty regarding these reserve additions by applying the same methodologies that have been used historically in this area. We also sold approximately 4.9 MMcfe of reserves during 2017 in conjunction with our dispositions, as described further in Note 9 of our consolidated financial statements in this Form 10-K.

We use the preceding 12-month's average price based on closing prices on the first business day of each month, adjusted for price differentials, in calculating our average prices used in the Standardized Measure calculation. Our average natural gas price used in the Standardized Measure calculation for 2017 was $2.95 per Mcf. This average price increased from the average price of $2.43 per Mcf used for 2016. Our average oil price used in the calculation for 2017 was $50.38 per Bbl. This average price increased from the average price of $41.07 per Bbl used in the calculation for 2016.



41





Results of Operations

Revenues — Year Ended December 31, 2017 (successor), the period of April 23, 2016 through December 31, 2016 (successor), the period of January 1, 2016 through April 22, 2016 (predecessor) and the year ended December 31, 2015 (predecessor)

The tables included below set forth financial information for the year ended December 31, 2017, the period of April 23, 2016 through December 31, 2016 (successor), the period of January 1, 2016 through April 22, 2016 (predecessor) and the year ended December 31, 2015 (predecessor) which are distinct reporting periods as a result of our emergence from bankruptcy on April 22, 2016.

2017 - Our oil and gas sales in 2017 increased by 19% compared to revenues in 2016, primarily due to overall higher commodity pricing and higher natural gas volumes, offset by lower oil and NGL volumes. Average oil prices we received were 29% higher than those received during 2016, while natural gas prices were 27% higher and NGL prices were 48% higher.

2016 - Our oil and gas sales in 2016 decreased by 33% compared to revenues in 2015, primarily due to lower oil and natural gas prices and overall lower production volumes. Average oil prices we received were 16% lower than those received during 2015, while natural gas prices were 7% higher, and NGL prices were flat.

Crude oil production was 7%, 12%, 19% and 22% of our production volumes while crude oil sales revenues were 18%, 29%, 38% and 46% of oil and gas sales revenue for the year ended December 31, 2017 (successor), the period of April 23, 2016 through December 31, 2016 (successor), the period of January 1, 2016 through April 22, 2016 (predecessor) and the year ended December 31, 2015 (predecessor), respectively. Natural gas production was 82%, 76%, 68% and 66% of our production volumes while natural gas sales revenues were 71%, 61%, 52%, and 46% of oil and gas sales for the year ended December 31, 2017 (successor), the period of April 23, 2016 through December 31, 2016 (successor), the period of January 1, 2016 through April 22, 2016 (predecessor) and the year ended December 31, 2015 (predecessor), respectively.

The following tables provide information regarding the changes in the sources of our oil and gas sales and volumes for the year ended December 31, 2017 (successor), the period of April 23, 2016 through December 31, 2016 (successor), the period of January 1, 2016 through April 22, 2016 (predecessor) and the year ended December 31, 2015 (predecessor):

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

(1) For 2016 and 2015, primarily fields sold during the year including our former Lake Washington, South Bearhead Creek and Burr Ferry fields. For 2017, primarily from our Oro Grande and Uno Mas fields.


42




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