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Section 1: 10-K (2018 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, 2018
396925555_silverbowlogoblacka01.jpg
Commission File Number 1-8754
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 $0.01 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 (or for such shorter period that the registrant was required to file such reports), 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 every Interactive Data File required to be submitted 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
 þ
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, 2018, the last business day of June 2018, was approximately $108,103,125.

The number of shares of common stock outstanding as of January 31, 2019 was 11,693,052.




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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
 16
 
 
 
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 it has assembled 100,161 net acres across five operating areas. The Company's acreage position in each of its operating areas is highly contiguous and designed for optimal and efficient horizontal well development. The Company has 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 operating areas. The Company produced an average 227 MMcfe per day during the fourth quarter of 2018 and had proved reserves of 1,345 MMcfe (81% natural gas) with a PV-10 of $1.1 billion as of December 31, 2018. 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. The Company leverages this in-depth knowledge to continue to assemble high quality drilling inventory while continuously enhancing its operations to maximize returns on capital invested.

Business Strategies

Leverage technical expertise to efficiently develop our extensive drilling inventory of high rate of return Eagle Ford Shale drilling locations. As of December 31, 2018, our technical team has an average of approximately 24 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 continue to optimize our drilling techniques, shorten our drill times and steer our laterals to target high quality intervals in the Eagle Ford. We have also enhanced fracture stimulation designs optimizing proppant usage and fracture stage spacing. These factors have further enhanced the return profile of our drilling and completion operations. Our 2019 capital budget range of $250 to $260 million provides for drilling 26-27 net (29-30 gross) horizontal wells.

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 our 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 our 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 acquisitions. 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 our extensive basin-wide experience 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, 2018, the Company had approximately $215.0 million in available borrowing capacity under our Credit Facility, which we believe

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provides us with a sufficient amount of liquidity to execute our 2019 development plan and opportunistically acquire or lease additional acreage even with modest changes in the commodity environment. Our Credit Facility and Second Lien Facility, 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 price risk management program also includes hedges to limit our basis differential to Henry Hub pricing. We take a systematic approach to hedging and periodically add hedges to our portfolio in an effort to protect the rates of returns on our drilling program. As of December 31, 2018, we had approximately 65% of total production volumes hedged for full year 2019 using the mid-point of production guidance of 225 to 239 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, 2018, we had 100,161 net acres in the Eagle Ford and roughly 677 gross horizontal drilling locations. Approximately 59% of our estimated proved reserves at December 31, 2018 were undeveloped. We operate essentially all of our proved reserves and have an average working interest of approximately 85% 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 liquids-rich areas. Our average daily production for the full year 2018 was 185 MMcfe/d and our proved developed reserves as of December 31, 2018 were 555 Bcfe. Our portfolio of properties and our 2019 capital plan couples this strong base of production and reserves with low risk in-fill drilling while increasing our exposure to liquids opportunities. In our La Salle Condensate area in Artesia, we turned five net wells online in 2018 and are pleased with the initial performance. Based on these results, we plan to accelerate the development of Artesia in 2019 by drilling 18-19 net (21-22 gross) wells which will increase our oil and natural gas liquids production. Furthermore, we are continuing to delineate our Southern Eagle Ford Gas fairway, which includes Oro Grande, Uno Mas and southern AWP. We have identified a total of 395 drilling locations in this area prospective for lower and upper Eagle Ford and plan on drilling three net wells in 2019. In addition, our recent success in our Oro Grande area has allowed us to capture significant upside associated with our blocky and contiguous 27,085 net acre position. We believe that our balanced portfolio and development approach allow us to deliver low-risk production and proved reserve growth and expose our 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 and oil regions of North America. Our proximity to the Gulf Coast affords us much lower commodity basis differentials and meaningfully higher price realizations when compared to other domestic basins. For instance, in 2018 our average natural gas basis differentials to NYMEX were positive $0.15/Mcfe versus $0.52/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. As of December 31, 2018, we employed 22 oil and gas technical professionals, including geophysicists, geologists, drilling, completion, production and reservoir engineers, and other oil and gas professionals who collectively have an average of approximately 24 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 EURs and maximize our per-well returns. Our enhanced completion designs include tighter fracture stage spacing as well as optimized proppant loadings and intensity. Additionally, we rely on advanced technologies to better define geologic risk and enhance the results of our drilling efforts. We are a leader in drilling some of the best natural gas wells in the play. 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 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. Additionally, we continually seek to optimize our production operations with the objective of reducing our operating

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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, 2018, the Company had approximately $215.0 million in available borrowing capacity under our Credit Facility, which we believe provides us with a sufficient amount of liquidity to execute our 2019 development plan and opportunistically acquire or lease additional acreage even with modest changes in the commodity environment. Our Credit Facility and Second Lien Facility, maturing in April 2022 and December 2024, respectively, are our only stated debt maturities. As of December 31, 2018, we had $195.0 million drawn on our $410.0 million borrowing base under the Credit Facility.

Property Overview

The Company's operations are focused in five fields located in the Eagle Ford Shale trend of South Texas. The following table sets forth information regarding its Eagle Ford fields in 2018:
Fields
 
Net Acreage
 
2018 Production (Mcfe/d)
 
Gas as % of 2018 Production
 
2018 Wells Net Drilled
 
2018 Wells Net Completed
Artesia
 
12,052

 
28,805

 
45
%
 
5

 
5

AWP
 
35,630

 
28,685

 
53
%
 
7

 
5

Fasken
 
7,742

 
98,566

 
100
%
 
14

 
15

Oro Grande
 
27,085

 
19,245

 
100
%
 
5

 
5

Uno Mas
 
17,652

 
9,510

 
97
%
 
2

 
2

Other
 

 
203

 
56
%
 

 

Total
 
100,161

 
185,014

 
84
%
 
33

 
32


The following table sets forth information regarding the Company's 2018 year-end proved reserves of 1,345.4 MMcfe and production of 67.5 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 (MMcfe)
Artesia
 
87.0

 
166.2

 
253.2

 
18.8
%
 
54.5
%
 
10,514

AWP
 
86.3

 
186.6

 
272.9

 
20.3
%
 
40.4
%
 
10,470

Fasken
 
311.0

 
310.5

 
621.5

 
46.2
%
 
%
 
35,976

Oro Grande
 
50.7

 
127.2

 
177.9

 
13.2
%
 
%
 
7,024

Uno Mas
 
19.3

 

 
19.3

 
1.4
%
 
3.0
%
 
3,471

Other
 
0.6

 

 
0.6

 
%
 
36.1
%
 
74

Total
 
554.9

 
790.5

 
1,345.4

 
100.0
%
 
18.5
%
 
67,530


Oil and Natural Gas Reserves

The following tables present information regarding proved oil and natural gas reserves attributable to the Company's interests in producing properties as of December 31, 2018, 2017 and 2016. 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. (“Gruy”), independent petroleum engineers, prepared the Company's proved reserves report as of December 31, 2018, 2017 and 2016.

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 Gruy to ensure the accuracy and completeness of the data utilized for the preparation of the 2018, 2017 and 2016 reserve reports. All information from the Company's secure engineering database as well as geographic maps, well logs, production tests and other pertinent data were provided to Gruy.

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

6




Board of Directors review the reserve data periodically and the independent Board members meet with Gruy in executive sessions at least annually.

The technical person at Gruy primarily responsible for overseeing preparation of the 2018, 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.

The Company's Chief Reservoir Engineer, the primary technical person responsible for overseeing the preparation of its 2018, 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 the Company's proved reserves, Standardized Measure and PV-10 (PV-10 is a non-GAAP measure defined below), as of December 31, 2018, 2017 and 2016 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. The Company has 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 were used to estimate the Company's SEC proved reserve volumes, year-end Standardized Measure and PV-10. The 12-month 2018 average adjusted prices after differentials were $3.04 per Mcf of natural gas, $66.96 per barrel of oil, and $26.63 per barrel of NGL, compared to $2.95 per Mcf of natural gas, $50.38 per barrel of oil, and $20.32 per barrel of NGL for 2017 and $2.43 per Mcf of natural gas, $41.07 per barrel of oil, and $16.13 per barrel of NGL for 2016.

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. The Company believes 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. The Company uses the PV-10 Value for comparison against its debt balances, to evaluate properties that are bought and sold and to assess the potential return on investment in its 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. The Company's PV-10 Value and the Standardized Measure do not purport to represent the fair value of the Company's 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)
2018
 
2017
 
2016
PV-10 Value
$
1,128

 
$
805

 
$
442

Less: Future income taxes (discounted at 10%)
134

 
73

 
35

Standardized Measure of Discounted Future Net Cash Flows
$
994

 
$
732

 
$
407


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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, 2018 and 2017. 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, 2018, the Company had estimated proved reserves of 1,345.4 MMcfe with a Standardized Measure of $994 million and PV-10 Value of $1.1 billion. This is an increase of approximately 321 MMcfe from the Company's year-end 2017 proved reserves quantities primarily due to drilling and an expanded development plan. The Company's total proved reserves at December 31, 2018 were approximately 6% crude oil, 81% natural gas, and 13% NGLs, while 41% of its total proved reserves were developed. Essentially all of the Company's proved reserves are located in Texas. The following amounts shown in MMcfe below are based on an oil and natural gas liquids conversion factor of 1 Bbl to 6 Mcf:
Estimated Proved Natural Gas, Oil and NGL Reserves
 
As of December 31,
 
 
2018
 
2017
 
2016
Natural gas reserves (Mcf):
 
 
 
 
 
 
   Proved developed
 
466,129

 
377,506

 
312,125

   Proved undeveloped (1)
 
630,279

 
465,230

 
314,664

      Total
 
1,096,408

 
842,736

 
626,789

Oil reserves (MBbl):
 
 
 
 
 
 
   Proved developed
 
5,507

 
5,027

 
4,513

   Proved undeveloped (1)
 
7,271

 
2,133

 
1,265

      Total
 
12,779

 
7,160

 
5,778

NGL reserves (MBbl):
 
 
 
 
 
 
   Proved developed
 
9,287

 
8,431

 
6,505

   Proved undeveloped (1)
 
19,427

 
14,690

 
7,209

      Total
 
28,714

 
23,121

 
13,714

 
 
 
 
 
 
 
Total Estimated Reserves (Mcfe) (1)(2)
 
1,345,362

 
1,024,422

 
743,742

 
 
 
 
 
 
 
Standardized Measure of Discounted Future Net Cash Flows (in millions) (3)
 
$
994

 
$
732

 
$
407

 
 
 
 
 
 
 
PV-10 by reserve category
 
 
 
 
 
 
Proved developed
 
$
681

 
$
470

 
$
252

Proved undeveloped
 
447

 
335

 
190

Total PV-10 Value (3)
 
$
1,128

 
$
805

 
$
442


(1) The increases in 2018 and 2017 were primarily attributable to extensions added based on drilling results and leasing of adjacent acreage.
(2) The reserve volumes exclude natural gas consumed in operations.
(3) The Standardized Measure and PV-10 Values as of December 31, 2018, 2017 and 2016 are net of $3.7 million, $7.1 million and $33.1 million of plugging and abandonment costs, respectively.

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 the Company's proved undeveloped reserves as of December 31, 2018:
Year Added
 
Volume
(MMcfe)
 
% of PUD
Volumes
2018
 
331.3
 
42
%
2017
 
298.1
 
38
%
2016 (1)
 
161.0
 
20
%
2015
 
0.0
 
%
2014
 
0.0
 
%
Total
 
790.4
 
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 2018, the Company's proved undeveloped reserves increased by approximately 224.3 MMcfe primarily due to additions of undeveloped reserves in the Company's Artesia and Oro Grande fields, partially offset by 2017 undeveloped reserves which were converted to proved developed reserves during 2018. The Company also incurred approximately $87.6 million in capital expenditures during the year which resulted in the conversion of 95.8 MMcfe of its December 31, 2017 proved undeveloped reserves to proved developed reserves, primarily in the Fasken field.

The PV-10 Value from the Company's proved undeveloped reserves was $447 million at December 31, 2018, which was approximately 40% of its total PV-10 Value of $1.1 billion. The PV-10 Value of the Company's proved undeveloped reserves, by year of booking was 47% in 2018, 35% in 2017 and 17% in 2016 (PV-10 is a non-GAAP measure defined above).

Sensitivity of Reserves to Pricing

As of December 31, 2018, a 5% increase in natural gas pricing would increase the Company's total estimated proved reserves by approximately 1.7 MMcfe and would increase the PV-10 Value by approximately $71.6 million. Similarly, a 5% decrease in natural gas pricing would decrease the Company's total estimated proved reserves by approximately 1.9 MMcfe and would decrease the PV-10 Value by approximately $71.6 million.

As of December 31, 2018, a 5% increase in oil and NGL pricing would increase the Company's total estimated proved reserves by approximately 0.8 MMcfe, and would increase the PV-10 Value by approximately $37.9 million. Similarly, a 5% decrease in oil and NGL pricing would decrease the Company's total estimated proved reserves by approximately 0.9 MMcfe and would decrease the PV-10 Value by approximately $37.8 million.



9




Oil and Gas Wells

The following table sets forth the total gross and net wells in which the Company owned an interest at the following dates:
 
Oil Wells
 
Gas Wells
 
Total
Wells(1)
December 31, 2018
 
 
 
 
 
Gross (1)
78

 
223

 
301

Net
76.1

 
178.1

 
254.1

December 31, 2017
 
 
 
 
 
Gross (1)
166

 
543

 
709

Net
161.7

 
500.0

 
661.7

December 31, 2016
 
 
 
 
 
Gross (1)
175

 
604

 
779

Net
172.1

 
558.7

 
730.8


(1)
Excludes 5, 8, and 9 service wells in 2018, 2017 and 2016.

Oil and Gas Acreage

The following table sets forth the developed and undeveloped leasehold acreage held by the Company at December 31, 2018:
 
Developed
 
Undeveloped
 
Gross
 
Net
 
Gross
 
Net
Texas (1)
40,039

 
36,191

 
73,092

 
63,970

Colorado(2)

 

 
3,099

 
3,099

Louisiana
5,084

 
4,775

 
4,920

 
4,478

Wyoming

 

 
3,013

 
1,442

Total
45,123

 
40,966

 
84,124

 
72,989


(1)
The Company's total acreage in Eagle Ford includes 111,925 gross and 100,161 net acres. The Company has option rights to acquire 4,513 gross and net additional acres in the Eagle Ford in 2019.
(2)
The Company's leasehold acreage in Colorado is exploration property, which is evaluated, inactive and will expire in 2019 unless otherwise drilled, sold or farmed out. The Company has no plans to extend the leases for the Colorado acreage and plans to let the leases expire.

As of December 31, 2018, the Company's net undeveloped acreage subject to expiration over the next three years, if not renewed, is approximately 6% in 2019, 35% in 2020 and 4% in 2021. In most cases, acreage scheduled to expire can be held through drilling operations or the Company can exercise extension options. The exploration potential of all undeveloped acreage is fully evaluated before expiration. In each fiscal year where undeveloped acreage is subject to expiration, our intent is to reduce the expirations through either development or extensions, if we believe it is commercially advantageous to do so.


10




Drilling and Other Exploratory and Development Activities

The following table sets forth the results of the Company's drilling and completion activities during the years ended December 31, 2018, 2017 and 2016:
 
 
 
 
Gross Wells
 
Net Wells
Year
 
Type of Well
 
Total
 
Producing
 
Dry
 
Total
 
Producing
 
Dry
2018
 
Exploratory
 

 

 

 

 

 

 
 
Development
 
37

 
37

 

 
32.7

 
32.7

 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2017
 
Exploratory
 

 

 

 

 

 

 
 
Development
 
27

 
27

 

 
22.0

 
22.0

 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2016
 
Exploratory
 

 

 

 

 

 

 
 
Development
 
8

 
8

 

 
5.1

 
5.1

 


Recent Activities

As of December 31, 2018, we were in the process of drilling three wells in our Fasken field where we have a 64% working interest. These wells will be completed in the first quarter of 2019.

Operations

The Company generally seeks to be the operator of the wells in which it has a significant economic interest. As operator, the Company designs and manages the development of a well and supervises operation and maintenance activities on a day-to-day basis. The Company does not own drilling rigs or other oil field services equipment used for drilling or maintaining wells on properties it operates. Independent contractors supervised by the Company provide this equipment and personnel. The Company employs drilling, production, and reservoir engineers, geologists, and other specialists who work to improve production rates, increase reserves, and lower the cost of operating the Company's oil and natural gas properties.

Operations on the Company's oil and natural gas properties are customarily accounted for in accordance with Council of Petroleum Accountants Societies' guidelines. The Company charges a monthly per-well supervision fee to the wells it operates including its wells in which it owns 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 2018 totaled $4.6 million and ranged from $125 to $1,533 per well per month.


11




Marketing of Production

The Company typically sells its oil and natural gas production at market prices near the wellhead or at a central point after gathering and/or processing. The Company usually sells its natural gas in the spot market on a monthly basis, while it sells its oil at prevailing market prices. The Company does not refine any oil it produces. For the years ended December 31, 2018 and 2017, parties which accounted for approximately 10% or more of the Company's total oil and gas receipts were as follows:

Sellers greater than 10%
Year Ended December 31, 2018
 
Year Ended December 31, 2017
Kinder Morgan
37
%
 
48
%


The Company has gas processing and gathering agreements with Southcross Energy for a majority of the Company's natural gas production in the AWP area. Oil production is transported to market by truck and sold at prevailing market prices.

The Company has a gas gathering agreement with Howard Energy providing for the transportation of the Company's 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, the Company also has a connection with the Navarro gathering system into which it may deliver natural gas from time to time.

The Company has an agreement with Eagle Ford Gathering LLC that provides for the gathering and processing for almost all of its natural gas production in the Artesia 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 area, the Company's 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.

The following table summarizes sales volumes, sales prices, and production cost information for the Company's net oil, NGL and natural gas production for the years ended December 31, 2018 and 2017:

 
 
Year Ended December 31,
All Fields

2018

2017
Net Sales Volume:




   Oil (MBbls)

688


685

   Natural Gas Liquids (MBbls)

1,123


1,046

Natural gas (MMcf)

56,665


45,751

      Total (MMcfe)

67,530


56,135






Average Sales Price:




   Oil (Per Bbl)

$
65.93


$
50.98

   Natural Gas Liquids (Per Bbl)

$
25.51


$
21.61

   Natural gas (Per Mcf)

$
3.23


$
3.03

   Total (Per Mcfe)

$
3.81


$
3.49






Average Production Cost (Per Mcfe sold) (1)

$
0.61


$
0.74


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


12




The following table provides a summary of the Company's sales volumes, average sales prices, and average production costs for its fields with proved reserves greater than 15% of total proved reserves. These fields account for approximately 85% of the Company's proved reserves based on total MMcfe as of December 31, 2018:
 
 
Year Ended December 31,
Fasken
 
2018
 
2017
Net Sales Volume:
 
 
 
 
   Natural Gas Liquids (MBbls)
 
2

 
2

   Natural gas (MMcf) (1)
 
35,963

 
33,757

      Total (MMcfe)
 
35,976

 
33,769

 
 
 
 
 
Average Sales Price:
 
 
 
 
   Natural Gas Liquids (Per Bbl)
 
$
24.96

 
$
18.13

   Natural gas (Per Mcf)
 
$
3.21

 
$
3.02

   Total (Per Mcfe)
 
$
3.21

 
$
3.02

 
 
 
 
 
Average Production Cost (Per Mcfe sold) (2)
 
$
0.60

 
$
0.59


(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.

 
 
Year Ended December 31,
AWP
 
2018
 
2017
Net Sales Volume:
 
 
 
 
   Oil (MBbls)
 
347

 
427

   Natural Gas Liquids (MBbls)
 
480

 
598

   Natural gas (MMcf) (1)
 
5,510

 
6,857

Total (MMcfe)
 
10,470

 
13,004

 
 
 
 
 
Average Sales Price:
 
 
 
 
   Oil (Per Bbl)
 
$
65.64

 
$
50.40

   Natural Gas Liquids (Per Bbl)
 
$
25.84

 
$
20.87

   Natural gas (Per Mcf)
 
$
3.20

 
$
3.09

   Total (Per Mcfe)
 
$
5.04

 
$
4.25

 
 
 
 
 
Average Production Cost (Per Mcfe sold) (2)
 
$
0.88

 
$
1.25


(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.


13




 
 
Year Ended December 31,
Artesia
 
2018
 
2017
Net Sales Volume:
 
 
 
 
   Oil (MBbls)
 
336

 
249

   Natural Gas Liquids (MBbls)
 
622

 
443

   Natural gas (MMcf) (1)
 
4,763

 
3,239

Total (MMcfe)
 
10,514

 
7,393

 
 
 
 
 
Average Sales Price:
 
 
 
 
   Oil (Per Bbl)
 
$
66.29

 
$
52.78

   Natural Gas Liquids (Per Bbl)
 
$
25.54

 
$
22.67

   Natural gas (Per Mcf)
 
$
3.27

 
$
3.08

   Total (Per Mcfe)
 
$
5.11

 
$
4.49

 
 
 
 
 
Average Production Cost (Per Mcfe sold) (2)
 
$
0.50

 
$
0.62


(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

The Company's 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 the Company to substantial liability due to pollution and other environmental damage. The Company maintains comprehensive insurance coverage, including general liability insurance, operators extra expense insurance, and property damage insurance. The Company's standing Insurable Risk Advisory Team, which includes individuals from operations, drilling, facilities, legal, health safety and environmental and finance departments, meets regularly to evaluate risks, review property values, review and monitor claims, review market conditions and assist with the selection of coverages. The Company believes that its 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 the Company. 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 its production against declines in oil and natural gas prices through the first quarter of 2021. For additional discussion related to the Company's price-risk policy, refer to Note 5 of the consolidated financial statements in this Form 10-K.

Competition

The Company operates 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 the Company's. The market for oil and natural gas properties is highly competitive and the Company may lack technological information or expertise available to other bidders. The Company may incur higher costs or be unable to acquire and develop desirable properties at costs the Company considers reasonable because of this competition. The Company's ability to replace and expand its reserve base depends on its continued ability to attract and retain quality personnel and identify and acquire suitable producing properties and prospects for future drilling and acquisition.


14




Environmental and Occupational Health and Safety Matters

The Company's 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, operational, monitoring, and reporting requirements and has been relied upon by the EPA 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 (“ESA”), 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.

Additionally, there exist regional, state and local jurisdictions in the United States where the Company’s operations are conducted that also have, or are developing or considering developing, similar environmental and occupational health and safety laws and regulations governing many of these same types of activities. While the legal requirements imposed in state and local jurisdictions 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 restrict, delay or cancel the permitting, development or expansion of the Company’s operations or substantially increase the cost of doing business. Additionally, the Company’s operations may require state-law based permits in addition to federal permits, requiring state agencies to consider a range of issues, many the same as federal agencies, including, among other things, a project's impact on wildlife and their habitats, historic and archaeological sites, aesthetics, agricultural operations, and scenic areas. These operations also are subject to a variety of local environmental and regulatory requirements, including land use, zoning, building, and transportation requirements.

15




Moreover, whether at the federal, tribal, regional, state and local levels, environmental and occupational health and safety laws and regulations may arise in the future to address potential environmental concerns such as air emissions, water discharges and disposals or other releases to surface and below-ground soils and groundwater or to address perceived health or safety-related concerns such as oil and natural gas development in close proximity to specific occupied structures and/or certain environmentally-sensitive or recreational areas. Any such future developments are expected to have a considerable impact on the Company’s business and results of 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 investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects; and the issuance of injunctions restricting or prohibiting some or all of the Company's 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 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.

The trend in environmental regulation is to place more restrictions on activities that may affect the environment and, thus, any new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement that result in more stringent and costly pollution control equipment, the occurrence of restrictions, delays or cancellations in the permitting or performance of projects, or waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on the Company’s financial condition and results of operations. The Company has 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, the Company's environmental compliance costs have not had a material adverse effect on its 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 its business and operational results.

Employees

As of December 31, 2018, the Company employed 88 people. None of the Company's employees were represented by a union and relations with employees are considered to be good.

Facilities

At December 31, 2018, the Company 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

The Company's 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 its 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 the Company's web site at www.sbow.com as soon as reasonably practicable after the Company electronically files 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, the Company has adopted a Code of Ethics for Senior Financial Officers and the Principal Executive Officers (“Code of Ethics”). The Company has posted this Code of Ethics on its website, where it also intends to post any waivers from or amendments to this Code of Ethics.



16




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. 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 2019 capital expenditure budget, including expenditures for leasehold acquisitions, drilling and infrastructure and fulfillment of abandonment obligations is expected to be in the range of $250 million and $260 million. We had approximately $308.3 million of capital expenditures in 2018. 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 Debt Facilities, as defined below, contain operating and financial restrictions that may restrict our business and financing activities.

Our Credit Facility and Second Lien Facility (collectively “Debt 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;
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, divide, merge or transfer all or substantially all of our assets;

17




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 Debt Facilities may be affected by events beyond our control. If market or other economic conditions deteriorate or if oil and natural gas prices decline from their current level for an extended period of time, our ability to comply with these covenants may be impaired. A failure to comply with the covenants, ratios or tests in our Debt Facilities or any future indebtedness could result in an event of default under our Debt 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 Debt 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.

The borrowing base under our Credit Facility is redetermined at least semi-annually, based in part on assumptions of the administrative agent with respect to, among other things, crude oil and natural gas prices. A negative adjustment to the borrowing base could occur if crude oil and natural gas prices used by the lenders are significantly lower than those used in the last redetermination, including as result of a decline in commodity prices or an expectation that reduced prices will continue. The next redetermination of our borrowing base in scheduled to occur in spring 2019. In addition, the portion of our borrowing base made available to us for borrowing is subject to the terms and covenants of our Credit Facility, including compliance with the ratios and other financial covenants of such facility. In the event that the amount outstanding under our Credit Facility exceeds the redetermined borrowing base, we could be forced to repay a portion of our borrowings.

In addition, our obligations under the Debt 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 (determined using commodity price assumptions by the Administrative Agent of the Credit Facility) 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 Facility), and if we are unable to repay our indebtedness under the Debt Facilities, (including any amount of borrowings in excess of the borrowing base resulting from a redetermination of our Credit Facility) 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 4,294 net acres that could potentially expire during fiscal year 2019, representing approximately 6% of our net undeveloped acreage, including 3,099 net acres in Colorado that are scheduled to expire. We have no plans to extend the leases for the Colorado acreage and plan to let the leases 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.



18




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 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 the past 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. 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 2018 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.

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

19




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.

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 the properties upon which the Company conducts operations were acquired from third parties, whose actions with respect to the management and disposal or release of hydrocarbons, hazardous substances or wastes at or from such properties were not under the Company’s control. Moreover, 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. New laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement relating to environmental requirements may occur, resulting in the occurrence of restrictions, delays or cancellations 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 of these 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 federal Bureau of Land Management (“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.


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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 restrictions, delays or cancellations 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. We could be exposed to liabilities for cleanup costs, natural resource damages, and other damages under these laws and regulations, with certain of these legal requirements imposing strict liability for such damages and costs, even though the conduct in pursuing the Company’s operations was lawful at the time it occurred or the conduct resulting in such damage and costs were caused by prior operators or other third-parties

Environmental laws and regulations in the United States are subject to change in the future, possibly resulting in more stringent legal requirements. If existing environmental regulatory requirements or enforcement policies change or new regulatory or enforcement initiatives are developed and implemented in the future, the partnership may be required to make significant, unanticipated capital and operating expenditures with respect to the continued operations of the Company. Examples of recent environmental regulations include the following:

Ground-Level Ozone Standards. In 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 parts per billion to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. In 2017 and 2018, the EPA issued area designations with respect to ground-level ozone as either “attainment/unclassifiable,” unclassifiable” or “non-attainment.” Additionally, in November 2018, the EPA issued final requirements that apply to state, local, and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. State implementation of the revised NAAQS could, among other things, require installation of new emission controls on some of the Company’s equipment, result in longer permitting timelines, and significantly increase the partnership’s capital expenditures and operating costs arising from the program’s operations.

EPA Review of Drilling Waste Classification. Drilling, fluids, produced water and most of the other wastes associated with the exploration, development and production of oil or natural gas, if properly handled, are currently exempt from regulation as hazardous waste under the RCRA and instead, are regulated under RCRA’s less stringent non-hazardous waste provisions. However, pursuant to a consent decree issued by the U.S. District Court for the District of Columbia in 2016, the EPA is required to propose by no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations that could result in oil and natural gas exploration and production wastes being regulated as hazardous wastes, or sign a determination that revision of the regulations is unnecessary. If EPA proposes a rulemaking for revised oil and natural gas waste regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021.

Federal Jurisdiction over Waters of the United States. In 2015, the EPA and U.S. Army Corps of Engineers (“Corps”) released a final rule outlining federal jurisdictional reach under the Clean Water Act, over waters of the United States, including wetlands. Beginning in the first quarter of 2017, the EPA and the Corps agreed to reconsider the 2015 rule and, thereafter, the agencies have (i) published a proposed rule in July 2017 to rescind the 2015 rule and recodify the regulatory text that governed waters of the United States prior to promulgation of the 2015 rule, (ii) published a final rule in February 2018 adding a February 6, 2020 applicable date to the 2015 rule, and (iii) published a proposed rule in December 2018 re-defining the Clean Water Act’s jurisdiction over waters of the United States for which the agencies will seek public comment. The 2015 and February 2018 final rules are being challenged by various factions in federal district court and implementation of the 2015 rule has been enjoined in twenty-eight states pending resolution of the various federal district court challenges. As a result of these legal developments, future implementation of the 2015 rule or a revised rule is uncertain at this time. To the extent that the 2015 rule or a revised rule expands the scope of the Clean Water Act’s jurisdiction in areas where the Company conducts operations, the Company could incur increased costs and restrictions,

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delays or cancellations in permitting or projects, which developments could expose the partnership to significant costs and liabilities.

Additionally, the federal Occupational Safety and Health Act and analogous state occupational safety and health laws require the program manager to organize information about materials, some of which may be hazardous or toxic, that are used, released or produced in the Company’s operations. Moreover, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in the Company’s operations and that this information be provided to employees, state and local government authorities and citizens.

Compliance of the Company with these regulations or other laws, regulations and regulatory initiatives, or any other new environmental and occupational health and safety legal requirements could, among other things, require the Company to install new or modified emission controls on equipment or processes, incur longer permitting timelines, and incur significantly increased capital or operating expenditures, which costs may be significant. Moreover, any failure of the Company’s operations to comply with applicable environmental laws and regulations may result in governmental authorities taking actions against the Company that could adversely impact its operations and financial condition.

The ESA 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 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 the Company’s operations may be located in or near areas that are designated as habitat for endangered or threatened species and, in these areas, the Company may be obligated to develop and implement plans to avoid potential adverse effects to protected species and their habitats, and the Company may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when its 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 the Company’s 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 the Company to incur increased costs arising from species protection measures, time delays or limitations or cancellations on its exploration and production activities, which costs, delays, limitations or cancellations could have an adverse impact on the Company’s ability to develop and produce reserves. If the Company were to have a portion of its leases designated as critical or suitable habitat, it could adversely impact the value of its 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 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.





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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 late 2016, the 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, the EPA has asserted regulatory authority pursuant to the SDWA Underground Injection Control (“UIC”) program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities as well as published an Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. The EPA also issued final regulations in 2012 and in 2016 under the CAA that govern performance standards, including standards for the capture of air emissions released during oil and natural gas hydraulic fracturing. Moreover, in 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. Also, the BLM published a final rule in 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands but the BLM rescinded the 2015 rule in late 2017; however, litigation challenging the BLM’s decision to rescind the 2015 rule is pending in federal district 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 where we conduct operations, 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 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 restrictions, delays or cancellation 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 restrictions, delays or cancellations with respect to 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

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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 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. 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 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. In Texas, 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.

Climate change legislation or regulations restricting emissions of greenhouse gases (“GHGs”) 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 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 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. Additionally, in 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.

Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In 2016, the EPA published a New Source Performance Standard, 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 expand previously issued New Source Performance Standards 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 2017, the EPA published a proposed rule to stay certain portions of the June 2016 standards for two years but the EPA has not yet published a final rule. Rather, in February 2018, the EPA finalized amendments to certain requirements of the 2016 final rule and, in September 2018, the agency proposed additional amendments that included rescission or revision of certain requirements such as fugitive emission monitoring frequency. In another example, in 2016, the BLM published a final rule to reduce methane emissions by regulating venting, flaring, and leaking from oil and natural gas operations on federal and Indian lands. However, in September 2018, the BLM published a final rule that rescinds most of the requirements in the 2016 final rule

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and codifies the BLM’s prior approach to venting and flaring. The rescission of the requirements in the 2016 final rule is being challenged in federal court. These rules, should they remain or be placed in effect, and any other new methane emission standards imposed on the oil and natural gas sector could result in increased costs to the Company’s operations as well as result in restrictions, delays or cancellations in such operations, which costs, restrictions, delays or cancellations could adversely affect our business. Additionally, in April 2016, the United States joined other counties in entering into a United Nations-sponsored non-binding agreement negotiated in Paris, France (“Paris Agreement”) for participating countries to reduce their GHG emissions over time. 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. 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 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 natural gas, which could reduce the demand for, or lower the value of, the oil and natural gas the Company produces. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil and natural gas will continue to represent a major share of global energy use through 2040, and other studies by the private sector project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities.

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.

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

Legislation 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) eliminated the deduction for certain domestic production activities, (ii) imposed new limitations on the utilization of net operating losses, (iii) eliminated the exception under Section 162(m) for qualified performance-based compensation and (iv) provided 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. The Company completed its review of previously recorded provisional income tax amounts related to its deferred tax assets impacted by the Act, and concluded that additional information, interpretation and guidance that became available during the twelve-month measurement period did not alter the Company’s application of tax law in remeasuring gross deferred tax assets and related valuation allowances. There were no material adjustments deemed necessary in the period ended December 31, 2018 and the Company’s accounting for the Act is now final.

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.


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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, 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.

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 15.6%, respectively, of our outstanding common stock. SVP currently has a right to nominate two of our directors under our director nominating agreement described below. 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.


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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;
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.


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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.



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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.
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.
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

29




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

Common Stock, 2018 and 2017

Our common stock is traded on the New York Stock Exchange under the symbol “SBOW”. Since inception, no cash dividends have been declared on our common stock. Cash dividends are restricted under the terms of our credit agreements, and we presently intend to continue a policy of using retained earnings for expansion of our business.

We had approximately 98 stockholders of record as of December 31, 2018.

Stock Repurchase

There were no repurchases of our common stock during the fourth quarter of 2018.
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, 2018 see Note 7 of the consolidated financial statements included in this Form 10-K.


31




Share Performance Graph
The following graph compares the cumulative total return to our stockholders on our common stock beginning October 4, 2016 through December 31, 2018, relative to the cumulative returns of the Standard and Poor's 500 Index (“S&P 500”) and the Standard and Poor's 500 Oil & Gas Exploration & Production Index (“S&P O&G E&P”) for the same period. The comparison was prepared based upon the assumption that $100 was invested on October 4, 2016 in each of the following: the common stock of SilverBow Resources, the S&P 500 and the S&P O&G E&P.
The graph begins on October 4, 2016, the date that our common stock began trading on the OTCQX market following our emergence from bankruptcy under the ticker “SWTF.” We successfully reorganized and emerged from bankruptcy on April 22, 2016; however, our former common stock was canceled as part of the reorganization and the new common stock that was issued upon our emergence was not trading on an exchange or platform until October 4, 2016. On May 5, 2017, through amendments to its Certificate of Incorporation and Bylaws, the Company rebranded and changed its name from Swift Energy Company to SilverBow Resources, Inc. Additionally, the Company’s common stock began trading on the New York Stock Exchange under the ticker symbol “SBOW” on May 5, 2017.
396925555_chart-72cd4c3f6b770fd9aaa.jpg
The performance graph above is being furnished solely to accompany this Report pursuant to Item 201(e) of Regulation S-K, is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

Item 6. Selected Financial Data

Not required.



32




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 the Company's financial information and its audited consolidated financial statements and accompanying notes for the years ended December 31, 2018 and 2017 included in this Form 10-K. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 42 of this report.

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 it has assembled 100,161 net acres across five operating areas. The Company's acreage position in each of its operating areas is highly contiguous and designed for optimal and efficient horizontal well development. The Company has 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 operating areas. The Company produced an average 227 MMcfe per day during the fourth quarter of 2018 and as of December 31, 2018 had proved reserves of 1,345 MMcfe (81% natural gas) with a PV-10 of $1.1 billion. 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. The Company leverages this in-depth knowledge to continue to assemble high quality drilling inventory while continuously enhancing its operations to maximize returns on capital invested.

Operational Results

The Company continues to optimize completion techniques in order to enhance well performance across its portfolio. The following table and discussion highlights the Company's drilling and completion schedule for 2018:
Fields
 
Net Acreage
 
2018 Production (Mcfe/d)
 
Gas as % of 2018 Production
 
2018 Net Wells Drilled
 
2018 Net Wells Completed
Artesia
 
12,052

 
28,805

 
45
%
 
5

 
5

AWP
 
35,630

 
28,685

 
53
%
 
7

 
5

Fasken
 
7,742

 
98,566

 
100
%
 
14

 
15

Oro Grande
 
27,085

 
19,245

 
100
%
 
5

 
5

Uno Mas
 
17,652

 
9,510

 
97
%
 
2

 
2

Other (1)
 

 
203

 
56
%
 

 

Total
 
100,161

 
185,014

 
84
%
 
33

 
32

(1) Other includes non-core properties.
    
During the fourth quarter 2018, the Company brought 12 net wells online. For the full year, the Company drilled 33 net wells and completed 32 net wells. The number of wells completed is above the Company's prior guidance of 25-27 net wells. The Company drilled in all areas of its portfolio during 2018 and more recently has increased its investment in liquids opportunities.

In the Webb County Gas area, which includes Fasken, the Company brought 13 net wells online in 2018. The Company focused on developing its high return Lower Eagle Ford wells and strategically appraising and delineating its Upper Eagle Ford locations. The Fasken development demonstrates the Company’s shift to selectively employing high intensity slickwater fracs across its portfolio. For the second half of 2018, the Company averaged a completion intensity of approximately 2,700 pounds of proppant per lateral foot and 59 barrels of fluid per lateral foot, an increase of 71% and 161%, respectively, from the first half of the year. The Company continues to value Fasken's consistent performance, low operating expense and upside potential.

In the La Salle Condensate area, which includes Artesia, the Company brought five net wells online in 2018. Due to operational improvements and service price reductions, the Company realized an 18% reduction in total well cost per foot from a two-well pad that was brought online in the third quarter and a three-well pad that was brought online in the fourth quarter. All five wells were completed similarly and averaged approximately 2,400 pounds of proppant per lateral foot and 64 barrels of slickwater fluid

33




per lateral foot. Based on these results, the Company plans to accelerate the development of the La Salle Condensate area in 2019, which it believes will increase its oil and natural gas liquids production.

In the Southern Eagle Ford Gas fairway, which includes Oro Grande, Uno Mas and south AWP, the Company carried forward its successful delineation and appraisal across its 60,000 gross acre position. The Company continues to realize operational efficiencies with its NMC 6H well costing 30% less and being drilled 35% faster than the average of its NMC 1H through NMC 5H wells. In addition, the Company continued to add to its position through leasing and acreage trades. The Company swapped 2,300 net isolated acres for 4,300 net acres contiguous to its Southern Eagle Ford Gas area. In total, this acreage trade added 35 gross drilling locations. Additionally, the acreage the Company traded away was stranded and would have required a significant amount of midstream capital investment in order to develop.

In the McMullen Oil area, which includes north AWP and where the Company had not been active for several years, the team set a Company record by drilling an 11,400 foot lateral in the fourth quarter with a second well on this pad also exceeding 11,000 feet. During 2018, the Company decreased its drilling cost per lateral foot on a recent three-well pad by 27% compared to a three-well pad drilled in 2014. These developments have affected both the cost and the speed of drilling, with the team setting a spud to total depth Company record of 6.8 days on the SMR 21H, a 31% reduction from the prior Company record.

In 2018, the Company conducted numerous initiatives to reduce capital expenditures, including moving to offline production cementing, using significant amounts of regional sand and the more widespread utilization of simultaneous-operations. Offline production cementing, which allows drilling rigs to reduce walking time in-between wells, saved roughly one-half day per well on multi-well pads. In 2018, the Company pumped over 200 million pounds of regional sand, over 30% of the total sand pumped for the year, and aims to increase this percentage in 2019 due to its compelling value proposition. The Company's use of simultaneous-operations, including flowback and drill out activities, helped decrease the time to bring a well online by two days on average. These shortened cycle times, combined with our artificial intelligence guided rate-transient analysis, allow the Company to turn wells online faster and manage them better during the critical initial flowback period.

2018 cost reduction initiatives: The Company continues to focus on cost reduction measures and took additional actions in 2018 to reduce operating and overhead costs. These initiatives included field staff reductions, the use of regional sand in completions, disposition of uneconomic and higher cost properties, improved utilization of existing facilities, elimination of redundant equipment, and replacement of rental equipment with company-owned equipment. As previously mentioned, the Company continues to improve its process for drilling and completing wells. The Company's procurement team takes a process-oriented 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, which has led to a significant reduction in the Company's overall lease operating expenses at the field level. For example, the Company's lease operating expenses were $0.26 per Mcfe for the year ended December 31, 2018, compared to $0.39 per Mcfe for 2017.

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 also underwent additional staff reductions and took additional steps to further reduce overhead costs. This has led to a decline in our net cash general and administrative costs (a non-GAAP financial measure calculated as net general and administrative costs less share based compensation) of $16.6 million in 2018 compared to $23.2 million in 2017.

We have continued to maintain a safe working environment while implementing these cost-reduction efforts. Our corporate total recordable incident rate (“TRIR”) was 0.38 incidents per 1.3 million work hours in 2018.

Strategic dispositions: On March 1, 2018, the Company divested certain wells in its AWP Olmos Field for $27.0 million in cash plus the assumption by the buyer of $6.3 million of asset retirement obligations. This transaction had an effective date of January 1, 2018. These assets are located in McMullen County, Texas and include approximately 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 were used to repay outstanding borrowings under the Company’s Credit Facility.

Liquidity and Capital Resources

The Company's primary use of cash has been to fund capital expenditures to develop its oil and gas properties. As of December 31, 2018, the Company’s liquidity consisted of approximately $2.5 million of cash-on-hand and $215.0 million in available borrowings on the Company's Credit Facility's $410.0 million borrowing base. Management believes the Company has

34




sufficient liquidity to meet its obligations for at least the next twelve months and execute its long-term development plans. See Note 4 to the Company's consolidated financial statements for more information on its Debt Facilities.

Summary of 2018 Financial Results

Revenues and net income (loss): The Company's oil and gas revenues were $257.3 million and $195.9 million for the years ended December 31, 2018 and 2017, respectively. Revenues were higher due to overall higher commodity pricing as well as overall higher production. The Company had net income of $74.6 million and $72.0 million for the years ended December 31, 2018 and 2017, respectively, due to higher production and commodity pricing partially offset by increased operating expenses and a loss on commodity derivative contracts.

Capital expenditures: The Company's capital expenditures on an accrual basis were $308.3 million and $203.3 million for the years ended December 31, 2018 and 2017, respectively. The expenditures for the year ended December 31, 2018, were primarily driven by continued legacy development and Southern Eagle Ford gas window delineation, while expenditures for the year ended December 31, 2017 were primarily driven by development activity in our Southern Eagle Ford fields. These expenditures were funded by cash flows and borrowings under our Credit Facility.    

Working capital: The Company had a working capital deficit of $39.7 million at December 31, 2018 and a deficit of $32.9 million at December 31, 2017. The working capital computation does not include available liquidity through the Company's Credit Facility.

Cash Flows: For the year ended December 31, 2018, the Company generated cash from operating activities of $121.6 million, of which $23.7 million was attributable to changes in working capital. Cash used for property additions was $266.5 million. This excluded $45.3 million attributable to a net increase of capital related payables and accrued costs. Additionally, $8.7 million was paid during the year for property sale obligations related to the sale of our former Bay De Chene field. The Company’s net borrowings under its revolving Credit Facility were $122.0 million for the year ended December 31, 2018.

For the year ended December 31, 2017, 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 Credit Facility were $125.0 million which includes the pay down on Credit Facility borrowings with proceeds from the Second Lien Facility.




35




Contractual Commitments and Obligations

Our contractual commitments for the next five years and thereafter are shown below as of December 31, 2018 (in thousands):
 
2019
2020
2021
2022
2023
Thereafter
Total
Non-cancelable operating leases
$
2,311

$
838

$
332

$

$

$

$
3,480

Drilling contracts
2,160






2,160

Gas transportation and processing (1)
8,260

12,567

5,636

3,968

2,762

2,711

35,904

Interest cost (2)
30,594

30,687

30,790

24,233

21,466

20,700

158,469

Long-term debt



195,000


200,000

395,000

Executive severance agreements
554






554

Other contractual commitments (3)
7,500






7,500

Total
$
51,378

$
44,092

$
36,758

$
223,201

$
24,228

$
223,411

$
603,068


(1) Amounts shown represent fees for the minimum delivery obligations. Any amount of transportation utilized in excess of the minimum will reduce future year obligations.
(2) Interest on our Credit Facility is estimated using the weighted average interest rate of 4.9% for the quarter ended December 31, 2018, while interest on our Second Lien is estimated using LIBOR plus 7.5%. See Note 4 of these consolidated financial statements in this Form 10-K for more information. Actual interest rate is variable over the term of the facility.
(3) Obligation under Bay De Chene sales contract.

As of December 31, 2018, we had no off-balance sheet arrangements requiring disclosure pursuant to article 303(a) of Regulation S-K.

Proved Oil and Gas Reserves

During 2018, our reserves increased by approximately 320.9 MMcfe due to increases in our natural gas reserves primarily from our AWP, Fasken and Oro Grande fields. As of December 31, 2018, 41% of our total proved reserves were proved developed, compared with 45% at year-end 2017 and 51% at year-end 2016.

At December 31, 2018, our proved reserves were 1,345.4 MMcfe with a Standardized Measure of $994 million, which is an increase of approximately $262.2 million, or 36%, from the prior year-end levels. In 2018, our proved natural gas reserves increased 253.7 MMcf, or 30%, while our proved oil reserves increased 5.6 MMBbl, or 78%, and our NGL reserves increased 5.6 MMBbl, or 24%, for a total equivalent increase of 320.9 MMcfe, or 31%.

We have added proved reserves primarily through our drilling activities, including 450.4 MMcfe added in 2018. 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 27.9 MMcfe of reserves during 2018 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 2018 was $3.04 per Mcf. This average price increased from the average price of $2.95 per Mcf used for 2017. Our average oil price used in the calculation for 2018 was $66.96 per Bbl. This average price increased from the average price of $50.38 per Bbl used in the calculation for 2017. Our average NGL price used in the calculation for 2018 was $26.63 per Bbl. This average price increased from the average price of $20.32 per Bbl used in the calculation for 2017.



36





Results of Operations

Revenues — Years Ended December 31, 2018 and 2017

2018 - Our oil and gas sales in 2018 increased by 31% compared to revenues in 2017, primarily due to overall higher commodity pricing and overall higher production. Average oil prices we received were 29% higher than those received during 2017, while natural gas prices were 7% higher and NGL prices were 18% higher.

Crude oil production was 6% and 7% of our production volumes for the years ended December 31, 2018 and 2017, respectively, while crude oil sales revenues were 18% of oil and gas sales revenue for each of the years ended December 31, 2018 and 2017. Natural gas production was 84% and 82% of our production volumes for the years ended December 31, 2018 and 2017, respectively, while natural gas sales revenues were 71% of oil and gas sales for each of the years ended December 31, 2018 and 2017.

The following tables provide information regarding the changes in the sources of our oil and gas sales and volumes for the years ended December 31, 2018 and 2017:

Fields
 
Oil and Gas Sales (In Millions)
 
Net Oil and Gas Production Volumes (MMcfe)
 
 
2018
 
2017
 
2018
 
2017
Artesia
 
$
53.8

 
$
33.2

 
10,514

 
7,393

AWP
 
52.8

 
55.2

 
10,470

 
13,004

Fasken
 
115.3

 
101.8

 
35,976

 
33,769

Other (1)
 
35.4

 
5.7

 
10,570

 
1,969

Total
 
$
257.3

 
$
195.9

 
67,530

 
56,135

(1) For 2017, primarily from our Oro Grande and Uno Mas fields.

Our production increase from 2017 to 2018 was primarily due to increased natural gas production and increased drilling and completion activity.

In 2018, our $61.4 million, or 31% increase in oil, NGL, and natural gas sales resulted from:

Price variances that had a $26.5 million favorable impact on sales, with an increase of $11.9 million due to the 7% increase in natural gas prices received, an increase of $10.3 million due to the 29% increase in oil prices received and an increase of $4.4 million due to the 18% increase in NGL prices received.
Volume variances that had a $34.9 million favorable impact on sales, with a $0.2 million increase due to a slight increase in oil production volumes, a $33.0 million increase due to the 10.9 Bcf increase in natural gas production volumes and a $1.7 million increase due to the 0.1 million Bbl increase in NGL production volumes.

37





The following table provides additional information regarding our oil and gas sales, by commodity type, for the years ended December 31, 2018 and 2017:

 
Production Volume
 
Average Price
 
Oil
 
NGL
 
Gas
 
Combined
 
Oil
 
NGL
 
Gas
 
(MBbl)
 
(MBbl)
 
(Bcf)
 
(Bcfe)
 
(Bbl)
 
(Bbl)
 
(Mcf)
2017
 
 
 
 
 
 
 
 
 
 
 
 
 
  First Quarter
146
 
204
 
10.1
 
12.2
 
$49.26
 
$20.33
 
$3.07
  Second Quarter
139
 
228
 
11.1
 
13.3
 
$46.82
 
$18.49
 
$3.16
  Third Quarter
170
 
267
 
11.7
 
14.3
 
$46.93
 
$21.67
 
$3.01
  Fourth Quarter
229
 
347
 
12.8
 
16.3
 
$57.64
 
$24.37
 
$2.88
    Total
684
 
1,046
 
45.7
 
56.1
 
$50.98
 
$21.61
 
$3.03
2018
 
 
 
 
 
 
 
 
 
 
 
 
 
  First Quarter
177
 
248
 
11.9
 
14.5
 
$64.59
 
$22.39
 
$3.00
  Second Quarter
141
 
211
 
12.4
 
14.5
 
$68.53
 
$25.36
 
$2.93
  Third Quarter
155
 
334
 
14.7
 
17.7
 
$71.68
 
$30.59
 
$2.97
  Fourth Quarter
215
 
330
 
17.6
 
20.8
 
$61.19
 
$22.81
 
$3.84
    Total
688
 
1,123
 
56.6
 
67.5
 
$65.93
 
$25.51
 
$3.23

For the years ended December 31, 2018 and 2017 we recorded net (losses) gains of $(9.8) million and $17.9 million, respectively, related to our derivative activities. The change was driven primarily by changes in commodity pricing. This activity is recorded in “Net gain (loss) on commodity derivatives” on the accompanying consolidated statements of operations.


38




Costs and Expenses

The following table provides additional information regarding our expenses for the years ended December 31, 2018 and 2017:

Costs and Expenses
Year Ended December 31, 2018
Year Ended December 31, 2017
General and administrative, net
$
22,570

$
30,000

Depreciation, depletion, and amortization
68,035

46,933

Accretion of asset retirement obligation
419

2,322

Lease operating cost
17,643

21,908

Transportation and gas processing
23,848

19,360

Severance and other taxes
11,394

8,205

Interest expense, net
27,666

15,070


2018 - Our costs and expenses during 2018 versus 2017 were as follows:

General and Administrative Expenses, Net. These expenses were $22.6 million and $30.0 million for the years ended December 31, 2018 and 2017, respectively. Cost reductions were primarily related to lower salaries and burdens and decreases in other expenses as a result of our cost reduction initiatives. Included in general and administrative expenses is $6.0 million and $6.8 million in share based compensation for the years ended December 31, 2018 and 2017, respectively.

Depreciation, Depletion and Amortization (“DD&A”). These expenses on a per Mcfe basis were $1.01 and $0.84 for the years ended December 31, 2018 and 2017, respectively. The increase in the rate per unit is primarily due to a higher depletable base relative to reserves. The higher depletion expense is due to a higher production and a higher per unit rate.

Lease Operating Cost. These expenses were $17.6 million and $21.9 million for the years ended December 31, 2018 and 2017, respectively. The decrease was primarily due to divestitures of assets and a concentrated effort by the Company to reduce overall operating costs.

Transportation and gas processing. These expenses all related to natural gas and NGL sales. These expenses on a per Mcfe basis were $0.35 and $0.34 for the years ended December 31, 2018 and 2017, respectively.

Severance and Other Taxes. These expenses on a per Mcfe basis were $0.17 and $0.15 for the years ended December 31, 2018 and 2017, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 4.4% and 4.2% for the years ended December 31, 2018 and 2017, respectively.
 
Interest. Our gross interest cost was $28.6 million and $15.9 million for the years ended December 31, 2018 and 2017, respectively, of which $0.9 million and $0.8 million was capitalized, respectively. The increase in gross interest from 2017 was primarily due to increased borrowings on our Credit Facility.

Income Taxes. The Company has significant deferred tax assets in excess of deferred tax liabilities. Because of uncertainty about the realization of any future tax benefits, the Company carries a full valuation allowance against its net deferred asset balance. Tax expense that would have been recognized at the statutory rate for 2018 was predominately offset by a reduction in the valuation allowance carried forward from 2017.



39




Non-GAAP Financial Measures

Adjusted EBITDA

We present adjusted EBITDA attributable to common stockholders (“Adjusted EBITDA”) in addition to our reported net income (loss) in accordance with U.S. GAAP. Adjusted EBITDA is a non-GAAP financial measure that is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess our operating performance as compared to that of other companies in our industry, without regard to financing methods, capital structure or historical costs basis. It is also used to assess our ability to incur and service debt and fund capital expenditures. We define Adjusted EBITDA as net income (loss):

Plus/(Less):
Depreciation, depletion, amortization;
Accretion of asset retirement obligations;
Interest expense;
Impairment of oil and natural gas properties;
Net losses (gains) on commodity derivative contracts;
Amounts collected (paid) for commodity derivative contracts held to settlement;
Income tax expense or (benefit); and
Share-based compensation expense.

Our Adjusted EBITDA should not be considered an alternative to net income (loss), operating income (loss), cash flows provided by (used in) operating activities or any other measure of financial performance or liquidity presented in accordance with U.S. GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of other companies because all companies may not calculate Adjusted EBITDA in the same manner.

The following tables present reconciliations of our net income (loss) (the most directly comparable financial measure calculated in accordance with U.S. GAAP) to Adjusted EBITDA for the periods indicated (in thousands):


Year Ended December 31, 2018
Year Ended December 31, 2017
Net Income (Loss)
$
74,615

$
71,971

Plus:


Depreciation, depletion and amortization
68,035

46,933

Accretion of asset retirement obligations
419

2,322

Interest expense
27,666

15,070

Derivative (gain)/loss
9,777

(17,913
)
Derivative cash settlements collected/(paid) (1)
(19,060
)
(1,545
)
Income tax expense/(benefit)
928

(1,954
)
Share-based compensation expense
5,980

6,849

Adjusted EBITDA
$
168,360

$
121,733

(1) This includes accruals for settled contracts covering commodity deliveries during the period where the actual cash settlements occur outside of the period.



40




Critical Accounting Policies and New Accounting Pronouncements

Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized including internal costs incurred that are directly related to these activities and which are not related to production, general corporate overhead, or similar activities. Future development costs are estimated on a property-by-property basis based on current economic conditions and are amortized to expense as our capitalized oil and natural gas property costs are amortized. We compute the provision for depreciation, depletion, and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method.

The costs of unproved properties not being amortized are assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, international economic conditions, capital availability, and available geological and geophysical information. As these factors may change from period to period, our evaluation of these factors will change. Any impairment assessed is added to the cost of proved properties being amortized.

The calculation of the provision for DD&A requires us to use estimates related to quantities of proved oil and natural gas reserves and estimates of the impairment of unproved properties. The estimation process for both reserves and the impairment of unproved properties is subjective, and results may change over time based on current information and industry conditions. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates.

Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations and deferred income taxes, and excluding the recognized asset retirement obligation liability) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects ("Ceiling Test").

We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates.

If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur in the future. We cannot control and cannot predict what future prices for oil and natural gas will be, thus we cannot estimate the amount or timing of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices.

New Accounting Pronouncements. In February 2016, the FASB issued ASU 2016-02, which requires lessees to record most leases on the balance sheet. Under the new guidance, lease classification as either a finance lease or an operating lease will determine how lease-related revenue and expense are recognized. The guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company adopted this guidance on January 1, 2019, with no significant impact on the company's financial statements resulting from implementation. See Note 2 to our consolidated financial statements for more information.



41




Forward-Looking Statements

This report includes forward-looking statements intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated production levels, expected oil and natural gas pricing, estimated oil and natural gas reserves or the present value thereof, reserve increases, capital expenditures, budget, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “budgeted,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:

volatility in natural gas, oil and NGL prices;
future cash flows and their adequacy to maintain our ongoing operations;
liquidity, including our ability to satisfy our short- or long-term liquidity needs;
our borrowing capacity, future covenant compliance, cash flows and liquidity;
operating results;
asset disposition efforts or the timing or outcome thereof;
ongoing and prospective joint ventures, their structure and substance, and the likelihood of their finalization or the timing thereof;
the amount, nature and timing of capital expenditures, including future development costs;
timing, cost and amount of future production of oil and natural gas;
availability of drilling and production equipment or availability of oil field labor;
availability, cost and terms of capital;
drilling of wells;
availability and cost for transportation of oil and natural gas;
costs of exploiting and developing our properties and conducting other operations;
competition in the oil and natural gas industry;
general economic conditions;
opportunities to monetize assets;
effectiveness of our risk management activities;
environmental liabilities;
counterparty credit risk;
governmental regulation and taxation of the oil and natural gas industry;
developments in world oil markets and in oil and natural gas-producing countries;
uncertainty regarding our future operating results; and
other risks and uncertainties described in Item 1A. “Risk Factors,” in this annual report on Form 10-K for the year ended December 31, 2018.

All forward-looking statements speak only as of the date they are made. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under "Risk Factors" in Item 1A of this annual report on Form 10-K for the year ended December 31, 2018. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release the results of any revisions to any such

42




forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.



43




Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk. Our major market risk exposure is the commodity pricing applicable to our oil and natural gas production. 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. This commodity pricing volatility has continued with unpredictable price swings in recent periods.

Our price-risk management policy permits the utilization of agreements and financial instruments (such as futures, forward contracts, swaps and options contracts) to mitigate price risk associated with fluctuations in oil and natural gas prices. We do not utilize these agreements and financial instruments for trading and only enter into derivative agreements with banks in our Credit Facility. For additional discussion related to our price-risk management policy, refer to Note 5 of the consolidated financial statements in this Form 10-K.

Customer Credit Risk. We are exposed to the risk of financial non-performance by customers. Our ability to collect on sales to our customers is dependent on the liquidity of our customer base. Continued volatility in both credit and commodity markets may reduce the liquidity of our customer base. To manage customer credit risk, we monitor credit ratings of customers and from certain customers we also obtain letters of credit, parent company guarantees if applicable, and other collateral as considered necessary to reduce risk of loss. Due to availability of other purchasers, we do not believe the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations.

Concentration of Sales Risk. For the year ended December 31, 2018, Kinder Morgan and affiliates accounted for approximately 37% of our oil and gas receipts. There were no other purchasers who individually accounted for 10% or more of our oil and gas receipts. We expect to continue this relationship in the future. We believe that the risk of these unsecured receivables is mitigated by the size, reputation and nature of the businesses and the availability of other purchasers in the areas where we operate.

Interest Rate Risk. At December 31, 2018, we had a combined $395.0 million drawn under our Credit Facility and our Second Lien Notes, which bear a floating rate of interest depending on the level of the borrowing base and the borrowing base loans outstanding and therefore is susceptible to interest rate fluctuations. These variable interest rate borrowings are impacted by changes in short-term interest rates. A hypothetical one-percentage point increase in interest rates on our borrowings outstanding under our Credit Facility and Second Lien Notes at December 31, 2018 would increase our annual interest expense by $4.0 million.



44




Item 8. Financial Statements and Supplementary Data
Page
 
 
Management's Report on Internal Control Over Financial Reporting
 
 
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
 
 
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements
 
 
Consolidated Balance Sheets
 
 
Consolidated Statements of Operations
 
 
Consolidated Statements of Stockholders' Equity (Deficit)
 
 
Consolidated Statements of Cash Flows
 
 
Notes to Consolidated Financial Statements
 
 
Supplementary Information



45




Management's Report on Internal Control Over Financial Reporting

Management of SilverBow Resources, Inc. is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company's internal control over financial reporting is a process designed by, or under the supervision of, the Company's Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial statements for external purposes in accordance with U. S. generally accepted accounting principles.

Management of the Company assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2018. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria) (2013 framework) in Internal Control-Integrated Framework. Based on our assessment and those criteria, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2018.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

BDO USA, LLP, the independent registered public accounting firm that audited the 2018 consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued an attestation report on the Company's internal control over financial reporting as of December 31, 2018, based on their audit.


46




Report of Independent Registered Public Accounting Firm

Shareholders and Board of Directors
SilverBow Resources, Inc.
Houston, Texas
Opinion on Internal Control over Financial Reporting
We have audited SilverBow Resources, Inc.’s (the “Company’s”) internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of December 31, 2018 and 2017, the related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended, and the related notes, and our report dated February 28, 2019 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ BDO USA, LLP

Houston, Texas
February 28, 2019



47




Report of Independent Registered Public Accounting Firm

Shareholders and Board of Directors
SilverBow Resources, Inc.
Houston, Texas
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of SilverBow Resources, Inc. (the “Company”) and subsidiaries as of December 31, 2018 and 2017, the related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company and subsidiaries as of December 31, 2018 and 2017, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 28, 2019 expressed an unqualified opinion thereon.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ BDO USA, LLP
We have served as the Company's auditor since 2016.

Houston, Texas
February 28, 2019



48




Consolidated Balance Sheets
SilverBow Resources, Inc. (in thousands, except share amounts)
 
December 31, 2018
 
December 31, 2017
ASSETS
 
 
 
Current Assets:
 
 
 
Cash and cash equivalents
$
2,465

 
$
7,806

Accounts receivable, net
46,472

 
27,263

Fair value of commodity derivatives
15,261

 
5,148

Other current assets
2,126

 
2,352

Total Current Assets
66,324

 
42,569

Property and Equipment:
 

 
 

Property and Equipment, Full Cost Method, including $56,715 and $50,377 of unproved property costs not being amortized
986,100

 
712,166

Less – Accumulated depreciation, depletion, amortization and impairment
(284,804
)
 
(216,769
)
Property and Equipment, Net
701,296

 
495,397

Fair Value of long-term commodity derivatives
4,333

 
2,553

Other Long-Term Assets
5,567

 
10,751

Total Assets
$
777,520

 
$
551,270

LIABILITIES AND STOCKHOLDERS’ EQUITY
 

 
 

Current Liabilities:
 

 
 

Accounts payable and accrued liabilities
$
48,921

 
$
44,437

Fair value of commodity derivatives
2,824

 
5,075

Accrued capital costs
38,073

 
10,883

Accrued interest
1,513

 
2,106

Undistributed oil and gas revenues
14,681

 
12,996

Total Current Liabilities
106,012

 
75,497

 
 
 
 
Long-term debt
387,988

 
265,325

Deferred tax liabilities, net
1,014

 

Asset retirement obligations
3,956

 
8,678

Fair value of long-term commodity derivatives
3,723

 
2,758

Other long-term liabilities

 
5,554

Commitments and Contingencies (Note 6)


 


Stockholders' Equity:
 

 
 

Preferred stock, $.01 par value, 10,000,000 shares authorized, none issued

 

Common stock, $.01 par value, 40,000,000 shares authorized, 11,757,972 and 11,621,385 shares issued and 11,692,101 and 11,570,621 shares outstanding
118

 
116

Additional paid-in capital
286,281

 
279,111

Treasury stock held, at cost, 65,871 and 50,764 shares
(1,870
)
 
(1,452
)
Retained earnings (Accumulated deficit)
(9,702
)
 
(84,317
)
Total Stockholders’ Equity
274,827

 
193,458

Total Liabilities and Stockholders’ Equity
$
777,520

 
$
551,270

See accompanying Notes to Consolidated Financial Statements.

49




Consolidated Statements of Operations
SilverBow Resources, Inc. (in thousands, except per-share amounts)
 
Year Ended December 31, 2018
 
Year Ended December 31, 2017
Revenues:
 
 
 
Oil and gas sales
$
257,286

 
$
195,910

 
 
 
 
Operating Expenses:
 
 
 

General and administrative, net
22,570

 
30,000

Depreciation, depletion, and amortization
68,035

 
46,933

Accretion of asset retirement obligations
419

 
2,322

Lease operating expense
17,643

 
21,908

Transportation and gas processing
23,848

 
19,360

Severance and other taxes
11,394

 
8,205

Total Operating Expenses
143,909

 
128,728

 
 
 
 
Operating Income (Loss)
113,377

 
67,182

 
 
 
 
Non-Operating Income (Expense)
 
 
 
Net gain (loss) on commodity derivatives
(9,777
)
 
17,913

Interest expense, net
(27,666
)
 
(15,070
)
Other income (expense), net
(391
)
 
(8
)
 
 
 
 
Income (Loss) Before Income Taxes
75,543

 
70,017

 
 
 
 
Provision (Benefit) for Income Taxes
928

 
(1,954
)
 
 
 
 
Net Income (Loss)
$
74,615

 
$
71,971

 
 
 
 
Per Share Amounts:
 
 
 

 
 
 
 
Basic:  Net Income (Loss)
$
6.40

 
$
6.28

 
 
 
 
Diluted:  Net Income (Loss)
$
6.34

 
$
6.25

 
 
 
 
Weighted Average Shares Outstanding - Basic
11,655

 
11,453

 
 
 
 
Weighted Average Shares Outstanding - Diluted
11,764

 
11,514

 
 
 
 
See accompanying Notes to Consolidated Financial Statements.


50




Consolidated Statements of Stockholders’ Equity (Deficit)
SilverBow Resources, Inc. (in thousands, except share amounts)
 
Common Stock
 
Additional Paid-in Capital
 
Treasury Stock
 
Retained Earnings (Accumulated Deficit)
 
Total
Balance, December 31, 2016
$
101

 
$
232,917

 
$
(675
)
 
$
(156,288
)
 
$
76,055

 
 
 
 
 
 
 
 
 
 
Purchase of treasury shares (28,279 shares)

 

 
(777
)
 

 
(777
)
Issuance of common stock (1,403,508 shares)
14

 
39,166

 

 

 
39,180

Issuance of restricted stock (141,818 shares)
1

 
(1
)