Title of Class
|
Trading Symbol(s)
|
Exchanges on Which Registered:
|
Common Stock, par value $0.01 per share
|
SBOW
|
New York Stock Exchange
|
Yes
|
o
|
No
|
þ
|
Yes
|
o
|
No
|
þ
|
Yes
|
þ
|
No
|
o
|
Yes
|
þ
|
No
|
o
|
Yes
|
o
|
No
|
þ
|
Part I
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Page
|
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Items 1 & 2
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Business and Properties
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Item 1A.
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Risk Factors
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Item 1B.
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Unresolved Staff Comments
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Item 3.
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Legal Proceedings
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Item 4.
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Mine Safety Disclosures
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Part II
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Item 5.
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Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
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Item 6.
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Selected Financial Data
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Item 7.
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Management's Discussion and Analysis of Financial Condition and Results of Operations
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Item 7A.
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Quantitative and Qualitative Disclosures About Market Risk
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Item 8.
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Financial Statements and Supplementary Data
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Item 9.
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Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
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Item 9A.
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Controls and Procedures
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Item 9B.
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Other Information
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Part III
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Item 10.
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Directors, Executive Officers and Corporate Governance
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Item 11.
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Executive Compensation
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Item 12.
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Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters
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Item 13.
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Certain Relationships and Related Transactions, and Director Independence
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Item 14.
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Principal Accounting Fees and Services
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Part IV
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Item 15.
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Exhibits and Financial Statement Schedules
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Item 16.
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10-K Summary
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•
|
Leverage technical expertise to efficiently develop our extensive drilling inventory of high rate of return Eagle Ford Shale drilling locations. As of December 31, 2019, our technical team has an average of approximately 23 years of experience 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 fluid and proppant usage and fracture stage spacing. These factors have further enhanced the return profile of our drilling and completion operations. Our 2020 capital budget range of $175 to $195 million provides for drilling 26 gross (25 net) horizontal wells which will be funded primarily from operating cash flow.
|
•
|
Grow and maintain balanced inventory mix of both gas and liquids-rich locations. We believe that oil, natural gas and natural gas liquids prices have the potential to exhibit volatile and unpredictable fluctuations in price. Further, the timing and duration of such fluctuations are difficult to predict. As a result, the Company is focused on continuing to expand its liquids-rich inventory through technical advancements on existing acreage, organic leasing and bolt-on acquisitions. This strategy of diversification allows us to pursue our most economic hydrocarbon locations that in turn generate the most compelling returns, with the ability to shift our focus to locations with different hydrocarbon mixes based on prevailing prices. Given the state of the commodity price environment, the Company allocated approximately 63% of its 2019 drilling and completion budget toward liquids development. Of the 581 gross undrilled horizontal locations at year-end 2019, 233 locations are liquids-weighted and 348 locations are gas-weighted. The Company’s balanced commodity mix provides opportunity to allocate capital towards the highest rate of return locations as dictated by prices.
|
•
|
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
|
•
|
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. 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 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, 2019, the Company had approximately $121.0 million in available borrowing capacity under our Credit Facility, which we believe, along with our projected operating cash flow, provides us with liquidity to execute our 2020 development plan and opportunistically acquire or lease additional acreage. Our Credit Facility and Second Lien, 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 February 25, 2020, we had approximately 56% of total production volumes hedged for full year 2020 using the midpoint of production guidance of 215 - 228 MMcfe/d.
|
•
|
Extensive inventory of drilling locations with high degree of operational control. We have developed a significant inventory of future drilling locations. As of December 31, 2019, we had approximately 118,000 net acres in the Eagle Ford and roughly 581 gross horizontal drilling locations. Approximately 59% of our estimated proved reserves at December 31, 2019 were undeveloped. We operate essentially all of our proved reserves and have an average working interest of approximately 86% 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 full year 2019 was 231 MMcfe/d and our proved developed reserves as of December 31, 2019 were 579 Bcfe. Our portfolio of properties and our 2020 capital plan couples this strong base of production and reserves with low risk drilling while increasing our exposure to liquids opportunities. In 2019, we brought online 11 net wells in our La Salle Condensate area and seven net wells in our McMullen Oil area and were pleased with the initial performance. Based on these results, we plan to drill and complete four net wells in our La Salle Condensate area and 21 net wells in our McMullen Oil area in 2020, which will increase our oil and natural gas liquids production from 24% at year-end 2019 to approximately 35% by year-end 2020. Furthermore, we are continuing to delineate our newest acreage position in Dimmit County. We have identified a total of 126 drilling locations in this area prospective for lower and upper Eagle Ford and plan to drill and complete two net wells in 2020. 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 2019 our average natural gas basis differentials to NYMEX were positive $0.02/Mcf versus $1.62/Mcf discount for the Permian Basin index into the El Paso pipeline. 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, 2019, we employed 19 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 23 years of experience in their technical fields. Our senior
|
•
|
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 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, 2019, the Company had approximately $121.0 million in available borrowing capacity under our Credit Facility, which we believe, along with our operating cash flow, provides us with a sufficient amount of liquidity to execute our 2020 development plan and opportunistically acquire or lease additional acreage even with modest changes in the commodity environment. Our Credit Facility and Second Lien, maturing in April 2022 and December 2024, respectively, are our only stated debt maturities. As of December 31, 2019, we had $279.0 million drawn on our $400.0 million borrowing base under the Credit Facility.
|
Fields
|
|
Net Acreage
|
|
2019 Production (Mcfe/d)
|
|
Gas as % of 2019 Production
|
|
2019 Net Wells Drilled
|
|
2019 Net Wells Completed
|
|||||
Artesia
|
|
12,402
|
|
|
53,680
|
|
|
43
|
%
|
|
11
|
|
|
11
|
|
AWP
|
|
36,435
|
|
|
40,101
|
|
|
45
|
%
|
|
6
|
|
|
7
|
|
Fasken
|
|
8,393
|
|
|
104,674
|
|
|
100
|
%
|
|
7
|
|
|
9
|
|
Oro Grande
|
|
27,085
|
|
|
20,167
|
|
|
100
|
%
|
|
1
|
|
|
1
|
|
Uno Mas
|
|
17,047
|
|
|
10,193
|
|
|
96
|
%
|
|
—
|
|
|
—
|
|
Other
|
|
16,338
|
|
|
2,202
|
|
|
35
|
%
|
|
2
|
|
|
2
|
|
Total
|
|
117,700
|
|
|
231,017
|
|
|
76
|
%
|
|
27
|
|
|
30
|
|
Fields
|
|
Proved Developed Reserves (Bcfe)
|
|
Proved Undeveloped Reserves
(Bcfe)
|
|
Total Proved Reserves
(Bcfe)
|
|
% of Total Proved Reserves
|
|
Oil and
NGLs as % of Proved Reserves
|
|
Total
Production (Bcfe)
|
||||||
Artesia
|
|
108.9
|
|
|
123.7
|
|
|
232.6
|
|
|
16.4
|
%
|
|
54.0
|
%
|
|
19.6
|
|
AWP
|
|
80.4
|
|
|
202.4
|
|
|
282.8
|
|
|
19.9
|
%
|
|
47.3
|
%
|
|
14.6
|
|
Fasken
|
|
338.8
|
|
|
424.1
|
|
|
762.9
|
|
|
53.7
|
%
|
|
—
|
%
|
|
38.2
|
|
Oro Grande
|
|
33.6
|
|
|
91.1
|
|
|
124.7
|
|
|
8.8
|
%
|
|
—
|
%
|
|
7.4
|
|
Uno Mas
|
|
13.6
|
|
|
—
|
|
|
13.6
|
|
|
1.0
|
%
|
|
3.7
|
%
|
|
3.7
|
|
Other
|
|
3.8
|
|
|
—
|
|
|
3.8
|
|
|
0.2
|
%
|
|
57.3
|
%
|
|
0.8
|
|
Total
|
|
579.1
|
|
|
841.3
|
|
|
1,420.4
|
|
|
100.0
|
%
|
|
18.5
|
%
|
|
84.3
|
|
|
As of December 31,
|
||||||||||
(in millions)
|
2019
|
|
2018
|
|
2017
|
||||||
PV-10 Value
|
$
|
976
|
|
|
$
|
1,128
|
|
|
$
|
805
|
|
Less: Future income taxes (discounted at 10%)
|
108
|
|
|
134
|
|
|
73
|
|
|||
Standardized Measure of Discounted Future Net Cash Flows
|
$
|
868
|
|
|
$
|
994
|
|
|
$
|
732
|
|
Estimated Proved Natural Gas, Oil and NGL Reserves
|
|
As of December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
Natural gas reserves (MMcf):
|
|
|
|
|
|
|
||||||
Proved developed
|
|
478,005
|
|
|
466,129
|
|
|
377,506
|
|
|||
Proved undeveloped (1)
|
|
680,347
|
|
|
630,279
|
|
|
465,230
|
|
|||
Total
|
|
1,158,352
|
|
|
1,096,408
|
|
|
842,736
|
|
|||
Oil reserves (MBbl):
|
|
|
|
|
|
|
||||||
Proved developed
|
|
6,476
|
|
|
5,507
|
|
|
5,027
|
|
|||
Proved undeveloped (1)
|
|
10,592
|
|
|
7,271
|
|
|
2,133
|
|
|||
Total
|
|
17,068
|
|
|
12,779
|
|
|
7,160
|
|
|||
NGL reserves (MBbl):
|
|
|
|
|
|
|
||||||
Proved developed
|
|
10,377
|
|
|
9,287
|
|
|
8,431
|
|
|||
Proved undeveloped (1)
|
|
16,236
|
|
|
19,427
|
|
|
14,690
|
|
|||
Total
|
|
26,614
|
|
|
28,714
|
|
|
23,121
|
|
|||
|
|
|
|
|
|
|
||||||
Total Estimated Reserves (MMcfe) (1)(2)
|
|
1,420,439
|
|
|
1,345,362
|
|
|
1,024,422
|
|
|||
|
|
|
|
|
|
|
||||||
Standardized Measure of Discounted Future Net Cash Flows (in millions) (3)
|
|
$
|
868
|
|
|
$
|
994
|
|
|
$
|
732
|
|
|
|
|
|
|
|
|
||||||
PV-10 by reserve category
|
|
|
|
|
|
|
||||||
Proved developed
|
|
$
|
635
|
|
|
$
|
681
|
|
|
$
|
470
|
|
Proved undeveloped
|
|
341
|
|
|
447
|
|
|
335
|
|
|||
Total PV-10 Value (3)
|
|
$
|
976
|
|
|
$
|
1,128
|
|
|
$
|
805
|
|
Year Added
|
|
Volume
(Bcfe)
|
|
% of PUD
Volumes
|
|
% of PV-10
|
||
2019
|
|
363.8
|
|
43
|
%
|
|
49
|
%
|
2018
|
|
223.0
|
|
27
|
%
|
|
25
|
%
|
2017
|
|
176.8
|
|
21
|
%
|
|
19
|
%
|
2016 (1)
|
|
77.8
|
|
9
|
%
|
|
7
|
%
|
2015
|
|
0.0
|
|
—
|
%
|
|
—
|
%
|
Total
|
|
841.3
|
|
100
|
%
|
|
100
|
%
|
|
Oil Wells
|
|
Gas Wells
|
|
Total
Wells(1)
|
|||
December 31, 2019
|
|
|
|
|
|
|||
Gross (1)
|
95
|
|
|
246
|
|
|
341
|
|
Net
|
93.0
|
|
|
198.8
|
|
|
291.8
|
|
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
|
|
|
661.7
|
|
(1)
|
Excludes 4, 5, and 8 service wells in 2019, 2018 and 2017, respectively.
|
|
Developed
|
|
Undeveloped
|
||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||
Texas
|
41,300
|
|
|
37,398
|
|
|
89,121
|
|
|
80,302
|
|
Louisiana
|
5,084
|
|
|
4,775
|
|
|
4,920
|
|
|
4,478
|
|
Wyoming
|
—
|
|
|
—
|
|
|
3,013
|
|
|
1,442
|
|
Total
|
46,384
|
|
|
42,173
|
|
|
97,054
|
|
|
86,222
|
|
|
|
|
|
Gross Wells
|
|
Net Wells
|
||||||||||||||
Year
|
|
Type of Well
|
|
Total
|
|
Producing
|
|
Dry
|
|
Total
|
|
Producing
|
|
Dry
|
||||||
2019
|
|
Exploratory
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Development
|
|
30
|
|
|
30
|
|
|
—
|
|
|
27.7
|
|
|
27.7
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
2018
|
|
Exploratory
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Development
|
|
37
|
|
|
37
|
|
|
—
|
|
|
32.7
|
|
|
32.7
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
2017
|
|
Exploratory
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Development
|
|
27
|
|
|
27
|
|
|
—
|
|
|
22.0
|
|
|
22.0
|
|
|
—
|
|
Purchasers greater than 10%
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
||
Kinder Morgan
|
31
|
%
|
|
37
|
%
|
Plains Marketing
|
14
|
%
|
|
*
|
|
Twin Eagle
|
13
|
%
|
|
*
|
|
Shell Trading
|
11
|
%
|
|
*
|
|
|
|
Year Ended December 31,
|
||||||||||
All Fields
|
|
2019
|
|
2018
|
|
2017
|
||||||
Net Sales Volume:
|
|
|
|
|
|
|
||||||
Oil (MBbls)
|
|
1,605
|
|
|
688
|
|
|
685
|
|
|||
Natural gas liquids (MBbls)
|
|
1,717
|
|
|
1,123
|
|
|
1,046
|
|
|||
Natural gas (MMcf)
|
|
64,388
|
|
|
56,665
|
|
|
45,751
|
|
|||
Total (MMcfe)
|
|
84,320
|
|
|
67,530
|
|
|
56,135
|
|
|||
|
|
|
|
|
|
|
||||||
Average Sales Price:
|
|
|
|
|
|
|
||||||
Oil (Per Bbl)
|
|
$
|
57.84
|
|
|
$
|
65.93
|
|
|
$
|
50.98
|
|
Natural gas liquids (Per Bbl)
|
|
$
|
14.70
|
|
|
$
|
25.51
|
|
|
$
|
21.61
|
|
Natural gas (Per Mcf)
|
|
$
|
2.65
|
|
|
$
|
3.23
|
|
|
$
|
3.03
|
|
Total (Per Mcfe)
|
|
$
|
3.42
|
|
|
$
|
3.81
|
|
|
$
|
3.49
|
|
|
|
|
|
|
|
|
||||||
Average Production Cost (Per Mcfe sold) (1)
|
|
$
|
0.57
|
|
|
$
|
0.61
|
|
|
$
|
0.74
|
|
|
|
Year Ended December 31,
|
||||||||||
Fasken
|
|
2019
|
|
2018
|
|
2017
|
||||||
Net Sales Volume:
|
|
|
|
|
|
|
||||||
Natural gas liquids (MBbls)
|
|
2
|
|
|
2
|
|
|
2
|
|
|||
Natural gas (MMcf) (1)
|
|
38,195
|
|
|
35,963
|
|
|
33,757
|
|
|||
Total (MMcfe)
|
|
38,206
|
|
|
35,976
|
|
|
33,769
|
|
|||
|
|
|
|
|
|
|
||||||
Average Sales Price:
|
|
|
|
|
|
|
||||||
Natural gas liquids (Per Bbl)
|
|
$
|
14.13
|
|
|
$
|
24.96
|
|
|
$
|
18.13
|
|
Natural gas (Per Mcf)
|
|
$
|
2.65
|
|
|
$
|
3.21
|
|
|
$
|
3.02
|
|
Total (Per Mcfe)
|
|
$
|
2.65
|
|
|
$
|
3.21
|
|
|
$
|
3.02
|
|
|
|
|
|
|
|
|
||||||
Average Production Cost (Per Mcfe sold) (2)
|
|
$
|
0.60
|
|
|
$
|
0.60
|
|
|
$
|
0.59
|
|
|
|
Year Ended December 31,
|
||||||||||
AWP
|
|
2019
|
|
2018
|
|
2017
|
||||||
Net Sales Volume:
|
|
|
|
|
|
|
||||||
Oil (MBbls)
|
|
846
|
|
|
347
|
|
|
427
|
|
|||
Natural gas liquids (MBbls)
|
|
491
|
|
|
480
|
|
|
598
|
|
|||
Natural gas (MMcf) (1)
|
|
6,613
|
|
|
5,510
|
|
|
6,857
|
|
|||
Total (MMcfe)
|
|
14,637
|
|
|
10,470
|
|
|
13,004
|
|
|||
|
|
|
|
|
|
|
||||||
Average Sales Price:
|
|
|
|
|
|
|
||||||
Oil (Per Bbl)
|
|
$
|
58.66
|
|
|
$
|
65.64
|
|
|
$
|
50.40
|
|
Natural gas liquids (Per Bbl)
|
|
$
|
14.89
|
|
|
$
|
25.84
|
|
|
$
|
20.87
|
|
Natural gas (Per Mcf)
|
|
$
|
2.59
|
|
|
$
|
3.20
|
|
|
$
|
3.09
|
|
Total (Per Mcfe)
|
|
$
|
5.06
|
|
|
$
|
5.04
|
|
|
$
|
4.25
|
|
|
|
|
|
|
|
|
||||||
Average Production Cost (Per Mcfe sold) (2)
|
|
$
|
0.75
|
|
|
$
|
0.88
|
|
|
$
|
1.25
|
|
|
|
Year Ended December 31,
|
||||||||||
Artesia
|
|
2019
|
|
2018
|
|
2017
|
||||||
Net Sales Volume:
|
|
|
|
|
|
|
||||||
Oil (MBbls)
|
|
698
|
|
|
336
|
|
|
249
|
|
|||
Natural gas liquids (MBbls)
|
|
1,173
|
|
|
622
|
|
|
443
|
|
|||
Natural gas (MMcf) (1)
|
|
8,366
|
|
|
4,763
|
|
|
3,239
|
|
|||
Total (MMcfe)
|
|
19,593
|
|
|
10,514
|
|
|
7,393
|
|
|||
|
|
|
|
|
|
|
||||||
Average Sales Price:
|
|
|
|
|
|
|
||||||
Oil (Per Bbl)
|
|
$
|
57.14
|
|
|
$
|
66.29
|
|
|
$
|
52.78
|
|
Natural gas liquids (Per Bbl)
|
|
$
|
14.69
|
|
|
$
|
25.54
|
|
|
$
|
22.67
|
|
Natural gas (Per Mcf)
|
|
$
|
2.59
|
|
|
$
|
3.27
|
|
|
$
|
3.08
|
|
Total (Per Mcfe)
|
|
$
|
4.02
|
|
|
$
|
5.11
|
|
|
$
|
4.49
|
|
|
|
|
|
|
|
|
||||||
Average Production Cost (Per Mcfe sold) (2)
|
|
$
|
0.36
|
|
|
$
|
0.50
|
|
|
$
|
0.62
|
|
•
|
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 (“GHG”) emissions;
|
•
|
the Federal Water Pollution Control Act, also known as the federal Clean Water Act, which regulates discharges of pollutants 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.
|
•
|
domestic and foreign supplies of oil and natural gas;
|
•
|
price and quantity of foreign imports of oil and natural gas;
|
•
|
actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil and natural gas price and production controls;
|
•
|
level of consumer product demand, including as a result of competition from alternative energy sources;
|
•
|
level of global oil and natural gas exploration and production activity;
|
•
|
domestic and foreign governmental regulations;
|
•
|
stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and natural gas;
|
•
|
level of global oil and natural gas inventories;
|
•
|
political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America, Africa and Russia;
|
•
|
weather conditions;
|
•
|
technological advances affecting oil and natural gas production and consumption;
|
•
|
overall U.S. and global economic conditions; and
|
•
|
price and availability of alternative fuels.
|
•
|
sell assets, including equity interests in our subsidiaries;
|
•
|
redeem our debt;
|
•
|
make investments;
|
•
|
incur or guarantee additional indebtedness;
|
•
|
create or incur certain liens;
|
•
|
make certain acquisitions and investments;
|
•
|
redeem or prepay other debt;
|
•
|
enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
|
•
|
consolidate, divide, merge or transfer all or substantially all of our assets;
|
•
|
engage in transactions with affiliates;
|
•
|
create unrestricted subsidiaries;
|
•
|
enter into swap agreements beyond certain maximum thresholds;
|
•
|
enter into sale and leaseback transactions; and
|
•
|
engage in certain business activities.
|
•
|
would not be required to lend any additional amounts to us;
|
•
|
could elect to declare all borrowings or notes outstanding, together with accrued and unpaid interest and fees, to be due and payable;
|
•
|
may have the ability to require us to apply all of our available cash to repay these borrowings or notes; or
|
•
|
may prevent us from making debt service payments under our other agreements.
|
•
|
hurricanes, tropical storms or other natural disasters;
|
•
|
environmental hazards, such as natural gas leaks, oil and produced water spills, pipeline or tank ruptures, encountering naturally occurring radioactive materials, blowouts, explosions 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.
|
•
|
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. Since that time, the EPA has issued area designations with respect to ground-level ozone and 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 Company'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, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, in response to a federal consent decree issued in 2016, the EPA was required during 2019 to determine whether certain Subtitle D criteria regulations required revision in a manner that could result in oil and natural gas wastes being regulated as RCRA hazardous wastes. In April 2019, the EPA made a determination that such revision of the regulations was unnecessary. Any future loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in the Company’s costs to manage and dispose of generated wastes, which could have a material adverse effect on the industry as well as on the Company’s business.
|
•
|
Federal Jurisdiction over Waters of the United States. In 2015, the EPA and U.S. Army Corps of Engineers (“Corps”) under the Obama Administration released a final rule outlining federal jurisdictional reach under the Clean Water Act, over waters of the United States, including wetlands. In 2017, the EPA and the Corps under the Trump Administration agreed to reconsider the 2015 rule and, thereafter, on October 22, 2019, the agencies published a final rule made effective on December 23, 2019, rescinding the 2015 rule. On January 23, 2020, the two agencies issued a final rule redefining the Clean Water Act’s jurisdiction over waters of the United States, which redefinition is narrower than found in the 2015 rule. Upon being published in the Federal Register and the passage of 60 days thereafter, the January 23, 2020 final rule will become effective, at which point the United States will be covered under a single regulatory scheme as it relates to federal jurisdictional reach over waters of the United States. However, there remains the expectation that the January 23, 2020 final rule also will be legally challenged in federal district court. To the extent that any challenge to the January 23, 2020 final rule is successful and 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, delays or cancellations in permitting or projects, which developments could expose it to significant costs and liabilities.
|
•
|
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 Exchange Act) acquiring “beneficial ownership” (as defined in Rules 13d-3 and 13d-5 under the Exchange Act) 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 Charter or the First Amended and Restated Bylaws of the Company (“Bylaws”); or
|
•
|
entering into any arrangements or transactions with affiliates of the Company.
|
•
|
provide for a classified board of directors;
|
•
|
authorize our Board to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;
|
•
|
establish advance notice procedures for nominating directors or presenting matters at stockholder meetings;
|
•
|
provide SVP and certain other institutional stockholders the right to nominate up to four of our directors;
|
•
|
limit the persons who may call special meetings of stockholders; and
|
•
|
provide veto rights to certain stockholders as detailed in our Charter, including any transaction that may constitute a change of control, as defined in the Charter.
|
Period
|
|
Total Number
of Shares
Purchased
|
|
Average Price
Paid Per Share
|
|
Total Number of
Shares Purchased as
Part of Publicly
Announced Plans
or Programs
|
|
Approximate Dollar
Value of Shares that
May Yet Be Purchased
Under the Plans or
Programs
(in thousands)
|
|||||
October 1 - 31, 2019
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$---
|
|
November 1- 30, 2019
|
|
7,118
|
|
|
$
|
12.55
|
|
|
—
|
|
|
—
|
|
December 1 - 31, 2019
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
|
7,118
|
|
|
$
|
12.55
|
|
|
—
|
|
|
$---
|
|
Fields
|
|
Net Acreage
|
|
2019 Production (Mcfe/d)
|
|
Gas as % of 2019 Production
|
|
2019 Net Wells Drilled
|
|
2019 Net Wells Completed
|
|||||
Artesia
|
|
12,402
|
|
|
53,680
|
|
|
43
|
%
|
|
11
|
|
|
11
|
|
AWP
|
|
36,435
|
|
|
40,101
|
|
|
45
|
%
|
|
6
|
|
|
7
|
|
Fasken
|
|
8,393
|
|
|
104,674
|
|
|
100
|
%
|
|
7
|
|
|
9
|
|
Oro Grande
|
|
27,085
|
|
|
20,167
|
|
|
100
|
%
|
|
1
|
|
|
1
|
|
Uno Mas
|
|
17,047
|
|
|
10,193
|
|
|
96
|
%
|
|
—
|
|
|
—
|
|
Other (1)
|
|
16,338
|
|
|
2,202
|
|
|
35
|
%
|
|
2
|
|
|
2
|
|
Total
|
|
117,700
|
|
|
231,017
|
|
|
76
|
%
|
|
27
|
|
|
30
|
|
•
|
Revenues and net income (loss): The Company's oil and gas revenues were $288.6 million and $257.3 million for the years ended December 31, 2019 and 2018, respectively. Revenues were higher due to overall increased production, partially offset by lower commodity pricing. The Company had net income of $114.7 million and $74.6 million for the years ended December 31, 2019 and 2018, respectively. The increase was primarily due to increased production, a gain on commodity derivative contracts and a benefit recorded for income tax expense for reversal of a valuation allowance for the Company's deferred tax assets.
|
•
|
Capital expenditures: The Company's capital expenditures on an accrual basis were $261.7 million and $308.3 million for the years ended December 31, 2019 and 2018, respectively. The expenditures for the year ended December 31, 2019, were primarily driven by continued legacy development and Southern Eagle Ford gas window delineation, while expenditures for the year ended December 31, 2018 were primarily driven by development activity in our Southern Eagle Ford fields. These expenditures were funded by cash flows from operations and borrowings under our Credit Facility.
|
•
|
Working capital: The Company had a working capital deficit of $27.8 million at December 31, 2019.
|
•
|
Cash Flows: For the year ended December 31, 2019, the Company generated cash from operating activities of $203.2 million, of which $4.9 million was attributable to changes in working capital. Cash used for property additions was $282.7 million. This excluded $21.6 million attributable to a net decrease of capital related payables and accrued costs. Additionally, $5.1 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 $84.0 million for the year ended December 31, 2019.
|
|
2020
|
2021
|
2022
|
2023
|
2024
|
Thereafter
|
Total
|
||||||||||||||
Non-cancelable operating leases
|
$
|
7,032
|
|
$
|
2,436
|
|
$
|
118
|
|
$
|
60
|
|
$
|
38
|
|
$
|
326
|
|
$
|
10,009
|
|
Gas transportation and processing (1)
|
8,811
|
|
5,383
|
|
3,868
|
|
2,626
|
|
1,614
|
|
1,088
|
|
23,391
|
|
|||||||
Interest cost (2)
|
32,503
|
|
32,606
|
|
23,999
|
|
20,342
|
|
19,623
|
|
—
|
|
129,075
|
|
|||||||
Long-term debt
|
—
|
|
—
|
|
279,000
|
|
—
|
|
200,000
|
|
—
|
|
479,000
|
|
|||||||
Other contractual commitments (3)
|
2,988
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
2,988
|
|
|||||||
Total
|
$
|
51,334
|
|
$
|
40,425
|
|
$
|
306,985
|
|
$
|
23,028
|
|
$
|
221,276
|
|
$
|
1,413
|
|
$
|
644,463
|
|
Fields
|
|
Oil and Gas Sales (In Millions)
|
|
Net Oil and Gas Production Volumes (MMcfe)
|
||||||||||
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
||||||
Artesia
|
|
$
|
78.8
|
|
|
$
|
53.8
|
|
|
19,593
|
|
|
10,514
|
|
AWP
|
|
74.1
|
|
|
52.8
|
|
|
14,637
|
|
|
10,470
|
|
||
Fasken
|
|
101.3
|
|
|
115.3
|
|
|
38,206
|
|
|
35,976
|
|
||
Other (1)
|
|
34.4
|
|
|
35.4
|
|
|
11,884
|
|
|
10,570
|
|
||
Total
|
|
$
|
288.6
|
|
|
$
|
257.3
|
|
|
84,320
|
|
|
67,530
|
|
•
|
Volume variances that had a $100.6 million favorable impact on sales, with a $60.4 million increase due to the 0.9 million Bbl increase in oil production volumes, a $25.0 million increase due to the 7.7 Bcf increase in natural gas production volumes and a $15.2 million increase due to the 0.6 million Bbl increase in NGL production volumes.
|
•
|
Price variances that had a $69.2 million unfavorable impact on sales, with a decrease of $37.7 million due to the 18% decrease in natural gas prices received, a decrease of $13.0 million due to the 12% decrease in oil prices received and a decrease of $18.6 million due to the 42% decrease in NGL prices received.
|
|
|
Year Ended December 31, 2019
|
Year Ended December 31, 2018
|
||||
Production volumes:
|
|
|
|
||||
Oil (MBbl) (1)
|
|
1,605
|
|
688
|
|
||
Natural gas (MMcf)
|
|
64,388
|
|
56,665
|
|
||
Natural gas liquids (MBbl) (1)
|
|
1,717
|
|
1,123
|
|
||
Total (MMcfe)
|
|
84,320
|
|
67,530
|
|
||
|
|
|
|
||||
Oil, natural gas and natural gas liquids sales:
|
|
|
|
||||
Oil
|
|
$
|
92,833
|
|
$
|
45,375
|
|
Natural gas
|
|
170,558
|
|
183,272
|
|
||
Natural gas liquids
|
|
25,241
|
|
28,639
|
|
||
Total
|
|
$
|
288,631
|
|
$
|
257,286
|
|
|
|
|
|
||||
Average realized price:
|
|
|
|
||||
Oil (per Bbl)
|
|
$
|
57.84
|
|
$
|
65.93
|
|
Natural gas (per Mcf)
|
|
2.65
|
|
3.23
|
|
||
Natural gas liquids (per Bbl)
|
|
14.70
|
|
25.51
|
|
||
Average per Mcfe
|
|
$
|
3.42
|
|
$
|
3.81
|
|
|
|
|
|
||||
Price impact of cash-settled derivatives:
|
|
|
|
||||
Oil (per Bbl)
|
|
$
|
1.19
|
|
$
|
(10.40
|
)
|
Natural gas (per Mcf)
|
|
0.26
|
|
(0.18
|
)
|
||
Natural gas liquids (per Bbl)
|
|
3.62
|
|
(1.65
|
)
|
||
Average per Mcfe
|
|
$
|
0.29
|
|
$
|
(0.28
|
)
|
|
|
|
|
||||
Average realized price including impact of cash-settled derivatives:
|
|
|
|
||||
Oil (per Bbl)
|
|
$
|
59.03
|
|
$
|
55.53
|
|
Natural gas (per Mcf)
|
|
2.91
|
|
3.06
|
|
||
Natural gas liquids (per Bbl)
|
|
18.32
|
|
23.87
|
|
||
Average per Mcfe
|
|
$
|
3.72
|
|
$
|
3.53
|
|
Costs and Expenses
|
Year Ended December 31, 2019
|
Year Ended December 31, 2018
|
||||
General and administrative, net
|
$
|
24,851
|
|
$
|
22,570
|
|
Depreciation, depletion, and amortization
|
95,915
|
|
68,035
|
|
||
Accretion of asset retirement obligation
|
329
|
|
419
|
|
||
Lease operating cost
|
20,763
|
|
17,643
|
|
||
Workovers
|
628
|
|
—
|
|
||
Transportation and gas processing
|
26,968
|
|
23,848
|
|
||
Severance and other taxes
|
13,874
|
|
11,394
|
|
||
Interest expense, net
|
$
|
36,561
|
|
$
|
27,666
|
|
•
|
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.
|
|
Year Ended December 31, 2019
|
Year Ended December 31, 2018
|
||||
Net Income (Loss)
|
$
|
114,656
|
|
$
|
74,615
|
|
Plus:
|
|
|
||||
Depreciation, depletion and amortization
|
95,915
|
|
68,035
|
|
||
Accretion of asset retirement obligations
|
329
|
|
419
|
|
||
Interest expense
|
36,561
|
|
27,666
|
|
||
Derivative (gain)/loss
|
(24,242
|
)
|
9,777
|
|
||
Derivative cash settlements collected/(paid) (1)
|
24,808
|
|
(19,060
|
)
|
||
Income tax expense/(benefit)
|
(21,582
|
)
|
928
|
|
||
Share-based compensation expense
|
6,148
|
|
5,980
|
|
||
Adjusted EBITDA
|
$
|
232,593
|
|
$
|
168,360
|
|
Less: Depreciation, depletion and amortization
|
(95,915
|
)
|
(68,035
|
)
|
||
Adjusted EBIT (A)
|
$
|
136,678
|
|
$
|
100,325
|
|
|
|
|
||||
Total Debt
|
$
|
395,000
|
|
$
|
273,000
|
|
Shareholders Equity
|
274,827
|
|
193,458
|
|
||
Capital Employed - Beginning of Year
|
$
|
669,827
|
|
$
|
466,458
|
|
|
|
|
||||
Total Debt
|
$
|
479,000
|
|
$
|
395,000
|
|
Shareholders Equity
|
395,707
|
|
274,827
|
|
||
Capital Employed - Year-End
|
$
|
874,707
|
|
$
|
669,827
|
|
|
|
|
||||
Average Capital Employed (B) (2)
|
$
|
772,267
|
|
$
|
568,143
|
|
|
|
|
||||
Return on Capital Employed (ROCE) (A / B)
|
18
|
%
|
18
|
%
|
||
(1) This includes accruals for settled contracts covering commodity deliveries during the period where the actual cash settlements occur outside of the period.
|
||||||
(2) B = Average of Beginning of Year and Year-End Capital Employed
|
•
|
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;
|
•
|
impact of governmental tariffs on cost of materials;
|
•
|
developments in world oil markets and in oil and natural gas-producing countries;
|
•
|
uncertainty regarding our future operating results; and
|
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
|
|
December 31, 2019
|
|
December 31, 2018
|
||||
ASSETS
|
|
|
|
||||
Current Assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
1,358
|
|
|
$
|
2,465
|
|
Accounts receivable, net
|
36,996
|
|
|
46,472
|
|
||
Fair value of commodity derivatives
|
12,833
|
|
|
15,261
|
|
||
Other current assets
|
2,121
|
|
|
2,126
|
|
||
Total Current Assets
|
53,308
|
|
|
66,324
|
|
||
Property and Equipment:
|
|
|
|
|
|
||
Property and Equipment, Full-Cost Method, including $41,201 and $56,715 of unproved property costs not being amortized
|
1,247,717
|
|
|
986,100
|
|
||
Less – Accumulated depreciation, depletion, amortization and impairment
|
(380,728
|
)
|
|
(284,804
|
)
|
||
Property and Equipment, Net
|
866,989
|
|
|
701,296
|
|
||
Right of Use Assets
|
9,374
|
|
|
—
|
|
||
Fair value of long-term commodity derivatives
|
3,854
|
|
|
4,333
|
|
||
Deferred Tax Asset
|
22,669
|
|
|
—
|
|
||
Other Long-Term Assets
|
3,622
|
|
|
5,567
|
|
||
Total Assets
|
$
|
959,816
|
|
|
$
|
777,520
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
||
Current Liabilities:
|
|
|
|
|
|
||
Accounts payable and accrued liabilities
|
$
|
39,343
|
|
|
$
|
48,921
|
|
Fair value of commodity derivatives
|
6,644
|
|
|
2,824
|
|
||
Accrued capital costs
|
17,889
|
|
|
38,073
|
|
||
Accrued interest
|
1,397
|
|
|
1,513
|
|
||
Current Lease Liability
|
6,707
|
|
|
—
|
|
||
Undistributed oil and gas revenues
|
9,166
|
|
|
14,681
|
|
||
Total Current Liabilities
|
81,146
|
|
|
106,012
|
|
||
|
|
|
|
||||
Long-term debt
|
472,900
|
|
|
387,988
|
|
||
Non-Current Lease liability
|
2,813
|
|
|
—
|
|
||
Deferred tax liabilities, net
|
1,582
|
|
|
1,014
|
|
||
Asset retirement obligations
|
4,055
|
|
|
3,956
|
|
||
Fair value of long-term commodity derivatives
|
1,613
|
|
|
3,723
|
|
||
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, 11,895,032 and 11,757,972 shares issued and 11,806,679 and 11,692,101 shares outstanding
|
119
|
|
|
118
|
|
||
Additional paid-in capital
|
292,916
|
|
|
286,281
|
|
||
Treasury stock held, at cost, 88,353 and 65,871 shares
|
(2,282
|
)
|
|
(1,870
|
)
|
||
Retained earnings (Accumulated deficit)
|
104,954
|
|
|
(9,702
|
)
|
||
Total Stockholders’ Equity
|
395,707
|
|
|
274,827
|
|
||
Total Liabilities and Stockholders’ Equity
|
$
|
959,816
|
|
|
$
|
777,520
|
|
See accompanying Notes to Consolidated Financial Statements.
|
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
||||
Revenues:
|
|
|
|
||||
Oil and gas sales
|
$
|
288,631
|
|
|
$
|
257,286
|
|
|
|
|
|
||||
Operating Expenses:
|
|
|
|
|
|||
General and administrative, net
|
24,851
|
|
|
22,570
|
|
||
Depreciation, depletion, and amortization
|
95,915
|
|
|
68,035
|
|
||
Accretion of asset retirement obligations
|
329
|
|
|
419
|
|
||
Lease operating expense
|
20,763
|
|
|
17,643
|
|
||
Workovers
|
628
|
|
|
—
|
|
||
Transportation and gas processing
|
26,968
|
|
|
23,848
|
|
||
Severance and other taxes
|
13,874
|
|
|
11,394
|
|
||
Total Operating Expenses
|
183,328
|
|
|
143,909
|
|
||
|
|
|
|
||||
Operating Income (Loss)
|
105,303
|
|
|
113,377
|
|
||
|
|
|
|
||||
Non-Operating Income (Expense)
|
|
|
|
||||
Net gain (loss) on commodity derivatives
|
24,242
|
|
|
(9,777
|
)
|
||
Interest expense, net
|
(36,561
|
)
|
|
(27,666
|
)
|
||
Other income (expense), net
|
90
|
|
|
(391
|
)
|
||
|
|
|
|
||||
Income (Loss) Before Income Taxes
|
93,074
|
|
|
75,543
|
|
||
|
|
|
|
||||
Provision (Benefit) for Income Taxes
|
(21,582
|
)
|
|
928
|
|
||
|
|
|
|
||||
Net Income (Loss)
|
$
|
114,656
|
|
|
$
|
74,615
|
|
|
|
|
|
||||
Per Share Amounts:
|
|
|
|
|
|||
|
|
|
|
||||
Basic: Net Income (Loss)
|
$
|
9.76
|
|
|
$
|
6.40
|
|
|
|
|
|
||||
Diluted: Net Income (Loss)
|
$
|
9.74
|
|
|
$
|
6.34
|
|
|
|
|
|
||||
Weighted Average Shares Outstanding - Basic
|
11,753
|
|
|
11,655
|
|
||
|
|
|
|
||||
Weighted Average Shares Outstanding - Diluted
|
11,778
|
|
|
11,764
|
|
||
|
|
|
|
||||
See accompanying Notes to Consolidated Financial Statements.
|
|
Common Stock
|
|
Additional Paid-in Capital
|
|
Treasury Stock
|
|
Retained Earnings (Accumulated Deficit)
|
|
Total
|
||||||||||
Balance, December 31, 2017
|
$
|
116
|
|
|
$
|
279,111
|
|
|
$
|
(1,452
|
)
|
|
$
|
(84,317
|
)
|
|
$
|
193,458
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Shares issued from option exercise (29,199 shares)
|
1
|
|
|
708
|
|
|
—
|
|
|
—
|
|
|
709
|
|
|||||
Purchase of treasury shares (15,107 shares)
|
—
|
|
|
—
|
|
|
(418
|
)
|
|
—
|
|
|
(418
|
)
|
|||||
Issuance of restricted stock (107,388 shares)
|
1
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Share-based compensation
|
—
|
|
|
6,463
|
|
|
—
|
|
|
—
|
|
|
6,463
|
|
|||||
Net Income
|
—
|
|
|
—
|
|
|
—
|
|
|
74,615
|
|
|
74,615
|
|
|||||
Balance, December 31, 2018
|
$
|
118
|
|
|
$
|
286,281
|
|
|
$
|
(1,870
|
)
|
|
$
|
(9,702
|
)
|
|
$
|
274,827
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Purchase of treasury shares (22,482 shares)
|
—
|
|
|
—
|
|
|
(412
|
)
|
|
—
|
|
|
(412
|
)
|
|||||
Issuance of restricted stock (137,060 shares)
|
1
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Share-based compensation
|
—
|
|
|
6,636
|
|
|
—
|
|
|
—
|
|
|
6,636
|
|
|||||
Net Income
|
—
|
|
|
—
|
|
|
—
|
|
|
114,656
|
|
|
114,656
|
|
|||||
Balance, December 31, 2019
|
$
|
119
|
|
|
$
|
292,916
|
|
|
$
|
(2,282
|
)
|
|
$
|
104,954
|
|
|
$
|
395,707
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
See accompanying Notes to Consolidated Financial Statements.
|
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
||||
Cash Flows from Operating Activities:
|
|
|
|
||||
Net income (loss)
|
$
|
114,656
|
|
|
$
|
74,615
|
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities-
|
|
|
|
|
|||
Depreciation, depletion, and amortization
|
95,915
|
|
|
68,035
|
|
||
Accretion of asset retirement obligations
|
329
|
|
|
419
|
|
||
Deferred income tax benefit
|
(22,101
|
)
|
|
1,014
|
|
||
Share-based compensation expense
|
6,148
|
|
|
5,980
|
|
||
(Gain) Loss on derivatives, net
|
(24,242
|
)
|
|
9,777
|
|
||
Cash settlements (paid) received on derivatives
|
24,631
|
|
|
(19,677
|
)
|
||
Settlements of asset retirement obligations
|
(83
|
)
|
|
(187
|
)
|
||
Write-down of debt issuance cost
|
82
|
|
|
—
|
|
||
Other
|
2,930
|
|
|
5,293
|
|
||
Change in operating assets and liabilities-
|
|
|
|
|
|||
(Increase) decrease in accounts receivable and other assets
|
11,605
|
|
|
(20,470
|
)
|
||
Increase (decrease) in accounts payable and accrued liabilities
|
(7,100
|
)
|
|
(2,686
|
)
|
||
Increase (decrease) in income taxes payable
|
519
|
|
|
53
|
|
||
Increase (decrease) in accrued interest
|
(116
|
)
|
|
(593
|
)
|
||
Net Cash Provided by (Used in) Operating Activities
|
203,173
|
|
|
121,573
|
|
||
Cash Flows from Investing Activities:
|
|
|
|
|
|||
Additions to property and equipment
|
(282,660
|
)
|
|
(266,532
|
)
|
||
Acquisition of producing properties
|
—
|
|
|
(1,002
|
)
|
||
Proceeds from (adjustments to) the sale of property and equipment
|
(96
|
)
|
|
27,673
|
|
||
Payments on property sale obligations
|
(5,112
|
)
|
|
(8,740
|
)
|
||
Transfer of company funds in restricted cash
|
—
|
|
|
(222
|
)
|
||
Net Cash Provided by (Used in) Investing Activities
|
(287,868
|
)
|
|
(248,823
|
)
|
||
Cash Flows from Financing Activities:
|
|
|
|
|
|||
Proceeds from bank borrowings
|
381,000
|
|
|
306,800
|
|
||
Payments of bank borrowings
|
(297,000
|
)
|
|
(184,800
|
)
|
||
Net proceeds from issuances of common stock
|
—
|
|
|
709
|
|
||
Purchase of treasury shares
|
(412
|
)
|
|
(418
|
)
|
||
Payments of debt issuance costs
|
—
|
|
|
(602
|
)
|
||
Net Cash Provided by (Used in) Financing Activities
|
83,588
|
|
|
121,689
|
|
||
|
|
|
|
||||
Net Increase (Decrease) in Cash and Cash Equivalents and Restricted Cash
|
(1,107
|
)
|
|
(5,561
|
)
|
||
Cash, Cash Equivalents and Restricted Cash at Beginning of Year
|
2,465
|
|
|
8,026
|
|
||
Cash, Cash Equivalents and Restricted Cash at End of Year
|
$
|
1,358
|
|
|
$
|
2,465
|
|
|
|
|
|
||||
Supplemental Disclosures of Cash Flows Information:
|
|
|
|
|
|||
Cash paid during period for interest, net of amounts capitalized
|
$
|
34,408
|
|
|
$
|
24,794
|
|
Changes in capital accounts payable and capital accruals
|
$
|
(21,584
|
)
|
|
$
|
45,349
|
|
Changes in other long-term liabilities for capital expenditures
|
$
|
—
|
|
|
$
|
(5,000
|
)
|
|
•
|
the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom, and the Ceiling Test impairment calculation,
|
•
|
estimates related to the collectability of accounts receivable and the credit worthiness of our customers,
|
•
|
estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf,
|
•
|
estimates of future costs to develop and produce reserves,
|
•
|
accruals related to oil and gas sales, capital expenditures and lease operating expenses,
|
•
|
estimates in the calculation of share-based compensation expense,
|
•
|
estimates of our ownership in properties prior to final division of interest determination,
|
•
|
the estimated future cost and timing of asset retirement obligations,
|
•
|
estimates made in our income tax calculations,
|
•
|
estimates in the calculation of the fair value of commodity derivative assets and liabilities,
|
•
|
estimates in the assessment of current litigation claims against the Company,
|
•
|
estimates in amounts due with respect to open state regulatory audits, and
|
•
|
estimates on future lease obligations.
|
|
|
|||||
|
December 31,
2019 |
December 31,
2018 |
||||
Property and Equipment
|
|
|
||||
Proved oil and gas properties
|
$
|
1,201,296
|
|
$
|
925,865
|
|
Unproved oil and gas properties
|
41,201
|
|
56,715
|
|
||
Furniture, fixtures, and other equipment
|
5,220
|
|
3,520
|
|
||
Less – Accumulated depreciation, depletion, amortization & impairment
|
(380,728
|
)
|
(284,804
|
)
|
||
Property and Equipment, Net
|
$
|
866,989
|
|
$
|
701,296
|
|
|
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
||||
Oil, natural gas and NGLs sales:
|
|
|
|
|
||||
Oil
|
|
$
|
92,833
|
|
|
$
|
45,375
|
|
Natural gas
|
|
170,472
|
|
|
183,288
|
|
||
NGLs
|
|
25,241
|
|
|
28,639
|
|
||
Other
|
|
86
|
|
|
(16
|
)
|
||
Total
|
|
$
|
288,631
|
|
|
$
|
257,286
|
|
|
December 31,
2019 |
December 31,
2018 |
||||
Trade accounts payable
|
$
|
26,121
|
|
$
|
32,683
|
|
Accrued operating expenses
|
3,873
|
|
3,549
|
|
||
Accrued compensation costs
|
4,601
|
|
4,785
|
|
||
Asset retirement obligations – current portion
|
392
|
|
302
|
|
||
Accrued non-income based taxes
|
1,413
|
|
3,583
|
|
||
Accrued corporate and legal fees
|
109
|
|
534
|
|
||
Other payables
|
2,834
|
|
3,485
|
|
||
Total accounts payable and accrued liabilities
|
$
|
39,343
|
|
$
|
48,921
|
|
Purchasers greater than 10%
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
||
Kinder Morgan
|
31
|
%
|
|
37
|
%
|
Plains Marketing
|
14
|
%
|
|
*
|
|
Twin Eagle
|
13
|
%
|
|
*
|
|
Shell Trading
|
11
|
%
|
|
*
|
|
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
||||||||||||||||||
|
Net Income (Loss)
|
|
Shares
|
|
Per Share
Amount |
|
Net Income (Loss)
|
|
Shares
|
|
Per Share
Amount |
||||||||||
Basic EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Net Income (Loss) and Share Amounts
|
$
|
114,656
|
|
|
11,753
|
|
|
$
|
9.76
|
|
|
$
|
74,615
|
|
|
11,655
|
|
|
$
|
6.40
|
|
Dilutive Securities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Restricted Stock Unit Awards
|
|
|
25
|
|
|
|
|
|
|
94
|
|
|
|
||||||||
Stock Option Awards
|
|
|
—
|
|
|
|
|
|
|
15
|
|
|
|
|
|||||||
Diluted EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Net Income (Loss) and Assumed Share Conversions
|
$
|
114,656
|
|
|
11,778
|
|
|
$
|
9.74
|
|
|
$
|
74,615
|
|
|
11,764
|
|
|
$
|
6.34
|
|
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
||||
Income (Loss) Before Income Taxes
|
$
|
93,074
|
|
|
$
|
75,543
|
|
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
||||
Current
|
$
|
519
|
|
|
$
|
(86
|
)
|
Deferred
|
(22,101
|
)
|
|
1,014
|
|
||
Total
|
$
|
(21,582
|
)
|
|
$
|
928
|
|
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
||
Federal Statutory Rate
|
21.0
|
%
|
|
21.0
|
%
|
State tax provisions (benefits), net of federal benefits
|
1.0
|
%
|
|
1.2
|
%
|
Executive compensation limitation
|
0.3
|
%
|
|
0.3
|
%
|
Other, net
|
0.1
|
%
|
|
0.2
|
%
|
Valuation allowance adjustments
|
(45.5
|
)%
|
|
(21.4
|
)%
|
Effective rate
|
(23.0
|
)%
|
|
1.2
|
%
|
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
||||
Deferred tax assets:
|
|
|
|
||||
Federal net operating loss (“NOL”) carryovers
|
$
|
67,610
|
|
|
$
|
71,736
|
|
Other carryover items
|
552
|
|
|
583
|
|
||
Asset retirement obligations
|
960
|
|
|
920
|
|
||
Share-based compensation
|
1,210
|
|
|
906
|
|
||
Lease liability
|
1,999
|
|
|
—
|
|
||
Other
|
874
|
|
|
956
|
|
||
Valuation allowance
|
—
|
|
|
(42,335
|
)
|
||
Total deferred tax assets
|
$
|
73,205
|
|
|
$
|
32,766
|
|
|
|
|
|
||||
Deferred tax liabilities:
|
|
|
|
||||
Oil and gas exploration and development costs
|
$
|
(48,329
|
)
|
|
$
|
(30,935
|
)
|
Derivative contracts
|
(1,820
|
)
|
|
(2,817
|
)
|
||
Leased assets
|
(1,968
|
)
|
|
—
|
|
||
Other
|
(1
|
)
|
|
(28
|
)
|
||
Total deferred tax liabilities
|
(52,118
|
)
|
|
(33,780
|
)
|
||
|
|
|
|
||||
Net deferred tax asset (liabilities)
|
$
|
21,087
|
|
|
$
|
(1,014
|
)
|
|
|
|
|
||||
State net deferred tax liabilities
|
$
|
(1,582
|
)
|
|
$
|
(1,014
|
)
|
Federal net deferred tax assets
|
22,669
|
|
|
—
|
|
||
Net deferred tax asset (liabilities)
|
$
|
21,087
|
|
|
$
|
(1,014
|
)
|
|
December 31, 2019
|
|
December 31, 2018
|
||||
Credit Facility Borrowings (1)
|
$
|
279,000
|
|
|
$
|
195,000
|
|
Second Lien Notes due 2024
|
200,000
|
|
|
200,000
|
|
||
|
479,000
|
|
|
395,000
|
|
||
Unamortized discount on Second Lien Notes due 2024
|
(1,550
|
)
|
|
(1,782
|
)
|
||
Unamortized debt issuance cost on Second Lien Notes due 2024
|
(4,550
|
)
|
|
(5,230
|
)
|
||
Total Long-Term Debt
|
$
|
472,900
|
|
|
$
|
387,988
|
|
•
|
a ratio of total debt to earnings before interest, tax, depreciation and amortization ("EBITDA"), as defined in the Credit Agreement, for the most recently completed four fiscal quarters, not to exceed 4.0 to 1.0 as of the last day of each fiscal quarter; and
|
•
|
a current ratio, as defined in the Credit Agreement, which includes in the numerator available borrowings undrawn under the borrowing base, of not less than 1.0 to 1.0 as of the last day of each fiscal quarter.
|
Oil Derivative Swaps
(NYMEX WTI Settlements) |
Total Volumes (Bbls)
|
|
Weighted Average Price
|
|||
2020 Contracts
|
|
|
|
|||
1Q20
|
361,597
|
|
|
$
|
56.61
|
|
2Q20
|
452,569
|
|
|
$
|
56.41
|
|
3Q20
|
500,279
|
|
|
$
|
55.92
|
|
4Q20
|
421,621
|
|
|
$
|
54.61
|
|
|
|
|
|
|||
2021 Contracts
|
|
|
|
|||
1Q21
|
328,603
|
|
|
$
|
53.11
|
|
2Q21
|
320,033
|
|
|
$
|
53.46
|
|
3Q21
|
313,848
|
|
|
$
|
52.38
|
|
4Q21
|
230,000
|
|
|
$
|
53.22
|
|
Natural Gas Derivative Swaps
(NYMEX Henry Hub Settlements) |
Total Volumes (MMBtu)
|
|
Weighted Average Price
|
|
Weighted Average Collar Floor Price
|
|
Weighted Average Collar Call Price
|
|||||||
2020 Contracts
|
|
|
|
|
|
|
|
|||||||
1Q20
|
9,920,000
|
|
|
$
|
2.73
|
|
|
|
|
|
||||
2Q20
|
7,328,000
|
|
|
$
|
2.63
|
|
|
|
|
|
||||
3Q20
|
7,265,000
|
|
|
$
|
2.63
|
|
|
|
|
|
||||
4Q20
|
7,042,000
|
|
|
$
|
2.63
|
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|||||||
2021 Contracts
|
|
|
|
|
|
|
|
|||||||
1Q21
|
148,078
|
|
|
$
|
2.70
|
|
|
|
|
|
||||
2Q21
|
442,255
|
|
|
$
|
2.30
|
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|||||||
Collar Contracts
|
|
|
|
|
|
|
|
|||||||
1Q21
|
4,354,800
|
|
|
|
|
$
|
2.50
|
|
|
$
|
3.52
|
|
||
2Q21
|
3,791,000
|
|
|
|
|
$
|
2.20
|
|
|
$
|
2.75
|
|
||
3Q21
|
4,007,175
|
|
|
|
|
$
|
2.00
|
|
|
$
|
2.70
|
|
||
4Q21
|
3,726,000
|
|
|
|
|
$
|
2.25
|
|
|
$
|
2.75
|
|
Natural Gas Basis Derivative Swaps
(East Texas Houston Ship Channel vs. NYMEX Settlements) |
Total Volumes (MMBtu)
|
|
Weighted Average Price
|
|||
2020 Contracts
|
|
|
|
|||
1Q20
|
11,739,000
|
|
|
$
|
(0.03
|
)
|
2Q20
|
11,739,000
|
|
|
$
|
(0.04
|
)
|
3Q20
|
11,868,000
|
|
|
$
|
(0.03
|
)
|
4Q20
|
11,868,000
|
|
|
$
|
(0.04
|
)
|
|
|
|
|
|||
2021 Contracts
|
|
|
|
|||
1Q21
|
7,200,000
|
|
|
$
|
(0.003
|
)
|
2Q21
|
7,280,000
|
|
|
$
|
(0.003
|
)
|
3Q21
|
7,360,000
|
|
|
$
|
(0.003
|
)
|
4Q21
|
7,360,000
|
|
|
$
|
(0.003
|
)
|
Oil Basis Derivative Swaps
(Argus Cushing (WTI) and LLS Settlements) |
Total Volumes (Bbls)
|
|
Weighted Average Price
|
|||
2020 Contracts (Calendar Monthly Roll Differential Swaps)
|
|
|
|
|||
1Q20
|
182,000
|
|
|
$
|
0.49
|
|
2Q20
|
182,000
|
|
|
$
|
0.49
|
|
3Q20
|
184,000
|
|
|
$
|
0.49
|
|
4Q20
|
184,000
|
|
|
$
|
0.49
|
|
|
Shares
|
|
Wtd. Avg.
Exer. Price
|
|||
Options outstanding, beginning of period
|
644,575
|
|
|
$
|
28.28
|
|
Options forfeited
|
(40,795
|
)
|
|
$
|
27.00
|
|
Options canceled in Equity Award Exchange
|
(201,406
|
)
|
|
$
|
31.14
|
|
Options expired
|
(71,557
|
)
|
|
$
|
23.81
|
|
Options outstanding, end of period
|
330,817
|
|
|
$
|
27.66
|
|
Options exercisable, end of period
|
166,824
|
|
|
$
|
28.94
|
|
|
Shares
|
|
Wtd. Avg.
Grant Price |
|||
Restricted units outstanding, beginning of period
|
340,678
|
|
|
$
|
27.64
|
|
Restricted stock units granted
|
115,957
|
|
|
$
|
20.13
|
|
Restricted stock units granted under Equity Award Exchange
|
99,500
|
|
|
$
|
16.70
|
|
Restricted stock canceled under Equity Award Exchange
|
(24,622
|
)
|
|
$
|
31.14
|
|
Restricted stock units forfeited
|
(59,842
|
)
|
|
$
|
24.13
|
|
Restricted stock units vested
|
(128,988
|
)
|
|
$
|
27.54
|
|
Restricted stock units outstanding, end of period
|
342,683
|
|
|
$
|
22.10
|
|
|
Year Ended December 31, 2019
|
||
Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets
|
|
||
Property, plant and equipment acquisitions - short-term leases
|
$
|
10,573
|
|
Property, plant and equipment acquisitions - operating leases
|
41
|
|
|
Total lease costs in property, plant and equipment additions
|
$
|
10,614
|
|
|
Year Ended December 31, 2019
|
||
Lease Costs Included in the Condensed Consolidated Statements of Operations
|
|
||
Lease operating costs - short-term leases
|
$
|
2,071
|
|
Lease operating costs - operating leases
|
3,945
|
|
|
General and administrative, net - operating leases
|
681
|
|
|
Total lease cost expensed
|
$
|
6,697
|
|
|
As of December 31, 2019
|
|
Weighted-average remaining lease term (in years)
|
1.8
|
|
Weighted-average discount rate
|
5.0
|
%
|
|
December 31, 2019
|
||
2020
|
$
|
7,032
|
|
2021
|
2,436
|
|
|
2022
|
118
|
|
|
2023
|
60
|
|
|
2024
|
38
|
|
|
Thereafter
|
325
|
|
|
Total undiscounted lease payments
|
$
|
10,009
|
|
Present value adjustment
|
(489
|
)
|
|
Net operating lease liabilities
|
$
|
9,520
|
|
|
Year Ended December 31, 2019
|
||
Cash paid for amounts included in the measurement of lease liabilities
|
|
||
Operating cash flows from operating leases
|
$
|
4,609
|
|
Investing cash flows from operating leases
|
$
|
41
|
|
|
December 31, 2018
|
||
2019
|
$
|
4,470
|
|
2020
|
838
|
|
|
2021
|
332
|
|
|
Thereafter
|
—
|
|
|
Total undiscounted lease payments
|
$
|
5,640
|
|
|
Fair Value Measurements at
|
||||||||||||||
(in millions)
|
Total
|
|
Quoted Prices in
Active markets for
Identical Assets
(Level 1)
|
|
Significant Other
Observable Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
||||||||
December 31, 2019
|
|
|
|
|
|
|
|
||||||||
Assets
|
|
|
|
|
|
|
|
||||||||
Natural Gas Derivatives
|
$
|
11.7
|
|
|
$
|
—
|
|
|
$
|
11.7
|
|
|
$
|
—
|
|
Natural Gas Basis Derivatives
|
$
|
3.4
|
|
|
$
|
—
|
|
|
$
|
3.4
|
|
|
$
|
—
|
|
Oil Derivatives
|
$
|
1.6
|
|
|
$
|
—
|
|
|
$
|
1.6
|
|
|
$
|
—
|
|
Liabilities
|
|
|
|
|
|
|
|
||||||||
Natural Gas Derivatives
|
$
|
0.2
|
|
|
$
|
—
|
|
|
$
|
0.2
|
|
|
$
|
—
|
|
Natural Gas Basis Derivatives
|
$
|
0.9
|
|
|
$
|
—
|
|
|
$
|
0.9
|
|
|
$
|
—
|
|
Oil Derivatives
|
$
|
7.0
|
|
|
$
|
—
|
|
|
$
|
7.0
|
|
|
$
|
—
|
|
Oil Basis Derivatives
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
||||||||
December 31, 2018
|
|
|
|
|
|
|
|
||||||||
Assets
|
|
|
|
|
|
|
|
||||||||
Natural Gas Derivatives
|
$
|
7.5
|
|
|
$
|
—
|
|
|
$
|
7.5
|
|
|
$
|
—
|
|
Natural Gas Basis Derivatives
|
$
|
0.4
|
|
|
$
|
—
|
|
|
$
|
0.4
|
|
|
$
|
—
|
|
Oil Derivatives
|
$
|
6.9
|
|
|
$
|
—
|
|
|
$
|
6.9
|
|
|
$
|
—
|
|
NGL Derivatives
|
$
|
4.7
|
|
|
$
|
—
|
|
|
$
|
4.7
|
|
|
$
|
—
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
||||
Natural Gas Derivatives
|
$
|
1.0
|
|
|
$
|
—
|
|
|
$
|
1.0
|
|
|
$
|
—
|
|
Natural Gas Basis Derivatives
|
$
|
5.3
|
|
|
$
|
—
|
|
|
$
|
5.3
|
|
|
$
|
—
|
|
NGL Derivatives
|
$
|
0.2
|
|
|
$
|
—
|
|
|
$
|
0.2
|
|
|
$
|
—
|
|
Asset Retirement Obligations as of December 31, 2017
|
$
|
10,787
|
|
Accretion expense
|
419
|
|
|
Liabilities incurred for new wells and facilities construction
|
93
|
|
|
Reductions due to sold wells and facilities
|
(6,298
|
)
|
|
Reductions due to plugged wells and facilities
|
(180
|
)
|
|
Revisions in estimates
|
(562
|
)
|
|
Asset Retirement Obligations as of December 31, 2018
|
$
|
4,259
|
|
Accretion expense
|
329
|
|
|
Liabilities incurred for new wells and facilities construction
|
250
|
|
|
Reductions due to sold wells and facilities
|
—
|
|
|
Reductions due to plugged wells and facilities
|
(82
|
)
|
|
Revisions in estimates
|
(309
|
)
|
|
Asset Retirement Obligations as of December 31, 2019
|
$
|
4,447
|
|
|
Total
|
||
December 31, 2019
|
|
||
Proved oil and gas properties
|
$
|
1,201,296
|
|
Unproved oil and gas properties
|
41,201
|
|
|
Total
|
1,242,497
|
|
|
Accumulated depreciation, depletion, amortization and impairment
|
(377,861
|
)
|
|
Net capitalized costs
|
$
|
864,636
|
|
|
|
||
December 31, 2018
|
|
||
Proved oil and gas properties
|
$
|
925,865
|
|
Unproved oil and gas properties
|
56,715
|
|
|
Total
|
982,580
|
|
|
Accumulated depreciation, depletion, amortization and impairment
|
(282,663
|
)
|
|
Net capitalized costs
|
$
|
699,917
|
|
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
||||
Lease acquisitions and prospect costs
|
$
|
22,798
|
|
|
$
|
22,681
|
|
Exploration
|
—
|
|
|
—
|
|
||
Development (1) (3)
|
236,223
|
|
|
284,525
|
|
||
Acquisition of property
|
940
|
|
|
1,096
|
|
||
Total acquisition, exploration, and development (2)
|
$
|
259,961
|
|
|
$
|
308,302
|
|
Estimates of Proved Reserves
|
Total
|
|
Natural Gas
|
|
Oil
|
|
NGL
|
||||
|
(Mcfe)
|
|
(Mcf)
|
|
(Bbls)
|
|
(Bbls)
|
||||
Proved reserves as of December 31, 2017
|
1,024,421,384
|
|
|
842,735,076
|
|
|
7,159,695
|
|
|
23,121,356
|
|
Extensions, discoveries, and other additions (3)
|
450,353,613
|
|
|
357,778,652
|
|
|
6,690,818
|
|
|
8,738,342
|
|
Revisions of previous estimates (1)
|
(34,442,827
|
)
|
|
(31,025,348
|
)
|
|
149,332
|
|
|
(718,912
|
)
|
Purchases of minerals in place
|
427,200
|
|
|
427,200
|
|
|
—
|
|
|
—
|
|
Sales of minerals in place (4)
|
(27,866,979
|
)
|
|
(16,842,753
|
)
|
|
(532,809
|
)
|
|
(1,304,562
|
)
|
Production
|
(67,530,138
|
)
|
|
(56,665,272
|
)
|
|
(688,221
|
)
|
|
(1,122,590
|
)
|
|
|
|
|
|
|
|
|
||||
Proved reserves as of December 31, 2018
|
1,345,362,253
|
|
|
1,096,407,555
|
|
|
12,778,815
|
|
|
28,713,634
|
|
Extensions, discoveries, and other additions (3)
|
434,834,382
|
|
|
346,973,742
|
|
|
6,891,900
|
|
|
7,751,540
|
|
Revisions of previous estimates (1)
|
(275,773,843
|
)
|
|
(220,640,925
|
)
|
|
(1,054,261
|
)
|
|
(8,134,558
|
)
|
Purchases of minerals in place
|
336,498
|
|
|
—
|
|
|
56,083
|
|
|
—
|
|
Production
|
(84,320,479
|
)
|
|
(64,388,294
|
)
|
|
(1,604,931
|
)
|
|
(1,717,100
|
)
|
|
|
|
|
|
|
|
|
||||
Proved reserves as of December 31, 2019
|
1,420,438,811
|
|
|
1,158,352,078
|
|
|
17,067,606
|
|
|
26,613,516
|
|
|
|
|
|
|
|
|
|
||||
Proved developed reserves (2)
|
|
|
|
|
|
|
|
||||
December 31, 2017
|
458,252,677
|
|
|
377,504,768
|
|
|
5,026,398
|
|
|
8,431,587
|
|
December 31, 2018
|
554,896,291
|
|
|
466,128,862
|
|
|
5,507,442
|
|
|
9,287,129
|
|
December 31, 2019
|
579,122,401
|
|
|
478,005,141
|
|
|
6,475,646
|
|
|
10,377,231
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves
|
|
|
|
|
|
|
|
||||
December 31, 2017
|
566,168,707
|
|
|
465,230,305
|
|
|
2,133,297
|
|
|
14,689,769
|
|
December 31, 2018
|
790,465,963
|
|
|
630,278,693
|
|
|
7,271,373
|
|
|
19,426,505
|
|
December 31, 2019
|
841,316,410
|
|
|
680,346,937
|
|
|
10,591,960
|
|
|
16,236,285
|
|
|
As of December 31,
|
||||||
|
2019
|
|
2018
|
||||
Future gross revenues
|
$
|
4,481,152
|
|
|
$
|
4,950,917
|
|
Future production costs
|
(1,340,278
|
)
|
|
(1,366,404
|
)
|
||
Future development costs (1)
|
(865,434
|
)
|
|
(866,436
|
)
|
||
Future net cash flows before income taxes
|
2,275,440
|
|
|
2,718,077
|
|
||
Future income taxes
|
(283,327
|
)
|
|
(431,513
|
)
|
||
Future net cash flows after income taxes
|
1,992,113
|
|
|
2,286,564
|
|
||
Discount at 10% per annum
|
(1,123,849
|
)
|
|
(1,292,835
|
)
|
||
Standardized Measure of discounted future net cash flows relating to proved oil and natural gas reserves
|
$
|
868,264
|
|
|
$
|
993,729
|
|
|
2019
|
|
2018
|
||||
Beginning balance
|
$
|
993,729
|
|
|
$
|
731,527
|
|
|
|
|
|
||||
Revisions to reserves proved in prior years:
|
|
|
|
||||
Net changes in prices, net of production costs
|
(254,543
|
)
|
|
182,718
|
|
||
Net changes in future development costs
|
41,083
|
|
|
(4,264
|
)
|
||
Net changes due to revisions in quantity estimates
|
(151,725
|
)
|
|
(38,067
|
)
|
||
Accretion of discount
|
112,751
|
|
|
106,129
|
|
||
Other
|
(71,243
|
)
|
|
80,573
|
|
||
Total revisions
|
(323,677
|
)
|
|
327,089
|
|
||
|
|
|
|
||||
New field discoveries and extensions, net of future production and development costs
|
260,853
|
|
|
182,030
|
|
||
Purchase of reserves
|
805
|
|
|
472
|
|
||
Sales of minerals in place
|
—
|
|
|
(39,598
|
)
|
||
Sales of oil and gas produced, net of production costs
|
(226,397
|
)
|
|
(204,403
|
)
|
||
Previously estimated development costs incurred
|
136,778
|
|
|
57,332
|
|
||
Net change in income taxes
|
26,173
|
|
|
(60,720
|
)
|
||
Net change in Standardized Measure of discounted future net cash flows
|
(125,465
|
)
|
|
262,202
|
|
||
Ending balance
|
$
|
868,264
|
|
|
$
|
993,729
|
|
|
Oil and Gas Sales
|
|
Net Income (Loss) Before Taxes
|
|
Net Income (Loss)
|
|
Basic EPS
|
|
Diluted EPS
|
||||||||||
2018
|
|
|
|
|
|
|
|
|
|
||||||||||
First
|
$
|
52,752
|
|
|
$
|
8,466
|
|
|
$
|
8,466
|
|
|
$
|
0.73
|
|
|
$
|
0.72
|
|
Second
|
51,347
|
|
|
2,647
|
|
|
2,319
|
|
|
0.20
|
|
|
0.20
|
|
|||||
Third
|
65,034
|
|
|
7,300
|
|
|
7,080
|
|
|
0.61
|
|
|
0.60
|
|
|||||
Fourth
|
88,153
|
|
|
57,130
|
|
|
56,750
|
|
|
4.85
|
|
|
4.82
|
|
|||||
Total
|
$
|
257,286
|
|
|
$
|
75,543
|
|
|
$
|
74,615
|
|
|
$
|
6.40
|
|
|
$
|
6.34
|
|
2019
|
|
|
|
|
|
|
|
|
|
||||||||||
First
|
72,064
|
|
|
16,285
|
|
|
16,053
|
|
|
$
|
1.37
|
|
|
$
|
1.36
|
|
|||
Second
|
74,703
|
|
|
43,969
|
|
|
64,704
|
|
|
5.51
|
|
|
5.49
|
|
|||||
Third
|
72,014
|
|
|
28,690
|
|
|
27,651
|
|
|
2.35
|
|
|
2.35
|
|
|||||
Fourth
|
69,850
|
|
|
4,130
|
|
|
6,248
|
|
|
0.53
|
|
|
0.53
|
|
|||||
Total
|
$
|
288,631
|
|
|
$
|
93,074
|
|
|
$
|
114,656
|
|
|
$
|
9.76
|
|
|
$
|
9.74
|
|
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
|
|
Consolidated Balance Sheets
|
|
Consolidated Statements of Operations
|
|
Consolidated Statements of Stockholders' Equity (Deficit)
|
|
Consolidated Statements of Cash Flows
|
|
Notes to Consolidated Financial Statements
|
3.1
|
|
|
|
3.2
|
|
|
|
4.1
|
|
|
|
4.2
|
|
|
|
4.3
|
|
|
|
4.4
|
|
|
|
4.5*
|
|
|
|
10.1
|
|
|
|
10.2
|
|
|
|
10.3
|
|
|
|
10.4
|
|
|
|
10.5
|
|
|
|
10.6
|
|
|
|
10.7
|
|
|
|
10.8
|
|
|
|
10.9
|
|
|
|
10.10
|
|
|
|
10.11+
|
|
|
|
10.12+
|
|
|
|
10.13+
|
|
|
|
10.14+
|
|
|
|
10.15+
|
|
|
|
10.16+
|
|
|
|
10.17+
|
|
|
|
10.18+
|
|
|
|
10.19+
|
|
|
|
10.20+
|
|
|
10.21+
|
|
|
|
10.22+
|
|
|
|
10.23+
|
|
|
|
10.24+
|
|
|
|
10.25+
|
|
|
|
10.26+
|
|
|
|
10.27+
|
|
|
|
10.28+
|
|
|
|
10.29+
|
|
|
|
10.30+
|
|
|
|
10.31+
|
|
|
|
10.32+
|
|
|
|
10.33+
|
|
|
|
10.34+
|
|
|
|
10.35+
|
|
|
|
10.36+
|
|
|
|
10.37+
|
|
|
|
21 *
|
|
|
|
23.1 *
|
|
|
|
23.2 *
|
|
|
|
31.1 *
|
|
|
|
31.2*
|
|
|
|
32**
|
|
|
|
99.1*
|
|
|
|
101.INS*
|
XBRL Instance Document
|
|
|
101.SCH*
|
XBRL Schema Document
|
|
|
101.CAL*
|
XBRL Calculation Linkbase Document
|
|
|
101.LAB*
|
XBRL Label Linkbase Document
|
|
|
101.PRE*
|
XBRL Presentation Linkbase Document
|
|
|
101.DEF*
|
XBRL Definition Linkbase Document
|
|
SILVERBOW RESOURCES, INC.
|
|
|
|
By: /s/ Sean C. Woolverton
|
|
Sean C. Woolverton
|
|
Chief Executive Officer
|
Signatures
|
Title
|
Date
|
|
|
|
|
|
|
/s/ Sean C. Woolverton
|
Chief Executive Officer
|
March 5, 2020
|
Sean C. Woolverton
|
|
|
|
|
|
|
Executive Vice President,
|
|
/s/ Christopher M. Abundis
|
Chief Financial Officer,
|
March 5, 2020
|
Christopher M. Abundis
|
General Counsel and Secretary
|
|
|
|
|
|
|
|
/s/ Gary G. Buchta
|
Controller
|
March 5, 2020
|
Gary G. Buchta
|
|
|
|
|
|
|
Chairman of the Board
|
|
/s/ Marcus C. Rowland
|
Director
|
March 5, 2020
|
Marcus C. Rowland
|
|
|
|
|
|
|
|
|
/s/ Michael Duginski
|
Director
|
March 5, 2020
|
Michael Duginski
|
|
|
|
|
|
|
|
|
/s/ Gabriel L. Ellisor
|
Director
|
March 5, 2020
|
Gabriel L. Ellisor
|
|
|
|
|
|
|
|
|
/s/ David Geenberg
|
Director
|
March 5, 2020
|
David Geenberg
|
|
|
|
|
|
|
|
|
/s/ Christoph O. Majeske
|
Director
|
March 5, 2020
|
Christoph O. Majeske
|
|
|
|
|
|
|
|
|
/s/ Charles W. Wampler
|
Director
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March 5, 2020
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Charles W. Wampler
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|
|
•
|
the transaction is approved by the Board before the date the interested stockholder attained that status;
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•
|
upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced; or
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•
|
on or after such time the business combination is approved by the Board and authorized at a meeting of stockholders by at least 66 2⁄3% of the outstanding voting stock that is not owned by the interested stockholder.
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•
|
provide for the division of the Board into three classes, each class consisting as nearly as possible of one-third of the whole. The term of office of one class of directors expires each year; with each class of directors elected for a term of three years and until the stockholders elect their qualified successors, subject to the terms of the Nomination Agreement (as defined below);
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•
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provide that all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock or certain board designation rights, and subject to the terms of the Nomination Agreement, be filled by a majority of directors then in office, even if less than a quorum, or by the sole remaining director;
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•
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provide that our Bylaws may be amended by the affirmative vote of the holders of at least 66 2⁄3% of our then outstanding voting stock;
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•
|
provide that special meetings of our stockholders may only be called by our Chairman of the Board, Chief Executive Officer or by a majority of the total number of directors which the Company would have if there were no vacancies;
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•
|
authorize the Board to adopt resolutions providing for the issuance of undesignated preferred stock. This ability makes it possible for the Board to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us;
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•
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provide that the authorized number of directors may be changed only by the Board, subject to the terms of the Nomination Agreement;
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•
|
establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business (other than proposals submitted in accordance with Rule 14a-8 for inclusion in our proxy proposals) to be brought before meetings of our stockholders. These procedures provide that notice of stockholder proposals must be timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. Generally, for a proposal to be timely submitted for consideration at an annual meeting, notice must be delivered to our secretary not less than 90 days nor more than 120 days prior to the first anniversary date of the annual meeting for the preceding year. Our Bylaws specify the requirements as to form and content of all stockholders’ notices. These requirements may preclude stockholders from bringing matters before the stockholders at an annual or special meeting;
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•
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provide that our Bylaws may be amended by the Board; and
|
•
|
provide that that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware shall, to the fullest extent permitted by law, be the sole and exclusive forum for (a) any derivative action or proceeding brought on behalf of the Company, (b) any action asserting a claim of breach of a fiduciary duty owed by any director, officer, employee or agent of the Company to the Company or the Company’s stockholders, (c) any action asserting a claim arising pursuant to any provision of the DGCL, the Certificate of Incorporation or Bylaws, or (d) any action asserting a claim against the Company or any director or officer or other employee of the Company governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein.
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H.J. GRUY AND ASSOCIATES, INC.
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|
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By:
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/s/ Marilyn Wilson
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|
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Marilyn Wilson, P.E.
President and Chief Executive Officer
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1.
|
I have reviewed this Annual Report on Form 10-K for the period ended December 31, 2019, of SilverBow Resources, Inc. (the "registrant");
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting, to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
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(d)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
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Date:
|
March 5, 2020
|
|
/s/Sean C. Woolverton
|
|
|
|
Sean C. Woolverton
Chief Executive Officer
|
1.
|
I have reviewed this Annual Report on Form 10-K for the period ended December 31, 2019, of SilverBow Resources, Inc. (the "registrant");
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting, to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date:
|
March 5, 2020
|
|
/s/ Christopher M. Abundis
|
|
|
|
Christopher M. Abundis Executive Vice President, Chief Financial Officer, General Counsel and Secretary
|
1.
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
|
2.
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
Date:
|
March 5, 2020
|
|
/s/ Sean C. Woolverton
|
|
|
|
Sean C. Woolverton
Chief Executive Officer
|
Date:
|
March 5, 2020
|
|
/s/ Christopher M. Abundis
|
|
|
|
Christopher M. Abundis Executive Vice President, Chief Financial Officer, General Counsel and Secretary
|
Proved Reserves
|
|||||||||||||
|
Estimated
|
|
Estimated
|
||||||||||
|
Net Reserves
|
|
Future Net Cash Flow
|
||||||||||
|
|
|
Natural
|
|
|
Discounted
|
|||||||
|
Oil
|
Gas
|
Gas Liquids
|
|
Not
|
at 10 Percent
|
|||||||
|
(Barrels)
|
(Mcf)
|
(Barrels)
|
|
Discounted
|
Per Year
|
|||||||
Proved Producing
|
6,374,100
|
|
455,377,200
|
|
10,084,700
|
|
|
$
|
1,111,213,500
|
|
$
|
620,824,900
|
|
Proved Nonproducing
|
101,500
|
|
22,627,800
|
|
292,500
|
|
|
$
|
35,467,600
|
|
$
|
15,929,800
|
|
Proved Undeveloped
|
10,592,000
|
|
680,346,900
|
|
16,236,300
|
|
|
$
|
1,168,881,900
|
|
$
|
340,797,300
|
|
Total Proved
|
17,067,600
|
|
1,158,351,900
|
|
26,613,500
|
|
|
$
|
2,315,563,000
|
|
$
|
977,552,000
|
|
1.
|
I am President of H.J. Gruy and Associates, Inc, and I am the engineer responsible for the estimates of reserves, future production, and future income determined by H.J. Gruy and Associates, Inc. and preparation of the reserves report for SilverBow Resources effective December 31, 2019, and dated January 22, 2020, attached herewith.
|
2.
|
I hold a Bachelor of Science Degree in Petroleum Engineering from Texas A&M University, and I am a Licensed Professional Engineer in the State of Texas, License Number 59498. I am a member of the Society of Petroleum Engineers, and I am a past President and member of the Society of Petroleum Evaluation Engineers. I have over 30 years of experience in the evaluation of oil and gas reserves.
|
3.
|
Based on my educational and professional background, I meet or exceed the professional qualifications as a Reserves Estimator presented in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers.
|