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

FORM 10-Q

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

For the quarterly period ended June 30, 2019March 31, 2020
Commission File Number 1-8754
silverbowlogoblacka07.jpgsilverbowlogoblack20.jpg
SILVERBOW RESOURCES, INC.
(Exact Name of Registrant as Specified in Its Charter)
Delaware
(State of Incorporation)
20-3940661
(I.R.S. Employer Identification No.)
  
575 North Dairy Ashford, Suite 1200
Houston, Texas 77079
(281) 874-2700
(Address and telephone number of principal executive offices)
Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(b) of the Act:

Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Stock, par value $0.01 per shareSBOWNew York Stock Exchange

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.
YesþNoo

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 such files).
YesþNo
 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 Filero Accelerated Filer
þ 
 Non-Accelerated Filer
 o
 Smaller Reporting Company
 þ
Emerging Growth Companyo         

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 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).
YesoNoþ

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d)of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
YesþNo
 o

Indicate the number of shares outstanding of each of the issuer’s classes
of common stock, as of the latest practicable date.
Common Stock ($.01 Par Value) (Class of Stock)11,758,31711,886,543 Shares outstanding at AugustMay 1, 20192020

SILVERBOW RESOURCES, INC.
 
FORM 10-Q
 
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2019MARCH 31, 2020
INDEX

  Page
Part IFINANCIAL INFORMATION 
   
Item 1.Condensed Consolidated Financial Statements 
   
 
   
 
   
 
   
 
   
 
   
Item 2.
   
Item 3.
   
Item 4.
   
Part IIOTHER INFORMATION 
   
Item 1.
Item 1A.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
  



PART I. FINANCIAL INFORMATION
Condensed Consolidated Balance Sheets (Unaudited)
SilverBow Resources, Inc. and Subsidiaries (in thousands, except share amounts)
June 30, 2019
December 31, 2018March 31, 2020
December 31, 2019
ASSETS 
  
 
Current Assets: 
  
 
Cash and cash equivalents$3,333

$2,465
$35,598

$1,358
Accounts receivable, net34,760

46,472
30,345

36,996
Fair value of commodity derivatives21,738

15,261
38,817

12,833
Other current assets3,241

2,126
2,846

2,121
Total Current Assets63,072

66,324
107,606

53,308
Property and Equipment: 

 
 

 
Property and equipment, full cost method, including $49,866 and $56,715, respectively, of unproved property costs not being amortized at the end of each period1,144,217

986,100
Property and equipment, full cost method, including $42,249 and $41,201, respectively, of unproved property costs not being amortized at the end of each period1,298,453

1,247,717
Less – Accumulated depreciation, depletion, amortization & impairment(330,638)
(284,804)(499,759)
(380,728)
Property and Equipment, Net813,579

701,296
798,694

866,989
Right of Use Assets12,568
 
7,839
 9,374
Fair Value of Long-Term Commodity Derivatives5,910

4,333
8,867

3,854
Deferred Tax Asset21,164
 
23,433
 22,669
Other Long-Term Assets4,895

5,567
2,770

3,622
Total Assets$921,188

$777,520
$949,209

$959,816
LIABILITIES AND STOCKHOLDERS’ EQUITY 

 
 

 
Current Liabilities: 

 
 

 
Accounts payable and accrued liabilities$33,320

$48,921
$36,159

$39,343
Fair value of commodity derivatives2,035

2,824
1,265

6,644
Accrued capital costs28,166

38,073
12,104

17,889
Accrued interest1,333

1,513
1,186

1,397
Current lease liability7,006
 
6,622
 6,707
Undistributed oil and gas revenues11,755

14,681
8,705

9,166
Total Current Liabilities83,615

106,012
66,041

81,146






Long-Term Debt, Net466,433

387,988
484,142

472,900
Non-Current Lease Liability5,605
 
1,397
 2,813
Deferred Tax Liabilities1,446

1,014
1,281

1,582
Asset Retirement Obligations4,218

3,956
4,170

4,055
Fair Value of Long-Term Commodity Derivatives987

3,723
1,047

1,613
Other Long-Term Liabilities30
 
Commitments and Contingencies (Note 11)









Stockholders' Equity: 

 
 

 
Preferred stock, $0.01 par value, 10,000,000 shares authorized, none issued





Common stock, $0.01 par value, 40,000,000 shares authorized, 11,838,397 and 11,757,972 shares issued, respectively, and 11,757,573 and 11,692,101 shares outstanding, respectively118

118
Common stock, $0.01 par value, 40,000,000 shares authorized, 12,000,140 and 11,895,032 shares issued, respectively, and 11,885,112 and 11,806,679 shares outstanding, respectively120

119
Additional paid-in capital289,899

286,281
294,250

292,916
Treasury stock, held at cost, 80,824 and 65,871 shares, respectively(2,188)
(1,870)
Retained earnings (accumulated deficit)71,055

(9,702)
Treasury stock, held at cost, 115,028 and 88,353 shares, respectively(2,365)
(2,282)
Retained earnings99,096

104,954
Total Stockholders’ Equity358,884

274,827
391,101

395,707
Total Liabilities and Stockholders’ Equity$921,188

$777,520
$949,209

$959,816






See accompanying Notes to Condensed Consolidated Financial Statements.

Condensed Consolidated Statements of Operations (Unaudited)
SilverBow Resources, Inc. and Subsidiaries (in thousands, except per-share amounts)
 Three Months Ended June 30, 2019
Three Months Ended June 30, 2018
Revenues: 

Oil and gas sales$74,703

$51,347






Operating Expenses: 



General and administrative, net6,624

5,794
Depreciation, depletion, and amortization24,029

13,096
Accretion of asset retirement obligations86

84
Lease operating costs5,035

3,760
Workovers(127) 
Transportation and gas processing6,728

5,421
Severance and other taxes3,950

2,662
Total Operating Expenses46,325
 30,817






Operating Income (Loss)28,378

20,530






Non-Operating Income (Expense)




Gain (loss) on commodity derivatives, net24,925

(10,752)
Interest expense, net(9,306)
(6,585)
Other income (expense), net(28)
(546)






Income (Loss) Before Income Taxes43,969

2,647






Provision (Benefit) for Income Taxes(20,735)
328






Net Income (Loss)$64,704

$2,319






Per Share Amounts 









Basic:  Net Income (Loss)$5.51

$0.20






Diluted:  Net Income (Loss)$5.49

$0.20






Weighted-Average Shares Outstanding - Basic11,746

11,655






Weighted-Average Shares Outstanding - Diluted11,780

11,757




See accompanying Notes to Condensed Consolidated Financial Statements.






 Six Months Ended June 30, 2019 Six Months Ended June 30, 2018
Revenues:   
Oil and gas sales$146,768
 $104,099
    
Operating Expenses: 
  
General and administrative, net12,900
 11,370
Depreciation, depletion, and amortization45,834
 26,228
Accretion of asset retirement obligations168
 243
Lease operating costs9,567
 8,721
Workovers519
 
Transportation and gas processing13,135
 10,446
Severance and other taxes7,266
 5,692
Total Operating Expenses89,389
 62,700
    
Operating Income (Loss)57,379
 41,399
    
Non-Operating Income (Expense)   
Gain (loss) on commodity derivatives, net20,903
 (17,107)
Interest expense, net(18,065) (12,474)
Other income (expense), net37
 (703)
    
Income (Loss) Before Income Taxes60,254
 11,115
    
Provision (Benefit) for Income Taxes(20,503) 328
    
Net Income (Loss)$80,757
 $10,787
    
Per Share Amounts 
  
    
Basic:  Net Income (Loss)$6.89
 $0.93
    
Diluted:  Net Income (Loss)$6.85
 $0.92
    
Weighted-Average Shares Outstanding - Basic11,727
 11,629
    
Weighted-Average Shares Outstanding - Diluted11,786
 11,742
    
See accompanying Notes to Condensed Consolidated Financial Statements.   





 Three Months Ended March 31, 2020
Three Months Ended March 31, 2019
Revenues: 

Oil and gas sales$53,377

$72,064






Operating Expenses: 



General and administrative, net5,913

6,276
Depreciation, depletion, and amortization23,439

21,805
Accretion of asset retirement obligations86

83
Lease operating costs5,812

4,531
Workovers
 646
Transportation and gas processing6,643

6,406
Severance and other taxes2,964

3,316
Write-down of oil and gas properties95,606


Total Operating Expenses140,463
 43,063






Operating Income (Loss)(87,086)
29,001






Non-Operating Income (Expense)




Gain (loss) on commodity derivatives, net88,287

(4,022)
Interest expense, net(8,407)
(8,759)
Other income (expense), net107

65






Income (Loss) Before Income Taxes(7,099)
16,285






Provision (Benefit) for Income Taxes(1,241)
232






Net Income (Loss)$(5,858)
$16,053






Per Share Amounts 









Basic:  Net Income (Loss)$(0.50)
$1.37






Diluted:  Net Income (Loss)$(0.50)
$1.36






Weighted-Average Shares Outstanding - Basic11,825

11,708






Weighted-Average Shares Outstanding - Diluted11,825

11,788




See accompanying Notes to Condensed Consolidated Financial Statements.



Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)
SilverBow Resources, Inc. and Subsidiaries (in thousands, except share amounts)
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)
 708
 
 
 708
Purchase of treasury shares (10,458 shares)
 
 (290) 
 (290)
Issuance of restricted stock (63,275 shares)1
 (1) 
 
 
Share-based compensation
 1,485
 
 
 1,485
Net Income
 
 
 8,466
 8,466
Balance, March 31, 2018$117
 $281,303
 $(1,742) $(75,851) $203,827
         
Purchase of treasury shares (4,649 shares)
 
 (128) 
 (128)
Issuance of restricted stock (19,177 shares)
 
 
 
 
Share-based compensation
 1,423
 
 
 1,423
Net Income
 
 
 2,319
 2,319
Balance, June 30, 2018$117
 $282,726
 $(1,870) $(73,532) $207,441
         Common Stock Additional Paid-In Capital Treasury Stock Retained Earnings (Accumulated Deficit) Total
Balance, December 31, 2018$118
 $286,281
 $(1,870) $(9,702) $274,827
$118
 $286,281
 $(1,870) $(9,702) $274,827
                  
Purchase of treasury shares (11,076 shares)
 
 (260) 
 (260)
 
 (260) 
 (260)
Issuance of restricted stock (61,263 shares)
 
 
 
 
Issuance of RSUs (61,263 shares)
 
 
 
 
Share-based compensation
 1,849
 
 
 1,849

 1,849
 
 
 1,849
Net Income
 
 
 16,053
 16,053

 
 
 16,053
 16,053
Balance, March 31, 2019$118
 $288,130
 $(2,130) $6,351
 $292,469
$118
 $288,130
 $(2,130) $6,351
 $292,469
                  
Purchase of treasury shares (3,877 shares)
 
 (58) 
 (58)
Issuance of restricted stock (19,162 shares)
 
 
 
 
Balance, December 31, 2019$119
 $292,916
 $(2,282) $104,954
 $395,707
         
Purchase of treasury shares (26,675 shares)
 
 (83) 
 (83)
Issuance of RSUs (105,108 shares)1
 (1) 
 
 
Share-based compensation
 1,769
 
 
 1,769

 1,335
 
 
 1,335
Net Income
 
 
 64,704
 64,704
Balance, June 30, 2019$118
 $289,899
 $(2,188) $71,055
 $358,884
Net Loss
 
 
 (5,858) (5,858)
Balance, March 31, 2020$120
 $294,250
 $(2,365) $99,096
 $391,101
         
See accompanying Notes to Condensed Consolidated Financial Statements.


Condensed Consolidated Statements of Cash Flows (Unaudited)
SilverBow Resources, Inc. and Subsidiaries (in thousands)

Six Months Ended June 30, 2019
Six Months Ended June 30, 2018Three Months Ended March 31, 2020
Three Months Ended March 31, 2019
Cash Flows from Operating Activities:





Net income (loss)$80,757

$10,787
$(5,858)
$16,053
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities





Depreciation, depletion, and amortization45,834

26,228
23,439

21,805
Write-down of oil and gas properties95,606


Accretion of asset retirement obligations168

243
86

83
Deferred income taxes(20,732)
328
(1,065)
134
Share-based compensation expense3,339

2,675
1,260

1,692
(Gain) Loss on derivatives, net(20,903)
17,107
(88,287)
4,022
Cash settlement (paid) received on derivatives4,381

(1,935)47,650

1,077
Settlements of asset retirement obligations(47)
(144)(2)
(31)
Other1,160

3,374
1,142

564
Change in operating assets and liabilities









(Increase) decrease in accounts receivable and other current assets13,411

2,332
9,436

14,401
Increase (decrease) in accounts payable and accrued liabilities(6,928)
(8,439)(6,937)
(9,105)
Increase (decrease) in income taxes payable(176)

Increase (decrease) in accrued interest(180)
491
(211)
(100)
Net Cash Provided by (Used in) Operating Activities100,260

53,047
76,083

50,595
Cash Flows from Investing Activities:





Additions to property and equipment(174,138)
(84,097)(52,618)
(86,555)
Proceeds from the sale of property and equipment(96)
26,924


(91)
Payments on property sale obligations(2,840)
(6,042)(142)
(1,278)
Net Cash Provided by (Used in) Investing Activities(177,074)
(63,215)(52,760)
(87,924)
Cash Flows from Financing Activities:





Proceeds from bank borrowings227,000

122,300
50,000

132,000
Payments of bank borrowings(149,000)
(113,300)(39,000)
(96,000)
Net proceeds from issuances of common stock

708
Purchase of treasury shares(318)
(418)(83)
(260)
Payments of debt issuance costs

(317)
Net Cash Provided by (Used in) Financing Activities77,682

8,973
10,917

35,740

Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash868

(1,195)
Cash, Cash Equivalents and Restricted Cash, at Beginning of Period2,465

8,026
Cash, Cash Equivalents and Restricted Cash at End of Period$3,333

$6,831
Net Increase (Decrease) in Cash and Cash Equivalents34,240

(1,589)
Cash and Cash Equivalents at Beginning of Period1,358

2,465
Cash and Cash Equivalents at End of Period$35,598

$876

Supplemental Disclosures of Cash Flow Information: 



 



Cash paid during period for interest, net of amounts capitalized$17,128

$10,926
$8,048

$8,303
Cash paid during period for income taxes


Changes in capital accounts payable and capital accruals$(16,521)
$35,299
$(1,989)
$1,487
Changes in other long-term liabilities for capital expenditures$

$(2,500)
See accompanying Notes to Condensed Consolidated Financial Statements.






Notes to Condensed Consolidated Financial Statements (Unaudited)
SilverBow Resources, Inc. and Subsidiaries


(1)           General Information

SilverBow Resources, Inc. (“SilverBow,” the “Company,” or “we”) 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. Being a committed and long-term operator in South Texas, the Company possesses a significant understanding of the reservoirs in the region. We leverage this competitive understanding to assemble high quality drilling inventory while continuously enhancing our operations to maximize returns on capital invested.

The condensed consolidated financial statements included herein are unaudited and have been prepared by the Company and reflect necessary adjustments, all of which were of a recurring nature unless otherwise disclosed herein, and are in the opinion of our management necessary for a fair presentation. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018,2019, as filed with the Securities and Exchange Commission on February 28, 2019.March 5, 2020.

As further discussed in Note 2, the impact of the Coronavirus Disease 2019 (“COVID-19”) pandemic and related economic, business and market disruptions is evolving rapidly and its future effects are uncertain. The actual impact of these recent developments on the Company will depend on many factors, many of which are beyond management's control and knowledge. It is therefore difficult for management to assess or predict with precision the broad future effect of this health crisis on the global economy, the energy industry or the Company. As additional information becomes available, events or circumstances change and strategic operational decisions are made by management, adjustments may be required which could have a material adverse impact on the Company's consolidated financial position, results of operations and cash flows.
 
(2)          Summary of Significant Accounting Policies

Basis of Presentation. The consolidated financial statements included herein have been prepared by SilverBow, and reflect necessary adjustments, all of which were of a recurring nature unless otherwise disclosed herein, and are in the opinion of our management necessary for a fair presentation.

Principles of Consolidation. The accompanying condensed consolidated financial statements include the accounts of SilverBow and its wholly-ownedwholly owned subsidiaries, which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on oil and natural gas reserves in the Eagle Ford trend in Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of the assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying condensed consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying condensed consolidated financial statements.

COVID-19.On January 30, 2020, the World Health Organization (“WHO”) announced a global health emergency because of a new strain of coronavirus, or COVID-19, that originated from Wuhan, China and the risks to the international community as the virus spread globally beyond its point of origin. In March 2020, the WHO classified the COVID-19 outbreak as a pandemic based on the rapid increase in exposure globally.

The full impact of the COVID-19 pandemic continues to evolve as of the date of this report. As such, the full magnitude that the pandemic will have on the Company’s financial condition, liquidity, and future results of operations is uncertain. Management is actively monitoring the impact of the COVID-19 pandemic on the Company's financial condition, liquidity, operations, suppliers, industry and workforce. Given the daily evolution of the COVID-19 pandemic and the global responses to curb its spread, the Company is currently not able to estimate the effects of the COVID-19 pandemic on its results of operations, financial condition, or liquidityfor fiscal year 2020.

Additionally, in March and April 2020, the COVID-19 pandemic has caused volatility in the market price for crude oil due to the disruption of global supply and demand. As a result, West Texas Intermediate (“WTI”) oil prices declined to approximately $10 per barrel for May 2020 delivery. In response to these market conditions, including the COVID-19 outbreak and the decline in oil prices and economic outlook, the Company released its sole drilling rig in April 2020 to reduce capital expenditures, began

curtailing production volumes beginning in March 2020, and, as described further below, recorded an impairment on oil and natural gas properties for the three months ended March 31, 2020. If the depressed pricing environment continues for an extended period, it may in the future lead to (i) a further reduction in oil and natural gas reserves, including the possible further removal of proved undeveloped reserves (ii) further impairment of proved and/or unproved oil and natural gas properties and a resulting increase in depletion expense and (iii) reductions in the borrowing base under the Credit Agreement as discussed in Note 6.

If the pandemic and low oil price environment continues, it may have a material adverse effect on the Company’s operating cash flows, liquidity, and future development plans.

Subsequent Events. We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements.

Through May 4, 2020, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after March 31, 2020:

Natural Gas Derivative Contracts
(NYMEX Henry Hub Settlements)
Total Volumes
(MMBtu)
 Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price
Swap Contracts       
2020 Contracts       
4Q20775,000
 $2.69
    
        
2021 Contracts       
1Q212,250,000
 $2.74
    
2Q21195,000
 $2.59
    
3Q21165,000
 $2.65
    
4Q21150,000
 $2.71
    
        
Collar Contracts       
2020 Contracts       
4Q20310,000
   $2.60
 $3.06
        
2021 Contracts       
1Q211,800,000
   $2.60
 $3.14
        
2022 Contracts       
1Q223,150,000
   $2.50
 $3.26

Oil Derivative Swaps
(New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) Settlements)
Total Volumes
(Bbls)
 Weighted-Average Price
2020 Contracts   
2Q20 (1)
(93,450) $17.69
    
2022 Contracts   
1Q2245,000
 $38.55
(1) WTI swap contract purchase to reduce the Company's total derivative position and bring in line with expected production.


Oil Basis Contracts
(Argus Cushing (WTI) and Magellan East Houston)
Total Volumes (Bbls) Weighted-Average Price
2020 Contracts   
2Q2066,000
 $3.35


There were no other material subsequent events requiring additional disclosure in these condensed consolidated financial statements.

Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include:

the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows there-from,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.

While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, re-allocationsreallocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known.

We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated.

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. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended June 30,March 31, 2020 and 2019, and 2018, such internal costs when capitalized totaled $1.3$1.1 million and $1.0 million, respectively. For the six months ended June 30, 2019 and 2018, such internal costs capitalized totaled $2.9 million and $2.4$1.6 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 6 of these Notes to Condensed Consolidated Financial Statements for further discussion on capitalized interest costs).


The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands):
June 30, 2019 December 31, 2018March 31, 2020 December 31, 2019
Property and Equipment      
Proved oil and gas properties$1,090,496
 $925,865
$1,251,110
 $1,201,296
Unproved oil and gas properties49,866
 56,715
42,249
 41,201
Furniture, fixtures and other equipment3,855
 3,520
5,094
 5,220
Less – Accumulated depreciation, depletion, amortization & impairment(330,638) (284,804)(499,759) (380,728)
Property and Equipment, Net$813,579

$701,296
$798,694

$866,989

No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred.

We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and natural gas properties, including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties, by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two and 20 years. Repairs and maintenance are charged to expense as incurred.

Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved oil and gas properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved oil and gas properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is 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, economic conditions, capital availability, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.

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, net of related salvage values and deferred income taxes) 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”).

The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Due to the effects of pricing and timing of projects, for the three months ended March 31, 2020, we reported a non-cash impairment write-down, on a pre-tax basis, of $95.6 million on our oil and natural gas properties. There was no write-down for each of the three and six months ended June 30, 2019 and the three and six months ended June 30, 2018March 31, 2019.

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 or remain at levels prevalent in the current period, 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; therefore, we cannot estimate the amount of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices. However, it is reasonably possible that we will record additional ceiling test write-downs in future periods.

Accounts Receivable, Net. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both June 30, 2019March 31, 2020 and December 31, 2018,2019, we had an allowance for doubtful accounts of less than $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable, net” balance on the accompanying condensed consolidated balance sheets.

At June 30,March 31, 2020, our “Accounts receivable, net” balance included $14.1 million for oil and gas sales, $3.0 million due from joint interest owners, $5.9 million for severance tax credit receivables and $7.3 million for other receivables. At December 31, 2019, our “Accounts receivable, net” balance included $25.5$24.6 million for oil and gas sales, $0.8$3.7 million due from joint interest owners, $4.1$5.4 million for severance tax credit receivables and $4.4 million for other receivables. At December 31, 2018, our “Accounts receivable, net” balance included $36.9 million for oil and gas sales, $5.6 million due from joint interest owners, $2.4 million for severance tax credit receivables and $1.6$3.3 million for other receivables.

Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the sixthree months ended June 30,March 31, 2020 and 2019 and 2018 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $1.3$1.2 million and $1.1$1.3 million for the three months ended June 30,March 31, 2020 and 2019, and 2018, and $2.6 million and $2.2 million for the six months ended June 30, 2019 and 2018, respectively.

Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws.

Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that iswith a greater than 50% likelihood of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At June 30, 2019,March 31, 2020, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.

The Company was in a net deferred tax asset position prior to valuation allowance considerations, at both June 30, 2019March 31, 2020 and December 31, 2018.2019. In periods prior periods,to the quarter ended June 30, 2019, management had determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and, accordingly, had maintained a full valuation allowance to offset its deferred tax assets. DuringFor the quarterthree months ended June 30,March 31, 2020 the Company recorded an income tax benefit of $1.2 million, while for the three months ended March 31, 2019 the Company completed several operational initiatives that resulted in increased production, lower development costs and an expanded inventory of development prospects. The successful results attributablerecognized $0.2 million for state income tax expense. Tax expense associated with federal income taxes was fully offset by adjustments to these initiatives led to management's determination, after weighing both positive and negative evidence, that the Company will more likely than not be able to realize the benefits of its deferred tax assets. Accordingly, the Company released $21.2 million of the valuation allowance resulting in a net deferred tax benefit of $20.7 million and $20.5 million for the three and six months ended June 30, 2019, respectively. The Company recognized state income tax expense of $0.3 million and $0.5March 31, 2019.

million forOn March 27, 2020, President Trump signed into law the threeCoronavirus Aid, Relief, and six months ended June 30, 2019, respectively.Economic Security Act (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer-side Social Security payments, net operating loss carryback periods, alternative minimum tax credit refunds and modifications to the net interest deduction limitation. The Company recognized $0.3 millioncontinues to examine the impact that the CARES Act may have on its business but does not currently expect the CARES Act to have a material effect on its financial condition, results of state income tax expense for the three and six months ended June 30, 2018.operation, or liquidity.

Revenue Recognition. Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. Natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers.

The following table provides information regarding our oil and gas sales, by product, reported on the Statements of Operations for the three months ended June 30,March 31, 2020 and 2019 and 2018 and the six months ended June 30, 2019 and 2018 (in thousands):


 Three Months Ended June 30, 2019 Three Months Ended June 30, 2018 Six Months Ended June 30, 2019 Six Months Ended June 30, 2018Three Months Ended March 31, 2020 Three Months Ended March 31, 2019
Oil, natural gas and NGLs sales:           
Oil $24,940
 $9,638
 $39,547
 $21,078
$18,050
 $14,607
Natural gas 43,587
 36,369
 94,874
 72,136
31,472
 51,304
NGLs 6,166
 5,339
 12,319
 10,900
3,855
 6,154
Other 10
 
 28
 (14)
Total $74,703
 $51,347
 $146,768
 $104,099
$53,377
 $72,064

Accounts Payable and Accrued Liabilities. The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands):
June 30, 2019 December 31, 2018March 31, 2020 December 31, 2019
Trade accounts payable$18,560
 $32,683
$27,409
 $26,121
Accrued operating expenses3,410
 3,549
3,388
 3,873
Accrued compensation costs3,175
 4,785
1,865
 4,601
Asset retirement obligations – current portion270
 302
387
 392
Accrued non-income based taxes4,279
 3,583
2,042
 1,413
Accrued corporate and legal fees239
 534
247
 109
Other payables3,387
 3,485
821
 2,834
Total accounts payable and accrued liabilities$33,320
 $48,921
$36,159
 $39,343

Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted.

Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock, held at cost” on the accompanying condensed consolidated balance sheets. For the sixthree months ended June 30, 2019,March 31, 2020, we purchased 14,95326,675 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares.

New Accounting Pronouncements. In February 2016,
(3)       Leases

The Company adopted the standard provided in the Financial Accounting Standards Board (the “FASB”) issuedBoard's Accounting Standards Update (“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 was effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company adopted this standard on January 1, 2019, using the modified retrospective transition approach. The Company has elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that allows an entity to carry forward historical accounting treatment for land easements on existing agreements upon adoption. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the Consolidated Balance Sheet. We have elected to not account for lease and non-lease components separately.


As a result of the adoption, the Company's 2019 opening balances for right-of-use assets and lease liabilities was $2.2 million, attributable to operating leases. During the second quarter of 2019, theThe Company recorded additions to right of use assets of $11.5 million, primarily for equipment leases entered into during the second quarter of 2019. See Note 3 for more information.

(3)       Leases

SilverBow Resources has contractual agreements for its corporate office lease, vehicle fleet, drilling rigs, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of June 30, 2019March 31, 2020, all of the Company’s leases were operating leases.

The initial asset and liability balances are recorded at the present value of the payment obligations over the lease term. If lease terms include options to extend the lease and it is reasonably certain that the Company will exercise that option, the lease term used for capitalization includes the expected renewal periods. Most leases do not provide an implicit interest rate. Unless the lease contract contains an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease inception to compute the fair value of the lease payments. The ROU asset balance and current and non-current lease liabilities are reported separately on the accompanying Condensed Consolidated Balance Sheet. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. Leases with an initial term of 12 months or less are not recorded on the balance sheet. The Company recognizes lease expense on a straight-line basis over the lease term.
    

Lease costs represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are classified as follows (in thousands):

Three Months Ended June 30, 2019 Six Months Ended June 30, 2019Three Months Ended March 31, 2020 Three Months Ended March 31, 2019
Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets      
Property, plant and equipment acquisitions - short-term leases$2,184
 $6,168
$2,184
 $3,983
Property, plant and equipment acquisitions - operating leases11
 18
5
 8
Total lease costs in property, plant and equipment additions$2,195
 $6,186
$2,189
 $3,991

Three Months Ended June 30, 2019 Six Months Ended June 30, 2019Three Months Ended March 31, 2020 Three Months Ended March 31, 2019
Lease Costs Included in the Condensed Consolidated Statement of Operations   
Lease Costs Included in the Condensed Consolidated Statements of Operations   
Lease operating costs - short-term leases$329
 $1,664
$250
 $1,335
Lease operating costs - operating leases1,084
 1,138
1,437
 54
General and administrative, net - operating leases175
 331
180
 156
Total lease cost expensed$1,588
 $3,133
$1,867
 $1,545

The lease term and the discount rate related to the Company's leases are as follows:

 As of June 30, 2019March 31, 2020
Weighted-average remaining lease term (in years)2.11.6
Weighted-average discount rate5.0%


As of June 30, 2019March 31, 2020, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands):

June 30, 2019March 31, 2020
2019 (remaining after June 30, 2019)$3,503
20207,091
2020 (Remaining)$5,192
20212,344
2,577
202240
194
202340
90
202440
Thereafter348
312
Total undiscounted lease payments$13,366
8,405
Present value adjustment
(386)
Net operating lease liabilities$13,366
$8,019

SupplementSupplemental cash flow information related to leases was as follows (in thousands):

Six Months Ended June 30, 2019Three Months Ended March 31, 2020
Cash paid for amounts included in the measurement of lease liabilities  
Operating cash flows from operating leases$1,457
$1,615
Investing cash flows from operating leases$18
$5

 

(4)          Share-Based Compensation

Share-Based Compensation Plans

In 2016, the Company adopted the 2016 Equity Incentive Plan (as amended from time to time, the “2016 Plan”). The Company also adopted the Inducement Plan (as amended from time to time, the “Inducement Plan,” and, together with the 2016 Plan, the “Plans”) on December 15, 2016. Under the Plans, the Company does not estimate the forfeiture rate during the initial calculation of compensation cost but rather has elected to account for forfeitures in compensation cost when they occur.

The Company computes a deferred tax benefit for restricted stock awardsunits (“RSUs”), performance-based stock units (“PSUs”) and stock options expected to generate future tax deductions by applying its effective tax rate to the expense recorded. For restricted stock units,RSUs, the Company's actual tax deduction is based on the value of the units at the time of vesting.

The expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying condensed consolidated statements of operations was $1.6$1.2 million and $1.3$1.7 million for the three months ended June 30,March 31, 2020 and 2019, and 2018, respectively, and $3.3 million and $2.7 million for the six months ended June 30, 2019 and 2018, respectively. Capitalized share-based compensation was $0.1 million for each of the three months ended June 30, 2019 and 2018, and $0.3 million and $0.2 million for the sixthree months ended June 30,March 31, 2020 and 2019, and 2018, respectively.

We view stock option awards and restricted stock unit awardsRSUs with graded vesting as single awards with an expected life equal to the average expected life of component awards, and we amortize the awards on a straight-line basis over the life of the awards.
    
On April 2, 2019, our Board of Directors authorized a one-time grant of market-based awards (both RSUs and PSUs) in exchange for the cancellation of special equity awards (both RSUs and stock options) made to our named executive officers on August 9, 2018 (the “Equity Award Exchange”). As required under the terms of the 2016 Plan, this Equity Award Exchange was subject to shareholder approval.approved by the Company's shareholders approval on May 21, 2019. Pursuant to the Equity Award Exchange our executives were given the opportunity to exchange out-of-the-money or “underwater” stock options that were granted in August 2018 and certain RSUs also granted in August 2018 to receive a new equity award that consists of 50% time-based RSUs and 50% PSUs, granted under the 2016 Plan. The incremental compensation cost associated with the Equity Award Exchange was determined to be $1.2 million. This incremental cost was measured as the excess of the fair value of each new equity award, measured as of the date the new equity awards were granted,

over the fair value of the stock options and RSUs surrendered in exchange for the new equity awards, measured immediately prior to the cancellation. This incremental compensation cost is being recognized ratably over the vesting period or performance period, as applicable, of the new equity awards.

Stock Option Awards

The compensation cost related to stock option awards is based on the grant date fair value and is typically expensed over the vesting period (generally one to five years). We use the Black-Scholes option pricing model to estimate the fair value of stock option awards.

At June 30, 2019,March 31, 2020, we had $2.2$1.0 million of unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the sixthree months ended June 30, 2019:March 31, 2020:
Shares Wtd. Avg. Exer. PriceShares Wtd. Avg. Exer. Price
Options outstanding, beginning of period644,575
 $28.28
324,324
 $27.68
Options forfeited(4,197) $27.00
Options canceled in Equity Award Exchange(201,406) $31.14
Options expired(68,987) $23.69
(17,372) $26.96
Options outstanding, end of period369,985
 $27.59
306,952
 $27.72
Options exercisable, end of period130,601
 $28.42
209,426
 $28.39

Our outstanding stock option awards at June 30, 2019March 31, 2020 had no measurable aggregate intrinsic value. At June 30, 2019,March 31, 2020, the weighted-average remaining contract life of stock option awards outstanding was 6.55.5 years and exercisable was 5.04.8 years. The total intrinsic value of stock option awards exercisable had no value for the sixthree months ended June 30, 2019.March 31, 2020.

Restricted Stock Units

The 2016 Plan and Inducement Plan allow for the issuance of restricted stock unit awards that generally may not be sold or otherwise transferred until certain restrictions have lapsed. The compensation cost related to these awards is based on the grant date fair value and is typically expensed over the requisite service period (generally one to five years).

As of June 30, 2019,March 31, 2020, we had $4.4 million unrecognized compensation expense of $7.1 million related to our restricted stock unitsRSUs which is expected to be recognized over a weighted-average period of 2.21.7 years.

The following table provides information regarding restricted stock unit awardRSU activity for the sixthree months ended June 30, 2019:March 31, 2020:
 Shares Grant Date Price
Restricted stock units outstanding, beginning of period340,678
 $27.64
Restricted stock units granted115,957
 $20.13
Restricted stock units granted under Equity Award Exchange99,500
 $16.70
Restricted stock united canceled under Equity Award Exchange(24,622) $31.14
Restricted stock units forfeited(16,342) $26.81
Restricted stock units vested(80,425) $26.46
Restricted stock units outstanding, end of period434,746
 $23.14
 RSUs Wtd. Avg. Grant Price
RSUs outstanding, beginning of period342,683
 $22.10
RSUs granted292,785
 $3.00
RSUs vested(105,108) $23.32
RSUs outstanding, end of period530,360
 $11.31

Performance-Based Stock Units

On February 20, 2018, the Company granted 30,700 performance-based stock unitsPSUs for which the number of shares earned is based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2018 to December 31, 2020. The awards contain market conditions which allow a payout ranging between 0% payout and 200% of the target payout. The fair value as of the grant date was $41.66 per unit or 150.6% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte-Carlo

Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years.

On May 21, 2019, the Company granted an additional 99,500 performance-based stock unitsPSUs (as part of the Equity Award Exchange discussed above) for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2019 to December 31, 2021. The awards contain market conditions which allow a payout ranging between 0% payout and 200% of the target payout. The fair value as of the grant date was $18.86 per unit or 112.9% of the stock price. The awards have a cliff-vesting period of three years.

As of June 30, 2019,March 31, 2020, we had $1.9 million unrecognized compensation expense of $3.5 million related to our performance-based stock unitsPSUs based on the assumption of 100% target payout. The remaining weighted-average performance period is 2.31.6 years. No shares vested during the sixthree months ended June 30, 2019.March 31, 2020.


(5)          Earnings Per Share

Basic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share ("(“Diluted EPS"EPS”) assumes, as of the beginning of the period, exercise of stock options and restricted stockRSU grants using the treasury stock method. Diluted EPS also assumes conversion of performance-based restricted stock unitsPSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and restricted stockRSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three months ended June 30,March 31, 2020 and 2019 and 2018 and the six months ended June 30, 2019 and 2018 are discussed below.


The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts):
 Three Months Ended June 30, 2019 Three Months Ended June 30, 2018
 Net Income (Loss) Shares Per Share
Amount
 Net Income (Loss) Shares Per Share
Amount
Basic EPS:           
Net Income (Loss) and Share Amounts$64,704
 11,746
 $5.51
 $2,319
 11,655
 $0.20
Dilutive Securities:           
Restricted Stock Awards  
     
  
Restricted Stock Unit Awards  34
     16
  
Stock Option Awards  
     86
  
Diluted EPS:           
Net Income (Loss) and Assumed Share Conversions$64,704
 11,780
 $5.49
 $2,319
 11,757
 $0.20

Six Months Ended June 30, 2019 Six Months Ended June 30, 2018Three Months Ended March 31, 2020 Three Months Ended March 31, 2019
Net Income (Loss) Shares Per Share
Amount
 Net Income (Loss) Shares Per Share
Amount
Net Income (Loss) Shares Per Share
Amount
 Net Income (Loss) Shares Per Share
Amount
Basic EPS:                      
Net Income (Loss) and Share Amounts$80,757
 11,727
 $6.89
 $10,787
 11,629
 $0.93
$(5,858) 11,825
 $(0.50) $16,053
 11,708
 $1.37
Dilutive Securities:                      
Restricted Stock Awards  
     
  
Restricted Stock Unit Awards  59
     17
  
RSU Awards  
     80
  
Stock Option Awards  
     96
    
     
  
Diluted EPS:                      
Net Income (Loss) and Assumed Share Conversions$80,757
 11,786
 $6.85
 $10,787
 11,742
 $0.92
$(5,858) 11,825
 $(0.50) $16,053
 11,788
 $1.36

Approximately 0.5 million and 0.40.3 million stock options to purchase shares were not included in the computation of Diluted EPS for the three months ended June 30, 2019 and 2018, respectively, andMarch 31, 2020 because they were antidilutive due to the net loss, while 0.6 million and 0.4 millionstock options to purchase shares were not included in the computation of Diluted EPS for the sixthree months ended June 30,March 31, 2019 and 2018, respectively, because these stock options were antidilutive.

Approximately 0.2 million and less than 0.10.4 million shares of restricted stock unitsRSUs that could be converted to common shares were not included in the computation of Diluted EPS for both the three months ended June 30, 2019 and 2018March 31, 2020 because they were antidilutive. There were approximately 0.1 million and less than 0.1 million antidilutive shares of restricted stock units for bothdue to the six months ended June 30, 2019 and 2018.

Approximately 0.1 million andnet loss, while less than 0.1 million shares of performance-based restricted stock unitsRSUs that could be converted to common shares were not included in the computation of Diluted EPS for the three and six months ended June 30,March 31, 2019 respectively, andbecause they were antidilutive.

Approximately 0.1 million shares of PSUs were not included in the computation of Diluted EPS for the three months ended March 31, 2020 because they were antidilutive due to the net loss, while less than 0.1 million shares of performance-based restricted stock unitsPSUs were not included for both the three and six months ended June 30, 2018March 31, 2019 because they were antidilutive.

Approximately 2.1 million warrants to purchase common stock were not included in the computation of Diluted EPS for both the three and six months ended June 30, 2019 andMarch 31, 2020 because they were antidilutive due to the net loss, while 4.3 million warrants to purchase common stock were not included in the computation of Diluted EPS for both the three and six months ended June 30, 2018March 31, 2019 because these warrants were antidilutive.

(6)          Long-Term Debt

The Company's long-term debt consisted of the following (in thousands):
June 30, 2019 December 31, 2018March 31, 2020 December 31, 2019
Credit Facility Borrowings (1)
$273,000
 $195,000
$290,000
 $279,000
Second Lien Notes due 2024200,000
 200,000
200,000
 200,000
473,000
 395,000
490,000
 479,000
Unamortized discount on Second Lien Notes due 2024(1,668) (1,782)(1,488) (1,550)
Unamortized debt issuance cost on Second Lien Notes due 2024(4,899) (5,230)(4,370) (4,550)
Long-Term Debt, net$466,433
 $387,988
$484,142
 $472,900
(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in Other Long-Term Assets in our consolidated balance sheet. As of June 30, 2019March 31, 2020 and December 31, 2018,2019, we had $3.8$2.7 million and $4.5$3.1 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.

Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $273.0$290.0 million and $195.0$279.0 million as of June 30, 2019March 31, 2020 and December 31, 2018,2019, respectively. On April 19, 2017, the Company entered into a First Amended and Restated Senior Secured Revolving Credit Agreement among the Company, as borrower, JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended, including the Fourth Amendment, effective November 6, 2018, (the “Fourth Amendment to Credit Agreement”), to the First Amended and Restated Senior Secured Credit Agreement (as so amended, the “Credit

Agreement” and such facility, the “Credit Facility”). The Fourth Amendment to Credit Agreement increasedAdditionally, on October 17, 2019, as part of our regularly scheduled borrowing base redetermination, the borrowing base was decreased from $330$410 million to $410 million and decreased$400 million. Based on informed discussions with certain of the applicable margins used to calculate the interest ratelenders under the Company's Credit Agreement by 25 basis points.Facility, we anticipate a borrowing base reduction of approximately 15% to 20% from the current $400 million borrowing base in connection with the May redetermination.

The Credit Facility matures April 19, 2022, and provides for a maximum credit amount of $600 million and a current borrowing base of $410 million.$400 million as of October 17, 2019. The borrowing base is regularly redetermined on or about May and November of each calendar year, is expected to be redetermined on or about May 12, 2020, and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, each of the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders, in their discretion, in accordance with their oil and gas lending criteria at the time of the relevant redetermination. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to $25 million, which reduces the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit.

Interest under the Credit Facility accrues at the Company’s option either at an Alternative Base Rate plus the applicable margin (“ABR Loans”) or the LIBOR Rate plus the applicable margin (“Eurodollar Loans”). Since November 6, 2018, the

applicable margin ranged from 1.00%1.0% to 2.00%2.0% for ABR Loans and 2.00%2.0% to 3.00%3.0% for Eurodollar Loans. The Alternate Base Rate and LIBOR Rate are defined, and the applicable margins are set forth, in the Credit Agreement. Undrawn amounts under the Credit Facility are subject to a 0.50%0.5% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.00%2.0% per annum above the rate and margin otherwise applicable thereto.

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

The Credit Agreement contains the following financial covenants:

a ratio of total debt to 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.

As of June 30, 2019,March 31, 2020, the Company was in compliance with all financial covenants under the Credit Agreement. Maintaining or increasing our borrowing base under our Credit Facility is dependent on many factors, including commodities pricing, our hedge positions and our ability to raise capital to drill wells to replace produced reserves.

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

Total interest expense on the Credit Facility, which includes commitment fees and amortization of debt issuance costs, was $4.0$3.5 million and $1.6 million for each of the three months ended June 30, 2019March 31, 2020 and 2018, respectively, and $7.5 million and $3.1 million for the six months ended June 30, 2019 and 2018, respectively.2019.

WeThere was no capitalized interest and $0.1 million in capitalized interest on our unproved properties in the amount of $0.1 million and $0.3 million for the three months ended June 30,March 31, 2020 and 2019, and 2018, respectively and $0.2 million and $0.7 million for the six months ended June 30, 2019 and 2018.respectively.

Senior Secured Second Lien Notes. On December 15, 2017, the Company entered into a Note Purchase Agreement for Senior Secured Second Lien Notes (as amended, the “Note Purchase Agreement,” and such second lien facility the “Second Lien”) among the Company as issuer, U.S. Bank National Association as agent and collateral agent, and certain holders that are a party thereto, and issued notes in an initial principal amount of $200.0 million, with a $2.0 million discount, for net proceeds of $198.0 million. The Company has the ability, subject to the satisfaction of certain conditions (including compliance with the Asset Coverage Ratio described below and the agreement of the holders to purchase such additional notes), to issue additional notes in a principal amount not to exceed $100.0 million. The Second Lien matures on December 15, 2024.

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

The Company has the right, to the extent permitted under the Credit Facility and subject to the terms and conditions of the Second Lien, to optionally prepay the notes, subject to the following repayment fees: during years one and two, a customary “make-whole” amount (which is equal to the present value of the remaining interest payments through the 24 month anniversary of the issuance of the Second Lien, discounted at a rate equal to the U.S. Treasury rate plus 50 basis points) plus 2.0% of the principal amount of the notes repaid; during year three, 2.0% of the principal amount of the Second Lien being prepaid; during year four, 1.0% of the principal amount of the Second Lien being prepaid; and thereafter, no premium. Additionally, the Second Lien contains customary mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and

incurrences of certain debt, subject to, in certain circumstances, reinvestment periods. Management believes the probability of mandatory prepayment due to default is remote.

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

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

The Second Lien also contains a financial covenant measuring the ratio of total net debt to EBITDA,debt-to-EBITDA, as defined in the Note Purchase Agreement, for the most recently completed four fiscal quarters, not to exceed 4.5 to 1.0 as of the last day of each fiscal quarter. As of June 30, 2019,March 31, 2020, the Company was in compliance with all financial covenants under the Second Lien.

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

    As of June 30, 2019,March 31, 2020, total net amounts recorded for the Second Lien were $193.4$194.1 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $5.5$4.9 million and $10.8$5.3 million for the three and six months ended June 30,March 31, 2020 and 2019, respectively, and $5.2 million and $10.0 million for the three and six months ended June 30, 2018 respectively.

Debt Issuance Costs. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings.

(7)           Acquisitions and Dispositions

On March 1, 2018, the Company closed the sale of certain wells in its AWP Olmos field for proceeds, net of selling expenses, of $27.0 million, with an effective date of January 1, 2018. The buyer assumed approximately $6.3 million in asset retirement obligations. No gain or loss was recorded on the sale of this property.

Effective December 22, 2017, the Company closed a purchase and sale contract to sell the Company's wellbores and facilities in the Bay De Chene field and recorded a $16.3 million obligation related to the funding of certain plugging and abandonment costs. Of the $16.3 million original obligation, $2.8$0.1 million and $1.3 million was paid during the sixthree months ended June 30, 2019.March 31, 2020 and 2019, respectively. The remaining obligation under this contract is $4.6$2.2 million and is carried in the

accompanying condensed consolidated balance sheet current liability in “Accounts payable and accrued liabilities” as of June 30, 2019.March 31, 2020.

There were no material acquisitions or dispositions of developed properties during the three and six months ended June 30, 2019.March 31, 2020.

(8)          Price-Risk Management Activities

Derivatives are recorded on the balance sheet at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. We have a price-risk management policy to use derivative instruments to protect against declines in oil and natural gas prices, primarily through the purchase of commodity price swaps and collars as well as basis swaps.

During the three months ended June 30,March 31, 2020 and 2019, and 2018, the Company recorded gains of $25.0$88.3 million and losses of $10.8 million, respectively, on its commodity derivatives. During the six months ended June 30, 2019 and 2018, the Company recorded gains of $20.9 million and losses of $17.1$4.0 million, respectively, on its commodity derivatives. The Company collected cash payments of $4.4$47.7 million and made cash payments of $1.9$1.1 million for settled derivative contracts during the sixthree months ended June 30,March 31, 2020 and 2019, and 2018, respectively. Included in our collected cash payments during the three months ended March 31, 2020 was $38.3 million for monetized derivative contracts.

At June 30, 2019,March 31, 2020, there were $3.6$6.4 million in receivables for settled derivatives while at December 31, 20182019, we had $0.7$2.9 million in receivables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts receivable, net” and were subsequently collected in July 2019April 2020 and January 2019,2020, respectively. At June 30, 2019March 31, 2020 and December 31, 2018,2019, we also had $0.2less than $0.1 million and $2.2$0.2 million, respectively, in payables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts payable and accrued liabilities” and were subsequently paid in July 2019April 2020 and January 2019,2020, respectively.

The fair values of our swap contracts are computed using observable market data whereas our collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. At June 30, 2019,March 31, 2020, there was $21.7$38.8 million and $5.9$8.9 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $2.0$1.3 million and $1.0 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2018,2019, there was $15.3$12.8 million and $4.3$3.9 million in current and long-term unsettled derivative assets, respectively, and $2.8$6.6 million and $3.7$1.6 million in current and long-term unsettled derivative liabilities, respectively.

The Company uses an International Swap and Derivatives Association master agreement for our derivative contracts. This is an industry-standardized contract containing the general conditions of our derivative transactions including provisions relating to netting derivative settlement payments under certain circumstances (such as default). For reporting purposes, the Company has elected to not offset the asset and liability fair value amounts of its derivatives on the accompanying balance sheets. Under the right of set-off, there was a $24.6$45.4 million net fair value asset at June 30, 2019March 31, 2020, and a $13.0$8.4 million net fair value asset at December 31, 2018.2019. For further discussion related to the fair value of the Company's derivatives, refer to Note 9 of these Notes to Condensed Consolidated Financial Statements.

The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of June 30, 2019:March 31, 2020:

Oil Derivative Swaps
(New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) Settlements)
Total Volumes
(Bbls)
 Weighted-Average Price
2019 Contracts   
3Q19314,500
 $60.41
4Q19249,000
 $59.52
   
Oil Derivative Swaps
(New York Mercantile Exchange (“NYMEX”) WTI Settlements)
Total Volumes
(Bbls)
 Weighted-Average Price
2020 Contracts      
1Q20194,800
 $58.16
2Q20191,350
 $58.32
359,126
 $53.60
3Q20189,200
 $58.43
293,538
 $53.28
4Q20118,000
 $55.65
244,556
 $52.76
      
2021 Contracts      
1Q2156,175
 $55.23
215,538
 $51.93
2Q2152,325
 $57.00
195,646
 $51.93
3Q21179,759
 $51.19
4Q21163,812
 $52.39


Natural Gas Derivative Contracts
(NYMEX Henry Hub Settlements)
Total Volumes
(MMBtu)
 Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call PriceTotal Volumes
(MMBtu)
 Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price
2019 Contracts       
3Q1912,680,000
 $2.81
    
4Q1911,486,000
 $2.89
    
       
2020 Contracts              
1Q206,280,000
 $2.87
    
2Q203,688,000
 $2.76
    7,430,000
 $2.62
    
3Q203,585,000
 $2.76
    7,265,000
 $2.63
    
4Q203,362,000
 $2.77
    7,042,000
 $2.63
    
       
2021 Contracts       
1Q21148,078
 $2.70
    
2Q21442,255
 $2.30
    
              
Collar Contracts              
2021 Contracts              
1Q214,354,800
   $2.50
 $3.52
5,227,800
   $2.50
 $3.40
2Q213,791,000
   $2.20
 $2.75
4,546,000
   $2.18
 $2.69
3Q214,665,175
   $2.02
 $2.65
4Q214,391,000
   $2.25
 $2.71


NGL ContractsTotal Volumes (Bbls) Weighted-Average Price
2019 Contracts   
3Q19180,000
 $27.93
4Q19180,000
 $27.93
Natural Gas Basis Derivative Swap
(East Texas Houston Ship Channel vs. NYMEX Settlements)
Total Volumes
(MMBtu)
 Weighted-Average Price
2020 Contracts   
2Q2011,739,000
 $(0.04)
3Q2011,868,000
 $(0.03)
4Q2011,868,000
 $(0.04)
    
2021 Contracts   
1Q217,200,000
 $(0.003)
2Q217,280,000
 $(0.003)
3Q217,360,000
 $(0.003)
4Q217,360,000
 $(0.003)

Natural Gas Basis Derivative Swap
(East Texas Houston Ship Channel vs. NYMEX Settlements)
Total Volumes
(MMBtu)
 Weighted-Average Price
2019 Contracts   
3Q1914,625,000
 $0.04
4Q1914,625,000
 $(0.02)
    
2020 Contracts   
1Q2011,739,000
 $(0.03)
2Q2011,739,000
 $(0.04)
3Q2011,868,000
 $(0.03)
4Q2011,868,000
 $(0.04)
    
2021 Contracts   
1Q217,200,000
 $(0.003)
2Q217,280,000
 $(0.003)
3Q217,360,000
 $(0.003)
4Q217,360,000
 $(0.003)

Oil Basis Contracts
(Argus Cushing (WTI) and Louisiana Light Sweet Settlements)
Total Volumes (Bbls) Weighted-Average Price
2019 Contracts   
3Q1975,000
 $3.73
4Q1975,000
 $3.73

Oil Basis Contracts
(Calendar Monthly Roll Differential Swaps)
Total Volumes (Bbls) Weighted-Average Price
2020 Contracts   
2Q20227,500
 $0.49
3Q20230,000
 $0.49
4Q20230,000
 $0.49



(9)           Fair Value Measurements

Fair Value on a Recurring Basis. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments.
The fair values of our derivative contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. These are considered Level 2 valuations (defined below).

The carrying value of our Credit Facility and Second Lien approximates fair value because the respective borrowing rates do not materially differ from market rates for similar borrowings. These are considered Level 3 valuations (defined below).

The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value (in millions):

Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets.

Level 2 – Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that are obtained from independent third-party sources.

Level 3 – Uses unobservable inputs for assets or liabilities that are in non-active markets.

The following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of June 30, 2019March 31, 2020 and December 31, 2018,2019, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these Notes to Condensed Consolidated Financial Statements.

Fair Value Measurements atFair 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)
Total Quoted Prices in
Active markets for
Identical Assets
(Level 1)
 Significant Other
Observable Inputs
 (Level 2)
 Significant
Unobservable
Inputs
(Level 3)
June 30, 2019       
March 31, 2020       
Assets              
Natural Gas Derivatives$13.9
 $
 $13.9
 $
$11.9
 $
 $11.9
 $
Natural Gas Basis Derivatives$5.8
 $
 $5.8
 $
$2.3
 $
 $2.3
 $
Oil Derivatives$4.4
 $
 $4.4
 $
$32.3
 $
 $32.3
 $
Oil Basis Derivatives$0.1
 $
 $0.1
 $
$1.2
 $
 $1.2
 $
NGL Derivatives$3.4
 $
 $3.4
 $
Liabilities              
Natural Gas Derivatives$0.3
 $
 $0.3
 $
$1.3
 $
 $1.3
 $
Natural Gas Basis Derivatives$0.6
 $
 $0.6
 $
$0.8
 $
 $0.8
 $
Oil Derivatives$2.1
 $
 $2.1
 $
$0.2
 $
 $0.2
 $
December 31, 2018       
December 31, 2019       
Assets              
Natural Gas Derivatives$7.5
 $
 $7.5
 $
$11.7
 $
 $11.7
 $
Natural Gas Basis Derivatives$0.4
 $
 $0.4
 $
$3.4
 $
 $3.4
 $
Oil Derivatives$6.9
 $
 $6.9
 $
$1.6
 $
 $1.6
 $
NGL Derivatives$4.7
 $
 $4.7
 $
Liabilities              
Natural Gas Derivatives$1.0
 $
 $1.0
 $
$0.2
 $
 $0.2
 $
Natural Gas Basis Derivatives$5.3
 $
 $5.3
 $
$0.9
 $
 $0.9
 $
NGL Derivatives$0.2
 $
 $0.2
 $
Oil Derivatives$7.0
 $
 $7.0
 $
Oil Basis Derivatives$0.1
 $
 $0.1
 $

Our current and long-term unsettled derivative assets and liabilities in the table above are measured at gross fair value and are shown on the accompanying condensed consolidated balance sheets in “Fair value of commodity derivatives” and “Fair Value of Long-Term Commodity Derivatives,” respectively.

(10)           Asset Retirement Obligations

Liabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets. This guidance requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values.

The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 20182019 and the sixthree months ended June 30, 2019March 31, 2020 (in thousands):

Asset Retirement Obligations as of December 31, 2017$10,787
Accretion expense419
Liabilities incurred for new wells and facilities construction93
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
$4,259
Accretion expense168
329
Liabilities incurred for new wells and facilities construction102
250
Reductions due to sold wells and facilities
Reductions due to plugged wells and facilities(47)(82)
Revisions in estimates7
(309)
Asset Retirement Obligations as of June 30, 2019$4,489
Asset Retirement Obligations as of December 31, 2019$4,447
Accretion expense86
Liabilities incurred for new wells and facilities construction33
Reductions due to plugged wells and facilities(8)
Asset Retirement Obligations as of March 31, 2020$4,558

At both June 30, 2019March 31, 2020 and December 31, 2018,2019, approximately $0.3$0.4 million of our asset retirement obligations were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets. The 2018 reductions due to sold wells and facilities are primarily attributable to the disposition of our assets from our AWP Olmos field.

(11)        Commitments and Contingencies

In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as an operator of oil and natural gas wells. In our management's 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. During the second quarter of 2019, the Company entered into new leases for compressors and operating equipment. Payment obligations under these leases are $3.0 million for the remainder of 2019, $6.1 million for 2020 and $1.8 million for 2021. There have been no other material changes to the Company's contractual obligations described in our December 31, 2018 Form 10-K.


Future minimum rental commitments under non-cancelable leases in effect at December 31, 2018 are as follows (in thousands):

 December 31, 2018
2019$4,470
2020838
2021332
Thereafter
Total undiscounted lease payments$5,640

The table above was prepared under the guidance of FASB Topic 840. As discussed in Note 3 above and in “Critical Accounting Policies and New Accounting Pronouncements,” the Company adopted the guidance of Topic 842, effective January 1, 2019.

Item 2. 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 consolidated financial statements and accompanying notes included in this report and its Annual Report on Form 10-K for the year ended December 31, 2018.2019. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 3732 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 the Companyit has assembled over 100,000approximately 200,000 net acres across fourfive operating areas. The Company'sSilverBow'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.
 
Being a committed and long-term operator in South Texas, the CompanySilverBow 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.

Recent Events, Actions Taken and Strategy

In March, the spot price of WTI crude oil declined over 50% in response to reductions in global demand due to the COVID-19 pandemic and announcements by Saudi Arabia and Russia of plans to increase crude oil production. Following this unprecedented collapse in crude oil prices, the spot price of Brent and WTI crude oil closed at $15 and $21 per barrel, respectively, on March 31, 2020. Since the end of the fiscal quarter covered by this Quarterly Report on Form 10-Q, crude oil prices have declined further to record low levels. The ultimate magnitude and duration of the COVID-19 pandemic, resulting governmental restrictions placing limitations on the mobility and ability to work of significant portions of the worldwide population, and the related impact on crude oil prices and the U.S. and global economy and capital markets is uncertain. While it is difficult for management to assess or predict with precision the broad future effect of this pandemic on the global economy, the energy industry or SilverBow, management expects that the pandemic will negatively affect the Company's results of operations, cash flows and financial condition during the remainder of 2020 due to lower commodity prices and reduced production levels. However, because a significant amount of SilverBow's total production is comprised of natural gas, the demand for and pricing of which has been less adversely affected by the response to the COVID-19 pandemic, the Company expects the impact to be less severe than that experienced by its more oil-weighted peers.

In response to current market conditions, including the recent outbreak of COVID-19 and the rapid decline in commodity prices and economic outlook, SilverBow has reduced its 2020 capital expenditure guidance to a range of $80-$95 million, representing an approximate 55% reduction to its original 2020 guidance of $175-$195 million. This estimate is subject to change based on, among other things, changes in the price of oil and natural gas, including the impact of the COVID-19 pandemic on such prices, the Company's actual capital requirements, the pace of regulatory approvals and the commodity mix of SilverBow’s projects.

In addition, the Company released its sole drilling rig in April, and has deferred the completion and placement on production of eight wells until the second half of 2020 at the earliest. The timing of bringing these eight wells to sales is dependent upon production economics. Additionally, SilverBow has begun curtailing production volumes, which began in March and continued into April. As with the Company's completion activities, the ultimate amount and duration of production curtailments remains fluid. Finally, given the reduced volume forecast, SilverBow strategically unwound hedges relating to 1,066,648 barrels of oil at a weighted average price of $32.97 per barrel for 2020 and 729,729 barrels of oil at a weighted average price of $34.55 per barrel for 2021. This resulted in hedge monetization proceeds of approximately $38 million before the end of the first quarter, the proceeds of which were used to repay borrowings on the Company's Credit Facility. SilverBow will continue to assess further hedge monetization opportunities, production curtailments and other value enhancing opportunities.

Overall, the Company's strategy remains the same. Having a diversified mix of both oil and gas inventory provides for optionality during volatile pricing environments and unforeseen changes in pricing outlook. SilverBow plans to continue pursuing a single-basin operating model, focused on low-cost structure and optionality across multiple commodity phase windows of the Eagle Ford. As a returns-focused operator, the Company maintains a strong hedge book covering forecasted production volumes,

and will continue to reduce downside risk through additional derivative contracts at favorable and opportunistic prices. As of May 4, 2020, the mark-to-market value of SilverBow's hedge book was approximately $45 million.

As a result of the COVID-19 pandemic, the Company continues to operate under a "work from home" policy applicable to all employees other than essential personnel whose physical presence is required either in the office or in the field. SilverBow has not experienced any material interruption to its ordinary course business processes as a result of COVID-19. The Company will continue to follow federal, state and local guidelines as to the reopening of its offices.

Operational Results

Total production for the sixthree months ended June 30, 2019March 31, 2020 increased 40%7% from the sixthree months ended June 30, 2018March 31, 2019 to 225 MMcfe/d228 million cubic feet of natural gas equivalent per day due to increased production from new wells in the Eagle Ford Shale, partially offset by normal production declines. Oil and natural gas liquids production for the six months ended June 30, 2019 was 7,760 Boe/d, an increase of 81% from the six months ended June 30, 2018, primarily driven by drilling in the La Salle Condensate area and McMullen Oil area.

During the secondfirst quarter the Companyof 2020, SilverBow drilled six11 gross (six(11 net) wells while completing 12eight gross (12(eight net) wells and bringing 16five gross (15(five net) wells online. Activity primarily focused on the La Salle Condensate area where seven net wells were completed during the quarter. The Company remains focused oncarried forward its capital efficiencies while optimizing well designs.efficiency into 2020. For the secondfirst quarter the Companyof 2020, SilverBow realized a 28%48% improvement in drilling timeslateral feet drilled per day over the full-year 2018full year 2019 average, resulting in ana decrease in average cost per lateral foot of $267, a 27% decrease over the same time frame.28%. On the completions side, the Company averaged eightover nine stages per day an 80%while increasing the total proppant pumped per day to over 4.9 million pounds per day, a 9% increase over the full-year 2018 average, and lowered completion costs per well by 43% over the same time frame.full year 2019 average.
The Company
SilverBow continues to see strong results in its McMullen Oil and La Salle Condensate assets. The HayesA two-well pad in the McMullen Oil area was brought online early in the secondfirst quarter of 2020, and produced a 30-daypeak 30 day per well average of 1,280 862 barrels of oil equivalent per day ("Boe/d (85%d") (84% liquids). Both Hayes wells exceeded 11,000 feet in lateral length, whilewere completed utilizing 2,400over 2,800 pounds of proppant and 5040 barrels of fluid per lateral foot. To date, both wells are performing in-line with the McMullen Oil area type curve onThe Company also completed a three-well pad utilizing 2,900 pounds of proppant and 46 barrels of fluid per lateral foot basis. The Company plans to complete three additional McMullen Oil wellsthat is scheduled for sales later in the second half of the year.2020. In the La Salle Condensate area, the CompanySilverBow completed its Briggsa three-well pad, which was brought online in late Maymid-quarter and produced a 30-day per well average of 977860 Boe/d (75%(70% liquids). These wells were completed using 2,500 pound of proppant and 33 barrels of fluid per lateral foot.

SilverBow has eight wells in the McMullen Oil area that it intends to complete and bring online based on the commodity price environment; currently these wells are planned to be brought online in the third quarter of 2020.

During the second half of March, the Company elected to curtail approximately 35 million cubic feet per day ("MMcf/d") of natural gas production. In April, SilverBow elected to increase the amount of curtailed natural gas production to approximately 50 MMcf/d and curtailed approximately 2,000 barrels per day ("Bbls/d") of oil production. As the year unfolds, the Company will continue to assess and respond to the evolving commodity price environment. SilverBow is focused on optimizing its capital program by adjusting the cadence of its activity through the timing of production curtailment and drilling and completion expenditures. The Company completed the three wellsis taking a measured approach to ensure return thresholds are met and preserve optionality in an averageorder to respond efficiently once market conditions show signs of nine days, with costs coming in 10% below expectations.recovery.
Through the first half of 2019, the Company successfully added to its acreage position through an organic leasing campaign. This includes approximately 1,000 net acres directly offsetting the Company's prolific Fasken property, which provides for 12 high-return, long-lateral locations. In addition, the Company is well-positioned to further its operational and technical efficiencies.
2019 cost reduction initiatives:2020 Cost Reduction Initiatives: The CompanySilverBow continues to focus on cost reduction measures. Initiativesmeasures in the areas that it can control. These initiatives include the use of regional sand in completions, 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, completing and completingequipping wells. The Company'sSilverBow's procurement team takes a process-oriented approach to reducing the total delivered costs of purchased services by examining costs at their most detailedgranular level. Services are commonlyroutinely 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, thesuppliers. The Company's lease operating expenses were $0.25/Mcfe$0.28 per thousand cubic feet of gas equivalent ("Mcfe") for the first sixthree months of 2019,2020, as compared to $0.30/$0.27 per Mcfe for the same period in 2018.2019.

The Company'sSilverBow's cash general and administrative costs were $9.6$4.7 million (a non-GAAP financial measure calculated as $12.9$5.9 million in net general and administrative costs less $3.3$1.2 million of share basedshare-based compensation) for the first sixthree months of 2019,2020, or $0.23$0.22 per Mcfe, compared to $8.7$4.6 million (a non-GAAP financial measure calculated as $11.4$6.3 million in net general and administrative costs less $2.7$1.7 million of share basedshare-based compensation), or $0.30/$0.24 per Mcfe, for the sixthree months ended June 30, 2018.March 31, 2019.

Liquidity and Capital Resources

The Company'sSilverBow's primary use of cash has been to fund capital expenditures to develop its oil and gas properties. As of June 30, 2019,March 31, 2020, the Company’s liquidity consisted of approximately $3.3$35.6 million of cash-on-hand and $137.0$110.0 million in available borrowings on theits Credit Facility, which hashad a $410.0$400 million borrowing base.base as of such date. Based on informed discussions with certain of the lenders under

SilverBow's Credit Facility, we anticipate a borrowing base reduction of approximately 15% to 20% from the current $400 million borrowing base in connection with the May redetermination. Management believes the Company has sufficient liquidity to meet its obligations and fund our planned capital expenditures for at leastthrough the next 12 monthssecond quarter of 2021 and execute its long-term development plans. See Note 6 to the Company'sSilverBow's condensed consolidated financial statements for more information on its Credit Facility.

Contractual Commitments and Obligations

During the second quarter of 2019, the Company entered into new leases for compressors and operating equipment. Payment obligations under these leases are $3.0 million for the remainder of 2019, $6.1 million for 2020 and $1.8 million for 2021.

There were no other material changes in the Company'sSilverBow's contractual commitments during the sixthree months ended June 30, 2019March 31, 2020 from amounts referenced under “Contractual Commitments and Obligations” in Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2018.2019.

Off-Balance Sheet Arrangements

As of June 30, 2019, weMarch 31, 2020, the Company had no off-balance sheet arrangements requiring disclosure pursuant to Item 303(a) of Regulation S-K.


Summary of First-Half 2019 Financial Results Through March 31, 2020

Revenues and net income (loss)Net Income (Loss): The Company's oil and gas revenues were $146.8$53.4 million for the sixthree months ended June 30, 2019,March 31, 2020, compared to $104.1$72.1 million for the sixthree months ended June 30, 2018.March 31, 2019. Revenues were higherlower primarily due to overall increased production,lower commodity pricing, partially offset by lower commodity pricing.higher oil and natural gas production. The Company's net incomeloss was $80.8$5.9 million for the sixthree months ended June 30, 2019,March 31, 2020, compared to $10.8net income of $16.1 million for the sixthree months ended June 30, 2018.March 31, 2019. The increasedecrease in net income was primarily due to overall increased production during the current period compared to the prior periodnon-cash impairment write-down, on a pre-tax basis, of $95.6 million on our oil and gains on commodity derivatives and a benefit recorded for income tax expense for reversal of a valuation allowance for the company's deferred tax assets.natural gas properties.

Capital expenditures:Expenditures: The Company's capital expenditures on an accrual basis were $158$51.0 million for the sixthree months ended June 30, 2019March 31, 2020 compared to $117.1$88.3 million for the sixthree months ended June 30, 2018.March 31, 2019. The expenditures for the sixthree months ended June 30,March 31, 2020 and 2019 and 2018 were attributable to drilling and completion activity.

Working capital:Capital: The Company had working capital of $41.6 million at March 31, 2020 and a working capital deficit of $20.5 million at June 30, 2019 and a deficit of $39.7$27.8 million at December 31, 2018.2019. The working capital computation does not include available liquidity through our Credit Facility.

Cash Flows: For the sixthree months ended June 30, 2019,March 31, 2020, the Company generated cash from operating activities of $100.3$76.1 million, of which $6.3$2.1 million was attributable to changes in working capital. Cash used for property additions was $174.1$52.6 million. This included $16.5$2.0 million attributable to a net decrease of capital-related payables and accrued costs. Additionally, $2.8$0.1 million was paid during the sixthree months ended June 30,March 31, 2020, for property sale obligations related to the sale of our former Bay De Chene field. The Company’s net borrowings on the Credit Facility were $11.0 million during the three months ended March 31, 2020.

For the three months ended March 31, 2019, the Company generated cash from operating activities of $50.6 million, of which $5.2 million was attributable to changes in working capital. Cash used for property additions was $86.6 million. This excluded $1.5 million attributable to a net increase of capital-related payables and accrued costs. Additionally, $1.3 million was paid during the three months ended March 31, 2019 for property sale obligations related to the sale of our former Bay De Chene field. The Company’s net borrowings on the revolving Credit Facility were $78.0$36.0 million during the sixthree months ended June 30,March 31, 2019.

For the six months ended June 30, 2018, the Company generated cash from operating activities of $53.0 million, of which $5.6 million was attributable to changes in working capital. Cash used for property additions was $84.1 million. This excluded $35.3 million attributable to a net increase of capital-related payables and accrued costs. Additionally, $6.0 million was paid during the six months ended June 30, 2018 for property sale obligations related to the sale of our former Bay De Chene field. The Company’s net payments on the revolving Credit Facility were $9.0 million, which includes the pay-down on Credit Facility borrowings with proceeds from our AWP Olmos field sale.



Results of Operations

Revenues — Three Months Ended June 30, 2019March 31, 2020 and Three Months Ended June 30, 2018March 31, 2019

Natural gas production was 77%79% and 86%82% of the Company's production volumes for the three months ended June 30,March 31, 2020 and 2019, and 2018, respectively. Natural gas sales were 58%59% and 71% of oil and gas sales for the three months ended June 30,March 31, 2020 and 2019, and 2018, respectively.

Crude oil production was 11% and 6% of the Company's production volumes for the three months ended June 30, 2019 and 2018, respectively. Crude oil sales were 33% and 19% of oil and gas sales for the three months ended June 30, 2019 and 2018, respectively.

NGL production was 12% and 8% of the Company's production volumes for the three months ended June 30,March 31, 2020 and 2019, and 2018, respectively. NGLCrude oil sales were 8%34% and 10%20% of oil and gas sales for the three months ended June 30,March 31, 2020 and 2019, respectively.

NGL production was 9% and 2018,10% of the Company's production volumes for the three months ended March 31, 2020 and 2019, respectively. NGL sales were 7% and 9% of oil and gas sales for the three months ended March 31, 2020 and 2019, respectively.

The following table provides additional information regarding the Company's oil and gas sales, by area, excluding any effects of the Company's hedging activities, for the three months ended June 30, 2019March 31, 2020 and 2018:2019:

Fields Three Months Ended June 30, 2019 Three Months Ended June 30, 2018 Three Months Ended March 31, 2020 Three Months Ended March 31, 2019
 Oil and Gas Sales
(In Millions)
Net Oil and Gas Production
Volumes (MMcfe)
 Oil and Gas Sales
(In Millions)
Net Oil and Gas Production
Volumes (MMcfe)
 Oil and Gas Sales
(In Millions)
Net Oil and Gas Production
Volumes (MMcfe)
 Oil and Gas Sales
(In Millions)
Net Oil and Gas Production
Volumes (MMcfe)
Artesia Wells $19.9
4,829
 $11.6
2,290
 $14.3
4,342
 $13.1
3,056
AWP 21.4
4,107
 8.8
1,665
 13.3
3,024
 16.1
3,019
Fasken 21.5
7,984
 25.3
8,644
 18.4
9,665
 25.4
7,832
Other (1)
 11.9
4,465
 5.6
1,941
 7.4
3,744
 17.5
5,452
Total $74.7
21,385
 $51.3
14,540
 $53.4
20,775
 $72.1
19,359
(1) Primarily composed of the Company's Rio Bravo, Oro Grande and Uno Mas fields.

The sales volumes increase from 20182019 to 20192020 was primarily due to increased natural gas production as a result of increased drilling and completion activity.

In the secondfirst quarter of 2019,2020, our $23.3$18.7 million, or 45% increase,26%, decrease in oil, NGL and natural gas sales from the prior year period resulted from:

Price variances that had an approximately $11.8$28.7 million unfavorable impact on sales due to overall lower commodity pricing; and
Volume variances that had an approximately $35.2$10.0 million favorable impact on sales due to overall increased commodity production.


The following table provides additional information regarding our oil and gas sales, by commodity type, as well as the effects of our hedging activities for derivative contracts held to settlement, for the three months ended June 30,March 31, 2020 and 2019 and 2018 (in thousands, except per-dollar amounts):


 Three Months Ended June 30, 2019Three Months Ended June 30, 2018 Three Months Ended March 31, 2020Three Months Ended March 31, 2019
Production volumes: 
 
Oil (MBbl) (1)
 405
141
 401
257
Natural gas (MMcf) 16,409
12,433
 16,498
15,907
Natural gas liquids (MBbl) (1)
 424
211
 312
319
Total (MMcfe) 21,385
14,540
 20,775
19,359

    
Oil, natural gas and natural gas liquids sales: 
 
Oil $24,940
$9,638
 $18,050
$14,607
Natural gas 43,597
36,369
 31,472
51,304
Natural gas liquids 6,166
5,339
 3,855
6,154
Total $74,703
$51,347
 $53,377
$72,064

    
Average realized price: 
 
Oil (per Bbl) $61.60
$68.53
 $45.05
$56.94
Natural gas (per Mcf) 2.66
2.93
 1.91
3.22
Natural gas liquids (per Bbl) 14.53
25.36
 12.35
19.30
Average per Mcfe $3.49
$3.53
 $2.57
$3.72

    
Price impact of cash-settled derivatives: 
 
Oil (per Bbl) $(0.01)$(14.76) $11.09
$(0.48)
Natural gas (per Mcf) 0.17
(0.06) 0.50
0.02
Natural gas liquids (per Bbl) 3.78
(2.11) 
2.73
Average per Mcfe $0.20
$(0.22) $0.61
$0.05

    
Average realized price including impact of cash-settled derivatives: 
 
Oil (per Bbl) $61.59
$53.76
 $56.15
$56.46
Natural gas (per Mcf) 2.82
2.87
 2.40
3.24
Natural gas liquids (per Bbl) 18.31
23.25
 12.35
22.03
Average per Mcfe $3.69
$3.31
 $3.18
$3.78
    
(1) Oil and natural gas liquids are converted at the rate of one barrel to six Mcfe.

For the three months ended June 30,March 31, 2020 and 2019, and 2018, the Company recorded net gains of $25.0$88.3 million and net losses of $10.8$4.0 million from our derivatives activities, respectively. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.


Costs and Expenses — Three Months Ended June 30, 2019March 31, 2020 and Three Months Ended June 30, 2018March 31, 2019
 
The following table provides additional information regarding our expenses for the three months ended June 30, 2019March 31, 2020 and 2018:2019:

Costs and ExpensesThree Months Ended June 30, 2019Three Months Ended June 30, 2018Three Months Ended March 31, 2020Three Months Ended March 31, 2019
General and administrative, net$6,624
$5,794
$5,913
$6,276
Depreciation, depletion, and amortization24,029
13,096
23,439
21,805
Accretion of asset retirement obligations86
84
86
83
Lease operating cost5,035
3,760
5,812
4,531
Workovers(127)

646
Transportation and gas processing6,728
5,421
6,643
6,406
Severance and other taxes3,950
2,662
2,964
3,316
Interest expense, net9,306
6,585
8,407
8,759
Write-down of oil and gas properties95,606


General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.31$0.28 and $0.40$0.32 for the three months ended June 30,March 31, 2020 and 2019, and 2018, respectively. The decrease per Mcfe was due to higher production while the increasedecrease in costs was primarily due to higher temporary labor, higherlower salaries and burdens and higher computer operation expenses.a lower benefit accrual. Included in general and administrative expenses is $1.6$1.2 million and $1.3$1.7 million in share basedshare-based compensation for the three months ended June 30,March 31, 2020 and 2019, and 2018, respectively.

Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were $1.12 and $0.90was $1.13 for each of the three months ended June 30, 2019March 31, 2020 and 2018, 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.2019.

Lease Operating Cost and Workovers. These expenses on a per-Mcfe basis were $0.23$0.28 and $0.26$0.27 for the three months ended June 30,March 31, 2020 and 2019, and 2018, respectively. The decrease per Mcfe was primarily due to a concentrated effort by the Company to reduce overall operating costs, along with higher production.

Transportation and Gas Processing. These expenses are related to natural gas and NGL sales. These expenses on a per Mcfe basis were $0.31 and $0.37 for the three months ended June 30, 2019 and 2018, respectively.

Severance and Other Taxes. These expenses on a per-Mcfe basis were $0.18 for each of the three months ended June 30, 2019 and 2018. Severance and other taxes, as a percentage of oil and gas sales, were approximately 5.3% and 5.2% for the three months ended June 30, 2019 and 2018, respectively.

Interest. Our gross interest cost was $9.4 million and $6.8 million for the three months ended June 30, 2019 and 2018, respectively. The increase in gross interest cost is primarily due to increased Credit Facility borrowings. Interest cost of $0.1 million and $0.3 million was capitalized for the three months ended June 30, 2019 and 2018.

Income Taxes. There was no expense for federal income taxes in three months ended June 30, 2018 as the Company had significant deferred tax assets in excess of deferred tax liabilities. In prior periods, management had determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and, accordingly, had taken a full valuation allowance to offset its tax assets. During the second quarter of 2019, the Company was able to complete several operational initiatives that resulted in increased production, lower development costs and expanded inventory of development prospects. The results of these initiatives led management to determine, after weighing both positive and negative evidence, that the Company will more likely than not be able to realize the benefits of its deferred tax assets. Accordingly, the Company released the valuation allowance, resulting in a net deferred tax benefit of $20.7 million for the three months ended June 30, 2019. State income tax expense of $0.3 million was recognized for the three months ended June 30, 2018.



Results of Operations

Revenues — Six Months Ended June 30, 2019 and Six Months Ended June 30, 2018

Natural gas production was 79% and 84% of the Company's production volumes for the six months ended June 30, 2019 and 2018, respectively. Natural gas sales were 65% and 69% of oil and gas sales for the six months ended June 30, 2019 and 2018, respectively.

Crude oil production was 10% and 7% of the Company's production volumes for the six months ended June 30, 2019 and 2018, respectively. Crude oil sales were 27% and 20% of oil and gas sales for the six months ended June 30, 2019 and 2018, respectively.

NGL production was 11% and 9% of the Company's production volumes for the six months ended June 30, 2019 and 2018, respectively. NGL sales were 8% and 11% of oil and gas sales for the six months ended June 30, 2019 and 2018, respectively.

The following table provides additional information regarding the Company's oil and gas sales, by area, excluding any effects of the Company's hedging activities, for the six months ended June 30, 2019 and 2018:

Fields Six Months Ended June 30, 2019 Six Months Ended June 30, 2018
  Oil and Gas Sales
(In Millions)
Net Oil and Gas Production
Volumes (MMcfe)
 Oil and Gas Sales
(In Millions)
Net Oil and Gas Production
Volumes (MMcfe)
Artesia Wells $33.0
7,884
 $23.9
4,814
AWP 37.5
7,127
 20.9
4,117
Fasken 46.9
15,817
 49.0
16,632
Other (1)
 29.4
9,916
 10.3
3,446
Total $146.8
40,744
 $104.1
29,009
(1) Primarily composed of the Company's Oro Grande and Uno Mas fields.

The sales volumes increase from 2018 to 2019 was primarily due to increased natural gas production as a result of increased drilling and completion activity.

In the first six months of 2019, our $42.6 million, or 41% increase, in oil, NGL and natural gas sales from the prior year period resulted from:

Price variances that had an approximately $10.5 million unfavorable impact on sales due to overall lower commodity pricing; and
Volume variances that had an approximately $53.2 million favorable impact on sales due to overall increased commodity production.


The following table provides additional information regarding our oil and gas sales, by commodity type, as well as the effects of our hedging activities for derivative contracts held to settlement, for the six months ended June 30, 2019 and 2018 (in thousands, except per-dollar amounts):


 Six Months Ended June 30, 2019Six Months Ended June 30, 2018
Production volumes:   
Oil (MBbl) (1)
 661
318
Natural gas (MMcf) 32,316
24,349
Natural gas liquids (MBbl) (1)
 743
459
Total (MMcfe) 40,744
29,009

   
Oil, natural gas and natural gas liquids sales:   
Oil $39,547
$21,078
Natural gas 94,902
72,122
Natural gas liquids 12,319
10,900
Total $146,768
$104,099

   
Average realized price:   
Oil (per Bbl) $59.79
$66.33
Natural gas (per Mcf) 2.94
2.96
Natural gas liquids (per Bbl) 16.58
23.75
Average per Mcfe $3.60
$3.59

   
Price impact of cash-settled derivatives:   
Oil (per Bbl) $(0.19)$(11.20)
Natural gas (per Mcf) 0.09
0.07
Natural gas liquids (per Bbl) 3.33
(1.38)
Average per Mcfe $0.13
$(0.09)

   
Average realized price including impact of cash-settled derivatives:   
Oil (per Bbl) $59.60
$55.13
Natural gas (per Mcf) 3.03
3.03
Natural gas liquids (per Bbl) 19.91
22.38
Average per Mcfe $3.73
$3.50
    
 
(1) Oil and natural gas liquids are converted at the rate of one barrel to six Mcfe.

For the six months ended June 30, 2019 and 2018, the Company recorded net gains of $20.9 million and net losses of $17.1 million from our derivative activities, respectively. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.


Costs and Expenses — Six Months Ended June 30, 2019 and Six Months Ended June 30, 2018
The following table provides additional information regarding our expenses for the six months ended June 30, 2019 and 2018:

Costs and ExpensesSix Months Ended June 30, 2019Six Months Ended June 30, 2018
General and administrative, net$12,900
$11,370
Depreciation, depletion, and amortization45,834
26,228
Accretion of asset retirement obligations168
243
Lease operating cost9,567
8,721
Workovers519

Transportation and gas processing13,135
10,446
Severance and other taxes7,266
5,692
Interest expense, net18,065
12,474

General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.32 and $0.39 for the six months ended June 30, 2019 and 2018, respectively. The decrease per Mcfe was due to higher production while the increase in costs was primarily due to higher temporary labor, higher salaries and burdens and higher computer operation expenses. Included in general and administrative expenses is $3.3 million and $2.7 million in share based compensation for the six months ended June 30, 2019 and 2018, respectively.

Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were $1.12 and $0.90 for the six months ended June 30, 2019 and 2018, 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 on a per-Mcfe basis were $0.25 and $0.30 for the six months ended June 30, 2019 and 2018, respectively. The decrease per Mcfe was primarily due to divestitures of assets and a concentrated effort by the Company to reduce overall operating costs, along with higher production.

Transportation and Gas Processing. These expenses are related to natural gas and NGL sales. These expenses on a per Mcfe basis were $0.32 and $0.36$0.33 for the sixthree months ended June 30,March 31, 2020 and 2019, and 2018, respectively.

Severance and Other Taxes. These expenses on a per Mcfeper-Mcfe basis were $0.18$0.14 and $0.20$0.17 for the sixthree months ended June 30,March 31, 2020 and 2019, and 2018, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 5.0%5.6% and 5.5%4.6% for the sixthree months ended June 30,March 31, 2020 and 2019, and 2018, respectively.

Interest. Our gross interest cost was $18.3$8.4 million and $13.1$8.9 million for the sixthree months ended June 30,March 31, 2020 and 2019, and 2018, respectively. The increase in gross interest cost is primarily due to increased Credit Facility borrowings. InterestThere was no capitalized interest cost and $0.1 million of $0.2 million and $0.7 million was capitalized interest for the sixthree months ended June 30,March 31, 2020 and 2019, respectively.

Write-down of oil and 2018.gas properties. Due to the effects of pricing and timing of projects, for the three months ended March 31, 2020, we reported a non-cash impairment write-down, on a pre-tax basis, of $95.6 million on our oil and natural gas properties. There was no write-down for the three months ended March 31, 2019.

Income Taxes. ThereThe Company recorded an income tax benefit of $1.2 million for the three months ended March 31, 2020, which was inclusive of state income tax expense. For the three months ended March 31, 2019 there was no expense for federal income taxes in six months ended June 30, 2018 as the Company had significant deferred tax assets in excess of deferred tax liabilities. In prior periods, management had determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and, accordingly, had taken a full valuation allowance to offset its tax assets. During the second quarter of 2019, the Company was able to complete several operational initiatives that resulted in increased production, lower development costs and expanded inventory of development prospects. The results of these initiatives led management to determine, after weighing both positive and negative evidence, that the Company will more likely than not be able to realize the benefits of its deferred tax assets. Accordingly, the Company released the valuation allowance, resulting in a net deferred tax benefit of $20.5We recognized $0.2 million for state income tax expense during the sixthree months ended June 30,March 31, 2019. State income tax of $0.3 million was recognized for the six months ended June 30, 2018.





Non-GAAP Financial Measures

Adjusted EBITDA and Adjusted EBITDA Margin

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

SilverBow defines Adjusted EBITDA as net income (loss):

Plus/Plus (Less):
Depreciation, depletion and 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 (benefit); and
Share-based compensation expense.

OurSilverBow defines Adjusted EBITDA Margin as Adjusted EBITDA divided by the sum of oil and gas sales and derivative cash settlements collected or paid. The Company's Adjusted EBITDA and Adjusted EBITDA Margin should not be considered an alternativealternatives 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. OurSilverBow's Adjusted EBITDA and Adjusted EBITDA Margin may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA and Adjusted EBITDA Margin in the same manner.

The followingbelow tables present reconciliationsprovide the calculation of our net income (loss) to Adjusted EBITDA and Adjusted EBITDA Margin for the following periods indicated (in thousands):.

Three Months Ended June 30, 2019Three Months Ended June 30, 2018
Net Income (Loss)$64,704
$2,319
Plus:

Depreciation, depletion and amortization24,029
13,096
Accretion of asset retirement obligations86
84
Interest expense9,306
6,585
Derivative (gain)/loss(24,925)10,752
Derivative cash settlements collected/(paid) (1)
4,319
(3,212)
Income tax expense/(benefit)(20,735)328
Share-based compensation expense1,648
1,316
Adjusted EBITDA$58,432
$31,268
(1) This includes accruals for settled contracts covering commodity deliveries during the period where the actual cash settlements occur outside of the period.



 Six Months Ended June 30, 2019Six Months Ended June 30, 2018
Net Income (Loss)$80,757
$10,787
Plus:  
Depreciation, depletion and amortization45,834
26,228
Accretion of asset retirement obligations168
243
Interest expense18,065
12,474
Derivative (gain)/loss(20,903)17,107
Derivative cash settlements collected/(paid) (1)
5,366
(2,476)
Income tax expense/(benefit)(20,503)328
Share-based compensation expense3,339
2,675
Adjusted EBITDA$112,123
$67,366
(1) This includes accruals for settled contracts covering commodity deliveries during the period where the actual cash settlements occur outside of the period.




Three Months Ended March 31, 2020Three Months Ended March 31, 2019
Net Income (Loss)$(5,858)$16,053
Plus:

Depreciation, depletion and amortization23,439
21,805
Accretion of asset retirement obligations86
83
Interest expense8,407
8,759
Impairment of oil and gas properties95,606

Derivative (gain)/loss(88,287)4,022
Derivative cash settlements collected/(paid) (1)
12,613
1,047
Income tax expense/(benefit)(1,241)232
Share-based compensation expense1,260
1,692
Adjusted EBITDA$46,025
$53,693
Adjusted EBITDA Margin (2)
70%73%
(1) This includes accruals for settled contracts covering commodity deliveries during the period where the actual cash settlements occur outside of the period.
(2) Adjusted EBITDA Margin equals Adjusted EBITDA divided by the sum of oil and gas sales and derivative cash settlements collected or paid.



Critical Accounting Policies and New Accounting Pronouncements

There have been no changes in the critical accounting policies disclosed in our 20182019 Annual Report on Form 10-K.

New Accounting Pronouncements. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to record certain 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 the guidance on January 1, 2019, with no significant impact on the company's financial statements resulting from implementation. See Note 3 to our consolidated financial statements for more information.




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:

the severity and duration of world health events, including the recent COVID-19 outbreak, related economic repercussions and the resulting severe disruption in the oil and gas industry and negative impact on demand for oil and gas, which is negatively impacting our business;
• the current significant surplus in the supply of oil and actions by the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC and other allied producing countries, “OPEC+”) with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations;
• operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruptions;
• shut-in of production due to decreases in available storage capacity;
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 and gas 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 Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2018.2019.

Many of the foregoing risks and uncertainties are, and will be, exacerbated by the COVID-19 pandemic and any consequent worsening of the global business and economic environment. New factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of the risks or uncertainties described in this Quarterly Report occur, or should underlying assumptions prove incorrect, actual results and plans could differ materially from those expressed in any forward-looking statements.

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 our Annual Report on Form 10-K for the year ended December 31, 2018.2019 and in subsequent Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. 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 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.


Item 3. 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 8 of our condensed consolidated financial statements included in Item 1 of this report.

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, when considered necessary, we also obtain letters of credit from certain customers, 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. A large portion of our oil and gas sales are made to Kinder Morgan, Inc. and its affiliates and we expect to continue this relationship in the future. We believe that the business risk of this relationship is mitigated by the reputation and nature of their business and the availability of other purchasers.

Interest Rate Risk. At June 30, 2019March 31, 2020, we had a combined $473.0$490.0 million drawn under our Credit Facility and our Second Lien, which bear floating rates of interest and therefore are susceptible to interest rate fluctuations. These variable interest rate borrowings are also 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 at June 30, 2019March 31, 2020 would increase our annual interest expense by $4.7$4.9 million.


Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, consisting of controls and other procedures designed to give reasonable assurance that information we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding such required disclosure.

AsOur Chief Executive Officer and Chief Financial Officer have evaluated such disclosure controls and procedures as of the end of the period covered by this quarterly report on Form 10-Q the Company’s management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Company’shave determined that such disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of result of the material weakness in our internal control over financial reporting more fully described below, our disclosure controls and procedures were not effective at a level that provides reasonable assurance as of the last day of the period covered by this report.

However, the Company concluded that the existence of this material weakness did not result in material misstatement of the Company’s financial statements included in this Quarterly Report or of those of any prior period.
Income Taxes

In connection with the preparation of our financial statements for the three months ended June 30, 2019, we identified a material weakness over certain aspects of accounting for income taxes. More specifically, we have determined that the design and operation of the controls over our income tax accounting process related to the review and analysis of the allocation of intra-period adjustments to deferred income tax expense resulting from significant, unusual and infrequent transactions were notare effective. Due to the infrequency and nature of accounting for adjustments to deferred income tax expense, the Company does not have the expertise in-house and engaged a third-party accounting firm to assist. Following closing of the Company’s books and records for the three months ended June 30, 2019 but before this Quarterly Report was filed, the Company’s independent registered public accounting firm notified the Company of the improper accounting treatment of the deferred income tax adjustment. Until this material weakness is remediated, there is a reasonable possibility that a material misstatement of our interim financial statements will not be prevented or detected on a timely basis.

Remediation Measures

We are committed to remediating the control deficiency that gave rise to the material weakness described above. Management is responsible for implementing changes and improvements to internal control over financial reporting and for remediating the control deficiency that gave rise to the material weakness.
With oversight from the Audit Committee, we intend to take the necessary steps to remediate the material weakness by enhancing our internal controls to ensure proper review by and communication between our external tax advisors and internal accounting personnel. Our efforts will consist primarily of strengthening our tax organization through continuing training and education and designing controls related to the components of our income tax process to enhance our management review controls over income taxes.
As part of the key remediation actions, we will:
Review our income tax processes and controls and enhance the overall design and procedures performed upon the review and analysis of the allocation of intra-period adjustments to deferred income tax expense resulting from significant, unusual and infrequent transactions;
Re-design our management review controls and enhance the precision of review around the key income tax areas relating to the allocation of intra-period adjustments to deferred income tax expense; and 
Evaluate the sufficiency of our income tax resources and personnel to determine whether additional resources are needed.
The material weakness will not be considered remediated until the applicable remedial controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively.



Changes in Internal Control Over Financial Reporting

Except as noted above, thereThere was no change in our internal control over financial reporting during the three months ended June 30, 2019March 31, 2020 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

No material legal proceedings are pending other than ordinary, routine litigation incidental to the Company’s business.

Item 1A. Risk Factors.
A description of our risk factors can be found in “Item 1A. Risk Factors” included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018. There2019 and in subsequent Quarterly Reports on Form 10-Q. Other than as provided below, there were no material changes to those risk factors during the sixthree months ended June 30, 2019, except that the below risk factor is hereby added:March 31, 2020.

We have identified a material weakness in our internal control over financial reportingThe imbalance between the supply of and may identify additional material weaknesses in the future or otherwise fail to maintain an effective system of internal controls, whichdemand for oil and natural gas has caused extreme market volatility and may result in material misstatementsincreased costs and decreased availability of storage capacity. The lack of a market or available storage for certain of our financial statementsproducts could cause interruptions in our operations, including temporary curtailments or cause us to fail to meet our periodic reporting obligations.

In connection with a review ofshut-ins, which could adversely affect our financial statements for the three months ended June 30, 2019, we identified a material weakness in allocationcondition and results of our intra-period adjustments to deferred income tax expense. We have determined that the design and operation of the controls over our income tax accounting process related to the review and analysis of the allocation of intra-period adjustments to deferred income tax expense resulting from significant, unusual and infrequent transactions were not effective. A material weakness is defined as a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

Although this material weakness did not result in a material misstatement to our consolidated financial statements for the quarter ended June 30, 2019 or for any prior period, this material weakness could result in a misstatement of income tax expense for interim periods that, if not remediated, could result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected.

With oversight from the Audit Committee, we intend to take the necessary steps to remediate the material weakness by enhancing our internal controls to ensure proper review by and communication between our external tax advisors and internal accounting personnel. Our efforts will consist primarily of strengthening our tax organization through continuing education and designing controls related to the components of our income tax process to enhance our management review controls over income taxes.operations.

The material weakness described above or any newly identified material weakness could limit our ability to prevent or detect a misstatementmarketing of our accounts or disclosures that could result in a material misstatementnatural gas and oil production is substantially dependent upon the existence of adequate markets for our annual or interim financial statements. We cannot assure you that any measures we may take will be sufficient to remediate the control deficiencies that ledproducts. In response to the material weaknessCOVID-19 pandemic, governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, which have caused a significant decrease in our internal control over financial reporting described above orthe demand for natural gas and oil. The imbalance between the supply of and demand for these products, as well as the uncertainty around the extent and timing of an economic recovery, have caused extreme market volatility and a substantial adverse effect on commodity prices in March and April. Also as a result of this imbalance, the industry is experiencing storage capacity constraints with respect to avoid potential future material weaknesses.

Effective internal controls are necessary for us to provide reliable financial reportscertain natural gas products and prevent fraud.oil. If we are unable to successfully remediatesell our existingproduction or any future material weaknessenter into additional storage arrangements on commercially reasonable terms or at all, we could be forced to temporarily shut in our internal control over financial reporting, or identify any additional material weaknesses that may exist, the accuracy and timinga portion of our financial reporting may be adversely affected,production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. Although our production is more heavily weighted to natural gas, the lack of a market or available storage for any one natural gas product or oil could result in temporary shut-ins as we may be unable to maintain compliance with securities law requirements regarding timely filingcurtail the production of periodic reportsindividual products in addition to applicable stock exchange listing requirements,a meaningful way without reducing the production of other products. Based on our expectation of available storage and overall demand, we may behave begun curtailing our production. We are unable to prevent fraud, investorsdetermine the extent or duration of any such curtailments. Any such shut-in or curtailment, or any inability to obtain favorable terms for delivery of the natural gas and oil we produce, could adversely affect our financial condition and results of operations.

A pandemic, epidemic or outbreak of an infectious disease, such as COVID-19, may lose confidencematerially adversely affect our business.

The global or national outbreak of an infectious disease, such as COVID-19, may cause disruptions to our business and operational plans, which may include (i) shortages of employees, (ii) unavailability of contractors and subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) recommendations of, or restrictions imposed by, government and health authorities, including quarantines, to address the COVID-19 outbreak and (v) restrictions that we and our contractors and subcontractors impose, including facility shutdowns, to ensure the safety of employees and others. While it is not possible to predict their extent or duration, these disruptions may have a material adverse effect on our business, financial condition and results of operations.

Further, the effects of COVID-19 and concerns regarding its global spread have negatively impacted domestic and international demand for crude oil and natural gas, which has contributed and could continue to contribute to price volatility, could impact the price we receive for natural gas and oil and could materially and adversely affect the demand for and marketability of our production, as well as lead to temporary curtailment of production due to lack of downstream demand or storage capacity. Additionally, to the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many of the other risks set forth in “Item 1A. Risk Factors” in our financial reporting, and our stock price may decline as a result.Annual Report on Form 10-K for the year ended December 31, 2019.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 3. Defaults Upon Senior Securities.

Not applicable.


Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

None.



Item 6. Exhibits.

The following exhibits in this index are required by Item 601 of Regulation S-K and are filed herewith or are incorporated herein by reference:
3.1
3.2
10.1+



10.2+
10.3+
10.4+





10.5+

10.6+*

10.7+*

10.8+*
10.2+*

10.3+*
10.4+*
31.1*
31.2*
32.1#
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
*Filed herewith
# Furnished herewith. Not considered to be "filed" for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.
+ Management contract or compensatory plan or arrangement.

SIGNATURES


Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

   
SILVERBOW RESOURCES, INC.
  (Registrant)
Date:August 9, 2019May 7, 2020 By:/s/ G. Gleeson Van RietChristopher M. Abundis
    
G. Gleeson Van RietChristopher M. Abundis
Executive Vice President, and
Chief Financial Officer,
General Counsel and Secretary
     
Date:August 9, 2019May 7, 2020 By:/s/ Gary G. BuchtaW. Eric Schultz
    
Gary G. BuchtaW. Eric Schultz
Controller


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