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Section 1: 10-Q (10-Q 2ND QUARTER 2019)

Document


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, 2019
Commission File Number 1-8754
399124926_silverbowlogoblacka07.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 class
Trading Symbol(s)
Name of each exchange on which registered
Common Stock, par value $0.01 per share
SBOW
New 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.
Yes
þ
No
o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definition of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer
o
 
Accelerated Filer
þ 
 
Non-Accelerated Filer
 o
 
Smaller Reporting Company
 þ
Emerging Growth Company
o
 
 
 
 
 
 
 
 
 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
o


1



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

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.
Yes
þ
No
 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)
11,758,317 Shares outstanding at August 1, 2019

2


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

 
 
Page
Part I
FINANCIAL INFORMATION
 
 
 
 
Item 1.
Condensed Consolidated Financial Statements
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 2.
 
 
 
Item 3.
 
 
 
Item 4.
 
 
 
Part II
OTHER INFORMATION
 
 
 
 
Item 1.
Item 1A.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
 
 



3

Table of Contents

PART I. FINANCIAL INFORMATION
Condensed Consolidated Balance Sheets (Unaudited)
SilverBow Resources, Inc. and Subsidiaries (in thousands, except share amounts)
 
June 30, 2019

December 31, 2018
ASSETS
 

 
Current Assets:
 

 
Cash and cash equivalents
$
3,333


$
2,465

Accounts receivable, net
34,760


46,472

Fair value of commodity derivatives
21,738


15,261

Other current assets
3,241


2,126

Total Current Assets
63,072


66,324

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 period
1,144,217


986,100

Less – Accumulated depreciation, depletion, amortization & impairment
(330,638
)

(284,804
)
Property and Equipment, Net
813,579


701,296

Right of Use Assets
12,568

 

Fair Value of Long-Term Commodity Derivatives
5,910


4,333

Deferred Tax Asset
21,164

 

Other Long-Term Assets
4,895


5,567

Total Assets
$
921,188


$
777,520

LIABILITIES AND STOCKHOLDERS’ EQUITY
 


 

Current Liabilities:
 


 

Accounts payable and accrued liabilities
$
33,320


$
48,921

Fair value of commodity derivatives
2,035


2,824

Accrued capital costs
28,166


38,073

Accrued interest
1,333


1,513

Current lease liability
7,006

 

Undistributed oil and gas revenues
11,755


14,681

Total Current Liabilities
83,615


106,012







Long-Term Debt, Net
466,433


387,988

Non-Current Lease Liability
5,605

 

Deferred Tax Liabilities
1,446


1,014

Asset Retirement Obligations
4,218


3,956

Fair Value of Long-Term Commodity Derivatives
987


3,723

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, respectively
118


118

Additional paid-in capital
289,899


286,281

Treasury stock, held at cost, 80,824 and 65,871 shares, respectively
(2,188
)

(1,870
)
Retained earnings (accumulated deficit)
71,055


(9,702
)
Total Stockholders’ Equity
358,884


274,827

Total Liabilities and Stockholders’ Equity
$
921,188


$
777,520







See accompanying Notes to Condensed Consolidated Financial Statements.

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Table of Contents

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, net
6,624


5,794

Depreciation, depletion, and amortization
24,029


13,096

Accretion of asset retirement obligations
86


84

Lease operating costs
5,035


3,760

Workovers
(127
)
 

Transportation and gas processing
6,728


5,421

Severance and other taxes
3,950


2,662

Total Operating Expenses
46,325

 
30,817







Operating Income (Loss)
28,378


20,530







Non-Operating Income (Expense)





Gain (loss) on commodity derivatives, net
24,925


(10,752
)
Interest expense, net
(9,306
)

(6,585
)
Other income (expense), net
(28
)

(546
)






Income (Loss) Before Income Taxes
43,969


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 - Basic
11,746


11,655







Weighted-Average Shares Outstanding - Diluted
11,780


11,757





See accompanying Notes to Condensed Consolidated Financial Statements.







5

Table of Contents

 
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, net
12,900

 
11,370

Depreciation, depletion, and amortization
45,834

 
26,228

Accretion of asset retirement obligations
168

 
243

Lease operating costs
9,567

 
8,721

Workovers
519

 

Transportation and gas processing
13,135

 
10,446

Severance and other taxes
7,266

 
5,692

Total Operating Expenses
89,389

 
62,700

 
 
 
 
Operating Income (Loss)
57,379

 
41,399

 
 
 
 
Non-Operating Income (Expense)
 
 
 
Gain (loss) on commodity derivatives, net
20,903

 
(17,107
)
Interest expense, net
(18,065
)
 
(12,474
)
Other income (expense), net
37

 
(703
)
 
 
 
 
Income (Loss) Before Income Taxes
60,254

 
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 - Basic
11,727

 
11,629

 
 
 
 
Weighted-Average Shares Outstanding - Diluted
11,786

 
11,742

 
 
 
 
See accompanying Notes to Condensed Consolidated Financial Statements.
 
 
 






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Table of Contents

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

 
 
 
 
 
 
 
 
 
 
Balance, December 31, 2018
$
118

 
$
286,281

 
$
(1,870
)
 
$
(9,702
)
 
$
274,827

 
 
 
 
 
 
 
 
 
 
Purchase of treasury shares (11,076 shares)

 

 
(260
)
 

 
(260
)
Issuance of restricted stock (61,263 shares)

 

 

 

 

Share-based compensation

 
1,849

 

 

 
1,849

Net Income

 

 

 
16,053

 
16,053

Balance, March 31, 2019
$
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)

 

 

 

 

Share-based compensation

 
1,769

 

 

 
1,769

Net Income

 

 

 
64,704

 
64,704

Balance, June 30, 2019
$
118

 
$
289,899

 
$
(2,188
)
 
$
71,055

 
$
358,884

See accompanying Notes to Condensed Consolidated Financial Statements.


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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, 2018
Cash Flows from Operating Activities:



Net income (loss)
$
80,757


$
10,787

Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities



Depreciation, depletion, and amortization
45,834


26,228

Accretion of asset retirement obligations
168


243

Deferred income taxes
(20,732
)

328

Share-based compensation expense
3,339


2,675

(Gain) Loss on derivatives, net
(20,903
)

17,107

Cash settlement (paid) received on derivatives
4,381


(1,935
)
Settlements of asset retirement obligations
(47
)

(144
)
Other
1,160


3,374

Change in operating assets and liabilities





(Increase) decrease in accounts receivable and other current assets
13,411


2,332

Increase (decrease) in accounts payable and accrued liabilities
(6,928
)

(8,439
)
Increase (decrease) in accrued interest
(180
)

491

Net Cash Provided by (Used in) Operating Activities
100,260


53,047

Cash Flows from Investing Activities:



Additions to property and equipment
(174,138
)

(84,097
)
Proceeds from the sale of property and equipment
(96
)

26,924

Payments on property sale obligations
(2,840
)

(6,042
)
Net Cash Provided by (Used in) Investing Activities
(177,074
)

(63,215
)
Cash Flows from Financing Activities:



Proceeds from bank borrowings
227,000


122,300

Payments of bank borrowings
(149,000
)

(113,300
)
Net proceeds from issuances of common stock


708

Purchase of treasury shares
(318
)

(418
)
Payments of debt issuance costs


(317
)
Net Cash Provided by (Used in) Financing Activities
77,682


8,973





Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash
868


(1,195
)
Cash, Cash Equivalents and Restricted Cash, at Beginning of Period
2,465


8,026

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


$
6,831







Supplemental Disclosures of Cash Flow Information:
 




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


$
10,926

Changes in capital accounts payable and capital accruals
$
(16,521
)

$
35,299

Changes in other long-term liabilities for capital expenditures
$


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




8

Table of Contents

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, as filed with the Securities and Exchange Commission on February 28, 2019.
 
(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-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.

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, 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.

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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-allocations 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, 2019 and 2018, such internal costs when capitalized totaled $1.3 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 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, 2018
Property and Equipment
 
 
 
Proved oil and gas properties
$
1,090,496

 
$
925,865

Unproved oil and gas properties
49,866

 
56,715

Furniture, fixtures and other equipment
3,855

 
3,520

Less – Accumulated depreciation, depletion, amortization & impairment
(330,638
)
 
(284,804
)
Property and Equipment, Net
$
813,579


$
701,296


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 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.

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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. 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, 2018

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

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, 2019 and December 31, 2018, 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, 2019, our “Accounts receivable, net” balance included $25.5 million for oil and gas sales, $0.8 million due from joint interest owners, $4.1 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 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 six months ended June 30, 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 million and $1.1 million for the three months ended June 30, 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 is 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, 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, 2019 and December 31, 2018. 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 maintained a full valuation allowance to offset its deferred tax assets. During the quarter ended June 30, 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 attributable 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 $0.5

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million for the three and six months ended June 30, 2019, respectively. The Company recognized $0.3 million of state income tax expense for the three and six months ended June 30, 2018.

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, 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, 2018
Oil, natural gas and NGLs sales:
 
 
 
 
 
 
 
 
Oil
 
$
24,940

 
$
9,638

 
$
39,547

 
$
21,078

Natural gas
 
43,587

 
36,369

 
94,874

 
72,136

NGLs
 
6,166

 
5,339

 
12,319

 
10,900

Other
 
10

 

 
28

 
(14
)
Total
 
$
74,703

 
$
51,347

 
$
146,768

 
$
104,099


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, 2018
Trade accounts payable
$
18,560

 
$
32,683

Accrued operating expenses
3,410

 
3,549

Accrued compensation costs
3,175

 
4,785

Asset retirement obligations – current portion
270

 
302

Accrued non-income based taxes
4,279

 
3,583

Accrued corporate and legal fees
239

 
534

Other payables
3,387

 
3,485

Total accounts payable and accrued liabilities
$
33,320

 
$
48,921


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 six months ended June 30, 2019, we purchased 14,953 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares.

New Accounting Pronouncements. In February 2016, the Financial Accounting Standards Board (the “FASB”) issued 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.


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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, the 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, 2019 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, 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

Property, plant and equipment acquisitions - operating leases
11

 
18

Total lease costs in property, plant and equipment additions
$
2,195

 
$
6,186


 
Three Months Ended June 30, 2019
 
Six Months Ended June 30, 2019
Lease Costs Included in the Condensed Consolidated Statement of Operations
 
 
 
Lease operating costs - short-term leases
$
329

 
$
1,664

Lease operating costs - operating leases
1,084

 
1,138

General and administrative, net - operating leases
175

 
331

Total lease cost expensed
$
1,588

 
$
3,133


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

 
As of June 30, 2019
Weighted-average remaining lease term (in years)
2.1

Weighted-average discount rate
5.0
%

    

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

 
June 30, 2019
2019 (remaining after June 30, 2019)
$
3,503

2020
7,091

2021
2,344

2022
40

2023
40

Thereafter
348

Total undiscounted lease payments
$
13,366

Present value adjustment

Net operating lease liabilities
$
13,366


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

 
Six Months Ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities
 
Operating cash flows from operating leases
$
1,457

Investing cash flows from operating leases
$
18


 
(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 awards (“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, 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 million and $1.3 million for the three months ended June 30, 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 six months ended June 30, 2019 and 2018, respectively.

We view stock option awards and restricted stock unit awards 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. 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,

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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, we had $2.2 million of unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the six months ended June 30, 2019:
 
Shares
 
Wtd. Avg. Exer. Price
Options outstanding, beginning of period
644,575

 
$
28.28

Options forfeited
(4,197
)
 
$
27.00

Options canceled in Equity Award Exchange
(201,406
)
 
$
31.14

Options expired
(68,987
)
 
$
23.69

Options outstanding, end of period
369,985

 
$
27.59

Options exercisable, end of period
130,601

 
$
28.42


Our outstanding stock option awards at June 30, 2019 had no measurable aggregate intrinsic value. At June 30, 2019, the weighted-average remaining contract life of stock option awards outstanding was 6.5 years and exercisable was 5.0 years. The total intrinsic value of stock option awards exercisable had no value for the six months ended June 30, 2019.

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, we had unrecognized compensation expense of $7.1 million related to our restricted stock units which is expected to be recognized over a weighted-average period of 2.2 years.

The following table provides information regarding restricted stock unit award activity for the six months ended June 30, 2019:
 
Shares
 
Grant Date Price
Restricted stock units outstanding, beginning of period
340,678

 
$
27.64

Restricted stock units granted
115,957

 
$
20.13

Restricted stock units granted under Equity Award Exchange
99,500

 
$
16.70

Restricted stock 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 period
434,746

 
$
23.14


Performance-Based Stock Units

On February 20, 2018, the Company granted 30,700 performance-based stock units 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

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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 units (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 stock price. The awards have a cliff-vesting period of three years.

As of June 30, 2019, we had unrecognized compensation expense of $3.5 million related to our performance-based stock units based on the assumption of 100% target payout. The remaining weighted-average performance period is 2.3 years. No shares vested during the six months ended June 30, 2019.

(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") assumes, as of the beginning of the period, exercise of stock options and restricted stock grants using the treasury stock method. Diluted EPS also assumes conversion of performance-based restricted stock units 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 stock grants that would potentially dilute Basic EPS in the future were also antidilutive for the three months ended June 30, 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, 2018
 
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

Dilutive Securities:
 
 
 
 
 
 
 
 
 
 
 
Restricted Stock Awards
 
 

 
 
 
 
 

 
 
Restricted Stock Unit Awards
 
 
59

 
 
 
 
 
17

 
 
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


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Approximately 0.5 million and 0.4 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, and 0.6 million and 0.4 million for the six months ended June 30, 2019 and 2018, respectively, because these stock options were antidilutive.

Approximately 0.2 million and less than 0.1 million shares of restricted stock units 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 2018 because they were antidilutive. There were approximately 0.1 million and less than 0.1 million antidilutive shares of restricted stock units for both the six months ended June 30, 2019 and 2018.

Approximately 0.1 million and less than 0.1 million shares of performance-based restricted stock units were not included in the computation of Diluted EPS for the three and six months ended June 30, 2019, respectively, and less than 0.1 million shares of performance-based restricted stock units were not included for both the three and six months ended June 30, 2018 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 and 4.3 million warrants for both the three and six months ended June 30, 2018 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, 2018
Credit Facility Borrowings (1)
$
273,000

 
$
195,000

Second Lien Notes due 2024
200,000

 
200,000

 
473,000

 
395,000

Unamortized discount on Second Lien Notes due 2024
(1,668
)
 
(1,782
)
Unamortized debt issuance cost on Second Lien Notes due 2024
(4,899
)
 
(5,230
)
Long-Term Debt, net
$
466,433

 
$
387,988

(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, 2019 and December 31, 2018, we had $3.8 million and $4.5 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 million and $195.0 million as of June 30, 2019 and December 31, 2018, 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 increased the borrowing base from $330 million to $410 million and decreased the applicable margins used to calculate the interest rate under the Credit Agreement by 25 basis points.

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. The borrowing base is regularly redetermined on or about May and November of each calendar year and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, each of the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders, in their discretion, 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

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

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

The Credit Agreement contains the following financial covenants:

a ratio of total debt to 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, 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 million and $1.6 million for the three months ended June 30, 2019 and 2018, respectively, and $7.5 million and $3.1 million for the six months ended June 30, 2019 and 2018, respectively.

We capitalized interest on our unproved properties in the amount of $0.1 million and $0.3 million for the three months ended June 30, 2019 and 2018, respectively and $0.2 million and $0.7 million for the six months ended June 30, 2019 and 2018.

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

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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, 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, 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, total net amounts recorded for the Second Lien were $193.4 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $5.5 million and $10.8 million for the three and six months ended June 30, 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 million was paid during the six months ended June 30, 2019. The remaining obligation under this contract is $4.6 million and is carried in the accompanying condensed consolidated balance sheet current liability in “Accounts payable and accrued liabilities” as of June 30, 2019.

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

(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.

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During the three months ended June 30, 2019 and 2018, the Company recorded gains of $25.0 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 million, respectively, on its commodity derivatives. The Company collected cash payments of $4.4 million and made cash payments of $1.9 million for settled derivative contracts during the six months ended June 30, 2019 and 2018, respectively.

At June 30, 2019, there were $3.6 million in receivables for settled derivatives while at December 31, 2018 we had $0.7 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 2019 and January 2019, respectively. At June 30, 2019 and December 31, 2018, we also had $0.2 million and $2.2 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 2019 and January 2019, 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, there was $21.7 million and $5.9 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $2.0 million and $1.0 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2018, there was $15.3 million and $4.3 million in current and long-term unsettled derivative assets, respectively, and $2.8 million and $3.7 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 million net fair value asset at June 30, 2019 and a $13.0 million net fair value asset at December 31, 2018. 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:

Oil Derivative Swaps
(New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) Settlements)
Total Volumes
(Bbls)
 
Weighted-Average Price
2019 Contracts
 
 
 
3Q19
314,500

 
$
60.41

4Q19
249,000

 
$
59.52

 
 
 
 
2020 Contracts
 
 
 
1Q20
194,800

 
$
58.16

2Q20
191,350

 
$
58.32

3Q20
189,200

 
$
58.43

4Q20
118,000

 
$
55.65

 
 
 
 
2021 Contracts
 
 
 
1Q21
56,175

 
$
55.23

2Q21
52,325

 
$
57.00



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Natural Gas Derivative Contracts
(NYMEX Henry Hub Settlements)
Total Volumes
(MMBtu)
 
Weighted-Average Price
 
Weighted-Average Collar Floor Price
 
Weighted-Average Collar Call Price
2019 Contracts
 
 
 
 
 
 
 
3Q19
12,680,000

 
$
2.81

 
 
 
 
4Q19
11,486,000

 
$
2.89

 
 
 
 
 
 
 
 
 
 
 
 
2020 Contracts
 
 
 
 
 
 
 
1Q20
6,280,000

 
$
2.87

 
 
 
 
2Q20
3,688,000

 
$
2.76

 
 
 
 
3Q20
3,585,000

 
$
2.76

 
 
 
 
4Q20
3,362,000

 
$
2.77

 
 
 
 
 
 
 
 
 
 
 
 
Collar Contracts
 
 
 
 
 
 
 
2021 Contracts
 
 
 
 
 
 
 
1Q21
4,354,800

 
 
 
$
2.50

 
$
3.52

2Q21
3,791,000

 
 
 
$
2.20

 
$
2.75


NGL Contracts
Total Volumes (Bbls)
 
Weighted-Average Price
2019 Contracts
 
 
 
3Q19
180,000

 
$
27.93

4Q19
180,000

 
$
27.93


Natural Gas Basis Derivative Swap
(East Texas Houston Ship Channel vs. NYMEX Settlements)
Total Volumes
(MMBtu)
 
Weighted-Average Price
2019 Contracts
 
 
 
3Q19
14,625,000

 
$
0.04

4Q19
14,625,000

 
$
(0.02
)
 
 
 
 
2020 Contracts
 
 
 
1Q20
11,739,000

 
$
(0.03
)
2Q20
11,739,000

 
$
(0.04
)
3Q20
11,868,000

 
$
(0.03
)
4Q20
11,868,000

 
$
(0.04
)
 
 
 
 
2021 Contracts
 
 
 
1Q21
7,200,000

 
$
(0.003
)
2Q21
7,280,000

 
$
(0.003
)
3Q21
7,360,000

 
$
(0.003
)
4Q21
7,360,000

 
$
(0.003
)

Oil Basis Contracts
(Argus Cushing (WTI) and Louisiana Light Sweet Settlements)
Total Volumes (Bbls)
 
Weighted-Average Price
2019 Contracts
 
 
 
3Q19
75,000

 
$
3.73

4Q19
75,000

 
$
3.73



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(9)           Fair Value Measurements

Fair Value on a Recurring Basis. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, 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 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, 2019 and December 31, 2018, 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 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)
June 30, 2019
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
Natural Gas Derivatives
$
13.9

 
$

 
$
13.9

 
$

Natural Gas Basis Derivatives
$
5.8

 
$

 
$
5.8

 
$

Oil Derivatives
$
4.4

 
$

 
$
4.4

 
$

Oil Basis Derivatives
$
0.1

 
$

 
$
0.1

 
$

NGL Derivatives
$
3.4

 
$

 
$
3.4

 
$

Liabilities
 
 
 
 
 
 
 
Natural Gas Derivatives
$
0.3

 
$

 
$
0.3

 
$

Natural Gas Basis Derivatives
$
0.6

 
$

 
$
0.6

 
$

Oil Derivatives
$
2.1

 
$

 
$
2.1

 
$

December 31, 2018
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
Natural Gas Derivatives
$
7.5

 
$

 
$
7.5

 
$

Natural Gas Basis Derivatives
$
0.4

 
$

 
$
0.4

 
$

Oil Derivatives
$
6.9

 
$

 
$
6.9

 
$

NGL Derivatives
$
4.7

 
$

 
$
4.7

 
$

Liabilities
 
 
 
 
 
 
 
Natural Gas Derivatives
$
1.0

 
$

 
$
1.0

 
$

Natural Gas Basis Derivatives
$
5.3

 
$

 
$
5.3

 
$

NGL Derivatives
$
0.2

 
$

 
$
0.2

 
$



22


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, 2018 and the six months ended June 30, 2019 (in thousands):

Asset Retirement Obligations as of December 31, 2017
$
10,787

Accretion expense
419

Liabilities incurred for new wells and facilities construction
93

Reductions due to sold wells and facilities
(6,298
)
Reductions due to plugged wells and facilities
(180
)
Revisions in estimates
(562
)
Asset Retirement Obligations as of December 31, 2018
$
4,259

Accretion expense
168

Liabilities incurred for new wells and facilities construction
102

Reductions due to sold wells and facilities

Reductions due to plugged wells and facilities
(47
)
Revisions in estimates
7

Asset Retirement Obligations as of June 30, 2019
$
4,489


At both June 30, 2019 and December 31, 2018, approximately $0.3 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.

    

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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

2020
838

2021
332

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.

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Table of Contents

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. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 37 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 Company has assembled over 100,000 net acres across four operating areas. The Company's acreage position in each of its operating areas is highly contiguous and designed for optimal and efficient horizontal well development. The Company has built a balanced portfolio of properties with a significant base of current production and reserves coupled with low-risk development drilling opportunities and meaningful upside from newer operating areas.
 
Being a committed and long-term operator in South Texas, the Company possesses a significant understanding of the reservoir characteristics, geology, landowners and competitive landscape in the region. The Company leverages this in-depth knowledge to continue to assemble high quality drilling inventory while continuously enhancing its operations to maximize returns on capital invested.

Operational Results

Total production for the six months ended June 30, 2019 increased 40% from the six months ended June 30, 2018 to 225 MMcfe/d 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 second quarter, the Company drilled six gross (six net) wells while completing 12 gross (12 net) wells and bringing 16 gross (15 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 on capital efficiencies while optimizing well designs. For the second quarter, the Company realized a 28% improvement in drilling times over the full-year 2018 average, resulting in an average cost per lateral foot of $267, a 27% decrease over the same time frame. On the completions side, the Company averaged eight stages per day, an 80% increase over the full-year 2018 average, and lowered completion costs per well by 43% over the same time frame.
The Company continues to see strong results in its McMullen Oil and La Salle Condensate assets. The Hayes two-well pad in the McMullen Oil area was brought online early in the second quarter, and produced a 30-day per well average of 1,280 Boe/d (85% liquids). Both Hayes wells exceeded 11,000 feet in lateral length, while utilizing 2,400 pounds of proppant and 50 barrels of fluid per lateral foot. To date, both wells are performing in-line with the McMullen Oil area type curve on a per lateral foot basis. The Company plans to complete three additional McMullen Oil wells in the second half of the year. In the La Salle Condensate area, the Company completed its Briggs three-well pad, which was brought online in late May and produced a 30-day per well average of 977 Boe/d (75% liquids). The Company completed the three wells in an average of nine days, with costs coming in 10% below expectations.
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: The Company continues to focus on cost reduction measures. 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 and completing wells. The Company's procurement team takes a process-oriented approach to reducing the total delivered costs of purchased services by examining costs at their most detailed level. Services are commonly sourced directly from the suppliers, which has led to a significant reduction in the Company's overall lease operating expenses at the field level. For example, the Company's lease operating expenses were $0.25/Mcfe for the first six months of 2019, as compared to $0.30/Mcfe for the same period in 2018.

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Table of Contents

The Company's cash general and administrative costs were $9.6 million (a non-GAAP financial measure calculated as $12.9 million in net general and administrative costs less $3.3 million of share based compensation) for the first six months of 2019, or $0.23 per Mcfe, compared to $8.7 million (a non-GAAP financial measure calculated as $11.4 million in net general and administrative costs less $2.7 million of share based compensation), or $0.30/Mcfe, for the six months ended June 30, 2018.

Liquidity and Capital Resources

The Company's primary use of cash has been to fund capital expenditures to develop its oil and gas properties. As of June 30, 2019, the Company’s liquidity consisted of approximately $3.3 million of cash-on-hand and $137.0 million in available borrowings on the Credit Facility, which has a $410.0 million borrowing base. Management believes the Company has sufficient liquidity to meet its obligations and fund our planned capital expenditures for at least the next 12 months and execute its long-term development plans. See Note 6 to the Company'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's contractual commitments during the six months ended June 30, 2019 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.

Off-Balance Sheet Arrangements

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


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Table of Contents

Summary of First-Half 2019 Financial Results

Revenues and net income (loss): The Company's oil and gas revenues were $146.8 million for the six months ended June 30, 2019, compared to $104.1 million for the six months ended June 30, 2018. Revenues were higher primarily due to overall increased production, partially offset by lower commodity pricing. The Company's net income was $80.8 million for the six months ended June 30, 2019, compared to $10.8 million for the six months ended June 30, 2018. The increase was primarily due to overall increased production during the current period compared to the prior period 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.

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

Working capital: The Company had a working capital deficit of $20.5 million at June 30, 2019 and a deficit of $39.7 million at December 31, 2018. The working capital computation does not include available liquidity through our Credit Facility.

Cash Flows: For the six months ended June 30, 2019, the Company generated cash from operating activities of $100.3 million, of which $6.3 million was attributable to changes in working capital. Cash used for property additions was $174.1 million. This included $16.5 million attributable to a net decrease of capital-related payables and accrued costs. Additionally, $2.8 million was paid during the six months ended June 30, 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 million during the six months ended June 30, 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.



27

Table of Contents

Results of Operations

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

Natural gas production was 77% and 86% of the Company's production volumes for the three months ended June 30, 2019 and 2018, respectively. Natural gas sales were 58% and 71% of oil and gas sales for the three months ended June 30, 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, 2019 and 2018, respectively. NGL sales were 8% and 10% of oil and gas sales for the three 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 three months ended June 30, 2019 and 2018:

Fields
 
Three Months Ended June 30, 2019
 
Three 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
 
$
19.9

4,829

 
$
11.6

2,290

AWP
 
21.4

4,107

 
8.8

1,665

Fasken
 
21.5

7,984

 
25.3

8,644

Other (1)
 
11.9

4,465

 
5.6

1,941

Total
 
$
74.7

21,385

 
$
51.3

14,540

(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 second quarter of 2019, our $23.3 million, or 45% increase, in oil, NGL and natural gas sales from the prior year period resulted from:

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


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Table of Contents

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, 2019 and 2018 (in thousands, except per-dollar amounts):


 
Three Months Ended June 30, 2019
Three Months Ended June 30, 2018
Production volumes:
 


Oil (MBbl) (1)
 
405

141

Natural gas (MMcf)
 
16,409

12,433

Natural gas liquids (MBbl) (1)
 
424

211

Total (MMcfe)
 
21,385

14,540


 
 
 
Oil, natural gas and natural gas liquids sales:
 


Oil
 
$
24,940

$
9,638

Natural gas
 
43,597

36,369

Natural gas liquids
 
6,166

5,339

Total
 
$
74,703

$
51,347


 
 
 
Average realized price:
 


Oil (per Bbl)
 
$
61.60

$
68.53

Natural gas (per Mcf)
 
2.66

2.93

Natural gas liquids (per Bbl)
 
14.53

25.36

Average per Mcfe
 
$
3.49

$
3.53


 
 
 
Price impact of cash-settled derivatives:
 


Oil (per Bbl)
 
$
(0.01
)
$
(14.76
)
Natural gas (per Mcf)
 
0.17

(0.06
)
Natural gas liquids (per Bbl)
 
3.78

(2.11
)
Average per Mcfe
 
$
0.20

$
(0.22
)

 
 
 
Average realized price including impact of cash-settled derivatives:
 


Oil (per Bbl)
 
$
61.59

$
53.76

Natural gas (per Mcf)
 
2.82

2.87

Natural gas liquids (per Bbl)
 
18.31

23.25

Average per Mcfe
 
$
3.69

$
3.31

 
 
 
 
 
(1) Oil and natural gas liquids are converted at the rate of one barrel to six Mcfe.

For the three months ended June 30, 2019 and 2018, the Company recorded net gains of $25.0 million and net losses of $10.8 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.


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Table of Contents

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

Costs and Expenses
Three Months Ended June 30, 2019
Three Months Ended June 30, 2018
General and administrative, net
$
6,624

$
5,794

Depreciation, depletion, and amortization
24,029

13,096

Accretion of asset retirement obligations
86

84

Lease operating cost
5,035

3,760

Workovers
(127
)

Transportation and gas processing
6,728

5,421

Severance and other taxes
3,950

2,662

Interest expense, net
9,306

6,585


General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.31 and $0.40 for the three 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 $1.6 million and $1.3 million in share based compensation for the three 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 three 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 $0.23 and $0.26 for the three months ended June 30, 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.



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Table of Contents

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.


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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, 2019
Six 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.


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Costs and Expenses — Six Months Ended June 30, 2019 and Six Months Ended June 30, 2018