SBOW SilverBow Resources Inc

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

Large Accelerated Filer	o		Accelerated Filer	þ		Non-Accelerated Filer	o		Smaller Reporting Company	þ
Emerging Growth Company	o

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PART I. FINANCIAL INFORMATION

Condensed Consolidated Balance Sheets (Unaudited)

SilverBow Resources, Inc. and Subsidiaries (in thousands, except share amounts)

	September 30, 2019				December 31, 2018
ASSETS
Current Assets:
Cash and cash equivalents	$	2,850			$	2,465
Accounts receivable, net	34,633				46,472
Fair value of commodity derivatives	20,604				15,261
Other current assets	2,683				2,126
Total Current Assets	60,770				66,324
Property and Equipment:
Property and equipment, full cost method, including $43,066 and $56,715, respectively, of unproved property costs not being amortized at the end of each period	1,193,671				986,100
Less – Accumulated depreciation, depletion, amortization & impairment	(355,574		)		(284,804		)
Property and Equipment, Net	838,097				701,296
Right of Use Assets	10,443				—
Fair Value of Long-Term Commodity Derivatives	7,051				4,333
Deferred Tax Asset	20,427				—
Other Long-Term Assets	4,558				5,567
Total Assets	$	941,346			$	777,520
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	38,951			$	48,921
Fair value of commodity derivatives	898				2,824
Accrued capital costs	10,655				38,073
Accrued interest	1,157				1,513
Current lease liability	6,386				—
Undistributed oil and gas revenues	8,983				14,681
Total Current Liabilities	67,030				106,012
Long-Term Debt, Net	475,663				387,988
Non-Current Lease Liability	4,154				—
Deferred Tax Liabilities	1,706				1,014
Asset Retirement Obligations	4,265				3,956
Fair Value of Long-Term Commodity Derivatives	142				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, 11,865,081 and 11,757,972 shares issued, respectively, and 11,783,846 and 11,692,101 shares outstanding, respectively	119				118
Additional paid-in capital	291,754				286,281
Treasury stock, held at cost, 81,235 and 65,871 shares, respectively	(2,193		)		(1,870		)
Retained earnings (accumulated deficit)	98,706				(9,702		)
Total Stockholders’ Equity	388,386				274,827
Total Liabilities and Stockholders’ Equity	$	941,346			$	777,520
See accompanying Notes to Condensed Consolidated Financial Statements.

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Condensed Consolidated Statements of Operations (Unaudited)

SilverBow Resources, Inc. and Subsidiaries (in thousands, except per-share amounts)

	Three Months Ended September 30, 2019				Three Months Ended September 30, 2018
Revenues:
Oil and gas sales	$	72,014			$	65,034
Operating Expenses:
General and administrative, net	6,247				5,486
Depreciation, depletion, and amortization	24,937				18,766
Accretion of asset retirement obligations	88				87
Lease operating costs	5,507				4,207
Workovers	93				—
Transportation and gas processing	6,782				6,138
Severance and other taxes	3,778				2,464
Total Operating Expenses	47,432				37,148
Operating Income (Loss)	24,582				27,886
Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net	13,409				(13,600		)
Interest expense, net	(9,435		)		(7,212		)
Other income (expense), net	134				226
Income (Loss) Before Income Taxes	28,690				7,300
Provision (Benefit) for Income Taxes	1,039				220
Net Income (Loss)	$	27,651			$	7,080
Per Share Amounts
Basic:  Net Income (Loss)	$	2.35			$	0.61
Diluted:  Net Income (Loss)	$	2.35			$	0.60
Weighted-Average Shares Outstanding - Basic	11,762				11,671
Weighted-Average Shares Outstanding - Diluted	11,780				11,792
See accompanying Notes to Condensed Consolidated Financial Statements.

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	Nine Months Ended September 30, 2019				Nine Months Ended September 30, 2018
Revenues:
Oil and gas sales	$	218,781			$	169,134
Operating Expenses:
General and administrative, net	19,146				16,856
Depreciation, depletion, and amortization	70,771				44,994
Accretion of asset retirement obligations	257				330
Lease operating costs	15,074				12,927
Workovers	613				—
Transportation and gas processing	19,917				16,585
Severance and other taxes	11,044				8,156
Total Operating Expenses	136,822				99,848
Operating Income (Loss)	81,959				69,286
Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net	34,312				(30,707		)
Interest expense, net	(27,500		)		(19,686		)
Other income (expense), net	173				(477		)
Income (Loss) Before Income Taxes	88,944				18,416
Provision (Benefit) for Income Taxes	(19,464		)		549
Net Income (Loss)	$	108,408			$	17,867
Per Share Amounts
Basic:  Net Income (Loss)	$	9.24			$	1.53
Diluted:  Net Income (Loss)	$	9.21			$	1.52
Weighted-Average Shares Outstanding - Basic	11,739				11,643
Weighted-Average Shares Outstanding - Diluted	11,776				11,759
See accompanying Notes to Condensed Consolidated Financial Statements.

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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	—				—				—				2,321				2,321
Balance, June 30, 2018	$	117			$	282,726			$	(1,870	)		$	(73,530	)		$	207,443
Issuance of restricted stock (24,936 shares)	1				—				—				—				1
Share-based compensation	—				1,680				—				—				1,680
Net Income	—				—				—				7,080				7,080
Balance, September 30, 2018	$	118			$	284,406			$	(1,870	)		$	(66,450	)		$	216,204
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
Purchase of treasury shares (411 shares)	—				—				(5		)		—				(5		)
Issuance of restricted stock (26,684 shares)	1				—				—				—				1
Share-based compensation	—				1,855				—				—				1,855
Net Income	—				—				—				27,651				27,651
Balance, September 30, 2019	$	119			$	291,754			$	(2,193	)		$	98,706			$	388,386
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)

	Nine Months Ended September 30, 2019				Nine Months Ended September 30, 2018
Cash Flows from Operating Activities:
Net income (loss)	$	108,408			$	17,867
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	70,771				44,994
Accretion of asset retirement obligations	257				330
Deferred income taxes	(19,735		)		549
Share-based compensation expense	5,091				4,240
(Gain) Loss on derivatives, net	(34,312		)		30,707
Cash settlement (paid) received on derivatives	16,087				(5,671		)
Settlements of asset retirement obligations	(67		)		(159		)
Other	1,782				4,114
Change in operating assets and liabilities
(Increase) decrease in accounts receivable and other current assets	13,746				(6,533		)
Increase (decrease) in accounts payable and accrued liabilities	(8,824		)		(2,612		)
Increase (decrease) in income taxes payable	217				—
Increase (decrease) in accrued interest	(356		)		198
Net Cash Provided by (Used in) Operating Activities	153,065				88,024
Cash Flows from Investing Activities:
Additions to property and equipment	(234,859		)		(163,151		)
Proceeds from the sale of property and equipment	(96		)		27,940
Payments on property sale obligations	(4,402		)		(7,036		)
Transfer of company funds from restricted cash	—				(222		)
Net Cash Provided by (Used in) Investing Activities	(239,357		)		(142,469		)
Cash Flows from Financing Activities:
Proceeds from bank borrowings	315,000				192,300
Payments of bank borrowings	(228,000		)		(141,300		)
Net proceeds from issuances of common stock	—				709
Purchase of treasury shares	(323		)		(418		)
Payments of debt issuance costs	—				(330		)
Net Cash Provided by (Used in) Financing Activities	86,677				50,961
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	385				(3,484		)
Cash, Cash Equivalents and Restricted Cash, at Beginning of Period	2,465				8,026
Cash, Cash Equivalents and Restricted Cash at End of Period	$	2,850			$	4,542
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for interest, net of amounts capitalized	$	26,172			$	17,620
Changes in capital accounts payable and capital accruals	$	(27,905	)		$	54,060
Changes in other long-term liabilities for capital expenditures	$	—			$	(3,750	)
See accompanying Notes to Condensed Consolidated Financial Statements.

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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.

Subsequent Events. We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements. Effective October 17, 2019, as part of our regularly scheduled borrowing base redetermination, the borrowing base of our Credit Facility (as defined below) was decreased from $410 million to $400 million. There were no other material subsequent events requiring additional disclosure in these condensed consolidated financial statements.

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

•	the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom, and the Ceiling Test impairment calculation,

•	estimates related to the collectability of accounts receivable and the credit worthiness of our customers,

•	estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf,

•	estimates of future costs to develop and produce reserves,

•	accruals related to oil and gas sales, capital expenditures and lease operating expenses,

•	estimates in the calculation of share-based compensation expense,

•	estimates of our ownership in properties prior to final division of interest determination,

•	the estimated future cost and timing of asset retirement obligations,

•	estimates made in our income tax calculations,

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•	estimates in the calculation of the fair value of commodity derivative assets and liabilities,

•	estimates in the assessment of current litigation claims against the Company,

•	estimates in amounts due with respect to open state regulatory audits, and

•	estimates on future lease obligations.

While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, reallocations 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 September 30, 2019 and 2018, such internal costs when capitalized totaled $1.2 million and $1.2 million, respectively. For the nine months ended September 30, 2019 and 2018, such internal costs capitalized totaled $4.1 million and $3.6 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 6 of these Notes to Condensed Consolidated Financial Statements for further discussion on capitalized interest costs).

The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands):

	September 30, 2019				December 31, 2018
Property and Equipment
Proved oil and gas properties	$	1,146,106			$	925,865
Unproved oil and gas properties	43,066				56,715
Furniture, fixtures and other equipment	4,499				3,520
Less – Accumulated depreciation, depletion, amortization & impairment	(355,574		)		(284,804		)
Property and Equipment, Net	$	838,097			$	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

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in “Unproved oil and gas properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, economic conditions, capital availability, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.

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

The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. There was no write-down for each of the three months ended September 30, 2019 and 2018 and the nine months ended September 30, 2019 and 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 September 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 September 30, 2019, our “Accounts receivable, net” balance included $24.8 million for oil and gas sales, $1.4 million due from joint interest owners, $4.3 million for severance tax credit receivables and $4.1 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 nine months ended September 30, 2019 and 2018 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $1.1 million and $1.2 million for the three months ended September 30, 2019 and 2018, and $3.7 million and $3.4 million for the nine months ended September 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 with a greater than 50% likelihood of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At September 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 September 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

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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 in the three months ended June 30, 2019. The remaining tax benefit associated with the release of the valuation allowance is being realized through our effective tax rate. The Company recorded an income tax provision of $1.0 million for the three months ended September 30, 2019 and an income tax benefit of $19.5 million for the nine months ended September 30, 2019. The Company recognized $0.2 million and $0.5 million of state income tax expense for the three and nine months ended September 30, 2018, respectively.

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 September 30, 2019 and 2018 and the nine months ended September 30, 2019 and 2018 (in thousands):

		Three Months Ended September 30, 2019				Three Months Ended September 30, 2018				Nine Months Ended September 30, 2019				Nine Months Ended September 30, 2018
Oil, natural gas and NGLs sales:
Oil		$	28,894			$	11,124			$	68,441			$	32,202
Natural gas		37,051				43,697				131,925				115,833
NGLs		6,080				10,213				18,400				21,113
Other		(11		)		—				16				(14		)
Total		$	72,014			$	65,034			$	218,781			$	169,134

Accounts Payable and Accrued Liabilities. The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands):

	September 30, 2019				December 31, 2018
Trade accounts payable	$	22,950			$	32,683
Accrued operating expenses	3,664				3,549
Accrued compensation costs	4,079				4,785
Asset retirement obligations – current portion	307				302
Accrued non-income based taxes	4,502				3,583
Accrued corporate and legal fees	314				534
Other payables	3,135				3,485
Total accounts payable and accrued liabilities	$	38,951			$	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 nine months ended September 30, 2019, we purchased 15,364 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

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those fiscal years. The Company adopted this standard on January 1, 2019, using the modified retrospective transition approach. The Company has elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that allows an entity to carry forward historical accounting treatment for land easements on existing agreements upon adoption. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the Consolidated Balance Sheet. We have elected to not account for lease and non-lease components separately.

As a result of the adoption, the Company's 2019 opening balances for right-of-use assets and lease liabilities was $2.2 million, attributable to operating leases. 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 September 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 September 30, 2019				Nine Months Ended September 30, 2019
Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets
Property, plant and equipment acquisitions - short-term leases	$	2,208			$	8,376
Property, plant and equipment acquisitions - operating leases	12				30
Total lease costs in property, plant and equipment additions	$	2,220			$	8,406

	Three Months Ended September 30, 2019				Nine Months Ended September 30, 2019
Lease Costs Included in the Condensed Consolidated Statements of Operations
Lease operating costs - short-term leases	$	357			$	2,022
Lease operating costs - operating leases	1,387				2,524
General and administrative, net - operating leases	173				504
Total lease cost expensed	$	1,917			$	5,050

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

	As of September 30, 2019
Weighted-average remaining lease term (in years)	1.9
Weighted-average discount rate	5.0	%

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

	September 30, 2019
2019 (remaining after September 30, 2019)	$	1,700
2020	6,784
2021	2,181
2022	70
2023	40
Thereafter	348
Total undiscounted lease payments	$	11,123
Present value adjustment	(583		)
Net operating lease liabilities	$	10,540

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

	Nine Months Ended September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	3,013
Investing cash flows from operating leases	$	30

 

(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 $1.8 million and $1.6 million for the three months ended September 30, 2019 and 2018, respectively, and $5.1 million and $4.2 million for the nine months ended September 30, 2019 and 2018, respectively. Capitalized share-based compensation was $0.1 million for each of the three months ended September 30, 2019 and 2018, and $0.4 million and $0.3 million for the nine months ended September 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

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

Stock Option Awards

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

At September 30, 2019, we had $1.8 million of unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the nine months ended September 30, 2019:

	Shares			Wtd. Avg. Exer. Price
Options outstanding, beginning of period	644,575			$	28.28
Options forfeited	(5,523	)		$	27.00
Options canceled in Equity Award Exchange	(201,406	)		$	31.14
Options expired	(68,987	)		$	23.69
Options outstanding, end of period	368,659			$	27.59
Options exercisable, end of period	152,022			$	29.14

Our outstanding stock option awards at September 30, 2019 had no measurable aggregate intrinsic value. At September 30, 2019, the weighted-average remaining contract life of stock option awards outstanding was 6.2 years and exercisable was 4.3 years. The total intrinsic value of stock option awards exercisable had no value for the nine months ended September 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 September 30, 2019, we had unrecognized compensation expense of $5.9 million related to our restricted stock units which is expected to be recognized over a weighted-average period of 2.1 years.

The following table provides information regarding restricted stock unit award activity for the nine months ended September 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	(20,469	)		$	26.43
Restricted stock units vested	(107,109	)		$	28.12
Restricted stock units outstanding, end of period	403,935			$	22.47

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

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the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte-Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years.

On May 21, 2019, the Company granted an additional 99,500 performance-based stock 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 September 30, 2019, we had unrecognized compensation expense of $3.1 million related to our performance-based stock units based on the assumption of 100% target payout. The remaining weighted-average performance period is 2.1 years. No shares vested during the nine months ended September 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 September 30, 2019 and 2018 and the nine months ended September 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 September 30, 2019											Three Months Ended September 30, 2018
	Net Income (Loss)				Shares			Per Share Amount				Net Income (Loss)				Shares			Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	27,651			11,762			$	2.35			$	7,080			11,671			$	0.61
Dilutive Securities:
Restricted Stock Unit Awards					18											103
Stock Option Awards					—											18
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	27,651			11,780			$	2.35			$	7,080			11,792			$	0.60

	Nine Months Ended September 30, 2019											Nine Months Ended September 30, 2018
	Net Income (Loss)				Shares			Per Share Amount				Net Income (Loss)				Shares			Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	108,408			11,739			$	9.24			$	17,867			11,643			$	1.53
Dilutive Securities:
Restricted Stock Unit Awards					37											99
Stock Option Awards					—											17
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	108,408			11,776			$	9.21			$	17,867			11,759			$	1.52

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Approximately 0.4 million and 0.5 million stock options to purchase shares were not included in the computation of Diluted EPS for the three months ended September 30, 2019 and 2018, respectively, and 0.5 million and 0.4 million for the nine months ended September 30, 2019 and 2018, respectively, because these stock options were antidilutive.

Approximately 0.4 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 September 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 nine months ended September 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 nine months ended September 30, 2019, respectively, and less than 0.1 million shares of performance-based restricted stock units were not included for both the three and nine months ended September 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 nine months ended September 30, 2019 and 4.3 million warrants for both the three and nine months ended September 30, 2018 because these warrants were antidilutive.

(6)          Long-Term Debt

The Company's long-term debt consisted of the following (in thousands):

	September 30, 2019				December 31, 2018
Credit Facility Borrowings (1)	$	282,000			$	195,000
Second Lien Notes due 2024	200,000				200,000
	482,000				395,000
Unamortized discount on Second Lien Notes due 2024	(1,610		)		(1,782		)
Unamortized debt issuance cost on Second Lien Notes due 2024	(4,727		)		(5,230		)
Long-Term Debt, net	$	475,663			$	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 September 30, 2019 and December 31, 2018, we had $3.5 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 $282.0 million and $195.0 million as of September 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, to the First Amended and Restated Senior Secured Credit Agreement (as so amended, the “Credit Agreement” and such facility, the “Credit Facility”). Additionally, on October 17, 2019, as part of our regularly scheduled borrowing base redetermination, the borrowing base was decreased from $410 million to $400 million.

The Credit Facility matures April 19, 2022, and provides for a maximum credit amount of $600 million and a current borrowing base of $400 million as of October 17, 2019. 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 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

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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 September 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 $4.2 million and $2.1 million for the three months ended September 30, 2019 and 2018, respectively, and $11.7 million and $5.1 million for the nine months ended September 30, 2019 and 2018, respectively.

There was no capitalized interest and $0.2 million in capitalized interest on our unproved properties for the three months ended September 30, 2019 and 2018, respectively, and $0.2 million and $0.9 million for the nine months ended September 30, 2019 and 2018, respectively.

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

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

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

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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 September 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 September 30, 2019, total net amounts recorded for the Second Lien were $193.7 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $5.2 million and $16.0 million for the three and nine months ended September 30, 2019, respectively, and $5.3 million and $15.3 million for the three and nine months ended September 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

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, $4.4 million and $7.0 million was paid during the nine months ended September 30, 2019 and 2018, respectively. The remaining obligation under this contract is $3.1 million and is carried in the accompanying condensed consolidated balance sheet current liability in “Accounts payable and accrued liabilities” as of September 30, 2019.

There were no material acquisitions or dispositions of developed properties during the three and nine months ended September 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.

During the three months ended September 30, 2019 and 2018, the Company recorded gains of $13.4 million and losses of $13.6 million, respectively, on its commodity derivatives. During the nine months ended September 30, 2019 and 2018, the Company recorded gains of $34.3 million and losses of $30.7 million, respectively, on its commodity derivatives. The Company

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collected cash payments of $16.1 million and made cash payments of $5.7 million for settled derivative contracts during the nine months ended September 30, 2019 and 2018, respectively.

At September 30, 2019, there were $3.2 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 September 30, 2019 and December 31, 2018, we also had $0.1 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 September 30, 2019, there was $20.6 million and $7.1 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $0.9 million and $0.1 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 $26.6 million net fair value asset at September 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.

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

Oil Derivative Swaps (New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) Settlements)	Total Volumes (Bbls)			Weighted-Average Price
2019 Contracts
4Q19	280,567			$	59.57
2020 Contracts
1Q20	272,767			$	56.97
2Q20	289,119			$	56.88
3Q20	306,904			$	56.70
4Q20	299,121			$	54.74
2021 Contracts
1Q21	56,175			$	55.23
2Q21	52,325			$	57.00

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
4Q19	11,486,000			$	2.89
2020 Contracts
1Q20	9,920,000			$	2.73
2Q20	7,328,000			$	2.63
3Q20	7,265,000			$	2.63
4Q20	7,042,000			$	2.63
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
4Q19	180,000			$	27.93

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Natural Gas Basis Derivative Swap (East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes (MMBtu)			Weighted-Average Price
2019 Contracts
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/Magellan East Houston)	Total Volumes (Bbls)			Weighted-Average Price
2019 Contracts
4Q19	75,000			$	3.73
2020 Contracts (Calendar Monthly Roll Differential Swaps)
1Q20	136,500			$	0.51
2Q20	136,500			$	0.51
3Q20	138,000			$	0.51
4Q20	138,000			$	0.51

(9)           Fair Value Measurements

Fair Value on a Recurring Basis. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments.

    

The fair values of our derivative contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. These are considered Level 2 valuations (defined below).

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

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

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

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

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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 September 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)
September 30, 2019
Assets
Natural Gas Derivatives	$	12.2			$	—			$	12.2			$	—
Natural Gas Basis Derivatives	$	5.4			$	—			$	5.4			$	—
Oil Derivatives	$	7.9			$	—			$	7.9			$	—
Oil Basis Derivatives	$	0.2			$	—			$	0.2			$	—
NGL Derivatives	$	2.0			$	—			$	2.0			$	—
Liabilities
Natural Gas Derivatives	$	0.5			$	—			$	0.5			$	—
Natural Gas Basis Derivatives	$	0.3			$	—			$	0.3			$	—
Oil Derivatives	$	0.2			$	—			$	0.2			$	—
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			$	—

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.

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The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2018 and the nine months ended September 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	257
Liabilities incurred for new wells and facilities construction	118
Reductions due to sold wells and facilities	—
Reductions due to plugged wells and facilities	(67		)
Revisions in estimates	6
Asset Retirement Obligations as of September 30, 2019	$	4,573

At both September 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. As of September 30, 2019, payment obligations under these leases were $1.4 million for the remainder of 2019, $5.7 million for 2020 and $1.6 million for 2021. There have been no other material changes to the Company's contractual obligations described in our December 31, 2018 Form 10-K.

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

	December 31, 2018
2019	$	4,470
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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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 approximately 118,000 net acres across five operating areas. The Company's acreage position in each of its operating areas is highly contiguous and designed for optimal and efficient horizontal well development. The Company has built a balanced portfolio of properties with a significant base of current production and reserves coupled with low-risk development drilling opportunities and meaningful upside from newer operating areas.

 

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 nine months ended September 30, 2019 increased 34% from the nine months ended September 30, 2018 to 230 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 nine months ended September 30, 2019 was 8,854 Boe/d, an increase of 91% from the nine months ended September 30, 2018, primarily driven by drilling in the La Salle Condensate area and McMullen Oil area.

During the third quarter, the Company drilled six gross (five net) wells while completing five gross (five net) wells and bringing seven gross (seven net) wells online. Activity primarily focused on the McMullen Oil area where three net wells were completed. The Company continues to focus on capital efficiency and optimizing well designs. Year-to-date, the Company has realized a 24% improvement in lateral feet drilled per day over the full-year 2018 average, resulting in a decrease in average cost per lateral foot of 22% over the same time frame. On the completions side, the Company averaged over seven stages per day year to date, a 64% increase over the full-year 2018 average, and lowered completion costs per well by 26% over the same time frame. Additionally, total proppant volumes pumped per day have averaged over 3.5 million lbs per day, a 54% increase compared to the full-year 2018 average.

The Company continues to see strong results in its McMullen Oil and La Salle Condensate assets. A two-well pad in the McMullen Oil area was brought online early in the third quarter, and produced a 30-day per well average of 1,200 barrels of oil equivalent per day ("Boe/d") (90% liquids). Both wells were completed utilizing over 3,000 pounds of proppant and 50 barrels of fluid per lateral foot. In the La Salle Condensate area, the Company completed one well, which was brought online in mid-August and produced a 30-day average of 1,209 Boe/d (73% liquids).

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 initiative 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. The Company's lease operating expenses were $0.25/Mcfe for the first nine months of 2019, as compared to $0.28/Mcfe for the same period in 2018.

The Company's cash general and administrative costs were $14.0 million (a non-GAAP financial measure calculated as $19.1 million in net general and administrative costs less $5.1 million of share based compensation) for the first nine months of 2019, or $0.22 per Mcfe, compared to $12.6 million (a non-GAAP financial measure calculated as $16.9 million in net general and administrative costs less $4.2 million of share based compensation), or $0.27/Mcfe, for the nine months ended September 30, 2018.

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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 September 30, 2019, the Company’s liquidity consisted of approximately $2.9 million of cash-on-hand and $128.0 million in available borrowings on the Credit Facility, which had a $410 million borrowing base as of such date. On October 17, 2019, the Company completed the fall 2019 borrowing base redetermination as a result of which the borrowing base of the Credit Facility was decreased from $410 million to $400 million. Management believes the Company has sufficient liquidity to meet its obligations and fund its 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. As of September 30, 2019, payment obligations under these leases were $1.4 million for the remainder of 2019, $5.7 million for 2020 and $1.6 million for 2021. There were no material leases entered into in the third quarter of 2019.

There were no other material changes in the Company's contractual commitments during the nine months ended September 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 September 30, 2019, the Company had no off-balance sheet arrangements requiring disclosure pursuant to Item 303(a) of Regulation S-K.

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Summary of 2019 Financial Results Through September 30, 2019

•

Revenues and net income (loss): The Company's oil and gas revenues were $218.8 million for the nine months ended September 30, 2019, compared to $169.1 million for the nine months ended September 30, 2018. Revenues were higher primarily due to overall increased production, partially offset by lower commodity pricing. The Company's net income was $108.4 million for the nine months ended September 30, 2019, compared to $17.9 million for the nine months ended September 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 $207.4 million for the nine months ended September 30, 2019 compared to $213.8 million for the nine months ended September 30, 2018. The expenditures for the nine months ended September 30, 2019 and 2018 were attributable to drilling and completion activity.

•	Working capital: The Company had a working capital deficit of $6.3 million at September 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 nine months ended September 30, 2019, the Company generated cash from operating activities of $153.1 million, of which $4.8 million was attributable to changes in working capital. Cash used for property additions was $234.9 million. This included $27.9 million attributable to a net decrease of capital-related payables and accrued costs. Additionally, $4.4 million was paid during the nine months ended September 30, 2019, for property sale obligations related to the sale of our former Bay De Chene field. The Company’s net borrowings on the Credit Facility were $87.0 million during the nine months ended September 30, 2019.

For the nine months ended September 30, 2018, the Company generated cash from operating activities of $88.0 million, of which $8.9 million was attributable to changes in working capital. Cash used for property additions was $163.2 million. This excluded $54.1 million attributable to a net increase of capital-related payables and accrued costs. Additionally, $7.0 million was paid during the nine months ended September 30, 2018 for property sale obligations related to the sale of our former Bay De Chene field. The Company’s net payments on the Credit Facility were $51.0 million.

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Results of Operations

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

Natural gas production was 72% and 83% of the Company's production volumes for the three months ended September 30, 2019 and 2018, respectively. Natural gas sales were 52% and 67% of oil and gas sales for the three months ended September 30, 2019 and 2018, respectively.

Crude oil production was 14% and 5% of the Company's production volumes for the three months ended September 30, 2019 and 2018, respectively. Crude oil sales were 40% and 17% of oil and gas sales for the three months ended September 30, 2019 and 2018, respectively.

NGL production was 14% and 12% of the Company's production volumes for the three months ended September 30, 2019 and 2018, respectively. NGL sales were 8% and 16% of oil and gas sales for the three months ended September 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 September 30, 2019 and 2018:

Fields		Three Months Ended September 30, 2019						Three Months Ended September 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		$	23.8		6,182			$	14.8		2,719
AWP		19.5			4,026			15.2			3,176
Fasken		21.6			9,244			28.1			9,465
Other (1)		7.1			2,582			6.9			2,306
Total		$	72.0		22,034			$	65.0		17,666

(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 production as a result of increased drilling and completion activity.

In the third quarter of 2019, our $7.0 million, or 11% increase, in oil, NGL and natural gas sales from the prior year period resulted from:

•	Price variances that had an approximately $27.1 million unfavorable impact on sales due to overall lower commodity pricing; and

•	Volume variances that had an approximately $34.1 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 three months ended September 30, 2019 and 2018 (in thousands, except per-dollar amounts):

		Three Months Ended September 30, 2019			Three Months Ended September 30, 2018
Production volumes:
Oil (MBbl) (1)		506			155
Natural gas (MMcf)		15,958			14,732
Natural gas liquids (MBbl) (1)		507			334
Total (MMcfe)		22,034			17,666
Oil, natural gas and natural gas liquids sales:
Oil		$	28,894		$	11,124
Natural gas		37,040			43,697
Natural gas liquids		6,080			10,213
Total		$	72,014		$	65,034
Average realized price:
Oil (per Bbl)		$	57.14		$	71.68
Natural gas (per Mcf)		2.32			2.97
Natural gas liquids (per Bbl)		11.99			30.59
Average per Mcfe		$	3.27		$	3.68
Price impact of cash-settled derivatives:
Oil (per Bbl)		$	2.39		$	(15.44	)
Natural gas (per Mcf)		0.51			(0.05		)
Natural gas liquids (per Bbl)		4.14			(2.91		)
Average per Mcfe		$	0.52		$	(0.23	)
Average realized price including impact of cash-settled derivatives:
Oil (per Bbl)		$	59.53		$	56.24
Natural gas (per Mcf)		2.83			2.92
Natural gas liquids (per Bbl)		16.14			27.68
Average per Mcfe		$	3.79		$	3.45

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

For the three months ended September 30, 2019 and 2018, the Company recorded net gains of $13.4 million and net losses of $13.6 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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Costs and Expenses — Three Months Ended September 30, 2019 and Three Months Ended September 30, 2018

 

The following table provides additional information regarding our expenses for the three months ended September 30, 2019 and 2018:

Costs and Expenses	Three Months Ended September 30, 2019			Three Months Ended September 30, 2018
General and administrative, net	$	6,247		$	5,486
Depreciation, depletion, and amortization	24,937			18,766
Accretion of asset retirement obligations	88			87
Lease operating cost	5,507			4,207
Workovers	93			—
Transportation and gas processing	6,782			6,138
Severance and other taxes	3,778			2,464
Interest expense, net	9,435			7,212

General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.28 and $0.31 for the three months ended September 30, 2019 and 2018, respectively. The decrease per Mcfe was due to higher production while the increase in costs was primarily due to higher salaries and burdens, higher accounting fees and higher professional fees. Included in general and administrative expenses is $1.8 million and $1.6 million in share based compensation for the three months ended September 30, 2019 and 2018, respectively.

Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were $1.13 and $1.06 for the three months ended September 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 and Workovers. These expenses on a per-Mcfe basis were $0.25 and $0.24 for the three months ended September 30, 2019 and 2018, respectively.

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 $0.35 for the three months ended September 30, 2019 and 2018, respectively.

Severance and Other Taxes. These expenses on a per-Mcfe basis were $0.17 and $0.14 for the three months ended September 30, 2019 and 2018, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 5.2% and 3.8% for the three months ended September 30, 2019 and 2018, respectively.

Interest. Our gross interest cost was $9.4 million and $7.4 million for the three months ended September 30, 2019 and 2018, respectively. The increase in gross interest cost is primarily due to increased Credit Facility borrowings. There was no capitalized interest cost and $0.2 million of capitalized interest for the three months ended September 30, 2019 and 2018, respectively.

Income Taxes. The Company's income tax provision was $1.0 million for the three months ended September 30, 2019, which was inclusive of state income tax expense. For the three months ended September 30, 2018 the Company's federal income tax expense computed from pre-tax net income was primarily applied to the reduction of the valuation allowance.

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Results of Operations

Revenues — Nine Months Ended September 30, 2019 and Nine Months Ended September 30, 2018

Natural gas production was 77% and 84% of the Company's production volumes for the nine months ended September 30, 2019 and 2018, respectively. Natural gas sales were 60% and 68% of oil and gas sales for the nine months ended September 30, 2019 and 2018, respectively.

Crude oil production was 11% and 6% of the Company's production volumes for the nine months ended September 30, 2019 and 2018, respectively. Crude oil sales were 31% and 19% of oil and gas sales for the nine months ended September 30, 2019 and 2018, respectively.

NGL production was 12% and 10% of the Company's production volumes for the nine months ended September 30, 2019 and 2018, respectively. NGL sales were 9% and 12% of oil and gas sales for the nine months ended September 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 nine months ended September 30, 2019 and 2018:

Fields		Nine Months Ended September 30, 2019						Nine Months Ended September 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		$	56.8		14,067			$	38.8		7,534
AWP		57.0			11,153			36.1			7,294
Fasken		68.5			25,061			77.2			26,097
Other (1)		36.5			12,497			17.0			5,750
Total		$	218.8		62,778			$	169.1		46,675

(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 production as a result of increased drilling and completion activity.

In the first nine months of 2019, our $49.6 million, or 29% increase, in oil, NGL and natural gas sales from the prior year period resulted from:

•	Price variances that had an approximately $37.1 million unfavorable impact on sales due to overall lower commodity pricing; and

•	Volume variances that had an approximately $86.7 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 nine months ended September 30, 2019 and 2018 (in thousands, except per-dollar amounts):

		Nine Months Ended September 30, 2019			Nine Months Ended September 30, 2018
Production volumes:
Oil (MBbl) (1)		1,167			473
Natural gas (MMcf)		48,274			39,081
Natural gas liquids (MBbl) (1)		1,250			793
Total (MMcfe)		62,778			46,675
Oil, natural gas and natural gas liquids sales:
Oil		$	68,441		$	32,202
Natural gas		131,941			115,833
Natural gas liquids		18,400			21,113
Total		$	218,781		$	169,148
Average realized price:
Oil (per Bbl)		$	58.65		$	68.09
Natural gas (per Mcf)		2.73			2.96
Natural gas liquids (per Bbl)		14.72			26.63
Average per Mcfe		$	3.49		$	3.62
Price impact of cash-settled derivatives:
Oil (per Bbl)		$	0.93		$	(12.59	)
Natural gas (per Mcf)		0.23			0.03
Natural gas liquids (per Bbl)		3.66			(2.02		)
Average per Mcfe		$	0.27		$	(0.14	)
Average realized price including impact of cash-settled derivatives:
Oil (per Bbl)		$	59.58		$	55.50
Natural gas (per Mcf)		2.96			2.99
Natural gas liquids (per Bbl)		18.38			24.61
Average per Mcfe		$	3.76		$	3.48

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

For the nine months ended September 30, 2019 and 2018, the Company recorded net gains of $34.3 million and net losses of $30.7 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 — Nine Months Ended September 30, 2019 and Nine Months Ended September 30, 2018

 

The following table provides additional information regarding our expenses for the nine months ended September 30, 2019 and 2018:

Costs and Expenses	Nine Months Ended September 30, 2019			Nine Months Ended September 30, 2018
General and administrative, net	$	19,146		$	16,856
Depreciation, depletion, and amortization	70,771			44,994
Accretion of asset retirement obligations	257			330
Lease operating cost	15,074			12,927
Workovers	613			—
Transportation and gas processing	19,917			16,585
Severance and other taxes	11,044			8,156
Interest expense, net	27,500			19,686

General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.30 and $0.36 for the nine months ended September 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, higher computer operation expenses, higher accounting fees and higher professional fees. Included in general and administrative expenses is $5.1 million and $4.2 million in share based compensation for the nine months ended September 30, 2019 and 2018, respectively.

Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were $1.13 and $0.96 for the nine months ended September 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 and Workovers. These expenses on a per-Mcfe basis were $0.25 and $0.28 for the nine months ended September 30, 2019 and 2018, respectively. The decrease per Mcfe was primarily due to higher production. The increase in costs was primarily driven by more operated wells and handling of higher production volumes compared to the prior year.

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

Severance and Other Taxes. These expenses on a per Mcfe basis were $0.18 and $0.17 for the nine months ended September 30, 2019 and 2018, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 5.0% and 4.8% for the nine months ended September 30, 2019 and 2018, respectively.

Interest. Our gross interest cost was $27.7 million and $20.6 million for the nine months ended September 30, 2019 and 2018, respectively. The increase in gross interest cost is primarily due to increased Credit Facility borrowings. Interest cost of $0.2 million and $0.9 million was capitalized for the nine months ended September 30, 2019 and 2018.

Income Taxes. There was no expense for federal income taxes in nine months ended September 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 $19.5 million for the nine months ended September 30, 2019. State income tax of $0.5 million was recognized for the nine months ended September 30, 2018.

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Non-GAAP Financial Measures

Adjusted EBITDA

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

Plus/(Less):

•	Depreciation, depletion and amortization;

•	Accretion of asset retirement obligations;

•	Interest expense;

•	Impairment of oil and natural gas properties;

•	Net losses (gains) on commodity derivative contracts;

•	Amounts collected (paid) for commodity derivative contracts held to settlement;

•	Income tax expense (benefit); and

•	Share-based compensation expense.

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

The following tables present reconciliations of our net income (loss) to Adjusted EBITDA for the periods indicated (in thousands):

	Three Months Ended September 30, 2019			Three Months Ended September 30, 2018
Net Income (Loss)	$	27,651		$	7,080
Plus:
Depreciation, depletion and amortization	24,937			18,766
Accretion of asset retirement obligations	88			87
Interest expense	9,435			7,212
Derivative (gain)/loss	(13,409		)	13,600
Derivative cash settlements collected/(paid) (1)	11,407			(4,060		)
Income tax expense/(benefit)	1,039			220
Share-based compensation expense	1,752			1,566
Adjusted EBITDA	$	62,900		$	44,471
Total production volumes (MMcfe)	22,034			17,666
Adjusted EBITDA per Mcfe	$	2.85		$	2.52
Adjusted EBITDA Margin (2)	75		%	73		%
(1) This includes accruals for settled contracts covering commodity deliveries during the period where the actual cash settlements occur outside of the period.
(2) Adjusted EBITDA Margin equals Adjusted EBITDA divided by the sum of Oil and Gas Sales and Derivative Cash Settlements Collected or Paid.

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	Nine Months Ended September 30, 2019			Nine Months Ended September 30, 2018
Net Income (Loss)	$	108,408		$	17,867
Plus:
Depreciation, depletion and amortization	70,771			44,994
Accretion of asset retirement obligations	257			330
Interest expense	27,500			19,686
Derivative (gain)/loss	(34,312		)	30,707
Derivative cash settlements collected/(paid) (1)	16,773			(6,536		)
Income tax expense/(benefit)	(19,464		)	549
Share-based compensation expense	5,091			4,241
Adjusted EBITDA	$	175,024		$	111,838
Total production volumes (MMcfe)	62,778			46,675
Adjusted EBITDA per Mcfe	$	2.79		$	2.40
Adjusted EBITDA Margin (2)	74		%	69		%
(1) This includes accruals for settled contracts covering commodity deliveries during the period where the actual cash settlements occur outside of the period.
(2) Adjusted EBITDA Margin equals Adjusted EBITDA divided by the sum of Oil and Gas Sales and Derivative Cash Settlements Collected or Paid.

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Critical Accounting Policies and New Accounting Pronouncements

There have been no changes in the critical accounting policies disclosed in our 2018 Annual Report on Form 10-K.

New Accounting Pronouncements. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to record certain leases on the balance sheet. Under the new guidance, lease classification as either a finance lease or an operating lease will determine how lease-related revenue and expense are recognized. The guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company adopted the guidance on January 1, 2019, with no significant impact on the company's financial statements resulting from implementation. See Note 3 to our consolidated financial statements for more information.

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Forward-Looking Statements

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

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

• volatility in natural gas, oil and NGL prices;

• future cash flows and their adequacy to maintain our ongoing operations;

• liquidity, including our ability to satisfy our short- or long-term liquidity needs;

• our borrowing capacity, future covenant compliance, cash flows and liquidity;

• operating results;

• asset disposition efforts or the timing or outcome thereof;

• ongoing and prospective joint ventures, their structure and substance, and the likelihood of their finalization or the timing thereof;

• the amount, nature and timing of capital expenditures, including future development costs;

• timing, cost and amount of future production of oil and natural gas;

• availability of drilling and production equipment or availability of oil field labor;

• availability, cost and terms of capital;

• drilling of wells;

• availability and cost for transportation of oil and natural gas;

• costs of exploiting and developing our properties and conducting other operations;

• competition in the oil and natural gas industry;

• general economic conditions;

• opportunities to monetize assets;

• effectiveness of our risk management activities;

• environmental liabilities;

• counterparty credit risk;

• governmental regulation and taxation of the oil and natural gas industry;

• developments in world oil and gas markets and in oil and natural gas-producing countries;

• uncertainty regarding our future operating results; and

• other risks and uncertainties described in Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2018 and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2019.

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

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All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release the results of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk. Our major market risk exposure is the commodity pricing applicable to our oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. This commodity pricing volatility has continued with unpredictable price swings in recent periods.

Our price risk management policy permits the utilization of agreements and financial instruments (such as futures, forward contracts, swaps and options contracts) to mitigate price risk associated with fluctuations in oil and natural gas prices. We do not utilize these agreements and financial instruments for trading and only enter into derivative agreements with banks in our Credit Facility. For additional discussion related to our price risk management policy, refer to Note 8 of our condensed consolidated financial statements included in Item 1 of this report.

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

Concentration of Sales Risk. A large portion of our oil and gas sales are made to Kinder Morgan, Inc. and its affiliates and we expect to continue this relationship in the future. We believe that the business risk of this relationship is mitigated by the reputation and nature of their business and the availability of other purchasers.

Interest Rate Risk. At September 30, 2019, we had a combined $482.0 million drawn under our Credit Facility and our Second Lien, which bear floating rates of interest and therefore are susceptible to interest rate fluctuations. These variable interest rate borrowings are also impacted by changes in short-term interest rates. A hypothetical one percentage point increase in interest rates on our borrowings outstanding under our Credit Facility and Second Lien at September 30, 2019 would increase our annual interest expense by $4.8 million.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

As of the end of the period covered by this Form 10-Q, the Company’s management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act). Due to the fact that the material weakness in our internal control over financial reporting described below has not been remediated, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective at a level that provides reasonable assurance as of the last day of the period covered by this report.

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

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

Remediation Measures

We are committed to remediating the control deficiency that gave rise to the material weakness described above. Management is responsible for implementing changes and improvements to internal control over financial reporting and for remediating the control deficiency that gave rise to the material weakness.

 

With oversight from the Audit Committee, we have undertaken steps to remediate the material weakness by enhancing our internal controls to ensure proper communication with our external tax advisors and proper review by internal accounting personnel. Our efforts include continuing training and designing controls related to the components of our income tax process to enhance our management review controls over income taxes.

 

As part of the key remediation actions, we re-designed and expanded our management review controls and enhanced the precision of review around the key income tax areas relating to the allocation of intra-period adjustments to deferred income tax expense.

The material weakness will not be considered remediated until the applicable remedial controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively.

Changes in Internal Control Over Financial Reporting

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

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

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

Item 1A. Risk Factors.

A description of our risk factors can be found in “Item 1A. Risk Factors” included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 and in subsequent Quarterly Reports on Form 10-Q. There were no material changes to those risk factors during the three months ended September 30, 2019.

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

None.

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

None.

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Item 6. Exhibits.

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

3.1	First Amended and Restated Certificate of Incorporation of SilverBow Resources, Inc., effective May 5, 2017 (incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.'s Form 10-Q filed May 8, 2017, File No. 001-087541).
3.2	First Amended and Restated Bylaws of SilverBow Resources, Inc., effective May 5, 2017 (incorporated by reference as Exhibit 3.2 to SilverBow Resources, Inc.'s Form 10-Q filed May 8, 2017, File No. 001-08754).
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1#	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Schema Document
101.CAL*	XBRL Calculation Linkbase Document
101.LAB*	XBRL Label Linkbase Document
101.PRE*	XBRL Presentation Linkbase Document
101.DEF*	XBRL Definition Linkbase Document

*Filed herewith

# Furnished herewith. Not considered to be "filed" for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

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SIGNATURES

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

			SILVERBOW RESOURCES, INC.   (Registrant)
Date:	November 7, 2019		By:	/s/ G. Gleeson Van Riet
				G. Gleeson Van Riet Executive Vice President and Chief Financial Officer
Date:	November 7, 2019		By:	/s/ Gary G. Buchta
				Gary G. Buchta Controller

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