UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(X)  Quarterly Report Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

For the quarterly period ended March 31, 2019

Commission File Number 1-8754

SILVERBOW RESOURCES, INC.

(Exact Name of Registrant as Specified in Its Charter)

Delaware (State of Incorporation)	20-3940661 (I.R.S. Employer Identification No.)
575 North Dairy Ashford, Suite 1200 Houston, Texas 77079 (281) 874-2700 (Address and telephone number of principal executive offices) Securities registered pursuant to Section 12(b) of the Act:

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definition of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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

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

o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

1

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

Yes þ No o

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

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.01 per share	SBOW	New York Stock Exchange

Indicate the number of shares outstanding of each of the issuer’s classes

of common stock, as of the latest practicable date.

Common Stock ($.01 Par Value) (Class of Stock) 11,743,159 Shares outstanding at May 1, 2019

2

SILVERBOW RESOURCES, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2019

INDEX

		Page
Part I	FINANCIAL INFORMATION
Item 1.	Condensed Consolidated Financial Statements
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Statements of Stockholders’ Equity	6
	Condensed Consolidated Statements of Cash Flows	7
	Notes to Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33
Item 4.	Controls and Procedures	34
Part II	OTHER INFORMATION
Item 1.	Legal Proceedings	35
Item 1A.	Risk Factors	35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35
Item 3.	Defaults Upon Senior Securities	35
Item 4.	Mine Safety Disclosures	35
Item 5.	Other Information	35
Item 6.	Exhibits	35
SIGNATURES		37

3

Condensed Consolidated Balance Sheets (Unaudited)

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

	March 31, 2019			December 31, 2018
ASSETS
Current Assets:
Cash and cash equivalents	$	876		$	2,465
Accounts receivable, net	31,342			46,472
Fair value of commodity derivatives	8,346			15,261
Other current assets	3,110			2,126
Total Current Assets	43,674			66,324
Property and Equipment:
Property and Equipment, full cost method, including $64,797 and $56,715 of unproved property costs not being amortized at the end of each period	1,074,453			986,100
Less – Accumulated depreciation, depletion, amortization & impairment	(306,609		)	(284,804		)
Property and Equipment, Net	767,844			701,296
Right of Use Assets	2,024			—
Fair value of long-term commodity derivatives	4,024			4,333
Other Long-Term Assets	5,231			5,567
Total Assets	$	822,797		$	777,520
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	31,978		$	48,921
Fair value of commodity derivatives	4,570			2,824
Accrued capital costs	46,992			38,073
Accrued interest	1,413			1,513
Current lease liability	860			—
Undistributed oil and gas revenues	11,719			14,681
Total Current Liabilities	97,532			106,012
Long-Term Debt, net	424,207			387,988
Non-current Lease Liability	1,171			—
Deferred Tax Liabilities	1,148			1,014
Asset Retirement Obligations	4,073			3,956
Fair value of long-term commodity derivatives	2,197			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, 11,819,235 and 11,757,972 shares issued and 11,742,288 and 11,692,101 shares outstanding, respectively	118			118
Additional paid-in capital	288,130			286,281
Treasury stock, held at cost, 76,947 and 65,871 shares	(2,130		)	(1,870		)
Retained earnings (Accumulated deficit)	6,351			(9,702		)
Total Stockholders’ Equity	292,469			274,827
Total Liabilities and Stockholders’ Equity	$	822,797		$	777,520
See accompanying Notes to Condensed Consolidated Financial Statements.

4

Condensed Consolidated Statements of Operations (Unaudited)

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

	Three Months Ended March 31, 2019			Three Months Ended March 31, 2018
Revenues:
Oil and gas sales	$	72,064		$	52,752
Operating Expenses:
General and administrative, net	6,276			5,576
Depreciation, depletion, and amortization	21,805			13,131
Accretion of asset retirement obligations	83			159
Lease operating costs	4,531			4,961
Workovers	646			—
Transportation and gas processing	6,406			5,025
Severance and other taxes	3,316			3,031
Total Operating Expenses	43,063			31,883
Operating Income (Loss)	29,001			20,869
Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net	(4,022		)	(6,355		)
Interest expense, net	(8,759		)	(5,890		)
Other income (expense), net	65			(158		)
Income (Loss) Before Income Taxes	16,285			8,466
Provision (Benefit) for Income Taxes	232			—
Net Income (Loss)	$	16,053		$	8,466
Per Share Amounts-
Basic:  Net Income (Loss)	$	1.37		$	0.73
Diluted:  Net Income (Loss)	$	1.36		$	0.72
Weighted Average Shares Outstanding - Basic	11,708			11,602
Weighted Average Shares Outstanding - Diluted	11,788			11,727
See accompanying Notes to Condensed Consolidated Financial Statements.

5

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
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
See accompanying Notes to Condensed Consolidated Financial Statements.

6

Condensed Consolidated Statements of Cash Flows (Unaudited)

SilverBow Resources, Inc. and Subsidiaries (in thousands)

	Three Months Ended March 31, 2019			Three Months Ended March 31, 2018
Cash Flows from Operating Activities:
Net income (loss)	$	16,053		$	8,466
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	21,805			13,131
Accretion of asset retirement obligations	83			159
Deferred income taxes	134			—
Share-based compensation expense	1,692			1,359
(Gain) Loss on derivatives, net	4,022			6,355
Cash settlement (paid) received on derivatives	1,077			977
Settlements of asset retirement obligations	(31		)	(120		)
Other	564			129
Change in operating assets and liabilities-
(Increase) decrease in accounts receivable and other current assets	14,401			4,005
Increase (decrease) in accounts payable and accrued liabilities	(9,105		)	(9,497		)
Increase (decrease) in accrued interest	(100		)	192
Net Cash Provided by (used in) Operating Activities	50,595			25,156
Cash Flows from Investing Activities:
Additions to property and equipment	(86,555		)	(33,753		)
Proceeds from the sale of property and equipment	(91		)	26,969
Payments on property sale obligations	(1,278		)	(6,042		)
Net Cash Provided by (Used in) Investing Activities	(87,924		)	(12,826		)
Cash Flows from Financing Activities:
Proceeds from bank borrowings	132,000			35,100
Payments of bank borrowings	(96,000		)	(55,100		)
Net proceeds from issuances of common stock	—			708
Purchase of treasury shares	(260		)	(290		)
Payments of debt issuance costs	—			(317		)
Net Cash Provided by (Used in) Financing Activities	35,740			(19,899		)
Net increase (decrease) in Cash, Cash Equivalents and Restricted Cash	(1,589		)	(7,569		)
Cash, Cash Equivalents and Restricted Cash, at Beginning of Period	2,465			8,026
Cash, Cash Equivalents and Restricted Cash at End of Period	$	876		$	457
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for interest, net of amounts capitalized	$	8,303		$	5,170
Changes in capital accounts payable and capital accruals	$	1,487		$	12,177
Changes in other long-term liabilities for capital expenditures	$	—		$	(1,250	)
See accompanying Notes to Condensed Consolidated Financial Statements

7

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. On April 12, 2019, as part of our regularly scheduled borrowing base redetermination, we reaffirmed the borrowing base of our Credit Facility at $410 million. See Note 6 of these condensed consolidated financial statements for further details on our Credit Facility. There were no other material subsequent events requiring additional disclosure in these condensed consolidated financial statements.

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

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

8

• estimates made in our income tax calculations,

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

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

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

• estimates on future lease obligations.

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

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

Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended March 31, 2019 and 2018, such internal costs capitalized totaled $1.6 million and $1.4 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 6 of these notes to condensed consolidated financial statements for further discussion on capitalized interest costs).

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

	March 31, 2019			December 31, 2018
Property and Equipment
Proved oil and gas properties	$	1,005,988		$	925,865
Unproved oil and gas properties	64,797			56,715
Furniture, fixtures and other equipment	3,668			3,520
Less – Accumulated depreciation, depletion, amortization & impairment	(306,609		)	(284,804		)
Property and Equipment, Net	$	767,844		$	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 properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved

9

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 March 31, 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 March 31, 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” balance on the accompanying condensed consolidated balance sheets.

At March 31, 2019, our “Accounts receivable” balance included $21.4 million for oil and gas sales, $4.5 million due from joint interest owners, $3.5 million for severance tax credit receivables and $1.9 million for other receivables. At December 31, 2018, our “Accounts receivable” 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 three months ended March 31, 2019 and 2018 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $1.3 million and $1.1 million for the three months ended March 31, 2019 and 2018, respectively.

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

Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent 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 March 31, 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 at both March 31, 2019 and December 31, 2018 for United States federal income taxes. Management has determined that it is not more likely than not that the Company will realize future cash benefits from its remaining federal carryover items and, accordingly, has taken a full valuation allowance to offset its tax assets. Tax expense associated with federal income taxes was fully offset by adjustments to the valuation allowance. We recognized $0.2

10

million for state income tax expense during the three months ended March 31, 2019. We did not recognize any state income tax expense during the three months ended March 31, 2018.

Revenue Recognition. Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. To comply with the new standard, 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 March 31, 2019 and 2018 (in thousands):

	Three Months Ended March 31, 2019		Three Months Ended March 31, 2018
Oil, natural gas and NGLs sales:
Oil	$	14,607	$	11,439
Natural gas	51,304		35,753
NGLs	6,154		5,560
Total	$	72,064	$	52,752

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

	March 31, 2019		December 31, 2018
Trade accounts payable	$	20,728	$	32,683
Accrued operating expenses	3,258		3,549
Accrued compensation costs	2,066		4,785
Asset retirement obligations – current portion	284		302
Accrued non-income based taxes	2,533		3,583
Accrued corporate and legal fees	335		534
Other payables	2,774		3,485
Total accounts payable and accrued liabilities	$	31,978	$	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 three months ended March 31, 2019, we purchased 11,076 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares.

New Accounting Pronouncements. In February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2016-02, which requires lessees to record most leases on the balance sheet. Under the new guidance, lease classification as either a finance lease or an operating lease will determine how lease-related revenue and expense are recognized. The guidance was effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company adopted this standard on January 1, 2019, using the modified retrospective transition approach. The Company has elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that allows an entity to carry forward historical accounting treatment for land easements on existing agreements upon adoption. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the Consolidated Balance Sheet and additionally we have elected to not account for lease and non-lease components separately.

11

As a result of adoption, the Company's 2019 opening balances for right-of-use assets and lease liabilities was $2.2 million, attributable to operating leases. The balance could increase during the year if the Company enters into new lease agreements. Adoption of this guidance did not result in a cumulative adjustment to retained earnings. 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 March 31, 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 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):

	March 31, 2019
Lease Costs included in the Condensed Consolidated Balance Sheets
Property, plant and equipment acquisitions - short-term leases	$	3,983
Property, plant and equipment acquisitions - operating leases	8
Total lease costs in property, plant and equipment additions	$	3,991

	Three Months Ended March 31, 2019
Lease Costs included in the Condensed Consolidated Statement of Operations
Lease operating costs - short-term leases	$	1,335
Lease operating costs - operating leases	54
General and administrative, net - operating leases	156
Total lease cost expensed	$	1,545

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

	Three Months Ended March 31, 2019
Weighted-average remaining lease term (in years)	4.2
Weighted-average discount rate	5.1	%

12

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

	March 31, 2019
2019 (remaining after March 31, 2019)	$	648
2020	841
2021	358
2022	36
2023	38
Thereafter	363
Total undiscounted lease payments	$	2,284
Present value adjustment	(253		)
Net operating lease liabilities	$	2,031

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

	Three Months Ended March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	203
Investing cash flows from operating leases	$	8

(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, unit awards 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 $1.7 million and $1.4 million for the three months ended March 31, 2019 and 2018, respectively. Capitalized share-based compensation was $0.2 million and $0.1 million for each of the three months ended March 31, 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.

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 March 31, 2019, we had $5.6 million of unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the three months ended March 31, 2019:

13

	Shares		Wtd. Avg. Exer. Price
Options outstanding, beginning of period	644,575		$	28.28
Options granted	—		$	—
Options forfeited	(4,197	)	$	26.96
Options expired	—		$	—
Options exercised	—		$	—
Options outstanding, end of period	640,378		$	28.29
Options exercisable, end of period	195,178		$	28.87

Our outstanding stock option awards atMarch 31, 2019 had $0.1 million of aggregate intrinsic value. At March 31, 2019, the weighted average remaining contract life of stock option awards outstanding was 6.9 years and exercisable was 3.5 years. The total intrinsic value of stock option awards exercisable had no value for the three months ended March 31, 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 March 31, 2019, we had unrecognized compensation expense of $6.4 million related to our restricted stock units which is expected to be recognized over a weighted-average period of 2.4 years.

The following table provides information regarding restricted stock unit award activity for the three months ended March 31, 2019:

	Shares		Grant Date Price
Restricted stock units outstanding, beginning of period	340,678		$	27.64
Restricted stock units granted	62,650		$	22.34
Restricted stock units forfeited	(8,044	)	$	27.47
Restricted stock units vested	(61,263	)	$	27.07
Restricted stock units outstanding, end of period	334,021		$	26.76

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 ("Peer Group") during the performance period from January 1, 2018 to December 31, 2020 ("Performance Period"). 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 stock price. The remaining performance period as of March 31, 2019 is 1.9 years. 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.

As of March 31, 2019, we had unrecognized compensation expense of $0.8 million related to our performance-based stock units based on the assumption of 100% target payout. No shares vested during the three months ended March 31, 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

14

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 March 31, 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 March 31, 2019					Three Months Ended March 31, 2018
	Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)		Shares	Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	16,053	11,708	$	1.37	$	8,466	11,602	$	0.73
Dilutive Securities:
Restricted Stock Awards			—					—
Restricted Stock Unit Awards			80					18
Stock Option Awards			—					107
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	16,053	11,788	$	1.36	$	8,466	11,727	$	0.72

Approximately 0.6 million and 0.4 million stock options to purchase shares were not included in the computation of Diluted EPS for the three months ended March 31, 2019 and 2018, respectively, because these stock options were antidilutive.

Less than 0.1 million and approximately 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 the three months ended March 31, 2019 and 2018, respectively, because they were antidilutive.

Less than 0.1 million shares of performance-based restricted stock units were not included in the computation of Diluted EPS for the three months ended March 31, 2019 and 2018 because they were antidilutive.

Approximately 4.3 million warrants to purchase common stock were not included in the computation of Diluted EPS for both the three months ended March 31, 2019 and 2018 because these warrants were antidilutive.

(6)          Long-Term Debt

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

	March 31, 2019			December 31, 2018
Credit Facility Borrowings (1)	$	231,000		$	195,000
Second Lien Notes due 2024	200,000			200,000
	431,000			395,000
Unamortized discount on Second Lien Notes due 2024	(1,726		)	(1,782		)
Unamortized debt issuance cost on Second Lien Notes due 2024	(5,067		)	(5,230		)
Long-Term Debt, net	$	424,207		$	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 March 31, 2019 and December 31, 2018, we had $4.1 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 $231.0 million and $195.0 million as of March 31, 2019 and December 31, 2018, respectively. On April 19, 2017, the Company entered into a First Amended and Restated Senior Secured Revolving Credit Agreement among the Company, as borrower, JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended, including the Fourth Amendment effective November 6, 2018 (the “Fourth Amendment to Credit Agreement”) to the First Amended and Restated Senior Secured Credit Agreement (as so amended, the “Credit Agreement” and such facility, the “Credit Facility”). The Fourth Amendment to

15

Credit Agreement increased the borrowing base from $330 million to $410 million and decreased the applicable margins used to calculate the interest rate under the Credit Agreement by 25 basis points.

The Credit Facility matures April 19, 2022, and provides for a maximum credit amount of $600 million and a current borrowing base of $410 million. The borrowing base is regularly redetermined on or about May and November of each calendar year and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, each of the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders, in their discretion, in accordance with their oil and gas lending criteria at the time of the relevant redetermination. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to $25 million, which reduce 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 Rates are defined, and the applicable margins are set forth, in the Credit Agreement. Undrawn amounts under the Credit Facility are subject to a 0.50% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto.

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

The Credit Agreement contains the following financial covenants:

• a ratio of total debt to 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 March 31, 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 $3.5 million and $1.5 million for the three months ended March 31, 2019 and 2018, respectively.

We capitalized interest on our unproved properties in the amount of $0.1 million and $0.4 million for the three months ended March 31, 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 (the “Second Lien Agent”), and certain holders that are a party thereto, and issued notes in an initial principal amount of $200 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 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.

16

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 twenty-four month anniversary of the issuance of the Second Lien, discounted at a rate equal to the Treasury Rate plus 50 basis points) plus 2.0% of the principal amount of the notes repaid; during year three, 2.0% of the principal amount of the Second Lien being prepaid; during year four, 1.0% of the principal amount of the Second Lien being prepaid; and thereafter, no premium. Additionally, the Second Lien contains customary mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and incurrences of certain debt, subject to, in certain circumstances, reinvestment periods. Management believes the probability of mandatory prepayment due to default is remote.

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

The Second Lien contains an Asset Coverage Ratio, which is only tested (i) as a condition to issuance of additional notes and (ii) in connection with certain asset sales in order to determine whether the proceeds of such asset sale must be applied as a prepayment of the notes and includes in the numerator 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 Requirement”). 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 Second Lien 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 March 31, 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 March 31, 2019, total net amounts recorded for the Second Lien were $193.2 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $5.3 million and $4.7 million for the three months ended March 31, 2019 and 2018, respectively.

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

(7)           Acquisitions and Dispositions

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

Effective December 22, 2017, the Company closed a Purchase and Sale contract to sell the Company's wellbores and facilities in Bay De Chene and recorded a $16.3 million obligation related to the funding of certain plugging and abandonment

17

costs. Of the $16.3 million original obligation, $1.3 million was paid during the three months ended March 31, 2019. The remaining obligation under this contract is $6.2 million and is carried in the accompanying condensed consolidated balance sheet current liability in “Accounts payable and accrued liabilities” as of March 31, 2019.

There were no material acquisitions or dispositions of developed properties during the three months ended March 31, 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 "Net gain (loss) on commodity derivatives" 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 March 31, 2019 and 2018, the Company recorded losses of $4.0 million and $6.4 million, respectively, on its commodity derivatives. The Company collected cash payments of $1.1 million and $1.0 million for settled derivative contracts during the three months ended March 31, 2019 and 2018, respectively.

At March 31, 2019, there were $1.0 million 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 April 2019 and January 2019, respectively. At March 31, 2019 and December 31, 2018, we also had $0.2 million and $2.2 million, respectively, in payables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts payable and accrued liabilities” and were subsequently paid in April 2019 and January 2019, respectively.

The fair values of our swap contracts are computed using observable market data while our collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. At March 31, 2019, there was $8.3 million and $4.0 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $4.6 million and $2.2 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 $5.6 million net fair value asset at March 31, 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.

18

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

Oil Derivative Swaps (NYMEX WTI Settlements)	Total Volumes (Bbls)	Weighted Average Price
2019 Contracts
2Q19	157,450	$	57.30
3Q19	176,500	$	57.98
4Q19	172,500	$	58.07
2020 Contracts
1Q20	149,300	$	57.32
2Q20	100,350	$	56.38
3Q20	97,200	$	56.49
4Q20	72,000	$	52.29
2021 Contracts
1Q21	56,175	$	55.23

Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted Average Price		Weighted Average Collar Floor		Weighted Average Collar Call Price
2019 Contracts
2Q19	12,130,000	$	2.80
3Q19	12,680,000	$	2.81
4Q19	11,486,000	$	2.89
2020 Contracts
1Q20	6,280,000	$	2.87
2Q20	3,688,000	$	2.76
3Q20	3,585,000	$	2.76
4Q20	3,362,000	$	2.77
Collar Contracts
2019 Contracts
2Q19	300,000			$	2.90	$	3.15
2021 Contracts
1Q21	4,354,800			$	2.50	$	3.52

NGL Contracts	Total Volumes (Bbls)	Weighted Average Price
2019 Contracts
2Q19	180,000	$	27.93
3Q19	180,000	$	27.93
4Q19	180,000	$	27.93

19

Natural Gas Basis Derivative Swap (East Texas Houston Ship Channel vs NYMEX Settlements)	Total Volumes (MMBtu)	Weighted Average Price
2019 Contracts
2Q19	14,477,500	$	0.05
3Q19	14,625,000	$	0.04
4Q19	14,625,000	$	(0.02	)
2020 Contracts
1Q20	11,739,000	$	(0.03	)
2Q20	11,739,000	$	(0.04	)
3Q20	11,868,000	$	(0.03	)
4Q20	11,868,000	$	(0.04	)
2021 Contracts
1Q21	7,200,000	$	(0.003	)
2Q21	7,280,000	$	(0.003	)
3Q21	7,360,000	$	(0.003	)
4Q21	7,360,000	$	(0.003	)

Oil Basis Contracts (Argus Cushing (WTI) and LLS Settlements)	Total Volumes (Bbls)	Weighted Average Price
2019 Contracts
2Q19	45,000	$	4.65
3Q19	45,000	$	4.65
4Q19	45,000	$	4.65

(9)           Fair Value Measurements

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

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

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

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

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

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

20

The following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of March 31, 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)
March 31, 2019
Assets
Natural Gas Derivatives	$	3.2	$	—	$	3.2	$	—
Natural Gas Basis Derivatives	$	4.3	$	—	$	4.3	$	—
Oil Derivatives	$	1.8	$	—	$	1.8	$	—
NGL Derivatives	$	3.1	$	—	$	3.1	$	—
Liabilities
Natural Gas Derivatives	$	1.8	$	—	$	1.8	$	—
Natural Gas Basis Derivatives	$	0.8	$	—	$	0.8	$	—
Oil Derivatives	$	4.1	$	—	$	4.1	$	—
Oil Basis Derivatives	$	0.1	$	—	$	0.1	$	—
December 31, 2018
Assets
Natural Gas Derivatives	$	7.5	$	—	$	7.5	$	—
Natural Gas Basis Derivatives	$	0.4	$	—	$	0.4	$	—
Oil Derivatives	$	6.9	$	—	$	6.9	$	—
NGL Derivatives	$	4.7	$	—	$	4.7	$	—
Liabilities
Natural Gas Derivatives	$	1.0	$	—	$	1.0	$	—
Natural Gas Basis Derivatives	$	5.3	$	—	$	5.3	$	—
NGL Derivatives	$	0.2	$	—	$	0.2	$	—

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.

21

The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2018 and the three months ended March 31, 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	83
Liabilities incurred for new wells and facilities construction	39
Reductions due to sold wells and facilities	—
Reductions due to plugged wells and facilities	(30		)
Revisions in estimates	6
Asset Retirement Obligations as of March 31, 2019	$	4,357

At both March 31, 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 operator of oil and natural gas wells. In 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. There have been no material changes to the Company's contractual obligations described in our 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 Topic 840. As discussed in Note 3 above, the Company adopted the guidance of Topic 842 effective January 1, 2019.

22

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 31 of this report.

Company Overview

SilverBow Resources is a growth oriented independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford Shale located in South Texas where it has assembled over 100,000 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 three months ended March 31, 2019 increased 34% from the three months ended March 31, 2018 to 215 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 three months ended March 31, 2019 was 6,392 Boe/d, an increase of 35% from the three months ended March 31, 2018, primarily driven by drilling in the La Salle Condensate area and McMullen Oil area.

During the first quarter, the Company drilled 11 gross (10 net) wells while completing eight gross (seven net) wells and bringing five gross (four net) wells online. In the Webb County Gas area, the Company completed a net two-well pad in the quarter, with one of the wells drilled in 2018. While it is early in the life of these wells, performance is in line with expectations. The Company drilled seven net wells and completed a net three-well pad in the La Salle Condensate area, with those wells being brought online in early March. In the Southern Eagle Ford Gas area, the Company drilled and completed a net two-well pad, with both wells being brought online in late April. After drilling a net two-well pad in the McMullen Oil area in the fourth quarter of 2018, the Company completed both wells, which exceeded 11,000 lateral feet with approximately 2,400 pounds of proppant per foot and 50 barrels of fluid per foot of lateral in the first quarter. These two wells came online early in the second quarter and combined have shown initial production rates of over 2,400 Boe/d. These results further support the Company's enthusiasm for new generation infill development on our legacy, liquids-rich acreage.

The Company ran two drilling rigs for most of the first quarter, but has recently stepped down to one super-spec drilling rig for the remainder of the year which will focus on the liquids-rich areas in McMullen and La Salle Counties. For the full-year, the Company expects to drill 26-27 net wells and complete 30-32 net wells with the majority of the completions occurring in the first half of the year given the nature of pad drilling.

The Company continues to strategically employ fit-for-purpose completion techniques across its portfolio. The Company utilized hybrid designs on the majority of the wells completed in the first quarter. Overall, the Company averaged a completion intensity of approximately 2,400 pounds of proppant and 50 barrels of fluid per foot of lateral. The Company continues to assess the performance of its completion designs, modifying them according to reservoir fluid system and class of well, parent or infill. The Company also continues to drive efficiencies into its operations as demonstrated by pumping 363 stages in 54 days, or just under seven stages per day, which represents a 39% increase over similar jobs compared to the prior quarter. Furthermore, the Company brought on two frac spreads in early March which were able to reduce cycle times and thereby accelerate production. Accordingly, the Company expects to see a significant increase in production in the second quarter over its first quarter results.

2019 cost reduction initiatives: The Company continues to focus on cost reduction measures and took additional actions in the first three months of 2019 to reduce operating and overhead costs. These initiatives included field staff reductions, the use of regional sand in completions, improved utilization of existing facilities, elimination of redundant equipment, and replacement of rental equipment with company-owned equipment. As previously mentioned, the Company continues to improve its process for drilling and completing wells. The Company's procurement team takes a process-oriented approach to reducing the total

23

delivered costs of purchased services by examining costs at their most detailed level. Services are commonly sourced directly from the suppliers, which has led to a significant reduction in the Company's overall lease operating expenses at the field level. For example, the Company's South Texas lease operating expenses were $0.27/Mcfe for the first three months of 2019 which compared to $0.34/Mcfe for the same period in 2018.

Additionally, the Company's significant operational control and manageable leasehold obligations provide the Company with the flexibility to control its costs as it transitions to a development mode across its portfolio. At the corporate level, the Company has also undergone additional work-flow optimizations and is taking additional steps to further reduce its overhead costs. These actions have led to cash general and administrative costs of $4.6 million (a non-GAAP financial measure calculated as $6.3 million in net general and administrative costs less $1.7 million of share based compensation) for the first three months of 2019 or $0.24 per Mcfe, compared to $4.2 million (a non-GAAP financial measure calculated as $5.6 million in net general and administrative costs less $1.4 million of share based compensation), or $0.29/Mcfe, for the three months ended March 31, 2018.

Liquidity and Capital Resources

The Company's primary use of cash has been to fund capital expenditures to develop its oil and gas properties. As of March 31, 2019, the Company’s liquidity consisted of approximately $0.9 million of cash-on-hand and $179 million in available borrowings on the Credit Facility which has a $410 million borrowing base. Management believes the Company has sufficient liquidity to meet its obligations for at least the next twelve 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

There were no material changes in the Company's contractual commitments during the three months ended March 31, 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 March 31, 2019, we had no off-balance sheet arrangements requiring disclosure pursuant to article 303(a) of Regulation S-K.

24

Summary of 2019 Financial Results

• Revenues and net income (loss):The Company's oil and gas revenues were $72.1 million for the three months ended March 31, 2019, compared to $52.8 million for the three months ended March 31, 2018. Revenues were higher primarily due to overall increased production as well as higher natural gas pricing, partially offset by lower oil and NGL pricing. The Company's net income was $16.1 million for the three months ended March 31, 2019, compared to $8.5 million for the three months ended March 31, 2018. The increase was primarily due to overall increased production during the current period compared to the prior period, partially offset by lower oil and NGL pricing.

• Capital expenditures:The Company's capital expenditures on an accrual basis were $88.3 million for the three months ended March 31, 2019 compared to $44.9 million for the three months ended March 31, 2018. The expenditures for the three months ended March 31, 2019 were primarily driven by continued legacy development and Southern Eagle Ford gas window delineation, while expenditures for the three months ended March 31, 2018, were primarily driven by development activity in our Fasken and Oro Grande fields.

• Working capital: The Company had a working capital deficit of $53.9 million at March 31, 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 three months ended March 31, 2019, the Company generated cash from operating activities of $50.6 million, of which $5.2 million was attributable to changes in working capital. Cash used for property additions was $86.6 million. This excluded $1.5 million attributable to a net increase of capital related payables and accrued costs. Additionally, $1.3 million was paid during the three months ended March 31, 2019, for property sale obligations related to the sale of our former Bay De Chene field. The Company’s net borrowings on the revolving Credit Facility were $36.0 million during the three months ended March 31, 2019.

For the three months ended March 31, 2018, the Company generated cash from operating activities of $25.2 million, of which $5.3 million was attributable to changes in working capital. Cash used for property additions was $33.8 million. This excluded $12.2 million attributable to a net increase of capital related payables and accrued costs. Additionally, $6.0 million was paid during the three months ended March 31, 2018 for property sale obligations related to the sale of our former Bay De Chene field. The Company’s net payments on the revolving Credit Facility were $20.0 million, which includes the pay down on Credit Facility borrowings with proceeds from our AWP Olmos sale.

25

Results of Operations

Revenues — Three Months Ended March 31, 2019 and Three Months Ended March 31, 2018

Natural gas production was 82% of the Company's production volumes for both of the three months ended March 31, 2019 and 2018. Natural gas sales were 71% and 68% of oil and gas sales for the three months ended March 31, 2019 and 2018, respectively.

Crude oil production was 8% and 7% of the Company's production volumes for the three months ended March 31, 2019 and 2018, respectively. Crude oil sales were 20% and 22% of oil and gas sales for the three months ended March 31, 2019 and 2018, respectively.

NGL production was 10% and 11% of the Company's production volumes for the three months ended March 31, 2019 and 2018, respectively. NGL sales were 9% and 11% of oil and gas sales for the three months ended March 31, 2019 and 2018, respectively.

The following tables provide 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 March 31, 2019 and 2018:

Fields	Three Months Ended March 31, 2019			Three Months Ended March 31, 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	$	13.1	3,056	$	12.4	2,524
AWP	16.1		3,019	12.0		2,452
Fasken	25.4		7,832	23.7		7,988
Other (1)	17.5		5,452	4.7		1,505
Total	$	72.1	19,359	$	52.8	14,469

(1) Primarily composed of the Company's Oro Grande and Uno Mas fields.

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

In the first quarter of 2019, our $19.3 million, or 37%increase, in oil, NGL and natural gas sales from the prior year period resulted from:

• Price variances that had an approximate $0.6 millionfavorable impact on sales due to the higher natural gas pricing, partially offset by lower oil and NGL pricing; and

• Volume variances that had an $18.7 millionfavorable impact on sales due to overall increased commodity production.

26

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 March 31, 2019 and 2018 (in thousands, except per-dollar amounts):

	Three Months Ended March 31, 2019			Three Months Ended March 31, 2018
Production volumes:
Oil (MBbl) (1)	257			177
Natural gas (MMcf)	15,907			11,917
Natural gas liquids (MBbl) (1)	319			248
Total (MMcfe)	19,359			14,469
Oil, Natural gas and Natural gas liquids sales:
Oil	$	14,607		$	11,439
Natural gas	51,304			35,753
Natural gas liquids	6,154			5,560
Total	$	72,064		$	52,752
Average realized price:
Oil (per Bbl)	$	56.94		$	64.59
Natural gas (per Mcf)	3.22			3.00
Natural gas liquids (per Bbl)	19.30			22.39
Average per Mcfe	$	3.72		$	3.65
Price impact of cash-settled derivatives:
Oil (per Bbl)	$	(0.48	)	$	(8.36	)
Natural gas (per Mcf)	0.02			0.20
Natural gas liquids (per Bbl)	2.73			(0.76		)
Average per Mcfe	$	0.05		$	0.05
Average realized price including cash settled derivatives:
Oil (per Bbl)	$	56.46		$	56.22
Natural gas (per Mcf)	3.24			3.20
Natural gas liquids (per Bbl)	22.03			21.63
Average per Mcfe	$	3.78		$	3.70

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

For the three months ended March 31, 2019 and 2018, the Company recorded net losses of $4.0 million and $6.4 million from our derivative activities, respectively. Hedging activity is recorded in “Net gain (loss) on commodity derivatives” on the accompanying condensed consolidated statements of operations.

27

Costs and Expenses — Three Months Ended March 31, 2019 and Three Months Ended March 31, 2018

The following table provides additional information regarding our expenses for the three months ended March 31, 2019 and 2018:

Costs and Expenses	Three Months Ended March 31, 2019		Three Months Ended March 31, 2018
General and administrative, net	$	6,276	$	5,576
Depreciation, depletion, and amortization	21,805		13,131
Accretion of asset retirement obligations	83		159
Lease operating cost	4,531		4,961
Workovers	646		—
Transportation and gas processing	6,406		5,025
Severance and other taxes	3,316		3,031
Interest expense, net	8,759		5,890

General and Administrative Expenses, Net. These expenses on a per Mcfe basis were $0.32 and $0.39 for the three months ended March 31, 2019 and 2018, respectively. The decrease per Mcfe was due to higher production while the increase in costs were primarily due to higher temporary labor, higher salaries and burdens and higher computer operation expenses. Included in general and administrative expenses is $1.7 million and $1.4 million in share based compensation for the three months ended March 31, 2019 and 2018, respectively.

Depreciation, Depletion and Amortization (“DD&A”). These expenses on a per Mcfe basis were $1.13 and $0.91 for the three months ended March 31, 2019 and 2018, respectively. The increase in the rate per unit is primarily due to a higher depletable base relative to reserves. The higher depletion expense is due to a higher production and a higher per unit rate.

Lease operating cost. These expenses on a per Mcfe basis were $0.27 and $0.34 for the three months ended March 31, 2019 and 2018, respectively. The decrease per Mcfe was primarily due to divestitures of assets and a concentrated effort by the Company to reduce overall operating costs, along with higher production.

Transportation and gas processing. These expenses are related to natural gas and NGL sales. These expenses on a per Mcfe basis were $0.33 and $0.35 for the three months ended March 31, 2019 and 2018, respectively.

Severance and Other Taxes. These expenses on a per Mcfe basis were $0.17 and $0.21 for the three months ended March 31, 2019 and 2018, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 4.6% and 5.7% for the three months ended March 31, 2019 and 2018, respectively.

Interest. Our gross interest cost was $8.9 million and $6.3 million for the three months ended March 31, 2019 and 2018, respectively. The increase in gross interest cost is primarily due to increased Credit Facility borrowings. Interest cost of $0.1 million and $0.4 million was capitalized for the three months ended March 31, 2019 and 2018.

Income Taxes. There was no expense for federal income taxes in each of the three months ended March 31, 2019 and 2018 as the Company had significant deferred tax assets in excess of deferred tax liabilities. Because management has determined that it is not more likely than not that the Company will realize future cash benefits from its remaining federal carryover items, the Company has carried a full valuation allowance against its Federal net deferred tax asset balance. Federal tax expense for income related to these periods was offset by reductions in our valuation allowance. We recognized $0.2 million for state income tax expense during the three months ended March 31, 2019. There was no state income tax expense recorded for the three months ended March 31, 2018.

28

Non-GAAP Financial Measures

Adjusted EBITDA

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

Plus/(Less):

• Depreciation, depletion, amortization;

• Accretion of asset retirement obligations;

• Interest expense;

• Impairment of oil and natural gas properties;

• Net losses (gains) on commodity derivative contracts;

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

• Income tax expense (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 March 31, 2019		Three Months Ended March 31, 2018
Net Income (Loss)	$	16,053	$	8,466
Plus:
Depreciation, depletion and amortization	21,805		13,131
Accretion of asset retirement obligations	83		159
Interest expense	8,759		5,890
Derivative (gain)/loss	4,022		6,355
Derivative cash settlements collected/(paid) (1)	1,047		735
Income tax expense/(benefit)	232		—
Share-based compensation expense	1,692		1,359
Adjusted EBITDA	$	53,693	$	36,095
(1) This includes accruals for settled contracts covering commodity deliveries during the period where the actual cash settlements occur outside of the period.

29

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.

30

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 and our annual report on Form 10-K for the year ended December 31, 2018.

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

31

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.

32

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 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 March 31, 2019, we had a combined $431.0 million drawn under our Credit Facility and our Second Lien, which bear floating rates of interest depending on the level of the borrowing base and the borrowing base loans outstanding 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 March 31, 2019 would increase our annual interest expense by $4.3 million.

33

Item 4. Controls and Procedures

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. Our Chief Executive Officer and Chief Financial Officer have evaluated such disclosure controls and procedures as of the end of the period covered by this quarterly report on Form 10-Q and have determined that such disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the three months ended March 31, 2019, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

34

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.

There have been no material changes in our risk factors disclosed in the 2018 Annual Report on Form 10-K.

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.

35

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.

36

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:	May 9, 2019	By:	/s/ G. Gleeson Van Riet
			G. Gleeson Van Riet Executive Vice President and Chief Financial Officer
Date:	May 9, 2019	By:	/s/ Gary G. Buchta
			Gary G. Buchta Controller

37