SILVERBOW RESOURCES, INC. (Form: 10-Q, Received: 11/04/2021 16:11:39)

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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 September 30, 2021

Commission File Number 1-8754

SILVERBOW RESOURCES, INC.

(Exact Name of Registrant as Specified in Its Charter)


Delaware			20-3940661
(State of Incorporation)			(I.R.S. Employer Identification No.)

920 Memorial City Way, Suite 850

Houston, Texas 77024

(281) 874-2700

(Address and telephone number of principal executive offices)

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


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

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


Yes			þ			No			o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).


Yes			þ			No			o

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

Large Accelerated Filer

Accelerated Filer

Non-Accelerated Filer

Smaller Reporting Company

Emerging Growth Company

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

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


Yes			þ			No			o

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

of common stock, as of the latest practicable date.


Common Stock ($.01 Par Value) (Class of Stock)			14,726,605 Shares outstanding at October 29, 2021

SILVERBOW RESOURCES, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2021

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	7

	Condensed Consolidated Statements of Cash Flows	8

	Notes to Condensed Consolidated Financial Statements	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38

Item 4.	Controls and Procedures	39

Part II	OTHER INFORMATION

Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 3.	Defaults Upon Senior Securities	40
Item 4.	Mine Safety Disclosures	40
Item 5.	Other Information	40
Item 6.	Exhibits	40

SIGNATURES		42

Table of Contents

PART I. FINANCIAL INFORMATION

Condensed Consolidated Balance Sheets (Unaudited)

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


	September 30, 2021		December 31, 2020

ASSETS
Current Assets:
Cash and cash equivalents	$	988	$	2,118
Accounts receivable, net	44,190		25,850
Fair value of commodity derivatives	668		4,821

Other current assets	4,016		2,184
Total Current Assets	49,862		34,973
Property and Equipment:
Property and equipment, full cost method, including $24,988 and $28,090, respectively, of unproved property costs not being amortized at the end of each period	1,476,586		1,343,373
Less – Accumulated depreciation, depletion, amortization & impairment	(846,822)		(801,279)
Property and Equipment, Net	629,764		542,094
Right of Use Assets	15,787		4,366
Fair Value of Long-Term Commodity Derivatives	18		281

Other Long-Term Assets	2,904		1,421
Total Assets	$	698,335	$	583,135
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	38,000	$	26,991
Fair value of commodity derivatives	94,778		8,171
Accrued capital costs	20,482		7,324
Accrued interest	846		983
Current lease liability	6,292		3,473
Undistributed oil and gas revenues	17,328		11,098

Total Current Liabilities	177,726		58,040
Long-Term Debt, Net	393,726		424,905
Non-Current Lease Liability	9,723		951
Deferred Tax Liabilities	303		303
Asset Retirement Obligations	4,706		4,533
Fair Value of Long-Term Commodity Derivatives	21,989		2,946
Other Long-Term Liabilities	846		424
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, 13,576,285 and 12,053,763 shares issued, respectively, and 13,384,615 and 11,936,679 shares outstanding, respectively	136		121
Additional paid-in capital	324,106		297,712
Treasury stock, held at cost, 191,670 and 117,084 shares, respectively	(2,984)		(2,372)
Accumulated deficit	(231,942)		(204,428)
Total Stockholders’ Equity	89,316		91,033
Total Liabilities and Stockholders’ Equity	$	698,335	$	583,135
See accompanying Notes to Condensed Consolidated Financial Statements.

Table of Contents

Condensed Consolidated Statements of Operations (Unaudited)

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


	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020
Revenues:
Oil and gas sales	$	99,249	$	45,699

Operating Expenses:
General and administrative, net	5,257		5,833
Depreciation, depletion, and amortization	16,054		13,975
Accretion of asset retirement obligations	77		90
Lease operating expenses	6,978		5,211
Workovers	423		8
Transportation and gas processing	5,913		5,094
Severance and other taxes	4,908		2,512

Total Operating Expenses	39,610		32,723

Operating Income	59,639		12,976

Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net	(88,554)		(12,944)
Interest expense, net	(7,433)		(7,444)
Other income (expense), net	(3)		(56)

Income (Loss) Before Income Taxes	(36,351)		(7,468)

Provision (Benefit) for Income Taxes	(408)		(572)

Net Income (Loss)	$	(35,943)	$	(6,896)

Per Share Amounts:

Basic Earnings (Loss) Per Share	$	(2.85)	$	(0.58)

Diluted Earnings (Loss) Per Share	$	(2.85)	$	(0.58)

Weighted-Average Shares Outstanding - Basic	12,629		11,935

Weighted-Average Shares Outstanding - Diluted	12,629		11,935

See accompanying Notes to Condensed Consolidated Financial Statements.

Table of Contents

Condensed Consolidated Statements of Operations (Unaudited)

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


	Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
Revenues:
Oil and gas sales	$	255,850	$	123,921

Operating Expenses:
General and administrative, net	14,872		17,926
Depreciation, depletion, and amortization	45,485		51,130
Accretion of asset retirement obligations	226		263
Lease operating expenses	18,767		16,023
Workovers	512		8
Transportation and gas processing	17,175		16,291
Severance and other taxes	11,974		7,513
Write-down of oil and gas properties	—		355,948
Total Operating Expenses	109,011		465,102

Operating Income (Loss)	146,839		(341,181)

Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net	(152,879)		66,884
Interest expense, net	(21,888)		(23,876)
Other income (expense), net	6		50

Income (Loss) Before Income Taxes	(27,922)		(298,123)

Provision (Benefit) for Income Taxes	(408)		20,607

Net Income (Loss)	$	(27,514)	$	(318,730)

Per Share Amounts:

Basic Earnings (Loss) Per Share	$	(2.24)	$	(26.81)

Diluted Earnings (Loss) Per Share	$	(2.24)	$	(26.81)

Weighted-Average Shares Outstanding - Basic	12,283		11,890

Weighted-Average Shares Outstanding - Diluted	12,283		11,890

See accompanying Notes to Condensed Consolidated Financial Statements.

Table of Contents

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

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


	Common Stock		Additional Paid-In Capital		Treasury Stock		Retained Earnings (Accumulated Deficit)		Total
Balance, December 31, 2019	$	119	$	292,916	$	(2,282)	$	104,954	$	395,707

Purchase of treasury shares (26,675 shares)	—		—		(83)		—		(83)

Vesting of share-based compensation (105,108 shares)	1		(1)		—		—		—
Share-based compensation	—		1,335		—		—		1,335
Net Loss	—		—		—		(5,858)		(5,858)
Balance, March 31, 2020	$	120	$	294,250	$	(2,365)	$	99,096	$	391,101
Shares issued from warrant exercise (5 shares)	—		—		—		—		—
Purchase of treasury shares (1,098 shares)	—		—		(3)		—		(3)
Vesting of share-based compensation (49,665 shares)	—		—		—		—		—
Share-based compensation	—		1,229		—		—		1,229
Net Loss	—		—		—		(305,976)		(305,976)
Balance, June 30, 2020	$	120	$	295,479	$	(2,368)	$	(206,880)	$	86,351
Purchase of treasury shares (958 shares)	—		—		(4)		—		(4)
Vesting of share-based compensation (3,953 shares)	1		—		—		—		1
Share-based compensation	—		1,150		—		—		1,150
Net Loss	—		—		—		(6,896)		(6,896)
Balance, September 30, 2020	$	121	$	296,629	$	(2,372)	$	(213,776)	$	80,602

Balance, December 31, 2020	$	121	$	297,712	$	(2,372)	$	(204,428)	$	91,033

Purchase of treasury shares (60,177 shares)	—		—		(488)		—		(488)

Vesting of share-based compensation (283,113 shares)	2		(2)		—		—		—
Share-based compensation	—		1,131		—		—		1,131
Net Income	—		—		—		28,380		28,380
Balance, March 31, 2021	$	123	$	298,841	$	(2,860)	$	(176,048)	$	120,056
Purchase of treasury shares (13,969 shares)	—		—		(115)		—		(115)
Vesting of share-based compensation (51,332 shares)	1		(1)		—		—		—

Share-based compensation	—		1,248		—		—		1,248
Net Loss	—		—		—		(19,951)		(19,951)
Balance, June 30, 2021	$	124	$	300,088	$	(2,975)	$	(195,999)	$	101,238
Purchase of treasury shares (440 shares)	—		—		(9)		—		(9)
Vesting of share-based compensation (1,802 shares)	—		—		—		—		—
Issuance of common stock (669,600 shares)	7		12,749		—		—		12,756
Issuance pursuant to acquisition (516,675 shares)	5		10,018		—		—		10,023
Share-based compensation	—		1,251		—		—		1,251
Net Loss	—		—		—		(35,943)		(35,943)
Balance, September 30, 2021	$	136	$	324,106	$	(2,984)	$	(231,942)	$	89,316
See accompanying Notes to Condensed Consolidated Financial Statements.

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Condensed Consolidated Statements of Cash Flows (Unaudited)

SilverBow Resources, Inc. and Subsidiary (in thousands)


	Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
Cash Flows from Operating Activities:
Net income (loss)	$	(27,514)	$	(318,730)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	45,485		51,130
Write-down of oil and gas properties	—		355,948
Accretion of asset retirement obligations	226		263
Deferred income taxes	—		21,087
Share-based compensation	3,450		3,503
(Gain) Loss on derivatives, net	152,879		(66,884)
Cash settlement (paid) received on derivatives	(28,976)		76,150
Settlements of asset retirement obligations	(151)		(27)
Write down of debt issuance cost	229		459
Other	1,883		2,436
Change in operating assets and liabilities:
(Increase) decrease in accounts receivable and other current assets	(20,941)		7,413
Increase (decrease) in accounts payable and accrued liabilities	7,215		(3,981)
Increase (decrease) in income taxes payable	—		(480)
Increase (decrease) in accrued interest	(137)		(505)
Net Cash Provided by (Used in) Operating Activities	133,648		127,782
Cash Flows from Investing Activities:
Additions to property and equipment	(98,219)		(102,713)
Acquisition of oil and gas properties	(13,219)		(3,441)
Proceeds from the sale of property and equipment	—		4,752
Payments on property sale obligations	(1,084)		(426)


Net Cash Provided by (Used in) Investing Activities	(112,522)		(101,828)
Cash Flows from Financing Activities:

Proceeds from bank borrowings	195,000		71,000
Payments of bank borrowings	(227,000)		(97,000)
Net proceeds from issuances of common stock	12,756		—
Purchase of treasury shares	(612)		(90)
Payments of debt issuance costs	(2,400)		—
Net Cash Provided by (Used in) Financing Activities	(22,256)		(26,090)
Net Increase (Decrease) in Cash and Cash Equivalents	(1,130)		(136)
Cash and Cash Equivalents at Beginning of Period	2,118		1,358
Cash and Cash Equivalents at End of Period	$	988	$	1,222
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for interest, net of amounts capitalized	$	20,277	$	22,290

Non-cash Investing and Financing Activities:
Changes in capital accounts payable and capital accruals	$	11,393	$	(25,641)
Non-cash equity consideration for acquisitions	$	(10,023)	$	—

See accompanying Notes to Condensed Consolidated Financial Statements.

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Notes to Condensed Consolidated Financial Statements (Unaudited)

SilverBow Resources, Inc. and Subsidiary

(1) General Information

SilverBow Resources, Inc. (“SilverBow,” the “Company,” or “we”) is an independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford and Austin Chalk 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 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, 2020.

(2) Summary of Significant Accounting Policies

Basis of Presentation. The condensed consolidated financial statements included herein 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 subsidiary, SilverBow Resources Operating LLC, which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on oil and natural gas reserves in the Eagle Ford trend in Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of the assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying condensed consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying condensed consolidated financial statements.

COVID-19. The spread of COVID-19 and its impact on the global supply of and demand for crude oil caused volatility in the market price for crude oil during 2020. The spot price of West Texas Intermediate (“WTI”) crude oil declined over 50% in March and April of 2020 before gradually improving through the rest of 2020 and through the first three quarters of 2021. The spot price of Brent and WTI crude oil closed at approximately $64 and $59 per barrel, respectively, on March 31, 2021, approximately $77 and $74 per barrel, respectively, on June 30, 2021, and approximately $78 and $75 per barrel, respectively, on September 30, 2021.

In response to these market conditions, including the COVID-19 pandemic and the volatility in oil prices during 2020, the Company released its sole drilling rig in April 2020 and deferred the completion and placement on production of eight wells until the second half of 2020. In the third quarter of 2020, the Company restarted completions activity and returned to sales all previously curtailed volumes as of December 31, 2020.

As a result of the COVID-19 pandemic, the Company operated under a “work from home” policy applicable to all employees other than essential personnel whose physical presence was required either in the office or in the field until March 2021. Effective March 2021, the Company adjusted its “work from home” policy to a flexible work schedule, so that all employees returned to the corporate office, on a weekly rotation, while continuing to work from home. Except as described above regarding the curtailment of production in 2020, SilverBow has not experienced any material interruption to its ordinary course business processes as a result of the COVID-19 pandemic and the volatility in oil and gas prices. The Company will continue to monitor the COVID-19 situation and follow the advice of government and health leaders.

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

On October 1, 2021, we closed on an all-stock transaction to acquire oil and gas assets in the Eagle Ford. The acquired assets include a 100% working interest in approximately 15,000 net oil-weighted acres across Atascosa, Fayette and Lavaca counties, as well as approximately 26,000 net gas-weighted acres directly offsetting our existing position in McMullen and Live Oak counties. After consideration of closing adjustments, we issued 1,341,990 shares of our common stock for an aggregate

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purchase price of $35.6 million, based on the Company's share price on the closing date. The acquisition is subject to further customary post-closing adjustments. The issuance of the shares of common stock was completed in reliance upon the exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”). The Company is currently evaluating the appropriate accounting treatment for this transaction.

On October 8, 2021, the Company entered into another purchase and sale agreement to acquire oil and gas assets in the Eagle Ford. The total aggregate consideration of the acquisition is approximately $75 million, which includes $45 million in cash with the rest to be paid with the greater of (i) 1,351,961 shares of our common stock and (ii) the number of shares equal to $25 million divided by the volume weighted average share price of the Company's common stock for the 30 consecutive trading days ending on and including the first trading day preceding the closing date, subject to customary purchase price adjustments. The acquisition includes 62 net PDP wells with liquids production of approximately 71% (46% of production attributable to oil) and approximately 17,000 net acres across the oil window in La Salle, McMullen, DeWitt and Lavaca counties. Closing of the pending acquisition is expected to occur in the fourth quarter of 2021, subject to the satisfaction of certain conditions set forth in the purchase and sale agreement. The shares of common stock to be issued upon closing in accordance with this purchase and sale agreement will be made in reliance upon the exemption from the registration requirements of the Securities Act. The Company is currently evaluating the appropriate accounting treatment for this transaction upon closing.

Through November 4, 2021, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after September 30, 2021:


Oil Derivative Contracts (New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) Settlements)	Total Volumes (Bbls)	Weighted-Average Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
Swap Contracts
2023 Contracts
1Q23	275	$	69.40
2Q23	575	$	68.40
3Q23	53,980	$	66.55
Collar Contracts
2022 Contracts
1Q22	45,000			$	73.00	$	79.75
2Q22	45,500			$	71.00	$	78.00
3Q22	46,000			$	70.00	$	75.40
4Q22	46,000			$	68.00	$	73.60
2023 Contracts
1Q23	45,000			$	65.00	$	72.80
2Q23	45,500			$	64.00	$	70.85
3Q23	46,000			$	63.00	$	69.10
4Q23	46,000			$	62.00	$	67.55


Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
Collar Contracts
2021 Contracts
4Q21	310,000	$	6.00	$	7.45
2022 Contracts
1Q22	590,000	$	6.00	$	7.45

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NGL Swaps (Mont Belvieu)	Total Volumes (Bbls)	Weighted-Average Price
2022 Contracts
1Q22	45,000	$	39.25
2Q22	45,500	$	32.82
3Q22	46,000	$	31.29
4Q22	46,000	$	31.09

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

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

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

•estimates related to the collectability of accounts receivable and the creditworthiness 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 (“LOE”),

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

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

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

•estimates made in our income tax calculations, including the valuation of our deferred tax assets,

•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 used in the assessment of business combinations and asset purchases,

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

•estimates on future lease obligations.

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

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

Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended September 30, 2021 and 2020, such internal costs when capitalized totaled $1.2 million and $0.8 million, respectively. For the nine months ended September 30, 2021 and 2020, such internal costs capitalized totaled $3.5 million and $2.8 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties

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(refer to Note 6 of these Notes to Condensed Consolidated Financial Statements for further discussion on capitalized interest costs).

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


	September 30, 2021		December 31, 2020
Property and Equipment
Proved oil and gas properties	$	1,445,818	$	1,310,008
Unproved oil and gas properties	24,988		28,090
Furniture, fixtures and other equipment	5,780		5,275
Less – Accumulated depreciation, depletion, amortization & impairment	(846,822)		(801,279)
Property and Equipment, Net	$	629,764	$	542,094

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

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

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

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

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

Due to the effects of pricing and timing of projects we reported a non-cash impairment write-down, on a pre-tax basis, of $355.9 million for the nine months ended September 30, 2020 on our oil and natural gas properties. There was no impairment for the three and nine months ended September 30, 2021 and the three months ended September 30, 2020.

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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 again in the future. We cannot control and cannot predict what future prices for oil and natural gas will be; therefore, we cannot estimate the amount of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices. However, it is reasonably possible that we will record additional Ceiling Test write-downs in future periods.

Accounts Receivable, Net. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both September 30, 2021 and December 31, 2020, we had an allowance for doubtful accounts of less than $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable, net” balance on the accompanying condensed consolidated balance sheets.

At September 30, 2021, our “Accounts receivable, net” balance included $41.8 million for oil and gas sales, $0.8 million due from joint interest owners, $1.2 million for severance tax credit receivables and $0.4 million for other receivables. At December 31, 2020, our “Accounts receivable, net” balance included $18.8 million for oil and gas sales, $4.0 million due from joint interest owners, $2.4 million for severance tax credit receivables and $0.7 million for other receivables.

Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the nine months ended September 30, 2021 and 2020 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 September 30, 2021 and 2020, respectively, and $3.6 million and $3.2 million for the nine months ended September 30, 2021 and 2020, 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. In March and April 2020, the COVID-19 pandemic caused volatility in the market price for crude oil due to the disruption of global supply and demand. In response to these market conditions and given the decline in oil prices and economic outlook for our Company, during the quarter ended June 30, 2020 management determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other federal deferred tax assets and, accordingly, recorded a full valuation allowance in the second quarter to offset its net federal deferred tax assets in excess of deferred tax liabilities. As a result of the full valuation allowance established at June 30, 2020, we recorded an income tax provision of $20.6 million for the nine months ended September 30, 2020, which was inclusive of state income tax expense. The Company maintains a full valuation allowance against its net federal deferred tax assets in excess of deferred tax liabilities as of September 30, 2021. We recorded an income tax benefit of $0.4 million for both the three and nine months ended September 30, 2021 and $0.6 million for the three months ended September 30, 2020 which were fully attributable to a current state income tax benefit.

Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At September 30, 2021 and December 31, 2020, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.

On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer-side Social Security payments, net operating loss carryback periods, alternative minimum tax credit refunds and modifications to the net interest deduction limitation. The Company continues to examine the impact that the CARES Act may have on its business but does not currently expect the CARES Act to have a material effect on its financial condition, results of operation, or liquidity.

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

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The following table provides information regarding our oil and gas sales, by product, reported on the Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2021 and 2020 (in thousands):


	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
Oil, natural gas and NGLs sales:
Oil	$	25,230	$	17,665	$	58,587	$	40,979
Natural gas	62,529		23,595		172,234		73,170
NGLs	11,489		4,439		25,030		9,772
Total	$	99,249	$	45,699	$	255,850	$	123,921

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


	September 30, 2021		December 31, 2020
Trade accounts payable	$	8,423	$	15,930
Accrued operating expenses	3,585		2,491
Accrued compensation costs	3,955		3,771
Asset retirement obligations – current portion	492		441
Accrued non-income based taxes	6,141		1,819
Accrued corporate and legal fees	132		150
Payable for settled derivatives	13,621		829
Other payables	1,651		1,560
Total accounts payable and accrued liabilities	$	38,000	$	26,991

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

Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock, held at cost” on the accompanying condensed consolidated balance sheets. For the nine months ended September 30, 2021 and 2020, we purchased 74,586 and 28,731 treasury shares, respectively, to satisfy withholding tax obligations arising upon the vesting of restricted shares.

ATM Program. On August 13, 2021, the Company entered into an equity distribution agreement pursuant to which the Company may sell, from time to time in the open market, shares of the Company’s common stock, having aggregate proceeds of up to $40.0 million (the “ATM Program”). The Company intends to use the net proceeds from any sales through the ATM Program for general corporate purposes, including, but not limited to, financing of capital expenditures, repayment or refinancing of outstanding debt, financing acquisitions or investments, financing other business opportunities, and general working capital purposes. During the three months ended September 30, 2021 (from August 13, 2021 through September 30, 2021), the Company sold 669,600 shares of common stock for net proceeds of $12.8 million after deducting sales agents' commissions and other related expenses.

(3) Leases

The Company adopted the standard provided in the Financial Accounting Standards Board's Accounting Standards Update 2016-02 and 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. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the Consolidated Balance Sheets. We have elected to not account for lease and non-lease components separately.

The Company has contractual agreements for its corporate office lease, vehicle fleet, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of September 30, 2021, all of the Company’s leases were operating leases.

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

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


	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets
Property, plant and equipment acquisitions - short-term leases	$	1,189	$	—	$	3,009	$	2,302
Property, plant and equipment acquisitions - operating leases	—		—		—		10
Total lease costs in property, plant and equipment additions	$	1,189	$	—	$	3,009	$	2,312


	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
Lease Costs Included in the Condensed Consolidated Statements of Operations
Lease operating expenses - short-term leases	$	314	$	124	$	1,399	$	575
Lease operating expenses - operating leases	1,504		1,397		3,774		4,267
General and administrative, net - operating leases	303		172		653		532
Total lease cost expensed	$	2,121	$	1,693	$	5,826	$	5,374

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


	September 30, 2021
Weighted-average remaining lease term (in years)	3.2
Weighted-average discount rate	4.1	%

As of September 30, 2021, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands):


	As of September 30, 2021
2021 (Remaining)	$	1,791
2022	6,767
2023	5,938
2024	776
2025	776
Thereafter	1,176
Total undiscounted lease payments	17,224
Present value adjustment	(1,209)
Net operating lease liabilities	$	16,015

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


	Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
Cash paid for amounts included in the measurement of lease liabilities;
Operating cash flows from operating leases	$	4,289	$	4,793
Investing cash flows from operating leases	$	—	$	10

(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.

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

The expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying condensed consolidated statements of operations was $1.2 million and $1.1 million for the three months ended September 30, 2021 and 2020, respectively, and $3.5 million for both the nine months ended September 30, 2021 and 2020. Capitalized share-based compensation was less than $0.1 million for both the three months ended September 30, 2021 and 2020 and $0.2 million for both the nine months ended September 30, 2021 and 2020.

We view stock option awards and RSUs 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. The Company accounts for forfeitures in compensation cost when they occur.

Stock Option Awards

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

At September 30, 2021, we had $0.2 million of unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the nine months ended September 30, 2021:


	Shares	Wtd. Avg. Exer. Price
Options outstanding, beginning of period	303,705	$	27.73

Options forfeited	(3,896)	$	16.96
Options expired	(23,800)	$	23.25

Options outstanding, end of period	276,009	$	28.12
Options exercisable, end of period	226,950	$	28.53

Our outstanding stock option awards had $0.1 million measurable aggregate intrinsic value at September 30, 2021. At September 30, 2021, the weighted-average remaining contract life of stock option awards outstanding was 4.4 years and exercisable was 4.1 years. The total intrinsic value of stock option awards exercisable was less than $0.1 million for the nine months ended September 30, 2021.

Restricted Stock Units

The compensation cost related to restricted stock awards is based on the grant date fair value and is typically expensed over the requisite service period (generally one to five years).

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As of September 30, 2021, we had $1.3 million unrecognized compensation expense related to our RSUs which is expected to be recognized over a weighted-average period of 0.8 years.

The following table provides information regarding RSU activity for the nine months ended September 30, 2021:


	RSUs	Wtd. Avg. Grant Price
RSUs outstanding, beginning of period	574,916	$	9.02
RSUs granted	100,178	$	8.33


RSUs forfeited	(17,802)	$	11.09
RSUs vested	(312,447)	$	9.14
RSUs outstanding, end of period	344,845	$	8.60

Performance-Based Stock Units

On February 20, 2018, the Company granted 30,700 PSUs for which the number of shares earned is based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2018 to December 31, 2020. The awards contain market conditions which allow a payout ranging between 0% payout and 200% of the target payout. The fair value as of the date of valuation was $41.66 per unit or 150.61% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte-Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards had a cliff-vesting period of three years and the period ended without any of the awards vesting. There are no outstanding PSUs related to this award as of September 30, 2021.

On May 21, 2019, the Company granted 99,500 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2019 to December 31, 2021. The awards contain market conditions which allow a payout ranging between 0% payout and 200% of the target payout. The fair value as of the grant date was $18.86 per unit or 112.9% of stock price. The awards have a cliff-vesting period of three years. There were 83,600 PSUs outstanding related to this award as of September 30, 2021.

On February 24, 2021, the Company granted 161,389 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2021 to December 31, 2022. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $13.13 per unit or 157.6% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of two years. All PSUs granted remain outstanding related to this award as of September 30, 2021.

As of September 30, 2021, we had $1.7 million unrecognized compensation expense related to our PSUs based on the assumption of 100% target payout. The remaining weighted-average performance period is 1.1 years while 23,800 shares vested during the nine months ended September 30, 2021.

(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 RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three and nine months ended September 30, 2021 and 2020 are discussed below.

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The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts):


	Three Months Ended September 30, 2021					Three Months Ended September 30, 2020
	Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)		Shares	Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	(35,943)	12,629	$	(2.85)	$	(6,896)	11,935	$	(0.58)
Dilutive Securities:

RSU Awards			—					—

Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	(35,943)	12,629	$	(2.85)	$	(6,896)	11,935	$	(0.58)


	Nine Months Ended September 30, 2021					Nine Months Ended September 30, 2020
	Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)		Shares	Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	(27,514)	12,283	$	(2.24)	$	(318,730)	11,890	$	(26.81)
Dilutive Securities:

RSU Awards			—					—

Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	(27,514)	12,283	$	(2.24)	$	(318,730)	11,890	$	(26.81)

Approximately 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for both the three months ended September 30, 2021 and 2020 because they were antidilutive due to the net loss, while 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for both the nine months ended September 30, 2021 and 2020 because they were antidilutive due to the net loss.

There were no antidilutive shares of RSUs that could be converted to common shares for the three months ended September 30, 2021, while approximately 0.2 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended September 30, 2020, because they were antidilutive due to the net loss, while less than 0.1 million and 0.2 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the nine months ended September 30, 2021 and 2020 because they were antidilutive due to the net loss.

There were no antidilutive shares of PSUs that could be converted to common shares for the three months ended September 30, 2021, while approximately 0.1 million shares of PSUs were not included for the three months ended September 30, 2020 because they were antidilutive due to the net loss, while there were no shares of PSUs that could be converted to common shares for the nine months ended September 30, 2021, while 0.1 million shares of PSUs were not included for the nine months ended September 30, 2020 because they were antidilutive due to the net loss.

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(6) Long-Term Debt

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


	September 30, 2021		December 31, 2020
Credit Facility Borrowings (1)	$	198,000	$	230,000
Second Lien Notes due 2024	200,000		200,000
	398,000		430,000
Unamortized discount on Second Lien Notes due 2024	(1,086)		(1,295)
Unamortized debt issuance cost on Second Lien Notes due 2024	(3,188)		(3,800)
Long-Term Debt, net	$	393,726	$	424,905

(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our consolidated balance sheet. As of September 30, 2021 and December 31, 2020, we had $2.8 million and $1.4 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.

Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $198.0 million and $230.0 million as of September 30, 2021 and December 31, 2020, respectively. The Company is a party to a First Amended and Restated Senior Secured Revolving Credit Agreement with JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended (such agreement, the “Credit Agreement” and the borrowing facility provided thereby, the “Credit Facility”). In conjunction with its regularly scheduled semi-annual redetermination, the Company entered into the Seventh Amendment to the Credit Facility, effective April 16, 2021 (the “Seventh Amendment”), which among other things, (i) redetermined the borrowing base under the Credit Facility to $300 million (from $310 million), (ii) extended the maturity of our Credit Facility from April 19, 2022 to April 19, 2024; (iii) increased the applicable margin used to calculate the interest rate under the Credit Facility by 50 basis points, with the specific applicable margins determined by reference to borrowing base utilization; (iv) reduced the permitted ratio of Total Debt to EBITDA (each as defined in the Credit Agreement) from 3.50 to 1.00 (a) to 3.25 to 1.00 for the fiscal quarters ending on or before December 31, 2021 and (b) to 3.00 to 1.00 commencing with the fiscal quarter ending March 31, 2022; (v) implemented a minimum rolling hedge requirement of 50% of reasonably anticipated projected production from proved developed producing reserves for a 24-month period, and (vi) increased the mortgage coverage and title requirements from 85% to 90%.

The Credit Facility provides for a maximum credit amount of $600.0 million, subject to the current borrowing base of $300.0 million as of September 30, 2021. 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, the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders, in their discretion, in accordance with their oil and gas lending criteria at the time of the relevant redetermination. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to $25 million, which reduces the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit. Maintaining or increasing our borrowing base under our Credit Facility is dependent on many factors, including commodity prices, our hedge positions, changes in our lenders' lending criteria and our ability to raise capital to drill wells to replace produced reserves.

Interest under the Credit Facility accrues at the Company’s option either at an Alternate Base Rate plus the applicable margin (“ABR Loans”) or the LIBOR Rate plus the applicable margin (“Eurodollar Loans”). Effective April 16, 2021, the applicable margin ranged from 2.25% to 3.25% for ABR Loans and 3.25% to 4.25% for Eurodollar Loans. The Alternate Base Rate and LIBOR Rate are defined, and the applicable margins are set forth, in the Credit Agreement. Undrawn amounts under the Credit Facility are subject to a 0.5% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. In July 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. At the present time, the Credit Facility is subject to LIBOR rates but has a term that extends beyond the end of 2021 when LIBOR will be phased out. The Credit Agreement currently provides for options in the event LIBOR is discontinued. It is expected that the Credit Agreement will be amended at its upcoming fall redetermination to reference an alternative rate as established by JP Morgan, as Administrative Agent, and the Company.

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 its subsidiary, including a first priority lien on properties attributed with at least 90% of estimated proved reserves of the Company and its subsidiary.

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The Credit Agreement contains the following financial covenants:

•a ratio of total debt to earnings before interest, tax, depreciation and amortization (“EBITDA”), as defined in the Credit Agreement, for the most recently completed four fiscal quarters, not to exceed (i) 3.25 to 1.00 as of the last day of each fiscal quarter for any fiscal quarter ending on or before December 31, 2021 and (ii) 3.00 to 1.00 as of the last day of each fiscal quarter, commencing with fiscal quarter ending March 31, 2022; 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 1.00 to 1.00 as of the last day of each fiscal quarter.

As of September 30, 2021, the Company was in compliance with all financial covenants under the Credit Agreement.

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 $2.8 million and $2.9 million for the three months ended September 30, 2021 and 2020, respectively, and $8.1 million and $9.8 million for the nine months ended September 30, 2021 and 2020, respectively.

There was no capitalized interest on our unproved properties for both the three months ended September 30, 2021 and 2020, respectively, and for both the nine months ended September 30, 2021 and 2020, respectively.

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

Interest on the Second Lien is payable quarterly and accrues at LIBOR plus 7.5%; provided that if LIBOR ceases to be available, the Second Lien provides for a mechanism to use ABR (an alternate base rate) plus 6.5% as the applicable interest rate. The definitions of LIBOR and ABR are set forth in the Note Purchase Agreement. 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 a repayment fee of 1.0% of the principal amount of the Second Lien being prepaid through December 15, 2021; 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 its subsidiary, including a mortgage lien on oil and gas properties attributed with at least 85% of estimated PV-9 (defined below), of proved reserves of the Company and its subsidiary 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. PV-9 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 9%.

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

The Second Lien also contains a financial covenant measuring the ratio of total net debt-to-EBITDA, as defined in the Note Purchase Agreement, for the most recently completed four fiscal quarters, not to exceed 4.5 to 1.0 as of the last day of each fiscal quarter. As of September 30, 2021, the Company was in compliance with all financial covenants under the Second Lien.

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

As of September 30, 2021, total net amounts recorded for the Second Lien were $195.7 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $4.6 million for both the three months ended September 30, 2021 and 2020, respectively, and $13.8 million and $14.1 million for the nine months ended September 30, 2021 and 2020, 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. During the nine months ended September 30, 2021 in connection with our semi-annual redetermination, the Company capitalized $2.4 million for expenses incurred under the Seventh Amendment to our Credit Facility. Additionally, the Company wrote-off $0.2 million in debt issuance costs related to lenders which fully exited the Credit Facility.

(7) Acquisitions and Dispositions

Effective December 22, 2017, the Company closed a purchase and sale contract to sell the Company's wellbores and facilities in the Bay De Chene field and recorded a $16.3 million obligation related to the funding of certain plugging and abandonment costs. Of the $16.3 million original obligation, $1.1 million and $0.4 million was paid during the nine months ended September 30, 2021 and 2020, respectively. The remaining obligation under this contract is $0.5 million and is carried in the accompanying condensed consolidated balance sheet current liability in “Accounts payable and accrued liabilities” as of September 30, 2021.

On August 3, 2021, the Company acquired the remaining working interest in 12 wells that SilverBow operates and additional Eagle Ford La Mesa assets and 850 net acres in our Webb County Dry Gas play. The total aggregate consideration was approximately $24 million, consisting of $13.2 million in cash and 516,675 shares of common stock valued at approximately $10.0 million on the closing date. The Company accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. As a result, we allocated the purchase price to proved oil and gas properties. The issuance of the shares of common stock of the Company was completed in reliance upon the exemption from the registration requirements of the Securities Act.

(8) Price-Risk Management Activities

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

During the three months ended September 30, 2021 and 2020, the Company recorded losses of $88.6 million and losses of $12.9 million, respectively, on its commodity derivatives. During the nine months ended September 30, 2021 and

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2020, the Company recorded losses of $152.9 million and gains of $66.9 million, respectively. The Company made cash payments of $29.0 million and collected cash payments of $76.1 million for settled derivative contracts during the nine months ended September 30, 2021 and 2020, respectively. Included in our collected cash payments during the nine months ended September 30, 2020 was $38.3 million for monetized derivative contracts.

At September 30, 2021 and December 31, 2020, there were less than $0.1 million and $0.8 million, respectively, in receivables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts receivable, net” and were subsequently collected in October 2021 and January 2021, respectively. At September 30, 2021 and December 31, 2020, we also had $13.6 million and $0.8 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 October 2021 and January 2021, respectively.

The fair values of our swap contracts are computed using observable market data whereas our collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. At September 30, 2021, there was $0.7 million and less than $0.1 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $94.8 million and $22.0 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2020, there was $4.8 million and $0.3 million in current and long-term unsettled derivative assets, respectively, and $8.2 million and $2.9 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 condensed consolidated balance sheet. Under the right of set-off, there was a $116.1 million net fair value liability at September 30, 2021, and a $6.0 million net fair value liability at December 31, 2020. For further discussion related to the fair value of the Company's derivatives, refer to Note 9 of these Notes to Condensed Consolidated Financial Statements.

The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of September 30, 2021:


Oil Derivative Contracts (New York Mercantile Exchange (“NYMEX”) WTI Settlements)	Total Volumes (Bbls)	Weighted-Average Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
Swap Contracts
2021 Contracts
4Q21	272,662	$	57.50
2022 Contracts
1Q22	223,455	$	49.32
2Q22	136,500	$	56.66
3Q22	246,100	$	49.63
4Q22	184,000	$	54.84
2023 Contracts
1Q23	81,900	$	55.70
Collar Contracts
2021 Contracts
4Q21	84,640			$	34.70	$	41.01
2022 Contracts
1Q22	40,500			$	40.00	$	45.55
2Q22	115,850			$	39.25	$	46.20
2023 Contracts
2Q23	65,975			$	56.00	$	63.20

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Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
Swap Contracts
2021 Contracts
4Q21	1,530,000	$	3.60
2022 Contracts
1Q22	232,500	$	4.00
2Q22	3,795,000	$	2.99
3Q22	4,142,100	$	3.02
4Q22	2,760,000	$	3.14
Collar Contracts
2021 Contracts
4Q21	9,301,000			$	2.73	$	3.15
2022 Contracts
1Q22	9,055,000			$	2.87	$	3.55
2Q22	6,156,500			$	2.29	$	2.74
3Q22	6,739,000			$	2.60	$	2.98
4Q22	7,765,076			$	2.69	$	3.20
2023 Contracts
1Q23	8,347,000			$	2.89	$	3.52
2Q23	4,125,000			$	2.49	$	2.92
3Q23	1,380,000			$	2.60	$	3.13


Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes (MMBtu)	Weighted-Average Price
2021 Contracts
4Q21	11,040,000	$	(0.013)
2022 Contracts
1Q22	8,100,000	$	0.093
2Q22	3,640,000	$	(0.051)
3Q22	3,680,000	$	(0.043)
4Q22	3,680,000	$	(0.048)


Oil Basis Swaps (Argus Cushing (WTI) and Magellan East Houston)	Total Volumes (Bbls)	Weighted-Average Price
2021 Contracts
4Q21	241,500	$	1.28
Calendar Monthly Roll Differential Swaps
2021 Contracts
4Q21	241,500	$	(0.33)
2022 Contracts
1Q22	261,000	$	0.19
2Q22	263,900	$	0.19
3Q22	266,800	$	0.19
4Q22	266,800	$	0.19

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NGL Swaps (Mont Belvieu)	Total Volumes (Bbls)	Weighted-Average Price
2021 Contracts
4Q21	192,324	$	24.26
2022 Contracts
1Q22	135,000	$	25.75
2Q22	91,000	$	26.87
3Q22	92,000	$	26.87
4Q22	92,000	$	26.87

(9) Fair Value Measurements

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

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

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

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

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

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

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

The following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of September 30, 2021 and December 31, 2020, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these Notes to Condensed Consolidated Financial Statements.


	Fair Value Measurements at
(in millions)	Total		Quoted Prices in Active markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
September 30, 2021
Assets

Natural Gas Basis Derivatives	$	0.6	$	—	$	0.6	$	—

Oil Basis Derivatives	0.1		—		0.1		—

Liabilities
Natural Gas Derivatives	80.3		—		80.3		—
Natural Gas Basis Derivatives	2.6		—		2.6		—
Oil Derivatives	26.3		—		26.3		—
Oil Basis Derivatives	0.8		—		0.8		—
NGL Derivatives	6.7		—		6.7		—
December 31, 2020
Assets
Natural Gas Derivatives	1.5		—		1.5		—
Natural Gas Basis Derivatives	1.1		—		1.1		—
Oil Derivatives	2.5		—		2.5		—

Liabilities
Natural Gas Derivatives	4.0		—		4.0		—
Natural Gas Basis Derivatives	0.4		—		0.4		—
Oil Derivatives	5.9		—		5.9		—
Oil Basis Derivatives	0.8		—		0.8		—

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. Estimates for the initial recognition of asset retirement obligations are derived from historical costs as well as management's expectation of future cost environments and other unobservable inputs. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3 fair value measurements. 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.

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The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2020 and the nine months ended September 30, 2021 (in thousands):


Asset Retirement Obligations as of December 31, 2019	$	4,447
Accretion expense	354
Liabilities incurred for new wells and facilities construction	281

Reductions due to plugged wells and facilities	(103)
Revisions in estimates	(5)
Asset Retirement Obligations as of December 31, 2020	$	4,974
Accretion expense	226
Liabilities incurred for new wells, acquired wells and facilities construction	347

Reductions due to plugged wells and facilities	(192)
Revisions in estimates	(157)
Asset Retirement Obligations as of September 30, 2021	$	5,198

At September 30, 2021 and December 31, 2020, approximately $0.5 million and $0.4 million, respectively, of our asset retirement obligations were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets.

(11) Commitments and Contingencies

In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as an operator of oil and natural gas wells. In our management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion and analysis in conjunction with the Company's financial information and its condensed consolidated financial statements and accompanying notes included in this report and its audited consolidated financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2020. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 36 of this report.

Company Overview

SilverBow is an independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford and Austin Chalk located in South Texas where it has assembled approximately 143,000 net acres across five operating areas. SilverBow'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, SilverBow possesses a significant understanding of the reservoir characteristics, geology, landowners and competitive landscape in the region. The Company leverages this in-depth knowledge to continue to assemble high quality drilling inventory while continuously enhancing its operations to maximize returns on capital invested.

Operational Results

Total production for the nine months ended September 30, 2021 increased 9% from the nine months ended September 30, 2020 to 203 million cubic feet of natural gas equivalent per day as SilverBow pursued a moderated growth strategy and did not have any curtailed production impacting results.

During the third quarter of 2021, SilverBow drilled six net wells, completed 11 wells and brought 11 wells online. As expected, the Company concluded its mid-year liquids development program with the majority of completion activity focused in its La Salle Condensate and McMullen Oil areas. As a result of strong well performance, oil production increased nearly 50% quarter-over-quarter. In the La Salle Condensate area, SilverBow brought online a Briggs Knolle two-well pad which produced a 30-day average of 2,524 barrels of oil equivalent per day (“Boe/d”) (72% liquids), and a Briggs Knolle four-well pad which produced a 30-day average of 4,202 Boe/d (78% liquids).

Across the 11 total well completions during the quarter, the Company realized $9 million of cost savings due to reduced cycle times for both drilling and completion ("D&C") operations along with various well design and construction optimizations. Year-to-date, D&C costs per lateral foot are 14% lower compared to 2020. Additionally, SilverBow extended its streak of zero total recordable incidents on a rolling twelve month basis from the beginning of 2020 through the third quarter of 2021.

The Company continues to drill and appraise the Austin Chalk and is reviewing early and encouraging results from its second Austin Chalk well in Webb County. The Fasken 201H, which came online in August, produced over 12 MMcf/d on average over the first 60 days, and thus far is producing in-line with SilverBow's first Austin Chalk well at Rio Bravo. Both wells are exceeding offset type curves in the area and are exhibiting some of the highest commercial economics in the Company's portfolio. SilverBow is also assessing the initial results of a third Webb County Austin Chalk well which started producing in October.

The Company currently does not have a drilling rig active, but plans to add one rig in December which will drill one net La Mesa well by year-end. As previously discussed, the Company has elected to participate in three gross (one net) non-operated Webb County wells which are expected to be brought online during the fourth quarter.

Recent Acquisitions: On August 3, 2021, the Company acquired the remaining working interest in 12 wells that that SilverBow operates, additional Eagle Ford La Mesa assets and 850 net acres in our Webb County Dry Gas play. On October 1, 2021, we closed on our previously announced all-stock transaction to acquire oil and gas assets in the Eagle Ford. The acquired assets include a 100% working interest in approximately 15,000 net oil-weighted acres across Atascosa, Fayette and Lavaca counties, as well as approximately 26,000 net gas-weighted acres directly offsetting our existing position in McMullen and Live Oak counties. On October 8, 2021, the Company entered into another purchase and sale agreement to acquire oil and gas assets in the Eagle Ford, including 62 net PDP wells with liquids production of approximately 71% (46% of production attributable to

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oil) and approximately 17,000 net acres across the oil window in La Salle, McMullen, DeWitt and Lavaca counties. See Note 7 and the Subsequent Event section within Note 2 to SilverBow's condensed consolidated financial statements for more information on our recent acquisitions. We continue to take advantage of opportunities to expand our core positions through acquisitions.

2021 Cost Reduction Initiatives: SilverBow continues to focus on cost reduction measures in the areas that it can control. These initiatives include the use of regional sand in completions and improved utilization of existing facilities. As previously mentioned, the Company continues to improve its process for drilling, completing and equipping wells. SilverBow's procurement team takes a process-oriented approach to reducing the total delivered costs of purchased services by examining costs at their most granular level. Services are routinely sourced directly from the suppliers. The Company's LOE and workover expenses were $19.3 million or $0.35 per thousand cubic feet of gas equivalent (“Mcfe”) for the first nine months of 2021, as compared to $16.0 million or $0.32 per Mcfe for the same period in 2020. The increase in costs was due to incremental expenses related to Winter Storm Uri, higher salt water disposal, utilities and higher compression costs. These increases were partially mitigated by lower treating and labor costs.

SilverBow's net general and administrative (“net G&A”) costs were $14.9 million, or $0.27 per Mcfe, and cash G&A costs were $11.4 million (a non-GAAP financial measure calculated as net G&A costs less $3.5 million of share-based compensation), or $0.21 per Mcfe, for the first nine months of 2021, compared to net G&A costs of $17.9 million, or $0.36 per Mcfe, and cash G&A costs of $14.4 million (a non-GAAP financial measure calculated as net G&A costs less $3.5 million of share-based compensation), or $0.29 per Mcfe, for the nine months ended September 30, 2020.

SilverBow reports cash G&A because management uses it as an indicator of cost management and operating efficiency on a comparable basis from period to period and SilverBow believes this provides useful information to analysts and investors. In addition, the Company believes cash G&A expenses are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A expenses should not be considered as an alternative to, or more meaningful than, total net G&A expenses.

Liquidity and Capital Resources

SilverBow's primary use of cash has been to fund capital expenditures to develop its oil and gas properties, fund acquisitions and to repay Credit Facility borrowings. As of September 30, 2021, the Company’s liquidity consisted of $1.0 million of cash-on-hand and $102.0 million in available borrowings on its Credit Facility, which had a $300 million borrowing base. Management believes the Company has sufficient liquidity to meet its obligations through the fourth quarter of 2022 and execute its long-term development plans. For more details, see the Credit Facility section within Note 6 to SilverBow's condensed consolidated financial statements for more information on its Credit Facility.

On August 13, 2021, we entered into an equity distribution agreement with Johnson Rice & Company L.L.C. and Truist Securities, Inc. (“Sales Agents”). Pursuant to the terms of the agreement, we may sell from time to time shares of our common stock having aggregate proceeds of up to $40,000,000 (the “ATM Program”). We intend to use the net proceeds from any sales through the ATM Program, after deducting the Sales Agent’s commission and the Company’s offering expenses, for general corporate purposes, including, but not limited to, financing of capital expenditures, repayment or refinancing of outstanding debt, financing acquisitions or investments, financing other business opportunities, and general working capital purposes. Under the Sale Agreement, the Company sold 669,600 shares during the three months ended September 30, 2021 for net proceeds of $12.8 million after underwriting commissions and other related expenses.

Contractual Commitments and Obligations

As of September 30, 2021 and December 31, 2020, the Company had approximately $16.0 million and $4.4 million, respectively, in net operating leases liabilities. The increase was primarily due to compression equipment leases and the Company's corporate office lease. There were no other material changes in SilverBow's contractual commitments during the nine months ended September 30, 2021 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, 2020.

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Summary of 2021 Financial Results Through September 30, 2021

•Revenues and Net Income (Loss): The Company's oil and gas revenues were $255.9 million for the nine months ended September 30, 2021, compared to $123.9 million for the nine months ended September 30, 2020. Revenues were higher due to increased production volumes and overall higher commodity pricing. The Company's net loss was $27.5 million for the nine months ended September 30, 2021, compared to a net loss of $318.7 million for the nine months ended September 30, 2020. The decrease in net loss was primarily due to higher revenues due to increased production volumes and higher commodity pricing along with no non-cash impairment write-down during the current period.

•Capital Expenditures: The Company's capital expenditures on an accrual basis were $109.9 million for the nine months ended September 30, 2021 compared to $75.7 million for the nine months ended September 30, 2020. The expenditures for the nine months ended September 30, 2021 and 2020 were primarily attributable to drilling and completion activity.

•Working Capital: The Company had a working capital deficit of $127.9 million at September 30, 2021 and a working capital deficit of $23.1 million at December 31, 2020. The working capital computation does not include available liquidity through our Credit Facility.

•Cash Flows: For the nine months ended September 30, 2021, the Company generated cash from operating activities of $133.6 million during which we had a working capital deficit of $13.9 million. Cash used for property additions was $98.2 million while cash used in property acquisitions was $13.2 million. This excluded $11.4 million attributable to a net increase of capital-related payables and accrued costs. Additionally, $1.1 million was paid during the nine months ended September 30, 2021 for property abandonment obligations related to the sale of our former Bay De Chene field. The Company’s net repayments on the Credit Facility were $32.0 million during the nine months ended September 30, 2021.

For the nine months ended September 30, 2020, the Company generated cash from operating activities of $127.8 million, of which $2.4 million was attributable to changes in working capital. Cash used for property additions was $102.7 million. This included $25.6 million attributable to a net decrease of capital-related payables and accrued costs. Additionally, $0.4 million was paid during the nine months ended September 30, 2020 for property abandonment obligations related to the sale of our former Bay De Chene field. The Company’s net repayments on the Credit Facility were $26.0 million during the nine months ended September 30, 2020.

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Results of Operations

Revenues — Three Months Ended September 30, 2021 and Three Months Ended September 30, 2020

Natural gas production was 77% and 71% of the Company's production volumes for the three months ended September 30, 2021 and 2020. Natural gas sales were 63% and 51% of oil and gas sales for the three months ended September 30, 2021 and 2020, respectively.

Crude oil production was 11% and 17% of the Company's production volumes for the three months ended September 30, 2021 and 2020, respectively. Crude oil sales were 25% and 39% of oil and gas sales for the three months ended September 30, 2021 and 2020, respectively.

NGL production was 12% of the Company's production volumes for both the three months ended September 30, 2021 and 2020, respectively. NGL sales were 12% and 10% of oil and gas sales for the three months ended September 30, 2021 and 2020, respectively.

The following table provides additional information regarding the Company's oil and gas sales, by area, excluding any effects of the Company's hedging activities, for the three months ended September 30, 2021 and 2020:


Fields	Three Months Ended September 30, 2021			Three Months Ended September 30, 2020
	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	$	30.9	4,807	$	11.8	3,802
AWP	15.5		2,073	15.3		3,659
Fasken	37.2		9,012	13.0		6,500
Other (1)	15.6		3,638	5.6		2,848
Total	$	99.2	19,530	$	45.7	16,809

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

The sales volumes increase from 2020 to 2021 was primarily due to overall increased production as a result of increased drilling and completion activity during 2021 and return of volumes that had been curtailed during 2020.

In the third quarter of 2021, our $53.5 million, or 117%, increase in oil, NGL and natural gas sales from the prior year period resulted from:

•Price variances that had an approximately $50.8 million favorable impact on sales due to overall higher commodity pricing; and

•Volume variances that had an approximately $2.8 million favorable impact on sales due to overall increased commodity production.

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The following table provides additional information regarding our oil and gas sales, by commodity type, as well as the effects of our hedging activities for derivative contracts held to settlement, for the three months ended September 30, 2021 and 2020 (in thousands, except per-dollar amounts):


	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020
Production volumes:
Oil (MBbl) (1)	368		472
Natural gas (MMcf)	15,092		11,897
Natural gas liquids (MBbl) (1)	372		347
Total (MMcfe)	19,530		16,809

Oil, natural gas and natural gas liquids sales:
Oil	$	25,230	$	17,665
Natural gas	62,529		23,595
Natural gas liquids	11,489		4,439
Total	$	99,249	$	45,699

Average realized price:
Oil (per Bbl)	$	68.54	$	37.45
Natural gas (per Mcf)	4.14		1.98
Natural gas liquids (per Bbl)	30.92		12.79
Average per Mcfe	$	5.08	$	2.72

Price impact of cash-settled derivatives:
Oil (per Bbl)	$	(17.18)	$	6.91
Natural gas (per Mcf)	(0.69)		0.39
Natural gas liquids (per Bbl)	(7.07)		(0.01)
Average per Mcfe	$	(0.99)	$	0.47

Average realized price including impact of cash-settled derivatives:
Oil (per Bbl)	$	51.36	$	44.36
Natural gas (per Mcf)	3.46		2.37
Natural gas liquids (per Bbl)	23.85		12.78
Average per Mcfe	$	4.09	$	3.19

(1) Oil and natural gas liquids are converted at the rate of one barrel to six Mcfe. Mcf refers to one thousand cubic feet, and MMcf refers to one million cubic feet. Bbl refers to one barrel of oil, and MBbl refers to one thousand barrels.

For the three months ended September 30, 2021 and 2020, the Company recorded net losses of $88.6 million and $12.9 million from our derivatives activities, respectively. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.

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Costs and Expenses — Three Months Ended September 30, 2021 and Three Months Ended September 30, 2020

The following table provides additional information regarding our expenses for the three months ended September 30, 2021 and 2020 (in thousands):


Costs and Expenses	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020
General and administrative, net	$	5,257	$	5,833
Depreciation, depletion, and amortization	16,054		13,975
Accretion of asset retirement obligations	77		90
Lease operating expenses	6,978		5,211
Workovers	423		8
Transportation and gas processing	5,913		5,094
Severance and other taxes	4,908		2,512
Interest expense, net	7,433		7,444

General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.27 and $0.35 for the three months ended September 30, 2021 and 2020, respectively. The decrease per Mcfe was due to higher production while the decrease in costs was primarily due to lower salaries and burdens, professional fees and lower temporary labor fees. Included in general and administrative expenses is $1.2 million and $1.1 million in share-based compensation for the three months ended September 30, 2021 and 2020, respectively.

Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were $0.82 and $0.83 for the three months ended September 30, 2021 and 2020, respectively.

Lease Operating Expenses and Workovers. These expenses on a per-Mcfe basis were $0.38 and $0.31 for the three months ended September 30, 2021 and 2020, respectively. The increase in costs was due to higher compression and salt water disposal costs, partially offset by lower treating costs.

Transportation and Gas Processing. These expenses are related to natural gas and NGL sales. These expenses on a per-Mcfe basis were $0.30 for both the three months ended September 30, 2021 and 2020.

Severance and Other Taxes. These expenses on a per-Mcfe basis were $0.25 and $0.15 for the three months ended September 30, 2021 and 2020, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 4.9% and 5.5% for the three months ended September 30, 2021 and 2020, respectively.

Interest. Our gross interest cost was $7.4 million for both the three months ended September 30, 2021 and 2020. There were no capitalized interest costs for the three months ended September 30, 2021 or 2020.

Income Taxes. The Company recorded an income tax benefit of $(0.4) million and $(0.6) million for the three months ended September 30, 2021 and 2020, respectively. The benefit was fully attributable to a current state income tax benefit.

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Revenues — Nine Months Ended September 30, 2021 and Nine Months Ended September 30, 2020

Natural gas production was 79% and 77% of the Company's production volumes for the nine months ended September 30, 2021 and 2020, respectively. Natural gas sales were 67% and 59% of oil and gas sales for the nine months ended September 30, 2021 and 2020, respectively.

Crude oil production was 10% and 13% of the Company's production volumes for both the nine months ended September 30, 2021 and 2020, respectively. Crude oil sales were 23% and 33% of oil and gas sales for the nine months ended September 30, 2021 and 2020, respectively.

NGL production was 11% and 10% of the Company's production volumes for the nine months ended September 30, 2021 and 2020, respectively. NGL sales were 10% and 8% of oil and gas sales for both the nine months ended September 30, 2021 and 2020, respectively.

The following table provides additional information regarding the Company's oil and gas sales, by area, excluding any effects of the Company's hedging activities, for the nine months ended September 30, 2021 and 2020:


Fields	Nine Months Ended September 30, 2021			Nine Months Ended September 30, 2020
	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	$	61.1	11,550	$	30.6	10,016
AWP	46.6		7,037	33.9		8,872
Fasken	99.0		25,567	44.2		23,676
Other (1)	49.1		10,967	15.2		7,904
Total	$	255.8	55,121	$	123.9	50,468

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

The sales volumes increase from 2020 to 2021 was primarily due to increased natural gas production partially offset by lower oil production in 2021 as well as the return of volumes that had been curtailed in 2020.

In the nine months ended September 30, 2021, our $131.9 million, or 106%, increase in oil, NGL and natural gas sales from the prior year period resulted from:

•Price variances that had an approximately $127.3 million favorable impact on sales due to overall higher commodity pricing; and

•Volume variances that had an approximately $4.6 million favorable impact on sales due to higher natural gas and NGL production.

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The following table provides additional information regarding our oil and gas sales, by commodity type, as well as the effects of our hedging activities for derivative contracts held to settlement, for the nine months ended September 30, 2021 and 2020 (in thousands, except per-dollar amounts):


	Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
Production volumes:
Oil (MBbl) (1)	933		1,093
Natural gas (MMcf)	43,594		39,018
Natural gas liquids (MBbl) (1)	988		815
Total (MMcfe)	55,121		50,468

Oil, natural gas and natural gas liquids sales:
Oil	$	58,587	$	40,979
Natural gas	172,234		73,170
Natural gas liquids	25,030		9,772
Total	$	255,850	$	123,921

Average realized price:
Oil (per Bbl)	$	62.82	$	37.48
Natural gas (per Mcf)	3.95		1.88
Natural gas liquids (per Bbl)	25.32		11.99
Average per Mcfe	$	4.64	$	2.46

Price impact of cash-settled derivatives:
Oil (per Bbl)	$	(16.57)	$	17.05
Natural gas (per Mcf)	(0.29)		0.50
Natural gas liquids (per Bbl)	(4.19)		—
Average per Mcfe	$	(0.58)	$	0.76

Average realized price including impact of cash-settled derivatives:
Oil (per Bbl)	$	46.25	$	54.54
Natural gas (per Mcf)	3.66		2.38
Natural gas liquids (per Bbl)	21.13		11.99
Average per Mcfe	$	4.06	$	3.22

For the nine months ended September 30, 2021 and 2020, the Company recorded net losses of $152.9 million and net gains of $66.9 million from our derivatives activities, respectively. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.

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Costs and Expenses — Nine Months Ended September 30, 2021 and Nine Months Ended September 30, 2020

The following table provides additional information regarding our expenses for the nine months ended September 30, 2021 and 2020 (in thousands):


Costs and Expenses	Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
General and administrative, net	$	14,872	$	17,926
Depreciation, depletion, and amortization	45,485		51,130
Accretion of asset retirement obligations	226		263
Lease operating expenses	18,767		16,023
Workovers	512		8
Transportation and gas processing	17,175		16,291
Severance and other taxes	11,974		7,513
Interest expense, net	21,888		23,876
Write-down of oil and gas properties	—		355,948

General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.27 and $0.36 for the nine months ended September 30, 2021 and 2020, respectively. The decrease per Mcfe was due to higher production while the decrease in costs was primarily due to lower salaries and burdens, professional fees and temporary labor fees. Included in general and administrative expenses is $3.5 million in share-based compensation for both the nine months ended September 30, 2021 and 2020, respectively.

Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were $0.83 and $1.01 for the nine months ended September 30, 2021 and 2020, respectively. The decrease on a per Mcfe basis was driven by reductions to our depletable base due to non-cash impairment write-downs in the previous year.

Lease Operating Expenses and Workovers. These expenses on a per-Mcfe basis were $0.35 and $0.32 for the nine months ended September 30, 2021 and 2020, respectively. The increase in costs was due to higher compression and salt water disposal costs, partially offset by lower treating and labor costs.

Transportation and Gas Processing. These expenses are related to natural gas and NGL sales. These expenses on a per-Mcfe basis were $0.31 and $0.32 for the nine months ended September 30, 2021 and 2020, respectively.

Severance and Other Taxes. These expenses on a per-Mcfe basis were $0.22 and $0.15 for the nine months ended September 30, 2021 and 2020, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 4.7% and 6.1% for the nine months ended September 30, 2021 and 2020, respectively.

Interest. Our gross interest cost was $21.9 million and $23.9 million for the nine months ended September 30, 2021 and 2020, respectively. The decrease in gross interest cost is primarily due to decreased borrowings. There were no capitalized interest costs for the nine months ended September 30, 2021 and 2020.

Write-down of oil and gas properties. Due to the effects of pricing and timing of projects, for the nine months ended September 30, 2020, we reported a non-cash impairment write-down, on a pre-tax basis, of $355.9 million on our oil and natural gas properties. There was no impairment for the nine months ended September 30, 2021.

Income Taxes. The Company recorded an income tax benefit of $(0.4) million for the nine months ended September 30, 2021 which was fully attributable to a current state income tax benefit. In March and April 2020, the COVID-19 pandemic caused volatility in the market price for crude oil due to the disruption of global supply and demand. In response to these market conditions and given the decline in oil prices and economic outlook for our Company, during the quarter ended June 30, 2020, management determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other deferred tax assets and, accordingly, recorded a full valuation allowance as a discrete item in the second quarter to offset its net deferred tax assets in excess of deferred tax liabilities. This resulted in tax expenses of $21.2 million in the second quarter of 2020 and an income tax provision of $20.6 million and the nine months ended September 30, 2020.

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Critical Accounting Policies and New Accounting Pronouncements

There have been no changes in the critical accounting policies disclosed in our 2020 Annual Report on Form 10-K.

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 based on current expectations and assumptions and 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, including those regarding our strategy, future operations, financial position, well expectations and drilling plans, 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,” “guidance,” “expect,” “may,” “continue,” “predict,” “potential,” “plan,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

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

• the severity and duration of world health events, including the COVID-19 pandemic, related economic repercussions, including disruptions in the oil and gas industry;

• actions by the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC and other allied producing countries) with respect to oil production levels and announcements of potential changes in such levels;

• operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruptions;

• shut-in and curtailment of production due to decreases in available storage capacity or other factors;

• 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 and future covenant compliance;

• operating results;

• asset disposition efforts or the timing or outcome thereof;

• ongoing and prospective joint ventures, their structures 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;

• impairment on our properties due to lower commodity prices;

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

• availability, cost and terms of capital;

• timing and successful drilling and completion 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;

• our ability to execute on strategic initiatives;

• effectiveness of our risk management activities including hedging strategy;

• environmental liabilities;

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• counterparty credit risk;

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

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

• uncertainty regarding our future operating results; and

• other risks and uncertainties described in this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2020.

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, 2020 and in subsequent Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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

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

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

Interest Rate Risk. At September 30, 2021, we had a combined $398.0 million drawn under our Credit Facility and our Second Lien, which bear floating rates of interest and therefore are susceptible to interest rate fluctuations. These variable interest rate borrowings are also impacted by changes in short-term interest rates. A hypothetical one percentage point increase in interest rates on our borrowings outstanding under our Credit Facility and Second Lien at September 30, 2021 would increase our annual interest expense by $4.0 million.

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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 September 30, 2021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

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

Item 1A. Risk Factors.

A description of our risk factors can be found in “Item 1A. Risk Factors” included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020. There have been no material changes in our risk factors disclosed in the 2020 Annual Report on Form 10-K.

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

On August 3, 2021, the Company acquired the remaining working interest in 12 wells that that SilverBow operates and additional Eagle Ford La Mesa assets and 850 net acres in our Webb County Dry Gas play. The total aggregate consideration was approximately $24 million, consisting of $13.2 million in cash and 516,675 shares of common stock valued at approximately $10.0 million issued to San Isidro Energy Company II, LLC on the closing date. The issuance of the shares of common stock of the Company was completed in reliance upon the exemption from the registration requirements of the Securities Act, provided by Section 4(a)(2) thereof.

Except as previously disclosed in a Current Report on Form 8-K, no other unregistered sales of our common stock were made during the three months ended September 30, 2021.

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Not applicable.

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Item 6. Exhibits.

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


3.1			First Amended and Restated Certificate of Incorporation of SilverBow Resources, Inc., effective May 5, 2017 (incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.'s Form 10-Q filed May 8, 2017, File No. 001-08754).
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).
10.1			Purchase and Sale Agreement, effective August 1, 2021, between the SilverBow Resources, Inc., and SilverBow Resources Operating, LLC and San Isidro Energy Company II, LLC. (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form S-3 filed August 27, 2021, File No. 333-259122).
31.1*			Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2*			Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32.1#			Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
101*			The following materials from SilverBow Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended September 30, 2021 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets (Unaudited), (ii) the Condensed Consolidated Statements of Operations (Unaudited), (iii) the Consolidated Statements of Stockholders Equity (Unaudited), (iv) the Condensed Consolidated Statements of Cash Flows (Unaudited), and (v) Notes to the Condensed Consolidated Financial Statements.
104			Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

*Filed herewith

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

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SIGNATURES

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

SILVERBOW RESOURCES, INC.
(Registrant)

Date:

November 4, 2021

By:

/s/ Christopher M. Abundis

Christopher M. Abundis
Executive Vice President,
Chief Financial Officer,
General Counsel and Secretary

Date:

November 4, 2021

By:

/s/ W. Eric Schultz

W. Eric Schultz
Controller


Date:	November 4, 2021	/s/ Sean C. Woolverton
		Sean C. Woolverton Chief Executive Officer