UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

of the Securities Exchange Act of 1934

For the quarterly period ended ~~June~~September 30, 2020

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.)

575 North Dairy Ashford, Suite 1200

Houston, Texas 77079

(281) 874-2700

(Address and telephone number of principal executive offices)

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


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)			~~11,934,420~~11,936,679 Shares outstanding at ~~July 31,~~October 28, 2020

SILVERBOW RESOURCES, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED ~~JUNE~~SEPTEMBER 30, 2020

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	2627

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3840

Item 4.	Controls and Procedures	3941

Part II	OTHER INFORMATION

Item 1.	Legal Proceedings	4042
Item 1A.	Risk Factors	4042
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4143
Item 3.	Defaults Upon Senior Securities	4143
Item 4.	Mine Safety Disclosures	4143
Item 5.	Other Information	4143
Item 6.	Exhibits	4143

SIGNATURES			4345

Table of Contents

PART I. FINANCIAL INFORMATION

Condensed Consolidated Balance Sheets (Unaudited)

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


		June 30, 2020		December 31, 2019			September 30, 2020		December 31, 2019

ASSETS	ASSETS					ASSETS
Current Assets:	Current Assets:					Current Assets:
Cash and cash equivalents	Cash and cash equivalents	$	6,610	$	1,358	Cash and cash equivalents	$	1,222	$	1,358
Accounts receivable, net	Accounts receivable, net	23,572		36,996		Accounts receivable, net	28,884		36,996
Fair value of commodity derivatives	Fair value of commodity derivatives	20,822		12,833		Fair value of commodity derivatives	11,850		12,833

Other current assets	Other current assets	3,028		2,121		Other current assets	2,628		2,121
Total Current Assets	Total Current Assets	54,032		53,308		Total Current Assets	44,584		53,308
Property and Equipment:	Property and Equipment:					Property and Equipment:
Property and equipment, full cost method, including $30,043 and $41,201, respectively, of unproved property costs not being amortized at the end of each period		1,303,551		1,247,717
Property and equipment, full cost method, including $30,661 and $41,201, respectively, of unproved property costs not being amortized at the end of each period						Property and equipment, full cost method, including $30,661 and $41,201, respectively, of unproved property costs not being amortized at the end of each period	1,323,789		1,247,717
Less – Accumulated depreciation, depletion, amortization & impairment	Less – Accumulated depreciation, depletion, amortization & impairment	(773,836)		(380,728)		Less – Accumulated depreciation, depletion, amortization & impairment	(787,830)		(380,728)
Property and Equipment, Net	Property and Equipment, Net	529,715		866,989		Property and Equipment, Net	535,959		866,989
Right of Use Assets	Right of Use Assets	7,586		9,374		Right of Use Assets	6,093		9,374
Fair Value of Long-Term Commodity Derivatives	Fair Value of Long-Term Commodity Derivatives	4,679		3,854		Fair Value of Long-Term Commodity Derivatives	2,291		3,854
Deferred Tax Asset	Deferred Tax Asset	—		22,669		Deferred Tax Asset	0		22,669
Other Long-Term Assets	Other Long-Term Assets	2,022		3,622		Other Long-Term Assets	1,752		3,622
Total Assets	Total Assets	$	598,034	$	959,816	Total Assets	$	590,679	$	959,816
LIABILITIES AND STOCKHOLDERS’ EQUITY	LIABILITIES AND STOCKHOLDERS’ EQUITY					LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:	Current Liabilities:					Current Liabilities:
Accounts payable and accrued liabilities	Accounts payable and accrued liabilities	$	15,800	$	39,343	Accounts payable and accrued liabilities	$	22,707	$	39,343
Fair value of commodity derivatives	Fair value of commodity derivatives	4,248		6,644		Fair value of commodity derivatives	10,420		6,644
Accrued capital costs	Accrued capital costs	5,436		17,889		Accrued capital costs	4,915		17,889
Accrued interest	Accrued interest	1,257		1,397		Accrued interest	892		1,397
Current lease liability	Current lease liability	5,972		6,707		Current lease liability	4,807		6,707
Undistributed oil and gas revenues	Undistributed oil and gas revenues	5,916		9,166		Undistributed oil and gas revenues	8,619		9,166

Total Current Liabilities	Total Current Liabilities	38,629		81,146		Total Current Liabilities	52,360		81,146
Long-Term Debt, Net	Long-Term Debt, Net	464,390		472,900		Long-Term Debt, Net	447,644		472,900
Non-Current Lease Liability	Non-Current Lease Liability	1,778		2,813		Non-Current Lease Liability	1,392		2,813
Deferred Tax Liabilities	Deferred Tax Liabilities	—		1,582		Deferred Tax Liabilities	0		1,582
Asset Retirement Obligations	Asset Retirement Obligations	4,312		4,055		Asset Retirement Obligations	4,344		4,055
Fair Value of Long-Term Commodity Derivatives	Fair Value of Long-Term Commodity Derivatives	2,412		1,613		Fair Value of Long-Term Commodity Derivatives	4,045		1,613
Other Long-Term Liabilities	Other Long-Term Liabilities	162		—		Other Long-Term Liabilities	292		0
Commitments and Contingencies (Note 11)	Commitments and Contingencies (Note 11)					Commitments and Contingencies (Note 11)
Stockholders' Equity:	Stockholders' Equity:					Stockholders' Equity:
Preferred stock, $0.01 par value, 10,000,000 shares authorized, none issued	Preferred stock, $0.01 par value, 10,000,000 shares authorized, none issued	—		—		Preferred stock, $0.01 par value, 10,000,000 shares authorized, none issued	0		0
Common stock, $0.01 par value, 40,000,000 shares authorized, 12,049,810 and 11,895,032 shares issued, respectively, and 11,933,684 and 11,806,679 shares outstanding, respectively		120		119
Common stock, $0.01 par value, 40,000,000 shares authorized, 12,053,763 and 11,895,032 shares issued, respectively, and 11,936,679 and 11,806,679 shares outstanding, respectively						Common stock, $0.01 par value, 40,000,000 shares authorized, 12,053,763 and 11,895,032 shares issued, respectively, and 11,936,679 and 11,806,679 shares outstanding, respectively	121		119
Additional paid-in capital	Additional paid-in capital	295,479		292,916		Additional paid-in capital	296,629		292,916
Treasury stock, held at cost, 116,126 and 88,353 shares, respectively		(2,368)		(2,282)
Treasury stock, held at cost, 117,084 and 88,353 shares, respectively						Treasury stock, held at cost, 117,084 and 88,353 shares, respectively	(2,372)		(2,282)
(Accumulated deficit) Retained earnings	(Accumulated deficit) Retained earnings	(206,880)		104,954		(Accumulated deficit) Retained earnings	(213,776)		104,954
Total Stockholders’ Equity	Total Stockholders’ Equity	86,351		395,707		Total Stockholders’ Equity	80,602		395,707
Total Liabilities and Stockholders’ Equity	Total Liabilities and Stockholders’ Equity	$	598,034	$	959,816	Total Liabilities and Stockholders’ Equity	$	590,679	$	959,816
See accompanying Notes to Condensed Consolidated Financial Statements.	See accompanying Notes to Condensed Consolidated Financial Statements.									See accompanying Notes to Condensed Consolidated Financial Statements.

Table of Contents

Condensed Consolidated Statements of Operations (Unaudited)

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


		Three Months Ended June 30, 2020		Three Months Ended June 30, 2019			Three Months Ended September 30, 2020		Three Months Ended September 30, 2019
Revenues:	Revenues:					Revenues:
Oil and gas sales	Oil and gas sales	$	24,846	$	74,703	Oil and gas sales	$	45,699	$	72,014

Operating Expenses:	Operating Expenses:					Operating Expenses:
General and administrative, net	General and administrative, net	6,180		6,624		General and administrative, net	5,833		6,247
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	13,716		24,029		Depreciation, depletion, and amortization	13,975		24,937
Accretion of asset retirement obligations	Accretion of asset retirement obligations	88		86		Accretion of asset retirement obligations	90		88
Lease operating costs	Lease operating costs	5,000		5,035		Lease operating costs	5,211		5,507
Workovers	Workovers	—		(127)		Workovers	8		93
Transportation and gas processing	Transportation and gas processing	4,554		6,728		Transportation and gas processing	5,094		6,782
Severance and other taxes	Severance and other taxes	2,037		3,950		Severance and other taxes	2,512		3,778
Write-down of oil and gas properties		260,342		—

Total Operating Expenses	Total Operating Expenses	291,917		46,325		Total Operating Expenses	32,723		47,432

Operating Income (Loss)	Operating Income (Loss)	(267,071)		28,378		Operating Income (Loss)	12,976		24,582

Non-Operating Income (Expense)	Non-Operating Income (Expense)					Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net	Gain (loss) on commodity derivatives, net	(8,458)		24,925		Gain (loss) on commodity derivatives, net	(12,944)		13,409
Interest expense, net	Interest expense, net	(8,026)		(9,306)		Interest expense, net	(7,444)		(9,435)
Other income (expense), net	Other income (expense), net	(1)		(28)		Other income (expense), net	(56)		134

Income (Loss) Before Income Taxes	Income (Loss) Before Income Taxes	(283,556)		43,969		Income (Loss) Before Income Taxes	(7,468)		28,690

Provision (Benefit) for Income Taxes	Provision (Benefit) for Income Taxes	22,420		(20,735)		Provision (Benefit) for Income Taxes	(572)		1,039

Net Income (Loss)	Net Income (Loss)	$	(305,976)	$	64,704	Net Income (Loss)	$	(6,896)	$	27,651

Per Share Amounts	Per Share Amounts					Per Share Amounts

Basic: Net Income (Loss)	Basic: Net Income (Loss)	$	(25.69)	$	5.51	Basic: Net Income (Loss)	$	(0.58)	$	2.35

Diluted: Net Income (Loss)	Diluted: Net Income (Loss)	$	(25.69)	$	5.49	Diluted: Net Income (Loss)	$	(0.58)	$	2.35

Weighted-Average Shares Outstanding - Basic	Weighted-Average Shares Outstanding - Basic	11,910		11,746		Weighted-Average Shares Outstanding - Basic	11,935		11,762

Weighted-Average Shares Outstanding - Diluted	Weighted-Average Shares Outstanding - Diluted	11,910		11,780		Weighted-Average Shares Outstanding - Diluted	11,935		11,780

See accompanying Notes to Condensed Consolidated Financial Statements.	See accompanying Notes to Condensed Consolidated Financial Statements.					See accompanying Notes to Condensed Consolidated Financial Statements.

Table of Contents

Condensed Consolidated Statements of Operations (Unaudited)

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


		Six Months Ended June 30, 2020		Six Months Ended June 30, 2019			Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
Revenues:	Revenues:					Revenues:
Oil and gas sales	Oil and gas sales	$	78,222	$	146,768	Oil and gas sales	$	123,921	$	218,781

Operating Expenses:	Operating Expenses:					Operating Expenses:
General and administrative, net	General and administrative, net	12,093		12,900		General and administrative, net	17,926		19,146
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	37,156		45,834		Depreciation, depletion, and amortization	51,130		70,771
Accretion of asset retirement obligations	Accretion of asset retirement obligations	173		168		Accretion of asset retirement obligations	263		257
Lease operating costs	Lease operating costs	10,812		9,567		Lease operating costs	16,023		15,074
Workovers	Workovers	—		519		Workovers	8		613
Transportation and gas processing	Transportation and gas processing	11,197		13,135		Transportation and gas processing	16,291		19,917
Severance and other taxes	Severance and other taxes	5,001		7,266		Severance and other taxes	7,513		11,044
Write-down of oil and gas properties	Write-down of oil and gas properties	355,948		—		Write-down of oil and gas properties	355,948		0
Total Operating Expenses	Total Operating Expenses	432,380		89,389		Total Operating Expenses	465,102		136,822

Operating Income (Loss)	Operating Income (Loss)	(354,158)		57,379		Operating Income (Loss)	(341,181)		81,959

Non-Operating Income (Expense)	Non-Operating Income (Expense)					Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net	Gain (loss) on commodity derivatives, net	79,829		20,903		Gain (loss) on commodity derivatives, net	66,884		34,312
Interest expense, net	Interest expense, net	(16,433)		(18,065)		Interest expense, net	(23,876)		(27,500)
Other income (expense), net	Other income (expense), net	107		37		Other income (expense), net	50		173

Income (Loss) Before Income Taxes	Income (Loss) Before Income Taxes	(290,655)		60,254		Income (Loss) Before Income Taxes	(298,123)		88,944

Provision (Benefit) for Income Taxes	Provision (Benefit) for Income Taxes	21,179		(20,503)		Provision (Benefit) for Income Taxes	20,607		(19,464)

Net Income (Loss)	Net Income (Loss)	$	(311,834)	$	80,757	Net Income (Loss)	$	(318,730)	$	108,408

Per Share Amounts	Per Share Amounts					Per Share Amounts

Basic: Net Income (Loss)	Basic: Net Income (Loss)	$	(26.28)	$	6.89	Basic: Net Income (Loss)	$	(26.81)	$	9.24

Diluted: Net Income (Loss)	Diluted: Net Income (Loss)	$	(26.28)	$	6.85	Diluted: Net Income (Loss)	$	(26.81)	$	9.21

Weighted-Average Shares Outstanding - Basic	Weighted-Average Shares Outstanding - Basic	11,868		11,727		Weighted-Average Shares Outstanding - Basic	11,890		11,739

Weighted-Average Shares Outstanding - Diluted	Weighted-Average Shares Outstanding - Diluted	11,868		11,786		Weighted-Average Shares Outstanding - Diluted	11,890		11,776

See accompanying Notes to Condensed Consolidated Financial Statements.	See accompanying Notes to Condensed Consolidated Financial Statements.					See accompanying Notes to Condensed Consolidated Financial Statements.

Table of Contents

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

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


		Common Stock		Additional Paid-In Capital		Treasury Stock		Retained Earnings (Accumulated Deficit)		Total			Common Stock		Additional Paid-In Capital		Treasury Stock		Retained Earnings (Accumulated Deficit)		Total
Balance, December 31, 2018	Balance, December 31, 2018	$	118	$	286,281	$	(1,870)	$	(9,702)	$	274,827	Balance, December 31, 2018	$	118	$	286,281	$	(1,870)	$	(9,702)	$	274,827

Purchase of treasury shares (11,076 shares)	Purchase of treasury shares (11,076 shares)	—		—		(260)		—		(260)		Purchase of treasury shares (11,076 shares)	0		0		(260)		0		(260)

Issuance of restricted stock (61,263 shares)	Issuance of restricted stock (61,263 shares)	—		—		—		—		—		Issuance of restricted stock (61,263 shares)	0		0		0		0		0
Share-based compensation	Share-based compensation	—		1,849		—		—		1,849		Share-based compensation	0		1,849		0		0		1,849
Net Income	Net Income	—		—		—		16,053		16,053		Net Income	0		0		0		16,053		16,053
Balance, March 31, 2019	Balance, March 31, 2019	$	118	$	288,130	$	(2,130)	$	6,351	$	292,469	Balance, March 31, 2019	$	118	$	288,130	$	(2,130)	$	6,351	$	292,469

Purchase of treasury shares (3,877 shares)	Purchase of treasury shares (3,877 shares)	—		—		(58)		—		(58)		Purchase of treasury shares (3,877 shares)	0		0		(58)		0		(58)
Issuance of restricted stock (19,162 shares)	Issuance of restricted stock (19,162 shares)	—		—		—		—		—		Issuance of restricted stock (19,162 shares)	0		0		0		0		0

Share-based compensation	Share-based compensation	—		1,769		—		—		1,769		Share-based compensation	0		1,769		0		0		1,769
Net Income	Net Income	—		—		—		64,704		64,704		Net Income	0		0		0		64,704		64,704
Balance, June 30, 2019	Balance, June 30, 2019	$	118	$	289,899	$	(2,188)	$	71,055	$	358,884	Balance, June 30, 2019	$	118	$	289,899	$	(2,188)	$	71,055	$	358,884

Purchase of treasury shares (411 shares)												Purchase of treasury shares (411 shares)	0		0		(5)		0		(5)
Issuance of restricted stock (26,684 shares)												Issuance of restricted stock (26,684 shares)	1		0		0		0		1
Share-based compensation												Share-based compensation	0		1,855		0		0		1,855
Net Income												Net Income	0		0		0		27,651		27,651
Balance, September 30, 2019												Balance, September 30, 2019	$	119	$	291,754	$	(2,193)	$	98,706	$	388,386

Balance, December 31, 2019	Balance, December 31, 2019	$	119	$	292,916	$	(2,282)	$	104,954	$	395,707	Balance, December 31, 2019	$	119	$	292,916	$	(2,282)	$	104,954	$	395,707

Purchase of treasury shares (26,675 shares)	Purchase of treasury shares (26,675 shares)	—		—		(83)		—		(83)		Purchase of treasury shares (26,675 shares)	0		—		(83)		0		(83)

Issuance of restricted stock (105,108 shares)	Issuance of restricted stock (105,108 shares)	1		(1)		—		—		—		Issuance of restricted stock (105,108 shares)	1		(1)		0		0		0
Share-based compensation	Share-based compensation	—		1,335		—		—		1,335		Share-based compensation	0		1,335		0		0		1,335
Net Loss	Net Loss	—		—		—		(5,858)		(5,858)		Net Loss	0		0		0		(5,858)		(5,858)
Balance, March 31, 2020	Balance, March 31, 2020	$	120	$	294,250	$	(2,365)	$	99,096	$	391,101	Balance, March 31, 2020	$	120	$	294,250	$	(2,365)	$	99,096	$	391,101

Shares issued from warrant exercise (5 shares)	Shares issued from warrant exercise (5 shares)	—		—		—		—		—		Shares issued from warrant exercise (5 shares)	0		0		0		0		0
Purchase of treasury shares (1,098 shares)	Purchase of treasury shares (1,098 shares)	—		—		(3)		—		(3)		Purchase of treasury shares (1,098 shares)	0		0		(3)		0		(3)
Issuance of restricted stock (49,665 shares)	Issuance of restricted stock (49,665 shares)	—		—		—		—		—		Issuance of restricted stock (49,665 shares)	0		0		0		0		0

Share-based compensation	Share-based compensation	—		1,229		—		—		1,229		Share-based compensation	0		1,229		0		0		1,229
Net Loss	Net Loss	—		—		—		(305,976)		(305,976)		Net Loss	0		0		0		(305,976)		(305,976)
Balance, June 30, 2020	Balance, June 30, 2020	$	120	$	295,479	$	(2,368)	$	(206,880)	$	86,351	Balance, June 30, 2020	$	120	$	295,479	$	(2,368)	$	(206,880)	$	86,351

Purchase of treasury shares (958 shares)												Purchase of treasury shares (958 shares)	0		0		(4)		0		(4)
Issuance of restricted stock (3,953 shares)												Issuance of restricted stock (3,953 shares)	1		0		0		0		1

Share-based compensation												Share-based compensation	0		1,150		0		0		1,150
Net Loss												Net Loss	0		0		0		(6,896)		(6,896)
Balance, September 30, 2020												Balance, September 30, 2020	$	121	$	296,629	$	(2,372)	$	(213,776)	$	80,602

See accompanying Notes to Condensed Consolidated Financial Statements.	See accompanying Notes to Condensed Consolidated Financial Statements.																					See accompanying Notes to Condensed Consolidated Financial Statements.

Table of Contents

Condensed Consolidated Statements of Cash Flows (Unaudited)

SilverBow Resources, Inc. and ~~Subsidiaries~~Subsidiary (in thousands)


		Six Months Ended June 30, 2020		Six Months Ended June 30, 2019			Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
Cash Flows from Operating Activities:	Cash Flows from Operating Activities:					Cash Flows from Operating Activities:
Net income (loss)	Net income (loss)	$	(311,834)	$	80,757	Net income (loss)	$	(318,730)	$	108,408
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities	Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities					Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	37,156		45,834		Depreciation, depletion, and amortization	51,130		70,771
Write-down of oil and gas properties	Write-down of oil and gas properties	355,948		—		Write-down of oil and gas properties	355,948		0
Accretion of asset retirement obligations	Accretion of asset retirement obligations	173		168		Accretion of asset retirement obligations	263		257
Deferred income taxes	Deferred income taxes	21,087		(20,732)		Deferred income taxes	21,087		(19,735)
Share-based compensation	Share-based compensation	2,437		3,339		Share-based compensation	3,503		5,091
(Gain) Loss on derivatives, net	(Gain) Loss on derivatives, net	(79,829)		(20,903)		(Gain) Loss on derivatives, net	(66,884)		(34,312)
Cash settlement (paid) received on derivatives	Cash settlement (paid) received on derivatives	67,496		4,381		Cash settlement (paid) received on derivatives	76,150		16,087
Settlements of asset retirement obligations	Settlements of asset retirement obligations	(15)		(47)		Settlements of asset retirement obligations	(27)		(67)
Write down of debt issuance cost	Write down of debt issuance cost	459		—		Write down of debt issuance cost	459		0
Other	Other	1,814		1,160		Other	2,436		1,782
Change in operating assets and liabilities	Change in operating assets and liabilities					Change in operating assets and liabilities
(Increase) decrease in accounts receivable and other current assets	(Increase) decrease in accounts receivable and other current assets	14,293		13,411		(Increase) decrease in accounts receivable and other current assets	7,413		13,746
Increase (decrease) in accounts payable and accrued liabilities	Increase (decrease) in accounts payable and accrued liabilities	(10,137)		(6,928)		Increase (decrease) in accounts payable and accrued liabilities	(3,981)		(8,824)
Increase (decrease) in income taxes payable	Increase (decrease) in income taxes payable	92		—		Increase (decrease) in income taxes payable	(480)		217
Increase (decrease) in accrued interest	Increase (decrease) in accrued interest	(140)		(180)		Increase (decrease) in accrued interest	(505)		(356)
Net Cash Provided by (Used in) Operating Activities	Net Cash Provided by (Used in) Operating Activities	99,000		100,260		Net Cash Provided by (Used in) Operating Activities	127,782		153,065
Cash Flows from Investing Activities:	Cash Flows from Investing Activities:					Cash Flows from Investing Activities:
Additions to property and equipment	Additions to property and equipment	(85,594)		(174,138)		Additions to property and equipment	(102,713)		(234,859)
Acquisition of oil and gas properties	Acquisition of oil and gas properties	(3,394)		—		Acquisition of oil and gas properties	(3,441)		0
Proceeds from the sale of property and equipment	Proceeds from the sale of property and equipment	4,752		(96)		Proceeds from the sale of property and equipment	4,752		(96)
Payments on property sale obligations	Payments on property sale obligations	(426)		(2,840)		Payments on property sale obligations	(426)		(4,402)

Net Cash Provided by (Used in) Investing Activities	Net Cash Provided by (Used in) Investing Activities	(84,662)		(177,074)		Net Cash Provided by (Used in) Investing Activities	(101,828)		(239,357)
Cash Flows from Financing Activities:	Cash Flows from Financing Activities:					Cash Flows from Financing Activities:

Proceeds from bank borrowings	Proceeds from bank borrowings	50,000		227,000		Proceeds from bank borrowings	71,000		315,000
Payments of bank borrowings	Payments of bank borrowings	(59,000)		(149,000)		Payments of bank borrowings	(97,000)		(228,000)

Purchase of treasury shares	Purchase of treasury shares	(86)		(318)		Purchase of treasury shares	(90)		(323)

Net Cash Provided by (Used in) Financing Activities	Net Cash Provided by (Used in) Financing Activities	(9,086)		77,682		Net Cash Provided by (Used in) Financing Activities	(26,090)		86,677

Net Increase (Decrease) in Cash and Cash Equivalents	Net Increase (Decrease) in Cash and Cash Equivalents	5,252		868		Net Increase (Decrease) in Cash and Cash Equivalents	(136)		385
Cash and Cash Equivalents at Beginning of Period	Cash and Cash Equivalents at Beginning of Period	1,358		2,465		Cash and Cash Equivalents at Beginning of Period	1,358		2,465
Cash and Cash Equivalents at End of Period	Cash and Cash Equivalents at End of Period	$	6,610	$	3,333	Cash and Cash Equivalents at End of Period	$	1,222	$	2,850

Supplemental Disclosures of Cash Flow Information:	Supplemental Disclosures of Cash Flow Information:					Supplemental Disclosures of Cash Flow Information:
Cash paid during period for interest, net of amounts capitalized	Cash paid during period for interest, net of amounts capitalized	$	15,006	$	17,128	Cash paid during period for interest, net of amounts capitalized	$	22,290	$	26,172

Changes in capital accounts payable and capital accruals	Changes in capital accounts payable and capital accruals	$	(28,618)	$	(16,521)	Changes in capital accounts payable and capital accruals	$	(25,641)	$	(27,905)

See accompanying Notes to Condensed Consolidated Financial Statements.	See accompanying Notes to Condensed Consolidated Financial Statements.					See accompanying Notes to Condensed Consolidated Financial Statements.

Table of Contents

Notes to Condensed Consolidated Financial Statements (Unaudited)

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

The condensed consolidated financial statements included herein are unaudited and 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, 2019.

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

(2) Summary of Significant Accounting Policies

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

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

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 March, the spot price of West Texas Intermediate (“WTI”) crude oil declined over 50% in response to reductions in global demand due to the COVID-19 pandemic and announcements by Saudi Arabia and Russia of plans to increase crude oil production. Following this unprecedented collapse in crude oil prices, the spot price of Brent and WTI crude oil closed at approximately $15 and $21 per barrel, respectively, on March 31, 2020.

In April 2020, WTI oil prices declined further to approximately $10 per barrel for May 2020 delivery. Crude oil prices fell further in April but partially recovered during the second quarter of 2020 with Brent and WTI crude oil closing at approximately $41 and $39 per barrel, respectively, on June 30, ~~2020, although crude~~2020. Crude oil prices ~~continue to be volatile.~~traded slightly higher in the third quarter of 2020 with Brent and WTI crude closing at approximately $42 and $40 per barrel, on September 30, 2020.

~~Table of Contents~~

In response to these market conditions, including the COVID-19 ~~outbreak~~pandemic and the decline in oil prices and economic outlook, 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 oil volumes and a substantial portion of natural gas volumes. Approximately 20 million cubic feet per day (“MMcf/d”) of net gas production remained shut-in at quarter-end. The Company began returning these volumes to production in late October 2020 to align with favorable natural gas prices.

Table of Contents

The full impact of the COVID-19 pandemic continues to evolve as of the date of this report. As such, the full magnitude that the pandemic will have on the Company’s financial condition, liquidity, and future results of operations is uncertain. Management is actively monitoring the impact of the COVID-19 pandemic on the Company's financial condition, liquidity, operations, suppliers, industry and workforce.

In addition, ~~as described further below, we also recorded an impairment on oil and natural gas properties for the three and six months ended June 30, 2020. If~~if the depressed pricing environment continues for an extended period, it may in the future lead to (i) a further reduction in oil and natural gas reserves, including the possible further removal of proved undeveloped reserves (ii) further impairment of proved and/or unproved oil and natural gas properties and a potential increase in depletion expense and (iii) reductions in the borrowing base under the Credit Agreement as discussed in Note 6.

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

Subsequent Events. We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements. Effective November 2, 2020, as part of our regularly scheduled borrowing base redetermination, the borrowing base of our Credit Facility (as defined below) was decreased from $330 million to $310 million. See Note 6 for more information.

Through ~~July~~October 31, 2020, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after ~~June~~September 30, 2020:


Oil Derivative Contracts (New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) Settlements)	Total Volumes (Bbls)(1)	Weighted-Average Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
2022 Contracts
Swap Contracts
3Q22	36,800	$	43.38
Collar Contracts
1Q22	40,500			$	40.00	$	45.55
2Q22	29,400			$	40.00	$	45.30

(1) Bbl refers to one barrel of oil.


Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
2022 Contracts
Collar Contracts
3Q22	920,000	$	2.35	$	2.65


Oil Derivative Collars (New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) Settlements)		Total Volumes (Bbls)	Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
Collar Contracts
Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements)							Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes (MMBtu)	Weighted-Average Price
2022 Contracts	2022 Contracts						2022 Contracts
1Q22							1Q22	1,800,000	$	(0.08)
2Q22	2Q22	86,450	$	39.00	$	46.50	2Q22	1,820,000	$	(0.08)
3Q22							3Q22	1,840,000	$	(0.08)
4Q22							4Q22	1,840,000	$	(0.08)

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

Table of Contents

may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include:

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

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

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

•estimates of future costs to develop and produce reserves,

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

~~Table of Contents~~

industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known.

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

Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended ~~June~~September 30, 2020 and 2019, such internal costs when capitalized totaled ~~$0.9~~$0.8 million and ~~$1.3~~$1.2 million, respectively. For the ~~six~~nine months ended ~~June~~September 30, 2020 and 2019, such internal costs capitalized totaled ~~$2.0~~$2.8 million and ~~$2.9~~$4.1 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 6 of these Notes to Condensed Consolidated Financial Statements for further discussion on capitalized interest costs).

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


		June 30, 2020		December 31, 2019			September 30, 2020		December 31, 2019
Property and Equipment	Property and Equipment					Property and Equipment
Proved oil and gas properties	Proved oil and gas properties	$	1,268,374	$	1,201,296	Proved oil and gas properties	$	1,287,962	$	1,201,296
Unproved oil and gas properties	Unproved oil and gas properties	30,043		41,201		Unproved oil and gas properties	30,661		41,201
Furniture, fixtures and other equipment	Furniture, fixtures and other equipment	5,134		5,220		Furniture, fixtures and other equipment	5,166		5,220
Less – Accumulated depreciation, depletion, amortization & impairment	Less – Accumulated depreciation, depletion, amortization & impairment	(773,836)		(380,728)		Less – Accumulated depreciation, depletion, amortization & impairment	(787,830)		(380,728)
Property and Equipment, Net	Property and Equipment, Net	$	529,715	$	866,989	Property and Equipment, Net	$	535,959	$	866,989

No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would

Table of Contents

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

~~Table of Contents~~

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 ~~$260.3 million and~~ $355.9 million for the ~~three and six~~nine months ended ~~June~~September 30, 2020 on our oil and natural gas properties. There was 0 impairment for the three ~~and six~~ months ended ~~June~~September 30, 2020 and 0 impairment for the three and nine months ended September 30, 2019.

If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, ~~or remain at levels prevalent in the current period,~~ it is possible that non-cash write-downs of our oil and natural gas properties will occur 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 ~~June~~September 30, 2020 and December 31, 2019, we had an allowance for doubtful accounts of less than $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable, net” balance on the accompanying condensed consolidated balance sheets.

At ~~June~~September 30, 2020, our “Accounts receivable, net” balance included ~~$11.2~~$17.8 million for oil and gas sales, ~~$0.4~~$0.5 million due from joint interest owners, ~~$6.3~~$6.4 million for severance tax credit receivables and ~~$5.6~~$4.2 million for other receivables.

Table of Contents

At December 31, 2019, our “Accounts receivable, net” balance included $24.6 million for oil and gas sales, $3.7 million due from joint interest owners, $5.4 million for severance tax credit receivables and $3.3 million for other receivables.

Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the ~~six~~nine months ended ~~June~~September 30, 2020 and 2019 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was ~~$0.9~~$1.1 million ~~and $1.3 million~~ for both the three months ended ~~June~~September 30, 2020 and 2019 ~~respectively,~~ and ~~$2.2~~$3.2 million and ~~$2.6~~$3.7 million for the ~~six~~nine months ended ~~June~~September 30, 2020 and 2019, 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. ~~During~~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 ~~had~~ determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other deferred tax assets and, accordingly, recorded a full valuation allowance in the second quarter to offset its net 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~~The Company’s effective tax ~~provision of $22.4 million~~rate was approximately 7.7% and ~~$21.2 million~~(6.9)% for the three and ~~six~~nine months ended ~~June~~September 30, 2020, ~~respectively, which was inclusive~~respectively. The difference in the Company’s effective tax rate and the statutory rate for the nine months ended September 30, 2020 related to the effects of recording a valuation allowance against the Company’s net deferred tax assets in the second quarter of 2020 and the state income tax ~~expense. In~~provision. Our income tax benefit for the three months ended September 30, 2020 is fully attributable to a current state income tax benefit. The income tax benefit for the nine months ended September 30, 2019 wewas primarily the effect of releasing the valuation allowance previously recorded against the Company’s net deferred tax assets. During the second quarter of 2019, the Company was able to complete several operational initiatives that resulted in increased production, lower development costs and expanded inventory of development prospects. The results of these initiatives led management to determine, after weighing both positive and negative evidence, that the Company will more likely than not be able to realize the benefits of its deferred tax assets. Accordingly, the Company released the valuation allowance, resulting in ~~a net deferred~~an income tax benefit of ~~$20.7 million and $20.5~~$19.5 million for the ~~three and six~~nine months ended ~~June~~September 30, ~~2019, respectively.~~2019.

Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At ~~June~~September 30, 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

~~Table of Contents~~

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.

Table of Contents

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


		Three Months Ended June 30, 2020		Three Months Ended June 30, 2019		Six Months Ended June 30, 2020		Six Months Ended June 30, 2019			Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
Oil, natural gas and NGLs sales:	Oil, natural gas and NGLs sales:									Oil, natural gas and NGLs sales:
Oil	Oil	$	5,265	$	24,940	$	23,315	$	39,547	Oil	$	17,665	$	28,894	$	40,979	$	68,441
Natural gas	Natural gas	18,103		43,597		49,574		94,902		Natural gas	23,595		37,040		73,170		131,941
NGLs	NGLs	1,478		6,166		5,333		12,319		NGLs	4,439		6,080		9,772		18,400
Total	Total	$	24,846	$	74,703	$	78,222	$	146,768	Total	$	45,699	$	72,014	$	123,921	$	218,781

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


		June 30, 2020		December 31, 2019			September 30, 2020		December 31, 2019
Trade accounts payable	Trade accounts payable	$	5,466	$	26,121	Trade accounts payable	$	8,063	$	26,121
Accrued operating expenses	Accrued operating expenses	2,587		3,873		Accrued operating expenses	2,816		3,873
Accrued compensation costs	Accrued compensation costs	2,784		4,601		Accrued compensation costs	3,414		4,601
Asset retirement obligations – current portion	Asset retirement obligations – current portion	382		392		Asset retirement obligations – current portion	439		392
Accrued non-income based taxes	Accrued non-income based taxes	3,102		1,413		Accrued non-income based taxes	4,133		1,413
Accrued corporate and legal fees	Accrued corporate and legal fees	158		109		Accrued corporate and legal fees	162		109
Other payables	Other payables	1,321		2,834		Other payables	3,680		2,834
Total accounts payable and accrued liabilities	Total accounts payable and accrued liabilities	$	15,800	$	39,343	Total accounts payable and accrued liabilities	$	22,707	$	39,343

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

Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock, held at cost” on the accompanying condensed consolidated balance sheets. For the ~~six~~nine months ended ~~June~~September 30, 2020, we purchased ~~27,773~~28,731 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares.

(3) Leases

The Company adopted the standard provided in the Financial Accounting Standards Board's Accounting Standards Update 2016-02 on January 1, 2019, using the modified retrospective transition approach. The Company has elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that allows an entity to carry forward historical accounting treatment for land easements on existing agreements upon adoption. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the Consolidated Balance Sheet. We have elected to not account for lease and non-lease components separately.

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 ~~June~~September 30, 2020, all of the Company’s leases were operating leases.

~~Table of Contents~~

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

Table of Contents

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


		Three Months Ended June 30, 2020		Three Months Ended June 30, 2019		Six Months Ended June 30, 2020		Six Months Ended June 30, 2019			Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets	Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets									Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets
Property, plant and equipment acquisitions - short-term leases	Property, plant and equipment acquisitions - short-term leases	$	118	$	2,184	$	2,302	$	6,168	Property, plant and equipment acquisitions - short-term leases	$	0	$	2,208	$	2,302	$	8,376
Property, plant and equipment acquisitions - operating leases	Property, plant and equipment acquisitions - operating leases	5		11		10		18		Property, plant and equipment acquisitions - operating leases	0		12		10		30
Total lease costs in property, plant and equipment additions	Total lease costs in property, plant and equipment additions	$	123	$	2,195	$	2,312	$	6,186	Total lease costs in property, plant and equipment additions	$	0	$	2,220	$	2,312	$	8,406


		Three Months Ended June 30, 2020		Three Months Ended June 30, 2019		Six Months Ended June 30, 2020		Six Months Ended June 30, 2019			Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
Lease Costs Included in the Condensed Consolidated Statements of Operations	Lease Costs Included in the Condensed Consolidated Statements of Operations									Lease Costs Included in the Condensed Consolidated Statements of Operations
Lease operating costs - short-term leases	Lease operating costs - short-term leases	$	650	$	329	$	900	$	1,664	Lease operating costs - short-term leases	$	124	$	357	$	575	$	2,022
Lease operating costs - operating leases	Lease operating costs - operating leases	1,433		1,084		2,870		1,138		Lease operating costs - operating leases	1,397		1,387		4,267		2,524
General and administrative, net - operating leases	General and administrative, net - operating leases	179		175		359		331		General and administrative, net - operating leases	172		173		532		504
Total lease cost expensed	Total lease cost expensed	$	2,262	$	1,588	$	4,129	$	3,133	Total lease cost expensed	$	1,693	$	1,917	$	5,374	$	5,050

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


	~~June~~September 30, 2020
Weighted-average remaining lease term (in years)	1.7
Weighted-average discount rate	~~4.7~~4.6	%

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


		As of June 30, 2020			As of September 30, 2020
2020 (Remaining)	2020 (Remaining)	$	3,573	2020 (Remaining)	$	1,772
2021	2021	3,676		2021	3,636
2022	2022	419		2022	559
2023	2023	93		2023	169
2024	2024	40		2024	40
Thereafter	Thereafter	312		Thereafter	310
Total undiscounted lease payments	Total undiscounted lease payments	8,113		Total undiscounted lease payments	6,486
Present value adjustment	Present value adjustment	(363)		Present value adjustment	(287)
Net operating lease liabilities	Net operating lease liabilities	$	7,750	Net operating lease liabilities	$	6,199

~~Table of Contents~~

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


		Six Months Ended June 30, 2020		Six Months Ended June 30, 2019			Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities	Cash paid for amounts included in the measurement of lease liabilities					Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	Operating cash flows from operating leases	$	3,225	$	1,457	Operating cash flows from operating leases	$	4,793	$	3,013
Investing cash flows from operating leases	Investing cash flows from operating leases	$	10	$	18	Investing cash flows from operating leases	$	10	$	30

(4) Share-Based Compensation

Table of Contents

Share-Based Compensation Plans

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

The Company computes a deferred tax benefit for restricted stock 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~~$1.1 million and ~~$1.6~~$1.8 million for the three months ended ~~June~~September 30, 2020 and 2019, respectively, and ~~$2.4~~$3.5 million and ~~$3.3~~$5.1 million for the ~~six~~nine months ended ~~June~~September 30, 2020 and 2019, respectively. Capitalized share-based compensation was less than $0.1 million and was $0.1 million for the three months ended ~~June~~September 30, 2020 and 2019, respectively, and ~~$0.1~~$0.2 million and ~~$0.3~~$0.4 million for the ~~six~~nine months ended ~~June~~September 30, 2020 and 2019, respectively.

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.

On April 2, 2019, our Board of Directors authorized a one-time grant of market-based awards (both RSUs and PSUs) in exchange for the cancellation of special equity awards (both RSUs and stock options) made to our named executive officers on August 9, 2018 (the “Equity Award Exchange”). As required under the terms of the 2016 Plan, this Equity Award Exchange was approved by the Company's shareholders on May 21, 2019. Pursuant to the Equity Award Exchange our executives were given the opportunity to exchange out-of-the-money or “underwater” stock options that were granted in August 2018 and certain RSUs also granted in August 2018 to receive a new equity award that consists of 50% time-based RSUs and 50% PSUs, granted under the 2016 Plan. The incremental compensation cost associated with the Equity Award Exchange was determined to be $1.2 million. This incremental cost was measured as the excess of the fair value of each new equity award, measured as of the date the new equity awards were granted, over the fair value of the stock options and RSUs surrendered in exchange for the new equity awards, measured immediately prior to the cancellation. This incremental compensation cost is being recognized ratably over the vesting period or performance period, as applicable, of the new equity awards.

Stock Option Awards

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

~~Table of Contents~~

At ~~June~~September 30, 2020, we had ~~$0.9~~$0.7 million of unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the ~~six~~nine months ended ~~June~~September 30, 2020:


	Shares	Wtd. Avg. Exer. Price
Options outstanding, beginning of period	324,324	$	27.68



Options expired	(17,372)	$	26.96

Options outstanding, end of period	306,952	$	27.72
Options exercisable, end of period	209,426	$	28.39

Our outstanding stock option awards at ~~June~~September 30, 2020 had 0 measurable aggregate intrinsic value. At ~~June~~September 30, 2020, the weighted-average remaining contract life of stock option awards outstanding was ~~5.3~~5.0 years and exercisable was ~~4.5~~4.3 years. The total intrinsic value of stock option awards exercisable had 0 value for the ~~six~~nine months ended ~~June~~September 30, 2020.

Table of Contents

Restricted Stock Units

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

As of ~~June~~September 30, 2020, we had ~~$3.8~~$3.1 million unrecognized compensation expense related to our RSUs which is expected to be recognized over a weighted-average period of ~~1.6~~1.3 years.

The following table provides information regarding RSU activity for the ~~six~~nine months ended ~~June~~September 30, 2020:


		RSUs	Wtd. Avg. Grant Price			RSUs	Wtd. Avg. Grant Price
RSUs outstanding, beginning of period	RSUs outstanding, beginning of period	342,683	$	22.10	RSUs outstanding, beginning of period	342,683	$	22.10
RSUs granted	RSUs granted	397,285	$	2.83	RSUs granted	397,285	$	2.83

RSUs forfeited					RSUs forfeited	(1,794)	$	8.41
RSUs vested	RSUs vested	(154,773)	$	21.42	RSUs vested	(158,726)	$	21.38
RSUs outstanding, end of period	RSUs outstanding, end of period	585,195	$	9.20	RSUs outstanding, end of period	579,448	$	9.13

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% and 200% of the target payout. The fair value as of the grant date was $41.66 per unit or 150.6% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years.

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

As of ~~June~~September 30, 2020, we had ~~$1.6~~$1.3 million unrecognized compensation expense related to our PSUs based on the assumption of 100% target payout. The remaining weighted-average performance period is ~~1.4~~1.2 years. NaN shares vested during the ~~six~~nine months ended ~~June~~September 30, 2020.

(5) Earnings Per Share

Basic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) 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

~~Table of Contents~~

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 ~~June~~September 30, 2020 and 2019 are discussed below.

Table of Contents

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


		Three Months Ended June 30, 2020								Three Months Ended June 30, 2019										Three Months Ended September 30, 2020			Three Months Ended September 30, 2019
		Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)		Shares	Per Share Amount			Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)		Shares	Per Share Amount
Basic EPS:	Basic EPS:											Basic EPS:
Net Income (Loss) and Share Amounts	Net Income (Loss) and Share Amounts	$	(305,976)	11,910	$	(25.69)	$	64,704	11,746	$	5.51	Net Income (Loss) and Share Amounts	$	(6,896)	11,935	$	(0.58)	$	27,651	11,762	$	2.35
Dilutive Securities:	Dilutive Securities:											Dilutive Securities:

RSU Awards	RSU Awards			—					34			RSU Awards			0					18

Diluted EPS:	Diluted EPS:											Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	Net Income (Loss) and Assumed Share Conversions	$	(305,976)	11,910	$	(25.69)	$	64,704	11,780	$	5.49	Net Income (Loss) and Assumed Share Conversions	$	(6,896)	11,935	$	(0.58)	$	27,651	11,780	$	2.35

Six Months Ended June 30, 2020 Six Months Ended June 30, 2019
Net Income (Loss) Shares Per Share Amount Net Income (Loss) Shares Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts $ (311,834) 11,868 $ (26.28) $ 80,757 11,727 $ 6.89
Dilutive Securities:
RSU Awards — 59
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions $ (311,834) 11,868 $ (26.28) $ 80,757 11,786 $ 6.85


	Nine Months Ended September 30, 2020					Nine Months Ended September 30, 2019
	Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)		Shares	Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	(318,730)	11,890	$	(26.81)	$	108,408	11,739	$	9.24
Dilutive Securities:

RSU Awards			0					37

Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	(318,730)	11,890	$	(26.81)	$	108,408	11,776	$	9.21

Approximately 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for the three months ended ~~June~~September 30, 2020 because they were antidilutive due to the net loss, and 0.4 million stock options to purchase shares were not included in the computation of Diluted EPS for the three months ended September 30, 2019 because they were antidilutive, while 0.3 million stock options to purchase shares were not included for the nine months ended September 30, 2020 because they were antidilutive due to the net loss, and 0.5 million stock options to purchase shares were not included in the computation of Diluted EPS for the ~~three~~nine months ended June 30, 2019 because they were antidilutive, while 0.3 million stock options to purchase shares were not included for the six months ended June 30, 2020 because they were antidilutive due to the net loss and 0.6 million stock options to purchase shares were not included in the computation of Diluted EPS for the six months ended JuneSeptember 30, 2019 because they were antidilutive.

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 ~~June~~September 30, 2020 because they were antidilutive due to the net loss, and ~~0.2~~0.4 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended ~~June~~September 30, 2019, because they were antidilutive, while 0.2 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the ~~six~~nine months ended ~~June~~September 30, 2020 because they were antidilutive due to the net loss, and approximately 0.1 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the ~~six~~nine months ended ~~June~~September 30, 2019 because they were antidilutive.

Approximately 0.1 million shares of PSUs that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended ~~June~~September 30, 2020 because they were antidilutive due to the net loss, and approximately 0.1 million shares of PSUs were not included for the three months ended ~~June~~September 30, 2019 because they were antidilutive, while 0.1 million shares of PSUs were not included for the ~~six~~nine months ended ~~June~~September 30, 2020 because they were antidilutive due to the net loss, and approximately 0.1 million shares of PSUs were not included for the ~~six~~nine months ended ~~June~~September 30, 2019 because they were antidilutive.

Approximately 2.1 million warrants to purchase common stock were not included in the computation of Diluted EPS for the three and ~~six~~nine months ended ~~June~~September 30, 2019 because these warrants were antidilutive. There were 0 warrants to purchase common stock for the three and ~~six~~nine months ended ~~June~~September 30, 2020 as the warrants expired.

1718

Table of Contents

(6) Long-Term Debt

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


		June 30, 2020		December 31, 2019			September 30, 2020		December 31, 2019
Credit Facility Borrowings ⁽¹⁾	Credit Facility Borrowings ⁽¹⁾	$	270,000	$	279,000	Credit Facility Borrowings (1)	$	253,000	$	279,000
Second Lien Notes due 2024	Second Lien Notes due 2024	200,000		200,000		Second Lien Notes due 2024	200,000		200,000
		470,000		479,000			453,000		479,000
Unamortized discount on Second Lien Notes due 2024	Unamortized discount on Second Lien Notes due 2024	(1,425)		(1,550)		Unamortized discount on Second Lien Notes due 2024	(1,361)		(1,550)
Unamortized debt issuance cost on Second Lien Notes due 2024	Unamortized debt issuance cost on Second Lien Notes due 2024	(4,185)		(4,550)		Unamortized debt issuance cost on Second Lien Notes due 2024	(3,995)		(4,550)
Long-Term Debt, net	Long-Term Debt, net	$	464,390	$	472,900	Long-Term Debt, net	$	447,644	$	472,900

(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our consolidated balance sheet. As of ~~June~~September 30, 2020 and December 31, 2019, we had ~~$2.0~~$1.7 million and $3.1 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.

Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were ~~$270.0~~$253.0 million and $279.0 million as of ~~June~~September 30, 2020 and December 31, 2019, 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”). The Company entered into the ~~Fifth~~Sixth Amendment to the Credit Facility, effective ~~May 12,~~November 2, 2020 (the ~~“Fifth~~“Sixth Amendment”), which among other things, (i) decreased the borrowing base under the Credit Facility to $310 million (from $330 ~~million~~million) as part of the regularly scheduled semi-annual ~~redetermination;~~redetermination and (ii) ~~increased~~decreased the ~~applicable margin used~~ratio of total debt to calculate the interest rate under the Credit Facility by 75 basis points; and (iii) incorporated anti-cash hoarding provisions, including defensive draw and sweep provisions for a Consolidated Cash Balance (as defined in the Credit Agreement) in excess of the lesser of $30 million and 10% of the borrowing base.EBITDA (defined below) to not exceed 3.5 to 1.0.

The Credit Facility matures April 19, 2022, and provides for a maximum credit amount of $600 million, subject to the current borrowing base of ~~$330~~$310 million as of ~~June 30,~~November 2, 2020. The borrowing base is regularly redetermined on or about May and November of each calendar year and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, ~~each of~~ the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders, in their discretion, in accordance with their oil and gas lending criteria at the time of the relevant redetermination. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to $25 million, which reduces the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit.

Interest under the Credit Facility accrues at the Company’s option either at an ~~Alternative~~Alternate Base Rate plus the applicable margin (“ABR Loans”) or the LIBOR Rate plus the applicable margin (“Eurodollar Loans”). Since May 12, 2020, the applicable margin ranged from 1.75% to 2.75% for ABR Loans and 2.75% to 3.75% 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 Sixth Amendment includes technical updates to address this matter, and we are currently evaluating the potential impact of eventual replacement of the LIBOR interest rate.

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

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) 4.0 to 1.0 as of the last day of each fiscal ~~quarter;~~quarter for any fiscal quarter ending on or before September 30, 2020 and (ii) 3.5 to 1.0 as of the last day of each fiscal quarter, commencing with fiscal quarter ending December 31, 2020; and

•a current ratio, as defined in the Credit Agreement, which includes in the numerator available borrowings undrawn under the borrowing base, of not less than 1.0 to 1.0 as of the last day of each fiscal quarter.

1819

Table of Contents

As of ~~June~~September 30, 2020, the Company was in compliance with all financial covenants under the Credit Agreement. Maintaining or increasing our borrowing base under our Credit Facility is dependent on many factors, including commodity prices, our hedge positions, changes in our lenders' lending criteria and our ability to raise capital to drill wells to replace produced reserves.

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

Total interest expense on the Credit Facility, which includes commitment fees and amortization of debt issuance costs, was ~~$3.5~~$2.9 million and ~~$4.0~~$4.2 million for the three months ended ~~June~~September 30, 2020 and 2019, respectively, and ~~$6.9~~$9.8 million and ~~$7.5~~$11.7 million for the ~~six~~nine months ended ~~June~~September 30, 2020 and 2019, respectively.

There was 0 capitalized interest ~~and $0.1 million in capitalized interest~~ on our unproved properties for both the three months ended ~~June~~September 30, 2020 and 2019, respectively, and 0 capitalized interest and $0.2 million in capitalized interest on our unproved properties for the ~~six~~nine months ended ~~June~~September 30, 2020 and 2019, respectively.

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

Interest on the Second Lien is payable quarterly and accrues at LIBOR plus 7.5%; provided that if LIBOR ceases to be available, the Second Lien provides for a mechanism to use ABR (an alternate base rate) plus 6.5% as the applicable interest rate. The definitions of LIBOR and ABR are set forth in the ~~Second Lien.~~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 the following repayment fees; during year three, 2.0% of the principal amount of the Second Lien being prepaid; during year four, 1.0% of the principal amount of the Second Lien being prepaid; and thereafter, no premium. Additionally, the Second Lien contains customary mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and incurrences of certain debt, subject to, in certain circumstances, reinvestment periods. Management believes the probability of mandatory prepayment due to default is remote.

The obligations under the Second Lien are secured, subject to certain exceptions and other permitted liens (including the liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit Facility, and mortgage lien on substantially all assets of the Company and ~~certain of~~ its ~~subsidiaries,~~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 ~~subsidiaries~~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%.

The Second Lien contains an Asset Coverage Ratio, which is only tested (i) as a condition to issuance of additional notes and (ii) in connection with certain asset sales in order to determine whether the proceeds of such asset sale must be applied as a prepayment of the notes and includes in the numerator of the PV-10 (defined below), based on forward strip pricing, plus the swap mark-to-market value of the commodity derivative contracts of the Company and its restricted ~~subsidiaries~~subsidiary and in the denominator the total net indebtedness of the Company and its restricted ~~subsidiaries,~~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%.

1920

Table of Contents

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

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

As of ~~June~~September 30, 2020, total net amounts recorded for the Second Lien were ~~$194.4~~$194.6 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $4.6 million and ~~$5.5~~$5.2 million for the three months ended ~~June~~September 30, 2020 and 2019, respectively, and ~~$9.5~~$14.1 million and ~~$10.8~~$16.0 million for the ~~six~~nine months ended ~~June~~September 30, 2020 and 2019, respectively.

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

(7) Acquisitions and Dispositions

Effective December 22, 2017, the Company closed a purchase and sale contract to sell the Company's wellbores and facilities in the Bay De Chene field and recorded a $16.3 million obligation related to the funding of certain plugging and abandonment costs. Of the $16.3 million original obligation, $0.4 million and ~~$2.8~~$4.4 million was paid during the ~~six~~nine months ended ~~June~~September 30, 2020 and 2019, respectively. The remaining obligation under this contract is $2.0 million and is carried in the accompanying condensed consolidated balance sheet current liability in “Accounts payable and accrued liabilities” as of ~~June~~September 30, 2020.

On April 3, 2020, we acquired additional properties in the Eagle Ford for approximately $5$5.0 million, including assumed liabilities. The acquisition included eight producing wells, basic infrastructure and acreage in Webb, La Salle, and McMullen Counties. We allocated all of the purchase price to proved oil and gas properties.

On May 13, 2020, the Company divested an overriding royalty interest in Converse and Niobrara Counties, Wyoming for approximately $4.8 million. The sales of our Wyoming assets did not significantly alter the relationship between capitalized costs and proved reserves, and as such, all proceeds were recorded as adjustments to our domestic full cost pool with no gain or loss recognized. These consolidated financial statements include the results of our Wyoming operations through the date of sale.

(8) Price-Risk Management Activities

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

During the three months ended ~~June~~September 30, 2020 and 2019, the Company recorded losses of ~~$8.5~~$12.9 million and gains of ~~$25.0~~$13.4 million, respectively, on its commodity derivatives. During the ~~six~~nine months ended ~~June~~September 30, 2020 and 2019, the Company recorded gains of ~~$79.8~~$66.9 million and ~~$20.9~~$34.3 million, respectively. The Company collected cash payments of ~~$67.5~~$76.1 million and ~~$4.4~~$16.1 million for settled derivative contracts during the ~~six~~nine months ended ~~June~~September 30, 2020 and 2019, respectively. Included in our collected cash payments during the ~~six~~nine months ended ~~June~~September 30, 2020 was $38.3 million for monetized derivative ~~contracts.~~contracts received in the first quarter of 2020.

At ~~June~~September 30, 2020, there were ~~$4.7~~$2.7 million in receivables for settled derivatives while at December 31, 2019, we had $2.9 million in receivables for settled derivatives which were included on the accompanying condensed consolidated

Table of Contents

balance sheet in “Accounts receivable, net” and were subsequently collected in ~~July~~October 2020 and January 2020, respectively. At ~~June~~September 30, 2020 and December 31, 2019, we also had ~~less than $0.1~~$0.5 million and $0.2 million, respectively, in payables for settled

~~Table of Contents~~

derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts payable and accrued liabilities” and were subsequently paid in ~~July~~October 2020 and January 2020, respectively.

The fair values of our swap contracts are computed using observable market data whereas our collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. At ~~June~~September 30, 2020, there was ~~$20.8~~$11.8 million and ~~$4.7~~$2.3 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and ~~$4.2~~$10.4 million and ~~$2.4~~$4.0 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2019, there was $12.8 million and $3.9 million in current and long-term unsettled derivative assets, respectively, and $6.6 million and $1.6 million in current and long-term unsettled derivative liabilities, respectively.

The Company uses an International Swap and Derivatives Association master agreement for our derivative contracts. This is an industry-standardized contract containing the general conditions of our derivative transactions including provisions relating to netting derivative settlement payments under certain circumstances (such as default). For reporting purposes, the Company has elected to not offset the asset and liability fair value amounts of its derivatives on the accompanying balance sheets. Under the right of set-off, there was a ~~$18.8~~$0.3 million net fair value ~~asset~~liability at ~~June~~September 30, 2020, and aan $8.4 million net fair value asset at December 31, 2019. For further discussion related to the fair value of the Company's derivatives, refer to Note 9 of these Notes to Condensed Consolidated Financial Statements.

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


Oil Derivative Swaps (New York Mercantile Exchange (“NYMEX”) WTI Settlements)	Oil Derivative Swaps (New York Mercantile Exchange (“NYMEX”) WTI Settlements)	Total Volumes (Bbls)	Weighted-Average Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price		Oil Derivative Swaps (New York Mercantile Exchange (“NYMEX”) WTI Settlements)	Total Volumes (Bbls)	Weighted-Average Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
2020 Contracts	2020 Contracts								2020 Contracts
3Q20		354,338	$	50.30
4Q20	4Q20	353,626	$	47.72					4Q20	353,626	$	47.72

2021 Contracts	2021 Contracts								2021 Contracts
1Q21	1Q21	215,538	$	51.93					1Q21	215,538	$	51.93
2Q21	2Q21	195,646	$	51.93					2Q21	195,646	$	51.93
3Q21	3Q21	179,759	$	51.19					3Q21	179,759	$	51.19
4Q21	4Q21	163,812	$	52.39					4Q21	163,812	$	52.39

2022 Contracts									2022 Contracts
1Q22									1Q22	88,455	$	36.79
Collar Contracts	Collar Contracts								Collar Contracts
2020 Contracts	2020 Contracts								2020 Contracts
3Q20		62,350			$	30.00	$	35.38
4Q20	4Q20	115,000			$	31.00	$	36.15	4Q20	115,000			$	31.00	$	36.15

2021 Contracts	2021 Contracts								2021 Contracts
1Q21	1Q21	161,475			$	34.29	$	39.36	1Q21	155,475			$	34.15	$	39.24
2Q21	2Q21	136,230			$	34.92	$	40.68	2Q21	116,980			$	34.33	$	40.30
3Q21	3Q21	90,620			$	34.34	$	39.87	3Q21	90,620			$	34.34	$	39.87
4Q21	4Q21	84,640			$	34.70	$	41.01	4Q21	84,640			$	34.70	$	41.01
2022 Contracts									2022 Contracts
2Q22									2Q22	86,450			$	39.00	$	46.50

2122

Table of Contents


Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price		Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
2020 Contracts	2020 Contracts								2020 Contracts
3Q20		7,575,000	$	2.60
4Q20	4Q20	7,817,000	$	2.63					4Q20	7,817,000	$	2.63

2021 Contracts	2021 Contracts								2021 Contracts
1Q21	1Q21	2,398,078	$	2.74					1Q21	2,398,078	$	2.74
2Q21	2Q21	832,255	$	2.42					2Q21	832,255	$	2.42
3Q21	3Q21	640,000	$	2.26					3Q21	330,000	$	2.62
4Q21	4Q21	290,000	$	2.69					4Q21	290,000	$	2.69

Collar Contracts	Collar Contracts								Collar Contracts
2020 Contracts	2020 Contracts								2020 Contracts
4Q20	4Q20	310,000			$	2.60	$	3.06	4Q20	920,000			$	2.57	$	2.93

2021 Contracts	2021 Contracts								2021 Contracts
1Q21	1Q21	7,027,800			$	2.53	$	3.33	1Q21	7,027,800			$	2.53	$	3.33
2Q21	2Q21	4,546,000			$	2.18	$	2.69	2Q21	4,546,000			$	2.18	$	2.69
3Q21	3Q21	4,665,175			$	2.02	$	2.65	3Q21	4,665,175			$	2.02	$	2.65
4Q21	4Q21	4,391,000			$	2.25	$	2.71	4Q21	4,391,000			$	2.25	$	2.71
2022 Contracts									2022 Contracts
1Q22									1Q22	4,415,000			$	2.50	$	3.35
2Q22									2Q22	4,200,000			$	2.23	$	2.70


Natural Gas Basis Derivative Swap (East Texas Houston Ship Channel vs. NYMEX Settlements)	Natural Gas Basis Derivative Swap (East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes (MMBtu)	Weighted-Average Price		Natural Gas Basis Derivative Swap (East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes (MMBtu)	Weighted-Average Price
2020 Contracts	2020 Contracts				2020 Contracts
3Q20		11,868,000	$	(0.07)
4Q20	4Q20	11,868,000	$	(0.04)	4Q20	11,868,000	$	(0.04)

2021 Contracts	2021 Contracts				2021 Contracts
1Q21	1Q21	8,100,000	$	(0.01)	1Q21	9,900,000	$	(0.02)
2Q21	2Q21	8,190,000	$	(0.01)	2Q21	10,010,000	$	(0.02)
3Q21	3Q21	8,280,000	$	(0.01)	3Q21	10,120,000	$	(0.02)
4Q21	4Q21	8,280,000	$	(0.01)	4Q21	10,120,000	$	(0.02)

Oil Basis Contracts
(Calendar Monthly Roll Differential Swaps) Total Volumes (Bbls) Weighted-Average Price
2020 Contracts
3Q20 821,525 $ 1.43
4Q20 935,175 $ 0.59
2021 Contracts
1Q21 749,750 $ 0.41
2Q21 634,050 $ 0.43
3Q21 515,200 $ 0.48
4Q21 483,000 $ 0.47

NGL Contracts Total Volumes
(Bbls) Weighted-Average Price
2020 Contracts
3Q20 35,119 $ 12.50


Oil Basis Contracts (Argus Cushing (WTI) and Magellan East Houston)	Total Volumes (Bbls)	Weighted-Average Price
2020 Contracts
4Q20	465,275	$	1.20
2021 Contracts
1Q21	373,750	$	1.19
2Q21	329,150	$	1.22
3Q21	262,200	$	1.27
4Q21	241,500	$	1.28
Calendar Monthly Roll Differential Swaps
2020 Contracts
4Q20	469,900	$	(0.02)
2021 Contracts
1Q21	367,000	$	(0.40)
2Q21	313,900	$	(0.37)
3Q21	253,000	$	(0.34)
4Q21	241,500	$	(0.33)

2223

(9) Fair Value Measurements

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

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

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

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

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

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

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

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


		Fair Value Measurements at															Fair Value Measurements at
(in millions)	(in millions)	Total		Quoted Prices in Active markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		(in millions)	Total		Quoted Prices in Active markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
June 30, 2020
September 30, 2020										September 30, 2020
Assets	Assets									Assets
Natural Gas Derivatives	Natural Gas Derivatives	$	7.1	$	—	$	7.1	$	—	Natural Gas Derivatives	$	0.3	$	0	$	0.3	$	0
Natural Gas Basis Derivatives	Natural Gas Basis Derivatives	$	1.8	$	—	$	1.8	$	—	Natural Gas Basis Derivatives	$	3.0	$	0	$	3.0	$	0
Oil Derivatives	Oil Derivatives	$	15.8	$	—	$	15.8	$	—	Oil Derivatives	$	10.0	$	0	$	10.0	$	0
Oil Basis Derivatives	Oil Basis Derivatives	$	0.8	$	—	$	0.8	$	—	Oil Basis Derivatives	$	0.8	$	0	$	0.8	$	0

Liabilities	Liabilities									Liabilities
Natural Gas Derivatives	Natural Gas Derivatives	$	2.8	$	—	$	2.8	$	—	Natural Gas Derivatives	$	10.7	$	0	$	10.7	$	0
Natural Gas Basis Derivatives	Natural Gas Basis Derivatives	$	0.5	$	—	$	0.5	$	—	Natural Gas Basis Derivatives	$	0.1	$	0	$	0.1	$	0
Oil Derivatives	Oil Derivatives	$	2.9	$	—	$	2.9	$	—	Oil Derivatives	$	3.4	$	0	$	3.4	$	0
Oil Basis Derivatives	Oil Basis Derivatives	$	0.5	$	—	$	0.5	$	—	Oil Basis Derivatives	$	0.2	$	0	$	0.2	$	0

December 31, 2019	December 31, 2019									December 31, 2019
Assets	Assets									Assets
Natural Gas Derivatives	Natural Gas Derivatives	$	11.7	$	—	$	11.7	$	—	Natural Gas Derivatives	$	11.7	$	0	$	11.7	$	0
Natural Gas Basis Derivatives	Natural Gas Basis Derivatives	$	3.4	$	—	$	3.4	$	—	Natural Gas Basis Derivatives	$	3.4	$	0	$	3.4	$	0
Oil Derivatives	Oil Derivatives	$	1.6	$	—	$	1.6	$	—	Oil Derivatives	$	1.6	$	0	$	1.6	$	0

Liabilities	Liabilities									Liabilities
Natural Gas Derivatives	Natural Gas Derivatives	$	0.2	$	—	$	0.2	$	—	Natural Gas Derivatives	$	0.2	$	0	$	0.2	$	0
Natural Gas Basis Derivatives	Natural Gas Basis Derivatives	$	0.9	$	—	$	0.9	$	—	Natural Gas Basis Derivatives	$	0.9	$	0	$	0.9	$	0
Oil Derivatives	Oil Derivatives	$	7.0	$	—	$	7.0	$	—	Oil Derivatives	$	7.0	$	0	$	7.0	$	0
Oil Basis Derivatives	Oil Basis Derivatives	$	0.1	$	—	$	0.1	$	—	Oil Basis Derivatives	$	0.1	$	0	$	0.1	$	0

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

(10) Asset Retirement Obligations

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

Table of Contents

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


Asset Retirement Obligations as of December 31, 2018	$	4,259
Accretion expense	329
Liabilities incurred for new wells and facilities construction	250

Reductions due to plugged wells and facilities	(82)
Revisions in estimates	(309)
Asset Retirement Obligations as of December 31, 2019	$	4,447
Accretion expense	~~173~~263
Liabilities incurred for new wells and facilities construction	89165

Reductions due to plugged wells and facilities	~~(15)~~(92)

Asset Retirement Obligations as of ~~June~~September 30, 2020	$	~~4,694~~4,783

At both ~~June~~September 30, 2020 and December 31, 2019, approximately $0.4 million of our asset retirement obligations were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets.

(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.

2526

Table of Contents

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

You should read the following discussion and analysis in conjunction with the Company's financial information and its consolidated financial statements and accompanying notes included in this report and its Annual Report on Form 10-K for the year ended December 31, 2019. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 3638 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 Shale located in South Texas where it has assembled approximately 167,000 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.

Recent Events, Actions Taken and Strategy

In March, the spot price of WTI crude oil declined over 50% in response to reductions in global demand due to the COVID-19 pandemic and announcements by Saudi Arabia and Russia of plans to increase crude oil production. Following this unprecedented collapse in crude oil prices, the spot price of Brent and WTI crude oil closed at approximately $15 and $21 per barrel, respectively, on March 31, 2020. Crude oil prices fell further in April but partially recovered during the second quarter of 2020 with Brent and WTI crude oil closing at approximately $41 and $39 per barrel, respectively on June 30, ~~2020, although crude~~2020. Crude oil prices ~~continue to be volatile. However,~~traded slightly higher in the third quarter of 2020 with Brent and WTI crude closing at approximately $42 and $40 per barrel, on September 30, 2020.

The ultimate magnitude and duration of the COVID-19 pandemic, resulting governmental restrictions placing limitations on the mobility and ability to work of significant portions of the worldwide population, and the related impact on crude oil prices and the U.S. and global economy and capital markets is uncertain. While it is difficult to assess or predict with precision the broad future effect of this pandemic on the global economy, the energy industry or SilverBow, management expects that the pandemic will negatively affect the Company's results of operations, cash flows and financial condition during the remainder of 2020 due to lower commodity prices and ~~reduced~~varied production levels.

In response to market conditions, including the ~~outbreak of~~ COVID-19 pandemic and the rapid decline in commodity prices and economic outlook, SilverBow reduced its original 2020 capital budget of $175-$195 million. 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. ~~SilverBow began curtailing production volumes in March and continued curtailment through the second quarter of 2020.~~ In total, the Company curtailed an average of 57 million cubic feet per day (“MMcf/d”) of net natural gas production and 1,930 barrels per day (“Bbls/d”) of net oil production throughout the quarter. In June, 2,750 Bbls/d of curtailed net oil production and 30 MMcf/d of curtailed net natural gas production was returned to sales. SilverBow plans on returning to sales the remaining curtailed volumes during the third quarter of ~~2020. Given~~2020, SilverBow restarted completions activity and returned to sales all previously curtailed oil volumes and a substantial portion of natural gas volumes. Approximately 20 MMcf/d of net gas production remained shut-in at quarter-end. The Company began returning these volumes to production in late October to align with favorable fundamentals and a strong natural gas price environment.

With the ~~Company's plans to add~~addition of a drilling rig in the fourth quarter of 2020, ~~SilverBow's revised~~SilverBow reaffirmed its capital budget for the full year 2020 isof $95-$105 million. As with the Company's completion activities, SilverBow will continue to assess optimal production timing in response to the ~~evolving~~dynamic commodity price environment. The re-imposition of restrictions by governments to mitigate the COVID-19 pandemic or other events that adversely affect crude oil prices could result in further curtailments and adversely affect our expectation for improved performance during the remainder of ~~2020.~~2020 and 2021.

Overall, the Company's strategy of ~~having a diversified mix of both oil~~procuring cost savings on drilling and ~~gas inventory provides for optionality during volatile pricing environments~~completion activities allows SilverBow to add activity and ~~unforeseen changes in the macro economic outlook. SilverBow~~stay within its capital range. The Company plans to continue pursuing a single-basin operating model, focused on its low-cost structure and optionality across multiple commodity phase ~~window~~swindows of the Eagle Ford. As a returns-focused operator, ~~the Company~~SilverBow employs a risk mitigation strategy by hedging forecasted production ~~volumes. As of July 31, 2020, the mark-to-market value of SilverBow's hedge book was approximately $11.8 million.~~volumes and protecting cash flow.

As a result of the COVID-19 pandemic, the Company continues to operate under a "work from home" policy applicable to all employees other than essential personnel whose physical presence is required either in the office or in the field.

2627

Table of Contents

SilverBow has not experienced any material interruption to its ordinary course business processes as a result of COVID-19. The Company will continue to monitor the COVID-19 situation and follow ~~federal, state~~the advice of government and ~~local guidelines as to the reopening of its offices.~~health leaders.

Operational Results

Total production for the ~~six~~nine months ended ~~June~~September 30, 2020 decreased ~~17%~~20% from the ~~six~~nine months ended ~~June~~September 30, 2019 to ~~185~~184 million cubic feet of natural gas equivalent per day due to curtailed production volumes.

During the ~~second~~third quarter of 2020, SilverBow ~~had essentially no drilling and~~resumed completion ~~("D&C")~~ activity ~~as a result~~by bringing online eight wells in its McMullen Oil area. The Company completed three of ~~releasing its super spec rig at~~these wells in the ~~beginning~~first quarter of ~~April.~~2020, but deferred bringing them online due to prevailing market conditions. The remaining five wells were drilled but uncompleted during the first quarter of 2020. As planned, all eight of these oil-weighted wells were placed on production in the third quarter of 2020, with the five DUCs completed nearly one month ahead of schedule. SilverBow's total well costs for the five DUCs were $8 million below budget, collectively. In addition to ~~temporarily suspending its D&C program,~~resuming capital activity, all remaining curtailed oil volumes were returned to sales during the ~~Company curtailed an average of 57~~third quarter. Approximately 20 MMcf/d of net gas production remained shut-in at quarter-end. The Company returned these volumes to production in late October to align with favorable natural gas and 1,930 Bbls/d of net oil production during the quarter. SilverBow commenced voluntary well shut-ins in March and increased the amount of shut-in production in April. Working with our midstream partners, approximately 2,750 Bbls/d of curtailed net oil production was returned to sales ahead of schedule in June, driving oil and natural gas liquids ("NGL") volumes above the second quarter guidance range. As the year unfolds, the Company will continue assessing optimal production timing in response to the evolving commodity price environment.prices.

~~The~~To date, wells that have been returned to ~~production to-date~~sales have not experienced any degradation and in some cases have exhibited higher production rates compared to pre-shut-in ~~levels.~~levels, as noted last quarter. SilverBow continues to monitor and analyze well data in real-time and implement choke management practices that optimize and preserve the integrity of each well. The Company ~~is analyzing~~believes these are primary drivers for the strong performance of ~~these~~the wells ~~in real time~~returned to ~~optimize choke management strategy and maximize production profiles and estimated ultimate recoveries.~~sales.

The operations team carried out significant pre-planning and contingency practices, and engaged in rigorous vendor bidding activities, to ensure continuation of the Company’s low-cost platform and operational efficiencies given the activity hiatus in the second quarter of 2020. The team also performed regular, in-depth reviews of operating and capital costs. On the ~~expense management front,~~operating cost side, labor, compression, salt-water disposal and chemicals were the notable areas that led to further LOE savings. On the capital side, service-pricing remains in a deflationary environment and the SilverBow ~~is actively engaging in~~team has been able to capture further ~~cost~~ savings ~~initiatives, primarily related to chemicals, rentals~~through selective de-bundling of capital costs and other ancillary services. The Company values its strong vendor relationships and is working together with them to ensure mutual success. As it pertains to SilverBow's recent acquisition, the Company has already identified a number of cost saving measures primarily through the use of existing infrastructure. SilverBow continues to analyze the subsurface characteristics of the new acreage to plan for future capital investment.process efficiencies.

~~Consistent with~~At the ~~Company's strategy to align production start dates with higher prices,~~beginning of October, the Company resumed drilling activity in the Webb County Gas area. SilverBow ~~intends to bring eight~~drilled the first three wells in the ~~McMullen Oil area online over~~Upper Eagle Ford at Fasken with first production expected towards year-end. The other six wells comprise the second, ~~half~~co-developed La Mesa pad. The first pad was drilled and completed last year and has demonstrated some of ~~2020. The Company secured favorable service pricing for~~ the ~~five wells it intends to complete~~strongest returns in the ~~third quarter, driving down capital costs by approximately 30% compared~~Company's portfolio. SilverBow expects to ~~initial estimates. SilverBow's procurement initiatives are laying~~finish the ~~groundwork for the resumption~~drilling and completion of the ~~Company's drilling program~~six-well La Mesa pad in early 2021, with first sales expected by the ~~fourth~~end of the first quarter.

For the full year 2020, ~~SilverBow increased~~ the ~~midpoint~~Company expects capital expenditures to be at the high end of ~~its 2020 capital budget by $12.5~~the $95-$100 million ~~with a revised guidance range of $95-$105 million.~~range.

2020 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, improved utilization of existing facilities, elimination of redundant equipment, and replacement of rental equipment with company-owned equipment. As previously mentioned, the Company continues to improve its process for drilling, completing and 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 ~~lease operating~~LOE and workover expenses were ~~$10.8~~$16.0 million or $0.32 per thousand cubic feet of gas equivalent ("Mcfe") for the first ~~six~~nine months of 2020, as compared to ~~$10.1~~$15.7 million or $0.25 per Mcfe for the same period in 2019. The increase in costs is due to higher labor and compression costs, partially offset by lower salt water disposal costs while the increase on a per Mcfe basis is due to the lower production volumes.

SilverBow's cash general and administrative costs were ~~$9.7~~$14.4 million (a non-GAAP financial measure calculated as ~~$12.1~~$17.9 million in net general and administrative costs less ~~$2.4~~$3.5 million of share-based compensation) for the first ~~six~~nine months of 2020, or $0.29 per Mcfe, compared to ~~$9.6~~$14.0 million (a non-GAAP financial measure calculated as ~~$12.9~~$19.1 million in net general and administrative costs less ~~$3.3~~$5.1 million of share-based compensation), or ~~$0.23~~$0.22 per Mcfe, for the ~~six~~nine months ended ~~June~~September 30, 2019. In September, the Company implemented corporate cost reduction initiatives. On a go forward basis SilverBow expects to save approximately $2.5 million in annualized general and administrative costs.

2728

Table of Contents

Liquidity and Capital Resources

SilverBow's primary use of cash has been to fund capital expenditures to develop its oil and gas properties and to repay Credit Facility borrowings. As of ~~June~~September 30, 2020, the Company’s liquidity consisted of ~~$6.6~~$1.2 million of cash-on-hand and ~~$60.0~~$77.0 million in available borrowings on its Credit Facility, which had a $330 million borrowing base as of such ~~date.~~date prior to the November 2, 2020 redetermination to $310 million. Management believes the Company has sufficient liquidity to meet its obligations through the ~~third~~fourth quarter of 2021 and execute its long-term development plans. See Note 6 to SilverBow's condensed consolidated financial statements for more information on its Credit Facility.

Contractual Commitments and Obligations

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

Off-Balance Sheet Arrangements

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

2829

Table of Contents

Summary of 2020 Financial Results Through ~~June~~September 30, 2020

•Revenues and Net Income (Loss): The Company's oil and gas revenues were ~~$78.2~~$123.9 million for the ~~six~~nine months ended ~~June~~September 30, 2020, compared to ~~$146.8~~$218.8 million for the ~~six~~nine months ended ~~June~~September 30, 2019. Revenues were lower primarily due to overall lower commodity pricing and production. The Company's net loss was ~~$311.8~~$318.7 million for the ~~six~~nine months ended ~~June~~September 30, 2020, compared to net income of ~~$80.8~~$108.4 million for the ~~six~~nine months ended ~~June~~September 30, 2019. The decrease in net income was primarily due to the non-cash impairment write-down, on a pre-tax basis, of $355.9 million on our oil and natural gas properties.

•Capital Expenditures: The Company's capital expenditures on an accrual basis were ~~$55.5~~$75.7 million for the ~~six~~nine months ended ~~June~~September 30, 2020 compared to ~~$158.0~~$207.4 million for the ~~six~~nine months ended ~~June~~September 30, 2019. The expenditures for the ~~six~~nine months ended ~~June~~September 30, 2020 and 2019 were attributable to drilling and completion activity.

•Working Capital: The Company had a working capital deficit of ~~$15.4~~$7.8 million at ~~June~~September 30, 2020 and a working capital deficit of $27.8 million at December 31, 2019. The working capital computation does not include available liquidity through our Credit Facility.

•Cash Flows: For the ~~six~~nine months ended ~~June~~September 30, 2020, the Company generated cash from operating activities of ~~$99.0~~$127.8 million, of which ~~$4.1~~$2.4 million was attributable to changes in working capital. Cash used for property additions was ~~$85.6~~$102.7 million. This included ~~$28.6~~$25.6 million attributable to a net decrease of capital-related payables and accrued costs. Additionally, $0.4 million was paid during the ~~six~~nine months ended ~~June~~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 ~~$9.0~~$26.0 million during the ~~six~~nine months ended ~~June~~September 30, 2020.

For the ~~six~~nine months ended ~~June~~September 30, 2019, the Company generated cash from operating activities of ~~$100.3~~$153.1 million, of which ~~$6.3~~$4.8 million was attributable to changes in working capital. Cash used for property additions was ~~$174.1~~$234.9 million. This ~~excluded $16.5~~included $27.9 million attributable to a net ~~increase~~decrease of capital-related payables and accrued costs. Additionally, ~~$2.8~~$4.4 million was paid during the ~~six~~nine months ended ~~June~~September 30, 2019 for property abandonment obligations related to the sale of our former Bay De Chene field. The Company’s net borrowings on the Credit Facility were ~~$78.0~~$87.0 million during the ~~six~~nine months ended ~~June~~September 30, 2019.

2930

Table of Contents

Results of Operations

Revenues — Three Months Ended ~~June~~September 30, 2020 and Three Months Ended ~~June~~September 30, 2019

Natural gas production was ~~82%~~71% and ~~77%~~72% of the Company's production volumes for the three months ended ~~June~~September 30, 2020 and 2019, respectively. Natural gas sales were ~~73%~~51% and ~~58%~~52% of oil and gas sales for the three months ended ~~June~~September 30, 2020 and 2019, respectively.

Crude oil production was ~~10%~~17% and ~~11%~~14% of the Company's production volumes for the three months ended ~~June~~September 30, 2020 and 2019, respectively. Crude oil sales were ~~21%~~39% and ~~33%~~40% of oil and gas sales for the three months ended ~~June~~September 30, 2020 and 2019, respectively.

NGL production was 8%12% and ~~12%~~14% of the Company's production volumes for the three months ended ~~June~~September 30, 2020 and 2019, respectively. NGL sales were 6%10% and 9%8% of oil and gas sales for the three months ended ~~June~~September 30, 2020 and 2019, respectively.

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


Fields	Fields	Three Months Ended June 30, 2020					Three Months Ended June 30, 2019			Fields		Three Months Ended September 30, 2020				Three Months Ended September 30, 2019
		Oil and Gas Sales (In Millions)		Net Oil and Gas Production Volumes (MMcfe)	Oil and Gas Sales (In Millions)		Net Oil and Gas Production Volumes (MMcfe)		Oil and Gas Sales (In Millions)		Net Oil and Gas Production Volumes (MMcfe)		Oil and Gas Sales (In Millions)		Net Oil and Gas Production Volumes (MMcfe)
Artesia Wells	Artesia Wells	$	4.4	1,872	$	19.9	4,829	Artesia Wells	$	11.8	3,802		$	23.8	6,182
AWP	AWP	5.3		2,189	21.4		4,107	AWP	15.3		3,659		19.5		4,026
Fasken	Fasken	12.8		7,511	21.5		7,984	Fasken	13.0		6,500		21.6		9,244
Other ⁽¹⁾	Other ⁽¹⁾	2.3		1,312	11.9		4,465	Other (1)	5.6		2,848		7.1		2,582
Total	Total	$	24.8	12,884	$	74.7	21,385	Total	$	45.7	16,809		$	72.0	22,034

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

The sales volumes decrease from 2019 to 2020 was primarily due to decreased production as a result of curtailed production volumes.

In the ~~second~~third quarter of 2020, our ~~$49.9~~$26.3 million, or ~~67%~~37%, decrease in oil, NGL and natural gas sales from the prior year period resulted from:

•Price variances that had an approximately ~~$19.3~~$13.0 million unfavorable impact on sales due to ~~overall~~ lower ~~commodity~~oil and natural gas pricing; and

•Volume variances that had an approximately ~~$30.6~~$13.3 million unfavorable impact on sales due to overall decreased commodity production.

3031

Table of Contents

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


		Three Months Ended June 30, 2020		Three Months Ended June 30, 2019			Three Months Ended September 30, 2020		Three Months Ended September 30, 2019
Production volumes:	Production volumes:					Production volumes:
Oil (MBbl) ⁽¹⁾	Oil (MBbl) ⁽¹⁾	221		405		Oil (MBbl) (1)	472		506
Natural gas (MMcf)	Natural gas (MMcf)	10,624		16,409		Natural gas (MMcf)	11,897		15,958
Natural gas liquids (MBbl) ⁽¹⁾	Natural gas liquids (MBbl) ⁽¹⁾	156		424		Natural gas liquids (MBbl) (1)	347		507
Total (MMcfe)	Total (MMcfe)	12,884		21,385		Total (MMcfe)	16,809		22,034

Oil, natural gas and natural gas liquids sales:	Oil, natural gas and natural gas liquids sales:					Oil, natural gas and natural gas liquids sales:
Oil	Oil	$	5,265	$	24,940	Oil	$	17,665	$	28,894
Natural gas	Natural gas	18,103		43,597		Natural gas	23,595		37,040
Natural gas liquids	Natural gas liquids	1,478		6,166		Natural gas liquids	4,439		6,080
Total	Total	$	24,846	$	74,703	Total	$	45,699	$	72,014

Average realized price:	Average realized price:					Average realized price:
Oil (per Bbl)	Oil (per Bbl)	$	23.82	$	61.60	Oil (per Bbl)	$	37.45	$	57.14
Natural gas (per Mcf)	Natural gas (per Mcf)	1.70		2.66		Natural gas (per Mcf)	1.98		2.32
Natural gas liquids (per Bbl)	Natural gas liquids (per Bbl)	9.49		14.53		Natural gas liquids (per Bbl)	12.79		11.99
Average per Mcfe	Average per Mcfe	$	1.93	$	3.49	Average per Mcfe	$	2.72	$	3.27

Price impact of cash-settled derivatives:	Price impact of cash-settled derivatives:					Price impact of cash-settled derivatives:
Oil (per Bbl)	Oil (per Bbl)	$	49.52	$	(0.01)	Oil (per Bbl)	$	6.91	$	2.39
Natural gas (per Mcf)	Natural gas (per Mcf)	0.64		0.17		Natural gas (per Mcf)	0.39		0.51
Natural gas liquids (per Bbl)	Natural gas liquids (per Bbl)	—		3.78		Natural gas liquids (per Bbl)	(0.01)		4.14
Average per Mcfe	Average per Mcfe	$	1.38	$	0.20	Average per Mcfe	$	0.47	$	0.52

Average realized price including impact of cash-settled derivatives:	Average realized price including impact of cash-settled derivatives:					Average realized price including impact of cash-settled derivatives:
Oil (per Bbl)	Oil (per Bbl)	$	73.34	$	61.59	Oil (per Bbl)	$	44.36	$	59.53
Natural gas (per Mcf)	Natural gas (per Mcf)	2.34		2.83		Natural gas (per Mcf)	2.37		2.83
Natural gas liquids (per Bbl)	Natural gas liquids (per Bbl)	9.49		18.31		Natural gas liquids (per Bbl)	12.78		16.14
Average per Mcfe	Average per Mcfe	$	3.31	$	3.69	Average per Mcfe	$	3.19	$	3.79

(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 ~~June~~September 30, 2020 and 2019, the Company recorded net losses of ~~$8.5~~$12.9 million and net gains of ~~$25.0~~$13.4 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.

3132

Table of Contents

Costs and Expenses — Three Months Ended ~~June~~September 30, 2020 and Three Months Ended ~~June~~September 30, 2019

The following table provides additional information regarding our expenses for the three months ended ~~June~~September 30, 2020 and 2019:


Costs and Expenses	Costs and Expenses	Three Months Ended June 30, 2020		Three Months Ended June 30, 2019		Costs and Expenses	Three Months Ended September 30, 2020		Three Months Ended September 30, 2019
General and administrative, net	General and administrative, net	$	6,180	$	6,624	General and administrative, net	$	5,833	$	6,247
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	13,716		24,029		Depreciation, depletion, and amortization	13,975		24,937
Accretion of asset retirement obligations	Accretion of asset retirement obligations	88		86		Accretion of asset retirement obligations	90		88
Lease operating cost	Lease operating cost	5,000		5,035		Lease operating cost	5,211		5,507
Workovers	Workovers	—		(127)		Workovers	8		93
Transportation and gas processing	Transportation and gas processing	4,554		6,728		Transportation and gas processing	5,094		6,782
Severance and other taxes	Severance and other taxes	2,037		3,950		Severance and other taxes	2,512		3,778
Interest expense, net	Interest expense, net	8,026		9,306		Interest expense, net	7,444		9,435
Write-down of oil and gas properties		260,342		—

General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were ~~$0.48~~$0.35 and ~~$0.31~~$0.28 for the three months ended ~~June~~September 30, 2020 and 2019, respectively. The increase per Mcfe was due to lower production while the decrease in costs was primarily due to lower salaries and burdens, lower share-based compensation and lower ~~share-based compensation.~~temporary labor fees. Included in general and administrative expenses is ~~$1.2~~$1.1 million and ~~$1.6~~$1.8 million in share-based compensation for the three months ended ~~June~~September 30, 2020 and 2019, respectively.

Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were ~~$1.06~~$0.83 and ~~$1.12~~$1.13 for the three months ended ~~June~~September 30, 2020 and 2019, respectively. The decrease on a per Mcfe basis was driven by reductions to our depletable base due to non-cash impairment write-downs during the year.

Lease Operating Cost and Workovers. These expenses on a per-Mcfe basis were ~~$0.39~~$0.31 and ~~$0.23~~$0.25 for the three months ended ~~June~~September 30, 2020 and 2019, respectively. The increase per Mcfe was due to lower production.

Transportation and Gas Processing. These expenses are related to natural gas and NGL sales. These expenses on a per-Mcfe basis were ~~$0.35~~$0.30 and $0.31 for the three months ended ~~June~~September 30, 2020 and 2019, respectively.

Severance and Other Taxes. These expenses on a per-Mcfe basis were ~~$0.16~~$0.15 and ~~$0.18~~$0.17 for the three months ended ~~June~~September 30, 2020 and 2019, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately ~~8.2%~~5.5% and ~~5.3%~~5.2% for the three months ended ~~June~~September 30, 2020 and 2019, respectively.

Interest. Our gross interest cost was ~~$8.0~~$7.4 million and $9.4 million for the three months ended ~~June~~September 30, 2020 and 2019, respectively. The decrease in gross interest cost is primarily due to decreased ~~borrowing~~borrowings and lower interest rates. There were no capitalized interest costs for both the three months ended September 30, 2020 and 2019.

Income Taxes. The Company recorded an income tax benefit of $0.6 million and an income tax provision of $1.0 million for the three months ended September 30, 2020 and 2019, respectively. During the quarter ended June 30, 2020, management had determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other deferred tax assets and, accordingly, recorded a full valuation allowance to offset its net deferred tax assets in excess of deferred tax liabilities. Our income tax benefit for the three months ended September 30, 2020 is fully attributable to a current state income tax benefit.

Table of Contents

Revenues — Nine Months Ended September 30, 2020 and Nine Months Ended September 30, 2019

Natural gas production was 77% of the Company's production volumes for both the nine months ended September 30, 2020 and 2019. Natural gas sales were 59% and 60% of oil and gas sales for the nine months ended September 30, 2020 and 2019, respectively.

Crude oil production was 13% and 11% of the Company's production volumes for the nine months ended September 30, 2020 and 2019, respectively. Crude oil sales were 33% and 31% of oil and gas sales for the nine months ended September 30, 2020 and 2019, respectively.

NGL production was 10% and 12% of the Company's production volumes for the nine months ended September 30, 2020 and 2019, respectively. NGL sales were 8% and 9% of oil and gas sales for the nine months ended September 30, 2020 and 2019, respectively.

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


Fields	Nine Months Ended September 30, 2020			Nine Months Ended September 30, 2019
	Oil and Gas Sales (In Millions)		Net Oil and Gas Production Volumes (MMcfe)	Oil and Gas Sales (In Millions)		Net Oil and Gas Production Volumes (MMcfe)
Artesia Wells	$	30.6	10,016	$	56.8	14,067
AWP	33.9		8,872	57.0		11,153
Fasken	44.2		23,676	68.5		25,061
Other (1)	15.2		7,904	36.5		12,497
Total	$	123.9	50,468	$	218.8	62,778

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

The sales volumes decrease from 2019 to 2020 was primarily due to decreased production as a result of curtailed production volumes.

In the nine months ended September 30, 2020, our $94.9 million, or 43%, decrease in oil, NGL and natural gas sales from the prior year period resulted from:

•Price variances that had an approximately $58.8 million unfavorable impact on sales due to overall lower commodity pricing; and

•Volume variances that had an approximately $36.1 million unfavorable impact on sales due to overall decreased commodity production due to curtailed volumes during the year.

Table of Contents

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


	Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
Production volumes:
Oil (MBbl) (1)	1,093		1,167
Natural gas (MMcf)	39,018		48,274
Natural gas liquids (MBbl) (1)	815		1,250
Total (MMcfe)	50,468		62,778

Oil, natural gas and natural gas liquids sales:
Oil	$	40,979	$	68,441
Natural gas	73,170		131,941
Natural gas liquids	9,772		18,400
Total	$	123,921	$	218,781

Average realized price:
Oil (per Bbl)	$	37.48	$	58.65
Natural gas (per Mcf)	1.88		2.73
Natural gas liquids (per Bbl)	11.99		14.72
Average per Mcfe	$	2.46	$	3.49

Price impact of cash-settled derivatives:
Oil (per Bbl)	$	17.05	$	0.93
Natural gas (per Mcf)	0.50		0.23
Natural gas liquids (per Bbl)	—		3.66
Average per Mcfe	$	0.76	$	0.27

Average realized price including impact of cash-settled derivatives:
Oil (per Bbl)	$	54.54	$	59.58
Natural gas (per Mcf)	2.38		2.96
Natural gas liquids (per Bbl)	11.99		18.38
Average per Mcfe	$	3.22	$	3.76

For the nine months ended September 30, 2020 and 2019, the Company recorded net gains of $66.9 million and $34.3 million from our derivatives activities, respectively. Included in our net gain during the nine months ended September 30, 2020 was $38.3 million for monetized derivative contracts received in the first quarter of 2020. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.

Table of Contents

Costs and Expenses — Nine Months Ended September 30, 2020 and Nine Months Ended September 30, 2019

The following table provides additional information regarding our expenses for the nine months ended September 30, 2020 and 2019:


Costs and Expenses	Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019
General and administrative, net	$	17,926	$	19,146
Depreciation, depletion, and amortization	51,130		70,771
Accretion of asset retirement obligations	263		257
Lease operating cost	16,023		15,074
Workovers	8		613
Transportation and gas processing	16,291		19,917
Severance and other taxes	7,513		11,044
Interest expense, net	23,876		27,500
Write-down of oil and gas properties	355,948		—

General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.36 and $0.30 for the nine months ended September 30, 2020 and 2019, respectively. The increase per Mcfe was due to lower production while the decrease in costs was primarily due to lower salaries and burdens, lower share-based compensation and lower temporary labor fees. Included in general and administrative expenses is $3.5 million and $5.1 million in share-based compensation for the nine months ended September 30, 2020 and 2019, respectively.

Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were $1.01 and $1.13 for the nine months ended September 30, 2020 and 2019, respectively. The decrease on a per Mcfe basis was driven by reductions to our depletable base due to non-cash impairment write-downs during the year.

Lease Operating Cost and Workovers. These expenses on a per-Mcfe basis were $0.32 and $0.25 for the nine months ended September 30, 2020 and 2019, respectively. The increase per Mcfe was due to lower production while the increase in costs is due to higher labor and compression costs, partially offset by lower salt water disposal costs.

Transportation and Gas Processing. These expenses are related to natural gas and NGL sales. These expenses on a per-Mcfe basis were $0.32 for both the nine months ended September 30, 2020 and 2019.

Severance and Other Taxes. These expenses on a per-Mcfe basis were $0.15 and $0.18 for the nine months ended September 30, 2020 and 2019, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 6.1% and 5.0% for the nine months ended September 30, 2020 and 2019, respectively.

Interest. Our gross interest cost was $23.9 million and $27.7 million for the nine months ended September 30, 2020 and 2019, respectively. The decrease in gross interest cost is primarily due to decreased borrowings and lower interest rates. There was no capitalized interest cost and ~~$0.1~~$0.2 million of capitalized interest for the ~~three~~nine months ended ~~June~~September 30, 2020 and 2019, respectively.

Write-down of oil and gas properties. Due to the effects of pricing and timing of projects, for the ~~three~~nine months ended ~~June~~September 30, 2020, we reported a non-cash impairment write-down, on a pre-tax basis, of ~~$260.3~~$355.9 million on our oil and natural gas properties. These impairments occurred in the first half of 2020. There was no ~~write-down~~impairment for the ~~three~~nine months ended ~~June~~September 30, 2019.

Income Taxes. 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 ~~had~~ determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and 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. ~~As a result~~This resulted in tax expenses of $21.2 million in the ~~full valuation allowance established at June 30, 2020, we recorded an~~second quarter of 2020. Our income tax provision of ~~$22.4~~$20.6 million for the ~~three~~nine months ended ~~June~~September 30, 2020 ~~which was~~is inclusive of a current state income tax ~~expense. During~~benefit of $0.6 million. For the ~~three~~nine months ended ~~June~~September 30, 2019, the Company was able to complete several operational initiatives that resulted in increased production, lower development costs and expanded inventory of development prospects. The results of these initiatives led management to determine, after weighing both positive and negative evidence, that the Company would more likely than not be able to realize the benefits of its deferred tax assets. Accordingly, we released the valuation allowance, resulting in a net deferred tax benefit of $20.7 million for the three months ended June 30, 2019.

3236

Table of Contents

~~Revenues — Six Months Ended June 30, 2020 and Six Months Ended June 30, 2019~~

Natural gas production was 81% and 79% of the Company's production volumes for the six months ended June 30, 2020 and 2019, respectively. Natural gas sales were 63% and 65% of oil and gas sales for the six months ended June 30, 2020 and 2019, respectively.

Crude oil production was 11% and 10% of the Company's production volumes for the six months ended June 30, 2020 and 2019, respectively. Crude oil sales were 30% and 27% of oil and gas sales for the six months ended June 30, 2020 and 2019, respectively.

NGL production was 8% and 11% of the Company's production volumes for the six months ended June 30, 2020 and 2019, respectively. NGL sales were 7% and 8% of oil and gas sales for the six months ended June 30, 2020 and 2019, respectively.

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

Fields Six Months Ended June 30, 2020 Six Months Ended June 30, 2019
Oil and Gas Sales
(In Millions) Net Oil and Gas Production
Volumes (MMcfe) Oil and Gas Sales
(In Millions) Net Oil and Gas Production
Volumes (MMcfe)
Artesia Wells $ 18.8 6,215 $ 33.0 7,884
AWP 18.6 5,214 37.5 7,127
Fasken 31.2 17,176 46.9 15,817
Other ⁽¹⁾
9.6 5,054 29.4 9,916
Total $ 78.2 33,659 $ 146.8 40,744

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

~~The sales volumes decrease from 2019 to 2020 was primarily due to decreased production as a result of curtailed production volumes.~~

~~In the six months ended June 30, 2020, our $68.5 million, or 47%, decrease in oil, NGL and natural gas sales from the prior year period resulted from:~~

•~~Price variances that had an approximately $46.3 million unfavorable impact on sales due to overall lower commodity pricing; and~~

•~~Volume variances that had an approximately $22.2 million unfavorable impact on sales due to overall decreased commodity production.~~

~~Table of Contents~~

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

Six Months Ended June 30, 2020 Six Months Ended June 30, 2019
Production volumes:
Oil (MBbl) ⁽¹⁾
622 661
Natural gas (MMcf) 27,121 32,316
Natural gas liquids (MBbl) ⁽¹⁾
468 743
Total (MMcfe) 33,659 40,744
Oil, natural gas and natural gas liquids sales:
Oil $ 23,315 $ 39,547
Natural gas 49,574 94,902
Natural gas liquids 5,333 12,319
Total $ 78,222 $ 146,768
Average realized price:
Oil (per Bbl) $ 37.51 $ 59.79
Natural gas (per Mcf) 1.83 2.94
Natural gas liquids (per Bbl) 11.40 16.58
Average per Mcfe $ 2.32 $ 3.60
Price impact of cash-settled derivatives:
Oil (per Bbl) $ 24.75 $ (0.19)
Natural gas (per Mcf) 0.55 0.09
Natural gas liquids (per Bbl) — 3.33
Average per Mcfe $ 0.90 $ 0.13
Average realized price including impact of cash-settled derivatives:
Oil (per Bbl) $ 62.26 $ 59.60
Natural gas (per Mcf) 2.38 3.03
Natural gas liquids (per Bbl) 11.40 19.91
Average per Mcfe $ 3.23 $ 3.73

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

For the six months ended June 30, 2020 and 2019, the Company recorded net gains of $79.8 million and $20.9 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.

~~Table of Contents~~

~~Costs and Expenses — Six Months Ended June 30, 2020 and Six Months Ended June 30, 2019~~

~~The following table provides additional information regarding our expenses for the six months ended June 30, 2020 and 2019:~~

Costs and Expenses Six Months Ended June 30, 2020 Six Months Ended June 30, 2019
General and administrative, net $ 12,093 $ 12,900
Depreciation, depletion, and amortization 37,156 45,834
Accretion of asset retirement obligations 173 168
Lease operating cost 10,812 9,567
Workovers — 519
Transportation and gas processing 11,197 13,135
Severance and other taxes 5,001 7,266
Interest expense, net 16,433 18,065
Write-down of oil and gas properties 355,948 —

~~General and Administrative Expenses, Net.~~ These expenses on a per-Mcfe basis were $0.36 and $0.32 for the six months ended June 30, 2020 and 2019, respectively. The increase per Mcfe was due to lower production while the decrease in costs was primarily due to lower salaries and burdens and lower share-based compensation. Included in general and administrative expenses is $2.4 million and $3.3 million in share-based compensation for the six months ended June 30, 2020 and 2019, respectively.

~~Depreciation, Depletion and Amortization.~~ ~~These expenses on a per-Mcfe basis were $1.10 and $1.12 for the six months ended June 30, 2020 and 2019, respectively.~~

~~Lease Operating Cost and Workovers. These expenses on a per-Mcfe basis were $0.32 and $0.25 for the six months ended June 30, 2020 and 2019, respectively. The increase per Mcfe was due to lower production.~~

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

~~Severance and Other Taxes.~~ These expenses on a per-Mcfe basis were $0.15 and $0.18 for the six months ended June 30, 2020 and 2019, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 6.4% and 5.0% for the six months ended June 30, 2020 and 2019, respectively.

~~Interest.~~ Our gross interest cost was $16.4 million and $18.3 million for the six months ended June 30, 2020 and 2019, respectively. The decrease in gross interest cost is primarily due to decreased borrowing rates. There was no capitalized interest cost and $0.2 million of capitalized interest for the six months ended June 30, 2020 and 2019, respectively.

~~Write-down of oil and gas properties~~. Due to the effects of pricing and timing of projects, for the six months ended June 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 six months ended June 30, 2019.

~~Income Taxes.~~ 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 had determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other deferred tax assets and, accordingly, recorded a full valuation allowance to offset its net 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 $21.2 million for the six months ended June 30, 2020, which was inclusive of state income tax expense. For the six months ended June 30, 2019, the Company was able to complete several operational initiatives that resulted in increased production, lower development costs and expanded inventory of development prospects. The results of these initiatives led management to determine, after weighing both positive and negative evidence, that the Company will more likely than not be able to realize the benefits of its deferred tax assets. Accordingly, we released the valuation allowance in the second quarter of 2019, resulting in a net deferred tax benefit of ~~$20.5~~$19.5 million for the ~~six~~nine months ended ~~June~~September 30, 2019.

3537

Table of Contents

Critical Accounting Policies and New Accounting Pronouncements

There have been no changes in the critical accounting policies disclosed in our 2019 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 subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated production levels, expected oil and natural gas pricing, estimated oil and natural gas reserves or the present value thereof, reserve increases, capital expenditures, budget, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “budgeted,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

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

• the severity and duration of world health events, including the ~~recent~~ COVID-19 ~~outbreak,~~pandemic, related economic repercussions and the resulting severe disruption in the oil and gas industry and negative impact on demand for oil and gas, which is negatively impacting our business;

• the current significant surplus in the supply of oil and actions by the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC and other allied producing countries, “OPEC+”) with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations;

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

• shut-in 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, future covenant compliance, cash flows and liquidity;

• operating results;

• asset disposition efforts or the timing or outcome thereof;

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

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

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

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

• availability, cost and terms of capital;

• drilling of wells;

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

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

• competition in the oil and natural gas industry;

• general economic conditions;

• opportunities to monetize assets;

• effectiveness of our risk management activities;

• environmental liabilities;

• counterparty credit risk;

3638

Table of Contents

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

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

• uncertainty regarding our future operating results; and

• other risks and uncertainties described in Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2019 and our Quarterly ~~Report~~Reports on Form 10-Q for the ~~quarter~~quarters ended March 31, 2020 and June 30, 2020.

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

All forward-looking statements speak only as of the date they are made. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under "Risk Factors" in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2019 and in subsequent Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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

3739

Table of Contents

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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

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

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

Interest Rate Risk. At ~~June~~September 30, 2020, we had a combined ~~$470.0~~$453.0 million drawn under our Credit Facility and our Second Lien, which bear floating rates of interest and therefore are susceptible to interest rate fluctuations. These variable interest rate borrowings are also impacted by changes in short-term interest rates. A hypothetical one percentage point increase in interest rates on our borrowings outstanding under our Credit Facility and Second Lien at ~~June~~September 30, 2020 would increase our annual interest expense by ~~$4.7~~$4.5 million.

3840

Table of Contents

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 ~~June~~September 30, 2020 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

3941

Table of Contents

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, 2019 and in subsequent Quarterly Reports on Form 10-Q. Other than as provided below, there were no material changes to those risk factors during the ~~six~~nine months ended ~~June~~September 30, 2020.

~~The~~An imbalance between the supply of and demand for oil and natural gas has caused and may continue to cause extreme market volatility and may result in increased costs and decreased availability of storage capacity. The lack of a market or available storage for certain of our products could cause interruptions in our operations, including temporary curtailments or shut-ins, which could adversely affect our financial condition and results of operations.

The marketing of our natural gas and oil production is substantially dependent upon the existence of adequate markets for our products. In response to the COVID-19 pandemic, governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, which have caused a significant decrease in the demand for natural gas and oil. The imbalance between the supply of and demand for these products, as well as the uncertainty around the extent and timing of an economic recovery, have caused extreme market volatility and a substantial adverse effect on commodity prices in March and ~~April.~~April and may continue to cause market volatility and adverse effects on commodity prices. Also as a result of this imbalance, the industry ~~is experiencing~~experienced storage capacity constraints with respect to certain natural gas products and oil. IfIn the event we are unable to sell our production or enter into additional storage arrangements on commercially reasonable terms or at all, we could be forced to temporarily shut in a portion of our production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. Although our production is more heavily weighted to natural gas, the lack of a market or available storage for any one natural gas product or oil could result in ~~temporary shut-ins~~us temporarily curtailing or shutting in such production as we may be unable to curtail the production of individual products in a meaningful way without reducing the production of other products. ~~Based on our expectation of available storage and overall demand, we have begun curtailing our production. We are unable to determine the extent or duration of any such curtailments.~~ Any such shut-in or curtailment, or any inability to obtain favorable terms for delivery of the natural gas and oil we produce, could adversely affect our financial condition and results of operations.

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

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

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

As domestic demand for crude oil has declined substantially due to the COVID-19 pandemic, we cannot ensure that there will be a physical market for our production at economic prices until markets stabilize.

As a result of low commodity prices or a future decrease in commodity prices, we did temporarily curtail and may curtail again in the future a portion of our estimated oil production and/or may store rather than sell additional crude oil

4042

Table of Contents

production in the near future. The excess supply of oil could lead to potential curtailments by our purchasers. While we believe that any potential shutting-in of such production will not impact the productivity of such wells when reopened, there is no assurance we will not have a degradation in well performance upon returning those wells to production. The storing or shutting in of a portion of our production could potentially also result in increased costs under our midstream and other contracts. Any of the foregoing could result in an adverse impact on our revenues, financial position and cash flows.

A financial crisis may impact our business, financial condition and cash flows and may adversely impact our ability to obtain funding.

We use our cash flows from operating activities and borrowings to fund our capital expenditures, and we rely on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions. However, the COVID-19 pandemic and the public and political responses thereto have contributed to equity market volatility and the potential risk of a global recession, and we expect this global equity market volatility to continue at least until the ~~outbreak~~pandemic of COVID-19 stabilizes, if not longer. As such, we may not be able to access adequate funding, including due to an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. We may also face limitations on our ability to access the debt and equity capital markets and complete asset sales, increased counterparty credit risk on derivatives contracts, and requirements by our contractual counterparties to post collateral guaranteeing performance.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel, water disposal and oilfield services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget and operate profitably.

Shortages or the high cost of drilling rigs, equipment, supplies or personnel, including shortages or unavailability of personnel, supplies and equipment arising from the COVID-19 pandemic could delay or adversely affect our development and exploration operations. If the price of oil and natural gas increases, the demand for production equipment and personnel will likely also increase, potentially resulting in shortages of equipment and personnel. In addition, larger producers may be more likely to secure access to such equipment by offering drilling companies more lucrative terms. If we are unable to acquire access to such resources, or can obtain access only at higher prices, this would potentially delay our ability to convert our reserves into cash flow and could also significantly increase the cost of producing those reserves, thereby negatively impacting anticipated net income.

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

None.

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

None.

4143

Table of Contents

Item 6. Exhibits.

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


3.1			First Amended and Restated Certificate of Incorporation of SilverBow Resources, Inc., effective May 5, 2017 (incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.'s Form 10-Q filed May 8, 2017, File No. 001-087541).
3.2			First Amended and Restated Bylaws of SilverBow Resources, Inc., effective May 5, 2017 (incorporated by reference as Exhibit 3.2 to SilverBow Resources, Inc.'s Form 10-Q filed May 8, 2017, File No. 001-08754).
~~10.1~~10.1*			~~Fifth~~Sixth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement effective as of ~~May 12,~~November 2, 2020, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party ~~thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources Inc's Form 8-K filed May 13, 2020, File No. 001-08754).~~thereto.
31.1*			Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*			Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1#			Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101*			The following materials from SilverBow Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended ~~June~~September 30, 2020 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.

4244

Table of Contents

SIGNATURES

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

SILVERBOW RESOURCES, INC.
(Registrant)

Date:

~~August~~November 5, 2020

By:

/s/ Christopher M. Abundis

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

Date:

~~August~~November 5, 2020

By:

/s/ W. Eric Schultz

W. Eric Schultz
Controller

4345


NGL Contracts	Total Volumes (Bbls)	Weighted-Average Price
2020 Contracts
3Q20	35,119	$	12.50