UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

of the Securities Exchange Act of 1934

For the quarterly period ended September 30, ~~2021~~2022

Commission File Number 1-8754

SILVERBOW RESOURCES, INC.

(Exact Name of Registrant as Specified in Its Charter)


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

920 Memorial City Way, Suite 850

Houston, Texas 77024

(281) 874-2700

(Address and telephone number of principal executive offices)

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


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.01 per share	SBOW	New York Stock Exchange
Preferred Stock Purchase Rights	None	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

oþ

Non-Accelerated Filer

þo

Smaller Reporting Company

Emerging Growth Company

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


o

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


Yes			o			No			þ

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


~~Yes~~			þ			No			o

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

of common stock, as of the latest practicable date.


Common Stock ($.01 Par Value) (Class of Stock)			~~14,726,605~~22,309,740 Shares outstanding at October ~~29, 2021~~28, 2022

SILVERBOW RESOURCES, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, ~~2021~~2022

INDEX


		Page
Part I	FINANCIAL INFORMATION

Item 1.	Condensed Consolidated Financial Statements

	Condensed Consolidated Balance Sheets	46

	Condensed Consolidated Statements of Operations	57

	Condensed Consolidated Statements of Stockholders’ Equity	79

	Condensed Consolidated Statements of Cash Flows	810

	Notes to Condensed Consolidated Financial Statements	911

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2735

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3845

Item 4.	Controls and Procedures	3946

Part II	OTHER INFORMATION

Item 1.	Legal Proceedings	4047
Item 1A.	Risk Factors	4047
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4048
Item 3.	Defaults Upon Senior Securities	4048
Item 4.	Mine Safety Disclosures	4049
Item 5.	Other Information	4049
Item 6.	Exhibits	4049

SIGNATURES		4251

Forward-Looking Statements

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

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

• the severity and duration of world health events, including the COVID-19 pandemic, related economic repercussions, including disruptions in the oil and gas industry, supply chain disruptions, and operational challenges including remote work arrangements and protecting the health and well-being of our employees;

• further actions by the members of the Organization of the Petroleum Exporting Countries, Russia and other allied producing countries with respect to oil production levels and announcements of potential changes in such levels;

• risks related to the recently completed transactions with SandPoint Operating, LLC, a subsidiary of SandPoint Resources, LLC (collectively, “SandPoint”) and Sundance Energy, Inc. and its affiliated entities (collectively, “Sundance”);

• volatility in natural gas, oil and natural gas liquids 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 flow and liquidity;

• operating results;

• asset disposition efforts or the timing or outcome thereof;

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

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

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

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

• availability, cost and terms of capital;

• timing and successful drilling and completion of wells;

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

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

• competition in the oil and natural gas industry;

• general economic and political conditions, including inflationary pressures, further increases in interest rates, a general economic slowdown or recession, political tensions and war (including future developments in the ongoing Russia-Ukraine conflict);

• opportunities to monetize assets;

• our ability to execute on strategic initiatives;

• effectiveness of our risk management activities including hedging strategy;

• environmental liabilities;

• counterparty credit risk;

• actions by third parties, including customers, service providers and shareholders;

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

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

• uncertainty regarding our future operating results; and

• other risks and uncertainties described in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2021 and our other filings with the Securities and Exchange Commission (“SEC”).

Many of the foregoing risks and uncertainties, as well as risks and uncertainties that are currently unknown to us, are, and may be, exacerbated by the ongoing Russia-Ukraine conflict, increasing economic uncertainty and inflationary pressures and 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, our annual report on Form 10-K for the year ended December 31, 2021 or other filings with the SEC, 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, 2021 and in subsequent Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and our other filings with the SEC. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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

Table of Contents

PART I. FINANCIAL INFORMATION

Condensed Consolidated Balance Sheets (Unaudited)

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


		September 30, 2021		December 31, 2020			September 30, 2022		December 31, 2021

ASSETS	ASSETS					ASSETS
Current Assets:	Current Assets:					Current Assets:
Cash and cash equivalents	Cash and cash equivalents	$	988	$	2,118	Cash and cash equivalents	$	1,924	$	1,121
Accounts receivable, net	Accounts receivable, net	44,190		25,850		Accounts receivable, net	102,691		49,777
Fair value of commodity derivatives	Fair value of commodity derivatives	668		4,821		Fair value of commodity derivatives	33,205		2,806

Other current assets	Other current assets	4,016		2,184		Other current assets	6,468		1,875
Total Current Assets	Total Current Assets	49,862		34,973		Total Current Assets	144,288		55,579
Property and Equipment:	Property and Equipment:					Property and Equipment:
Property and equipment, full cost method, including $24,988 and $28,090, respectively, of unproved property costs not being amortized at the end of each period		1,476,586		1,343,373
Property and equipment, full cost method, including $17,478 and $17,090, respectively, of unproved property costs not being amortized at the end of each period						Property and equipment, full cost method, including $17,478 and $17,090, respectively, of unproved property costs not being amortized at the end of each period	2,345,317		1,611,953
Less – Accumulated depreciation, depletion, amortization & impairment	Less – Accumulated depreciation, depletion, amortization & impairment	(846,822)		(801,279)		Less – Accumulated depreciation, depletion, amortization & impairment	(959,139)		(869,985)
Property and Equipment, Net	Property and Equipment, Net	629,764		542,094		Property and Equipment, Net	1,386,178		741,968
Right of Use Assets		15,787		4,366
Fair Value of Long-Term Commodity Derivatives		18		281
Right of use assets						Right of use assets	13,669		16,065
Fair value of long-term commodity derivatives						Fair value of long-term commodity derivatives	27,410		201

Other Long-Term Assets		2,904		1,421
Other long-term assets						Other long-term assets	18,368		5,641
Total Assets	Total Assets	$	698,335	$	583,135	Total Assets	$	1,589,913	$	819,454
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	$	38,000	$	26,991	Accounts payable and accrued liabilities	$	80,107	$	35,034
Fair value of commodity derivatives	Fair value of commodity derivatives	94,778		8,171		Fair value of commodity derivatives	108,618		47,453
Accrued capital costs	Accrued capital costs	20,482		7,324		Accrued capital costs	54,210		7,354
Accrued interest	Accrued interest	846		983		Accrued interest	2,385		697
Current lease liability	Current lease liability	6,292		3,473		Current lease liability	8,579		7,222
Undistributed oil and gas revenues	Undistributed oil and gas revenues	17,328		11,098		Undistributed oil and gas revenues	32,318		23,577

Total Current Liabilities	Total Current Liabilities	177,726		58,040		Total Current Liabilities	286,217		121,337
Long-Term Debt, Net		393,726		424,905
Non-Current Lease Liability		9,723		951
Deferred Tax Liabilities		303		303
Asset Retirement Obligations		4,706		4,533
Fair Value of Long-Term Commodity Derivatives		21,989		2,946
Other Long-Term Liabilities		846		424
Long-term debt, net						Long-term debt, net	626,351		372,825
Non-current lease liability						Non-current lease liability	5,379		9,090
Deferred tax liabilities						Deferred tax liabilities	14,012		6,516
Asset retirement obligations						Asset retirement obligations	8,255		5,526
Fair value of long-term commodity derivatives						Fair value of long-term commodity derivatives	29,950		8,585
Other long-term liabilities						Other long-term liabilities	2,764		3,043
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	—		—
Common stock, $0.01 par value, 40,000,000 shares authorized, 13,576,285 and 12,053,763 shares issued, respectively, and 13,384,615 and 11,936,679 shares outstanding, respectively		136		121
Common stock, $0.01 par value, 40,000,000 shares authorized, 22,663,135 and 16,822,845 shares issued, respectively, and 22,309,740 and 16,631,175 shares outstanding, respectively						Common stock, $0.01 par value, 40,000,000 shares authorized, 22,663,135 and 16,822,845 shares issued, respectively, and 22,309,740 and 16,631,175 shares outstanding, respectively	227		168
Additional paid-in capital	Additional paid-in capital	324,106		297,712		Additional paid-in capital	574,885		413,017
Treasury stock, held at cost, 191,670 and 117,084 shares, respectively		(2,984)		(2,372)
Accumulated deficit		(231,942)		(204,428)
Treasury stock, held at cost, 353,395 and 191,670 shares, respectively						Treasury stock, held at cost, 353,395 and 191,670 shares, respectively	(7,534)		(2,984)
Retained earnings (Accumulated deficit)						Retained earnings (Accumulated deficit)	49,407		(117,669)
Total Stockholders’ Equity	Total Stockholders’ Equity	89,316		91,033		Total Stockholders’ Equity	616,985		292,532
Total Liabilities and Stockholders’ Equity	Total Liabilities and Stockholders’ Equity	$	698,335	$	583,135	Total Liabilities and Stockholders’ Equity	$	1,589,913	$	819,454
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 Subsidiary (in thousands, except per-share amounts)


		Three Months Ended September 30, 2021		Three Months Ended September 30, 2020			Three Months Ended September 30, 2022		Three Months Ended September 30, 2021
Revenues:	Revenues:					Revenues:
Oil and gas sales	Oil and gas sales	$	99,249	$	45,699	Oil and gas sales	$	242,181	$	99,249

Operating Expenses:	Operating Expenses:					Operating Expenses:
General and administrative, net	General and administrative, net	5,257		5,833		General and administrative, net	4,343		5,257
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	16,054		13,975		Depreciation, depletion, and amortization	41,501		16,054
Accretion of asset retirement obligations	Accretion of asset retirement obligations	77		90		Accretion of asset retirement obligations	166		77
Lease operating expenses	Lease operating expenses	6,978		5,211		Lease operating expenses	17,701		6,978
Workovers	Workovers	423		8		Workovers	284		423
Transportation and gas processing	Transportation and gas processing	5,913		5,094		Transportation and gas processing	9,662		5,913
Severance and other taxes	Severance and other taxes	4,908		2,512		Severance and other taxes	12,581		4,908

Total Operating Expenses	Total Operating Expenses	39,610		32,723		Total Operating Expenses	86,238		39,610

Operating Income	Operating Income	59,639		12,976		Operating Income	155,943		59,639

Non-Operating Income (Expense)	Non-Operating Income (Expense)					Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net	Gain (loss) on commodity derivatives, net	(88,554)		(12,944)		Gain (loss) on commodity derivatives, net	4,832		(88,554)
Interest expense, net	Interest expense, net	(7,433)		(7,444)		Interest expense, net	(12,173)		(7,433)
Other income (expense), net	Other income (expense), net	(3)		(56)		Other income (expense), net	5		(3)

Income (Loss) Before Income Taxes	Income (Loss) Before Income Taxes	(36,351)		(7,468)		Income (Loss) Before Income Taxes	148,607		(36,351)

Provision (Benefit) for Income Taxes	Provision (Benefit) for Income Taxes	(408)		(572)		Provision (Benefit) for Income Taxes	6,066		(408)

Net Income (Loss)	Net Income (Loss)	$	(35,943)	$	(6,896)	Net Income (Loss)	$	142,541	$	(35,943)

Per Share Amounts:	Per Share Amounts:					Per Share Amounts:

Basic Earnings (Loss) Per Share	Basic Earnings (Loss) Per Share	$	(2.85)	$	(0.58)	Basic Earnings (Loss) Per Share	$	6.39	$	(2.85)

Diluted Earnings (Loss) Per Share	Diluted Earnings (Loss) Per Share	$	(2.85)	$	(0.58)	Diluted Earnings (Loss) Per Share	$	6.29	$	(2.85)

Weighted-Average Shares Outstanding - Basic	Weighted-Average Shares Outstanding - Basic	12,629		11,935		Weighted-Average Shares Outstanding - Basic	22,308		12,629

Weighted-Average Shares Outstanding - Diluted	Weighted-Average Shares Outstanding - Diluted	12,629		11,935		Weighted-Average Shares Outstanding - Diluted	22,669		12,629

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 Subsidiary (in thousands, except per-share amounts)

Nine Months Ended September 30, 2021 Nine Months Ended September 30, 2020
Revenues:
Oil and gas sales $ 255,850 $ 123,921
Operating Expenses:
General and administrative, net 14,872 17,926
Depreciation, depletion, and amortization 45,485 51,130
Accretion of asset retirement obligations 226 263
Lease operating expenses 18,767 16,023
Workovers 512 8
Transportation and gas processing 17,175 16,291
Severance and other taxes 11,974 7,513
Write-down of oil and gas properties — 355,948
Total Operating Expenses 109,011 465,102
Operating Income (Loss) 146,839 (341,181)
Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net (152,879) 66,884
Interest expense, net (21,888) (23,876)
Other income (expense), net 6 50
Income (Loss) Before Income Taxes (27,922) (298,123)
Provision (Benefit) for Income Taxes (408) 20,607
Net Income (Loss) $ (27,514) $ (318,730)
Per Share Amounts:
Basic Earnings (Loss) Per Share $ (2.24) $ (26.81)
Diluted Earnings (Loss) Per Share $ (2.24) $ (26.81)
Weighted-Average Shares Outstanding - Basic 12,283 11,890
Weighted-Average Shares Outstanding - Diluted 12,283 11,890
See accompanying Notes to Condensed Consolidated Financial Statements.


	Nine Months Ended September 30, 2022		Nine Months Ended September 30, 2021
Revenues:
Oil and gas sales	$	554,442	$	255,850

Operating Expenses:
General and administrative, net	14,840		14,872
Depreciation, depletion, and amortization	89,096		45,485
Accretion of asset retirement obligations	366		226
Lease operating expenses	37,095		18,767
Workovers	933		512
Transportation and gas processing	22,784		17,175
Severance and other taxes	30,183		11,974

Total Operating Expenses	195,297		109,011

Operating Income	359,145		146,839

Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net	(157,816)		(152,879)
Interest expense, net	(26,632)		(21,888)
Other income (expense), net	57		6

Income (Loss) Before Income Taxes	174,754		(27,922)

Provision (Benefit) for Income Taxes	7,678		(408)

Net Income (Loss)	$	167,076	$	(27,514)

Per Share Amounts:

Basic Earnings (Loss) Per Share	$	8.85	$	(2.24)

Diluted Earnings (Loss) Per Share	$	8.69	$	(2.24)

Weighted-Average Shares Outstanding - Basic	18,885		12,283

Weighted-Average Shares Outstanding - Diluted	19,237		12,283

See accompanying Notes to Condensed Consolidated Financial Statements.

Table of Contents

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

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


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

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

Vesting of share-based compensation (105,108 shares)		1		(1)		—		—		—
Share-based compensation		—		1,335		—		—		1,335
Net Loss		—		—		—		(5,858)		(5,858)
Balance, March 31, 2020		$	120	$	294,250	$	(2,365)	$	99,096	$	391,101
Shares issued from warrant exercise (5 shares)		—		—		—		—		—
Purchase of treasury shares (1,098 shares)		—		—		(3)		—		(3)
Vesting of share-based compensation (49,665 shares)		—		—		—		—		—
Share-based compensation		—		1,229		—		—		1,229
Net Loss		—		—		—		(305,976)		(305,976)
Balance, June 30, 2020		$	120	$	295,479	$	(2,368)	$	(206,880)	$	86,351
Purchase of treasury shares (958 shares)		—		—		(4)		—		(4)
Vesting of share-based compensation (3,953 shares)		1		—		—		—		1
Share-based compensation		—		1,150		—		—		1,150
Net Loss		—		—		—		(6,896)		(6,896)
Balance, September 30, 2020		$	121	$	296,629	$	(2,372)	$	(213,776)	$	80,602
													Common Stock		Additional Paid-In Capital		Treasury Stock		Retained Earnings (Accumulated Deficit)		Total
Balance, December 31, 2020	Balance, December 31, 2020	$	121	$	297,712	$	(2,372)	$	(204,428)	$	91,033	Balance, December 31, 2020	$	121	$	297,712	$	(2,372)	$	(204,428)	$	91,033

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

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

Purchase of treasury shares (13,969 shares)	Purchase of treasury shares (13,969 shares)	—		—		(115)		—		(115)		Purchase of treasury shares (13,969 shares)	—		—		(115)		—		(115)
Vesting of share-based compensation (51,332 shares)	Vesting of share-based compensation (51,332 shares)	1		(1)		—		—		—		Vesting of share-based compensation (51,332 shares)	1		(1)		—		—		—

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

Balance, December 31, 2021												Balance, December 31, 2021	$	168	$	413,017	$	(2,984)	$	(117,669)	$	292,532

Purchase of treasury shares (96,012 shares)												Purchase of treasury shares (96,012 shares)	—		—		(2,462)		—		(2,462)
Treasury shares pursuant to purchase price adjustment (41,191 shares)												Treasury shares pursuant to purchase price adjustment (41,191 shares)	—		—		(1,146)		—		(1,146)
Vesting of share-based compensation (318,390 shares)												Vesting of share-based compensation (318,390 shares)	3		(3)		—		—		—
Issuance pursuant to acquisition (489 shares)												Issuance pursuant to acquisition (489 shares)	—		12		—		—		12
Share-based compensation												Share-based compensation	—		1,101		—		—		1,101
Net Loss												Net Loss	—		—		—		(64,255)		(64,255)
Balance, March 31, 2022												Balance, March 31, 2022	$	171	$	414,127	$	(6,592)	$	(181,924)	$	225,782
Stock options exercised (4,497 shares)												Stock options exercised (4,497 shares)	—		39		—		—		39
Purchase of treasury shares (16,485 shares)												Purchase of treasury shares (16,485 shares)	—		—		(503)		—		(503)
Vesting of share-based compensation (57,355 shares)												Vesting of share-based compensation (57,355 shares)	1		(1)		—		—		—

Issuance pursuant to acquisitions (5,448,472 shares)												Issuance pursuant to acquisitions (5,448,472 shares)	55		157,338		—		—		157,393
Share-based compensation												Share-based compensation	—		1,756		—		—		1,756
Net Income												Net Income	—		—		—		88,790		88,790
Balance, June 30, 2022												Balance, June 30, 2022	$	227	$	573,259	$	(7,095)	$	(93,134)	$	473,257
Stock options exercised (11,087 shares)												Stock options exercised (11,087 shares)	—		387		—		—		387
Purchase of treasury shares (7,853 shares)												Purchase of treasury shares (7,853 shares)	—		—		(432)		—		(432)
Treasury shares pursuant to purchase price adjustment (184 shares)												Treasury shares pursuant to purchase price adjustment (184 shares)	—		—		(7)		—		(7)

Share-based compensation												Share-based compensation	—		1,239		—		—		1,239
Net Income												Net Income	—		—		—		142,541		142,541
Balance, September 30, 2022												Balance, September 30, 2022	$	227	$	574,885	$	(7,534)	$	49,407	$	616,985
See accompanying Notes to Condensed Consolidated Financial Statements.	See accompanying Notes to Condensed Consolidated Financial Statements.											See accompanying Notes to Condensed Consolidated Financial Statements.

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Condensed Consolidated Statements of Cash Flows (Unaudited)

SilverBow Resources, Inc. and Subsidiary (in thousands)


		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020			Nine Months Ended September 30, 2022		Nine Months Ended September 30, 2021
Cash Flows from Operating Activities:	Cash Flows from Operating Activities:					Cash Flows from Operating Activities:
Net income (loss)	Net income (loss)	$	(27,514)	$	(318,730)	Net income (loss)	$	167,076	$	(27,514)
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	45,485		51,130		Depreciation, depletion, and amortization	89,096		45,485
Write-down of oil and gas properties		—		355,948

Accretion of asset retirement obligations	Accretion of asset retirement obligations	226		263		Accretion of asset retirement obligations	366		226
Deferred income taxes	Deferred income taxes	—		21,087		Deferred income taxes	7,496		—
Share-based compensation	Share-based compensation	3,450		3,503		Share-based compensation	3,901		3,450
(Gain) Loss on derivatives, net	(Gain) Loss on derivatives, net	152,879		(66,884)		(Gain) Loss on derivatives, net	157,816		152,879
Cash settlement (paid) received on derivatives	Cash settlement (paid) received on derivatives	(28,976)		76,150		Cash settlement (paid) received on derivatives	(182,058)		(28,976)
Settlements of asset retirement obligations	Settlements of asset retirement obligations	(151)		(27)		Settlements of asset retirement obligations	(47)		(151)
Write down of debt issuance cost	Write down of debt issuance cost	229		459		Write down of debt issuance cost	350		229
Other	Other	1,883		2,436		Other	(6,425)		1,883
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	(20,941)		7,413		(Increase) decrease in accounts receivable and other current assets	(47,320)		(20,941)
Increase (decrease) in accounts payable and accrued liabilities	Increase (decrease) in accounts payable and accrued liabilities	7,215		(3,981)		Increase (decrease) in accounts payable and accrued liabilities	20,260		7,215
Increase (decrease) in income taxes payable	Increase (decrease) in income taxes payable	—		(480)		Increase (decrease) in income taxes payable	(21)		—
Increase (decrease) in accrued interest	Increase (decrease) in accrued interest	(137)		(505)		Increase (decrease) in accrued interest	1,688		(137)
Net Cash Provided by (Used in) Operating Activities	Net Cash Provided by (Used in) Operating Activities	133,648		127,782		Net Cash Provided by (Used in) Operating Activities	212,178		133,648
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	(98,219)		(102,713)		Additions to property and equipment	(163,567)		(98,219)
Acquisition of oil and gas properties		(13,219)		(3,441)
Acquisition of oil and gas properties, net of purchase price adjustments						Acquisition of oil and gas properties, net of purchase price adjustments	(293,880)		(13,219)
Proceeds from the sale of property and equipment	Proceeds from the sale of property and equipment	—		4,752		Proceeds from the sale of property and equipment	4,415		—
Payments on property sale obligations	Payments on property sale obligations	(1,084)		(426)		Payments on property sale obligations	(750)		(1,084)

Net Cash Provided by (Used in) Investing Activities	Net Cash Provided by (Used in) Investing Activities	(112,522)		(101,828)		Net Cash Provided by (Used in) Investing Activities	(453,782)		(112,522)
Cash Flows from Financing Activities:	Cash Flows from Financing Activities:					Cash Flows from Financing Activities:

Proceeds from bank borrowings	Proceeds from bank borrowings	195,000		71,000		Proceeds from bank borrowings	679,000		195,000
Payments of bank borrowings	Payments of bank borrowings	(227,000)		(97,000)		Payments of bank borrowings	(426,000)		(227,000)
Net proceeds from issuances of common stock	Net proceeds from issuances of common stock	12,756		—		Net proceeds from issuances of common stock	—		12,756
Net proceeds from stock options exercised						Net proceeds from stock options exercised	39		—
Purchase of treasury shares	Purchase of treasury shares	(612)		(90)		Purchase of treasury shares	(3,404)		(612)
Payments of debt issuance costs	Payments of debt issuance costs	(2,400)		—		Payments of debt issuance costs	(7,228)		(2,400)
Net Cash Provided by (Used in) Financing Activities	Net Cash Provided by (Used in) Financing Activities	(22,256)		(26,090)		Net Cash Provided by (Used in) Financing Activities	242,407		(22,256)
Net Increase (Decrease) in Cash and Cash Equivalents	Net Increase (Decrease) in Cash and Cash Equivalents	(1,130)		(136)		Net Increase (Decrease) in Cash and Cash Equivalents	803		(1,130)
Cash and Cash Equivalents at Beginning of Period	Cash and Cash Equivalents at Beginning of Period	2,118		1,358		Cash and Cash Equivalents at Beginning of Period	1,121		2,118
Cash and Cash Equivalents at End of Period	Cash and Cash Equivalents at End of Period	$	988	$	1,222	Cash and Cash Equivalents at End of Period	$	1,924	$	988
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	$	20,277	$	22,290	Cash paid during period for interest, net of amounts capitalized	$	22,701	$	20,277

Non-cash Investing and Financing Activities:	Non-cash Investing and Financing Activities:					Non-cash Investing and Financing Activities:
Changes in capital accounts payable and capital accruals	Changes in capital accounts payable and capital accruals	$	11,393	$	(25,641)	Changes in capital accounts payable and capital accruals	$	60,595	$	11,393
Non-cash equity consideration for acquisitions	Non-cash equity consideration for acquisitions	$	(10,023)	$	—	Non-cash equity consideration for acquisitions	$	(156,259)	$	(10,023)

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

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Notes to Condensed Consolidated Financial Statements (Unaudited)

SilverBow Resources, Inc. and Subsidiary

(1) General Information

SilverBow Resources, Inc. (“SilverBow,” the “Company,” or “we”) is an independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford and Austin Chalk located in South Texas. Being a committed and long-term operator in South Texas, the Company possesses a significant understanding of the reservoirs in the region. We leverage this competitive understanding to assemble high quality drilling inventory while continuously enhancing our operations to maximize returns on capital invested.

The condensed consolidated financial statements included herein are unaudited and certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2020.~~2021.

(2) Summary of Significant Accounting Policies

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

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

~~COVID-19~~Stockholder Rights Agreement. On September 20, 2022, the Board adopted a stockholder rights agreement (the “Rights Agreement”) and declared a dividend distribution of one right (each, a “Right” and together with all such rights distributed or issued pursuant to the Rights Agreement, dated as of September 20, 2022, by and between the Company and American Stock Transfer & Trust Company, LLC, as rights agent, the “Rights”) for each outstanding share of Company common stock to holders of record on October 5, 2022. In the event that a person or group acquires beneficial ownership of 15% or more of the Company’s then-outstanding common stock, subject to certain exceptions, each Right would entitle its holder (other than such person or members of such group) to purchase additional shares of Company common stock at a substantial discount to the public market price. In addition, at any time after a person or group acquires beneficial ownership of 15% or more of the outstanding common stock, subject to certain exceptions, the Board may direct the Company to exchange the Rights (other than Rights owned by such person or certain related parties, which will have become null and void), in whole or in part, at an exchange ratio of one share of common stock per Right (subject to adjustment). While in effect, the Rights Agreement could make it more difficult for a third party to acquire control of the Company or a large block of the common stock of the Company without the approval of the Board. The ~~spread of COVID-19 and its impact~~Rights Agreement will expire on the ~~global supply~~earliest of and demand for crude oil caused volatility in the market price for crude oil during 2020. The spot price of West Texas Intermediate (“WTI”) crude oil declined over 50% in March and April of 2020 before gradually improving through the rest of 2020 and through(a) 5:00 p.m., New York City time, on the first ~~three quarters of 2021. The spot price of Brent and WTI crude oil closed at approximately $64 and $59 per barrel, respectively, on March 31, 2021, approximately $77 and $74 per barrel, respectively,~~business day after the 2023 annual stockholders’ meeting, (b) 5:00 p.m., New York City time, on June 30, ~~2021,~~2023, (c) the time at which the Rights are redeemed and ~~approximately $78 and $75 per barrel, respectively, on September 30, 2021.~~

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

full.

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

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

On October ~~1, 2021, we~~31, 2022, the Company closed ~~on an all-stock~~a transaction to acquire Eagle Ford and Austin Chalk oil and gas assets in ~~the Eagle Ford. The acquired assets include a 100% working interest in approximately 15,000 net oil-weighted acres across Atascosa, Fayette~~DeWitt and ~~Lavaca counties, as well as approximately 26,000 net gas-weighted acres directly offsetting our existing position in McMullen and Live Oak~~Gonzales counties. After consideration of closing adjustments, ~~we issued 1,341,990 shares~~SilverBow paid $79.3 million for the assets. The acquisition is subject to further customary post-closing adjustments. As of ~~our common stock for~~September 30, 2022, the Company paid an ~~aggregate~~$8.7 million deposit associated with this acquisition which is recorded in “Other long-term assets” in the accompanying condensed consolidated balance sheet. The company did not incur any significant third party transaction costs associated with this acquisition.

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

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

~~Through November 4, 2021,~~31, 2022, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after September 30, ~~2021:~~2022:


Oil Derivative Contracts (New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) Settlements)		Total Volumes (Bbls)	Weighted-Average Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
Swap Contracts
2023 Contracts
1Q23		275	$	69.40
2Q23		575	$	68.40
3Q23		53,980	$	66.55
Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)									Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
Collar Contracts	Collar Contracts								Collar Contracts
2022 Contracts
1Q22		45,000			$	73.00	$	79.75
2Q22		45,500			$	71.00	$	78.00
3Q22		46,000			$	70.00	$	75.40
4Q22		46,000			$	68.00	$	73.60
2023 Contracts	2023 Contracts								2023 Contracts
1Q23	1Q23	45,000			$	65.00	$	72.80	1Q23	900,000	$	5.00	$	7.55
2Q23	2Q23	45,500			$	64.00	$	70.85	2Q23	910,000	$	4.00	$	5.20
3Q23	3Q23	46,000			$	63.00	$	69.10	3Q23	920,000	$	4.00	$	5.52
4Q23	4Q23	46,000			$	62.00	$	67.55	4Q23	920,000	$	4.50	$	6.08
2024 Contracts									2024 Contracts
1Q24									1Q24	910,000	$	4.75	$	6.25
2Q24									2Q24	910,000	$	3.75	$	4.45
3Q24									3Q24	920,000	$	3.75	$	4.70
4Q24									4Q24	920,000	$	4.00	$	5.42


Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes (MMBtu)	Weighted-Average Price
2023 Contracts
1Q23	3,600,000	$	(0.03)
2Q23	3,640,000	$	(0.24)
3Q23	3,680,000	$	(0.21)
4Q23	3,680,000	$	(0.28)

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

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


NGL Swaps (Mont Belvieu)	Total Volumes (Bbls)	Weighted-Average Price
2023 Contracts
1Q23	45,000	$	27.09
2Q23	45,500	$	27.09
3Q23	46,000	$	27.09
4Q23	46,000	$	27.09

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

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

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

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

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

•estimates of future costs to develop and produce reserves,

•accruals related to oil and gas sales, capital expenditures and lease operating expenses, ~~(“LOE”),~~

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

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

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

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

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

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

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

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

•estimates on future lease obligations.

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

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

Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended September 30, ~~2021~~2022 and ~~2020,~~2021, such internal costs when capitalized totaled ~~$1.2~~$1.1 million and ~~$0.8~~$1.2 million, respectively. For the nine months ended September 30, ~~2021~~2022 and ~~2020,~~2021, such internal costs when capitalized totaled ~~$3.5~~$3.3 million and ~~$2.8~~$3.5 million, respectively. Interest costs are also capitalized to unproved oil and natural gas ~~properties~~

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~~(refer to Note 6 of these Notes to Condensed Consolidated Financial Statements for further discussion on~~properties. There was no capitalized interest ~~costs).~~on our unproved properties for the three months ended September 30, 2022 and 2021 and the nine months ended September 30, 2022 and 2021.

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


		September 30, 2021		December 31, 2020			September 30, 2022		December 31, 2021
Property and Equipment	Property and Equipment					Property and Equipment
Proved oil and gas properties	Proved oil and gas properties	$	1,445,818	$	1,310,008	Proved oil and gas properties	$	2,321,809	$	1,588,978
Unproved oil and gas properties	Unproved oil and gas properties	24,988		28,090		Unproved oil and gas properties	17,478		17,090
Furniture, fixtures and other equipment	Furniture, fixtures and other equipment	5,780		5,275		Furniture, fixtures and other equipment	6,030		5,885
Less – Accumulated depreciation, depletion, amortization & impairment	Less – Accumulated depreciation, depletion, amortization & impairment	(846,822)		(801,279)		Less – Accumulated depreciation, depletion, amortization & impairment	(959,139)		(869,985)
Property and Equipment, Net	Property and Equipment, Net	$	629,764	$	542,094	Property and Equipment, Net	$	1,386,178	$	741,968

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

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

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recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two and 20 years. Repairs and maintenance are charged to expense as incurred.

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

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

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

Due to the effects of pricing and timing of projects we reported a non-cash impairment write-down, on a pre-tax basis, of $355.9 million for the nine months ended September 30, 2020 on our oil and natural gas properties. There was no impairment for the three months ended September 30, 2022 and 2021 and the nine months ended September 30, ~~2021~~2022 and ~~the three months ended September 30, 2020.~~2021.

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If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur again in the future. We cannot control and cannot predict what future prices for oil and natural gas will be; therefore, we cannot estimate the amount of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices. However, it is reasonably possible that we will record additional Ceiling Test write-downs in future periods.

Accounts Receivable, Net. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both September 30, ~~2021~~2022 and December 31, ~~2020,~~2021, we had an allowance for doubtful accounts of less than $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable, net” balance on the accompanying condensed consolidated balance sheets.

At September 30, 2022, our “Accounts receivable, net” balance included $91.6 million for oil and gas sales, $2.8 million due from joint interest owners, $2.6 million for severance tax credit receivables and $5.6 million for other receivables. At December 31, 2021, our “Accounts receivable, net” balance included ~~$41.8~~$45.3 million for oil and gas sales, ~~$0.8~~$1.9 million due from joint interest owners, ~~$1.2~~$1.0 million for severance tax credit receivables and $0.4 million for other receivables. At December 31, 2020, our “Accounts receivable, net” balance included $18.8 million for oil and gas sales, $4.0 million due from joint interest owners, $2.4 million for severance tax credit receivables and $0.7$1.5 million for other receivables.

Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the nine months ended September 30, ~~2021~~2022 and ~~2020~~2021 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was ~~$1.3~~$2.8 million and ~~$1.1~~$1.3 million for the three months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively, and ~~$3.6~~$6.1 million and ~~$3.2~~$3.6 million for the nine months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively.

Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. In March and April 2020, the COVID-19 pandemic caused volatility in the market price for crude oil due to the disruption of global supply and demand. In response to these market conditions and given the decline in oil prices and economic outlook for our Company, during the quarter ended June 30, 2020 managementManagement has determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other federal deferred tax assets and, accordingly, has recorded a ~~full~~ valuation allowance ~~in the second quarter~~ to offset its net federal deferred tax assets in excess of deferred tax liabilities. As a result of the full valuation allowance established at June 30, 2020, we recorded an income tax provision of $20.6 million for the nine months ended September 30, 2020, which was inclusive of state income tax expense. The Company maintains a full valuation allowance against its net federal deferred tax assets in excess of deferred tax liabilities, with the exception of a $11.3 million and $5.5 million deferred

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tax liability that was recorded as of September 30, ~~2021.~~2022 and December 31, 2021, respectively. We recorded an income tax ~~benefit~~provision of $6.1 million and $7.7 million for the three and nine months ended September 30, 2022, respectively, which was primarily attributable to a deferred federal income tax expense and state deferred income tax expense. The provision for the three and nine months ended September 30, 2022 is a product of the overall forecasted annual effective tax rate applied to the year to date income. There was $0.4 million income tax benefit for both the three and nine months ended September 30, ~~2021~~2021.

As of the third quarter of 2022, the Company still maintains a full valuation allowance. Management will continue to assess available positive and ~~$0.6 million for~~negative evidence to estimate whether sufficient future taxable income will be generated to permit the ~~three~~use of deferred tax assets. The amount of the deferred tax asset considered realizable, however, could be adjusted based on changes in subjective estimates of future taxable income or if objectively verifiable positive evidence is deemed to outweigh the objectively verifiable negative evidence. The Company intends to continue to record a full valuation allowance on its deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of the allowance. However, if current commodity prices are sustained and absent any additional objectively verifiable negative evidence, it is reasonably possible that sufficient objectively verifiable positive evidence will exist within the next 12 months ~~ended September 30, 2020 which were fully attributable~~ to adjust the current valuation allowance position. Exact timing and amount of the adjustment to the valuation allowance is unknown at this time.

Section 382 of the Internal Revenue Code (“Section 382”) imposes limitations on a ~~current state income tax benefit.~~corporation’s ability to utilize its net operating losses (“NOLs”) if it experiences an ownership change. Generally, an “ownership change” occurs if one or more shareholders, each of whom is deemed to own five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50 percent over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382. We believe we had an ownership change in August 2022 and, therefore, are subject to an annual limitation on the usage of our NOLs generated prior to the ownership change. However, we do not expect to have any of our NOLs expire before becoming available to be utilized by the Company. Management will continue to monitor the potential impact of Section 382 with respect to our NOLs.

Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At September 30, ~~2021~~2022 and December 31, ~~2020,~~2021, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.

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

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

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The following table provides information regarding our oil and gas sales, by product, reported on the Condensed Consolidated Statements of Operations for the three months ended September 30, 2022 and 2021 and the nine months ended September 30, ~~2021~~2022 and ~~2020~~2021 (in thousands):


		Three Months Ended September 30, 2021		Three Months Ended September 30, 2020		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020			Three Months Ended September 30, 2022		Three Months Ended September 30, 2021		Nine Months Ended September 30, 2022		Nine Months Ended September 30, 2021
Oil, natural gas and NGLs sales:	Oil, natural gas and NGLs sales:									Oil, natural gas and NGLs sales:
Oil	Oil	$	25,230	$	17,665	$	58,587	$	40,979	Oil	$	71,811	$	25,230	$	155,566	$	58,587
Natural gas	Natural gas	62,529		23,595		172,234		73,170		Natural gas	150,958		62,530		351,626		172,234
NGLs	NGLs	11,489		4,439		25,030		9,772		NGLs	19,412		11,489		47,250		25,029
Total	Total	$	99,249	$	45,699	$	255,850	$	123,921	Total	$	242,181	$	99,249	$	554,442	$	255,850

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

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

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	September 30, 2022		December 31, 2021
Trade accounts payable	$	21,154	$	9,688
Accrued operating expenses	10,175		4,192
Accrued compensation costs	3,775		7,029
Asset retirement obligations – current portion	529		524
Accrued non-income based taxes	16,352		3,314
Accrued corporate and legal fees	560		1,972
WTI contingency payouts - current portion	2,948		—
Payable for settled derivatives	19,463		6,371
Other payables	5,151		1,944
Total accounts payable and accrued liabilities	$	80,107	$	35,034

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. The Company maintains cash and cash equivalent balances with major financial institutions, which at times exceed federally insured limits. The Company monitors the financial condition of the financial institutions and has experienced no losses associated with these accounts.

Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock, held at cost” on the accompanying condensed consolidated balance sheets. For the nine months ended September 30, ~~2021~~2022, we purchased 120,350 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares and ~~2020,~~received 41,375 shares in conjunction with our post-closing settlement for a previously disclosed acquisition. For the nine months ended September 30, 2021 we purchased 74,586 ~~and 28,731~~ treasury shares ~~respectively,~~ to satisfy withholding tax obligations arising upon the vesting of restricted shares.

~~ATM Program.~~New Accounting Pronouncements ~~On August 13, 2021,~~. In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13 , Credit Losses - Measurement of Credit Losses on Financial Instruments. The standard changes how entities will measure credit losses for most financial assets, including accounts and notes receivables. The new standard replaces the existing incurred loss impairment methodology with a methodology that requires consideration of a broader range of reasonable and supportable forward-looking information to estimate all expected credit losses. The updated guidance is effective for the Company ~~entered into~~for annual and quarterly reporting periods beginning after December 15, 2022. We are currently reviewing these new requirements and adoption of this guidance is not expected to have a material impact on the Company’s financial statements or disclosures.

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021. The guidance provides and clarifies optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The amendments within these ASUs were in effect for a limited time beginning March 12, 2020, and an ~~equity distribution agreement pursuant~~entity may elect to ~~which~~apply the amendments prospectively through December 31, 2022. In April 2022, the FASB proposed to extend the effective date through December 31, 2024; however, a final ruling has not been issued. As of September 30, 2022, the Company ~~may sell, from time to time in the open market, shares of the Company’s common stock, having aggregate proceeds of up to $40.0 million (the “ATM Program”). The Company intends~~has not elected to use the ~~net proceeds from any sales through~~optional guidance and continues to evaluate the ~~ATM Program~~options provided by ASU 2020-04 and ASU 2021-01.

In August 2020, the FASB issued ASU No. 2020-06, Accounting for ~~general corporate purposes,~~Convertible Instruments and Contracts in an Entity’s Own Equity. The guidance simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including ~~but not limited~~convertible instruments and contracts in an entity’s own equity. Additionally, the amendment requires the application of the if-converted method to ~~financing~~calculate the impact of capital expenditures, repayment or refinancing of outstanding debt, financing acquisitions or investments, financing other business opportunities, and general working capital purposes. During the three months ended September 30, 2021 (from August 13, 2021 through September 30, 2021),convertible instruments on diluted earnings per share (EPS). The guidance is effective the Company ~~sold 669,600 shares~~for fiscal years beginning after December 15, 2022. The adoption of ~~common stock for net proceeds of $12.8 million after deducting sales agents' commissions and other related expenses.~~this guidance is not expected to have a material impact on the Company’s financial statements or disclosures.

(3) Leases

The Company ~~adopted the standard provided in~~follows the Financial Accounting Standards Board's Accounting Standards Update 2016-02 and elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that

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allows an entity to carry forward historical accounting treatment for land easements on existing agreements. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the Consolidated Balance Sheets. We have elected to not account for lease and non-lease components separately.

The Company has contractual agreements for its corporate office lease, vehicle fleet, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of September 30, ~~2021,~~2022, all of the Company’s leases were operating leases.

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

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


		Three Months Ended September 30, 2021		Three Months Ended September 30, 2020		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020			Three Months Ended September 30, 2022		Three Months Ended September 30, 2021		Nine Months Ended September 30, 2022		Nine Months Ended September 30, 2021
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	$	1,189	$	—	$	3,009	$	2,302	Property, plant and equipment acquisitions - short-term leases	$	5,850	$	1,189	$	9,883	$	3,009
Property, plant and equipment acquisitions - operating leases	Property, plant and equipment acquisitions - operating leases	—		—		—		10		Property, plant and equipment acquisitions - operating leases	—		—		—		—
Total lease costs in property, plant and equipment additions	Total lease costs in property, plant and equipment additions	$	1,189	$	—	$	3,009	$	2,312	Total lease costs in property, plant and equipment additions	$	5,850	$	1,189	$	9,883	$	3,009


		Three Months Ended September 30, 2021		Three Months Ended September 30, 2020		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020			Three Months Ended September 30, 2022		Three Months Ended September 30, 2021		Nine Months Ended September 30, 2022		Nine Months Ended September 30, 2021
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 expenses - short-term leases	Lease operating expenses - short-term leases	$	314	$	124	$	1,399	$	575	Lease operating expenses - short-term leases	$	1,714	$	314	$	3,677	$	1,399
Lease operating expenses - operating leases	Lease operating expenses - operating leases	1,504		1,397		3,774		4,267		Lease operating expenses - operating leases	2,163		1,504		6,118		3,774
General and administrative, net - operating leases	General and administrative, net - operating leases	303		172		653		532		General and administrative, net - operating leases	186		303		568		653
Total lease cost expensed	Total lease cost expensed	$	2,121	$	1,693	$	5,826	$	5,374	Total lease cost expensed	$	4,063	$	2,121	$	10,363	$	5,826

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


	September 30, ~~2021~~2022
Weighted-average remaining lease term (in years)	~~3.2~~2.6
Weighted-average discount rate	~~4.1~~4.4	%

As of September 30, ~~2021,~~2022, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands):

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

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	As of September 30, 2022
2022 (Remaining)	$	2,474
2023	8,675
2024	1,600
2025	839
2026	699
Thereafter	524
Total undiscounted lease payments	14,811
Present value adjustment	(853)
Net operating lease liabilities	$	13,958

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


		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020			Nine Months Ended September 30, 2022		Nine Months Ended September 30, 2021
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	$	4,289	$	4,793	Operating cash flows from operating leases	$	6,643	$	4,289
Investing cash flows from operating leases		$	—	$	10

Non-cash Investing and Financing Activities						Non-cash Investing and Financing Activities
Additions to ROU assets obtained from new operating lease liabilities						Additions to ROU assets obtained from new operating lease liabilities	$	4,453	$	6,541

(4) Share-Based Compensation

Share-Based Compensation Plans

In 2016, the Company adopted the 2016 Equity Incentive Plan (as amended from time to time, the “2016 Plan”). The Company also adopted the Inducement Plan (as amended from time to time, the “Inducement Plan,” and, together with the 2016 Plan, the “Plans”) on December 15, 2016.

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

The expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying condensed consolidated statements of operations was $1.2 million ~~and $1.1 million~~ for both the three months ended September 30, 2022 and 2021, and ~~2020, respectively,~~$3.9 million and $3.5 million for ~~both~~ the nine months ended September 30, 2022 and 2021, ~~and 2020.~~respectively. Capitalized share-based compensation was less than $0.1 million for both the three months ended September 30, ~~2021~~2022 and ~~2020~~2021 and $0.2 million for both the nine months ended September 30, ~~2021~~2022 and ~~2020.~~2021.

We view stock option awards and RSUs with graded vesting as single awards with an expected life equal to the average expected life of component awards, and we amortize the awards on a straight-line basis over the life of the awards. The Company accounts for forfeitures in compensation cost when they occur.

Stock Option Awards

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

At September 30, ~~2021,~~2022, we had ~~$0.2 million of~~no unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the nine months ended September 30, ~~2021:~~2022:

Shares Wtd. Avg. Exer. Price
Options outstanding, beginning of period 303,705 $ 27.73
Options forfeited (3,896) $ 16.96
Options expired (23,800) $ 23.25
Options outstanding, end of period 276,009 $ 28.12
Options exercisable, end of period 226,950 $ 28.53

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	Shares	Wtd. Avg. Exer. Price
Options outstanding, beginning of period	276,009	$	28.12


Options expired	(64,263)	$	33.48
Options exercised	(15,584)	$	26.96
Options outstanding, end of period	196,162	$	26.46
Options exercisable, end of period	196,162	$	26.46

Our outstanding stock option awards had ~~$0.1~~$0.3 million measurable aggregate intrinsic value at September 30, ~~2021.~~2022. At September 30, ~~2021,~~2022, the weighted-average remaining contract life of stock option awards outstanding was ~~4.4~~4.6 years and exercisable was ~~4.1~~4.6 years. The total intrinsic value of stock option awards exercisable was ~~less than $0.1~~$0.3 million ~~for the nine months ended~~as of September 30, ~~2021.~~2022.

Restricted Stock Units

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

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As of September 30, ~~2021,~~2022, we had ~~$1.3~~$3.4 million unrecognized compensation expense related to our RSUs which is expected to be recognized over a weighted-average period of ~~0.8~~2.2 years.

The following table provides information regarding RSU activity for the nine months ended September 30, ~~2021:~~2022:


		RSUs	Wtd. Avg. Grant Price			RSUs	Wtd. Avg. Grant Price
RSUs outstanding, beginning of period	RSUs outstanding, beginning of period	574,916	$	9.02	RSUs outstanding, beginning of period	344,845	$	8.60
RSUs granted	RSUs granted	100,178	$	8.33	RSUs granted	179,416	$	26.00

RSUs forfeited	RSUs forfeited	(17,802)	$	11.09	RSUs forfeited	(8,734)	$	21.20
RSUs vested	RSUs vested	(312,447)	$	9.14	RSUs vested	(277,933)	$	8.86
RSUs outstanding, end of period	RSUs outstanding, end of period	344,845	$	8.60	RSUs outstanding, end of period	237,594	$	20.97

Performance-Based Stock Units

On ~~February 20, 2018,~~May 21, 2019, the Company granted ~~30,700~~99,500 PSUs for which the number of shares earned iswas based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2018 to December 31, 2020. The awards contain market conditions which allow a payout ranging between 0% payout and 200% of the target payout. The fair value as of the date of valuation was $41.66 per unit or 150.61% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte-Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards had a cliff-vesting period of ~~three~~ ~~years and the period ended without any of the awards vesting. There are no outstanding PSUs related to this award as of September 30, 2021.~~

On May 21, 2019, the Company granted 99,500 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2019 to December 31, 2021. The awards ~~contain~~contained market conditions which ~~allow~~allowed a payout ranging between 0% payout and 200% of the target payout. The fair value as of the grant date was $18.86 per unit or 112.9% of stock price. The awards ~~have~~had a cliff-vesting period of three years. ~~There~~In the first quarter of 2022, the Board and its Compensation Committee approved payout of these awards at 117% of target. Accordingly, 97,812 shares were ~~83,600 PSUs outstanding related to this award as of September 30, 2021.~~issued on February 23, 2022.

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

On February 23, 2022, the Company granted 122,111 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2022 to December 31, 2024. 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 $36.47 per unit or 150.93% 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

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awards have a cliff-vesting period of three years. All PSUs granted remain outstanding related to this award as of September 30, 2022.

As of September 30, ~~2021,~~2022, we had ~~$1.7~~$3.8 million unrecognized compensation expense related to our PSUs based on the assumption of 100% target payout. The remaining weighted-average performance period is ~~1.1 years while 23,800 shares vested during~~2.1 years.

The following table provides information regarding performance-based stock unit activity for the nine months ended September 30, ~~2021.~~2022:


	PSUs	Wtd. Avg. Grant Price
Performance based stock units outstanding, beginning of period	244,989	$	18.84
Performance based stock units granted	122,111	$	36.47
Performance based stock units incremental shares granted	14,212	$	18.86
Performance based stock units vested	(97,812)	$	18.86
Performance based stock units outstanding, end of period	283,500	$	23.18

(5) Earnings Per Share

Basic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three and nine months ended September 30, ~~2021~~2022 and ~~2020~~2021 are discussed below.

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


		Three Months Ended September 30, 2021					Three Months Ended September 30, 2020						Three Months Ended September 30, 2022					Three Months Ended September 30, 2021
		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	$	(35,943)	12,629	$	(2.85)	$	(6,896)	11,935	$	(0.58)	Net Income (Loss) and Share Amounts	$	142,541	22,308	$	6.39	$	(35,943)	12,629	$	(2.85)
Dilutive Securities:	Dilutive Securities:											Dilutive Securities:

Performance Based Stock Unit Awards												Performance Based Stock Unit Awards			169					—
RSU Awards	RSU Awards			—					—			RSU Awards			137					—

Stock Option Awards												Stock Option Awards			55					—
Diluted EPS:	Diluted EPS:											Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	Net Income (Loss) and Assumed Share Conversions	$	(35,943)	12,629	$	(2.85)	$	(6,896)	11,935	$	(0.58)	Net Income (Loss) and Assumed Share Conversions	$	142,541	22,669	$	6.29	$	(35,943)	12,629	$	(2.85)

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

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	Nine Months Ended September 30, 2022					Nine Months Ended September 30, 2021
	Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)		Shares	Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	167,076	18,885	$	8.85	$	(27,514)	12,283	$	(2.24)
Dilutive Securities:
Performance Based Stock Unit Awards			141					—
RSU Awards			171					—
Stock Option Awards			40					—
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	167,076	19,237	$	8.69	$	(27,514)	12,283	$	(2.24)

~~Approximately 0.3 million~~There were no antidilutive stock options ~~to purchase shares were not included in the computation of Diluted EPS~~ for ~~both~~ the three months ended September 30, ~~2021 and 2020 because they were antidilutive due to the net loss,~~2022, while 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for ~~both the nine months ended September 30, 2021 and 2020 because they were antidilutive due to the net loss.~~

~~There were no antidilutive shares of RSUs that could be converted to common shares for~~ the three months ended September 30, 2021 ~~while approximately 0.2 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended September 30, 2020,~~ because they were ~~antidilutive due to the net loss, while less~~antidilutive. Less than 0.1 million and ~~0.2~~0.3 million ~~of RSUs that could be converted~~stock options to ~~common~~purchase shares were not included in the computation of Diluted EPS for the nine months ended September 30, 2022 and 2021, ~~and 2020~~respectively, because they were antidilutive.

Less than 0.1 million shares of RSUs were not included in the computation of Diluted EPS for the three months ended September 30, 2022 because they were antidilutive. There were 0.3 million shares of RSUs excluded from Diluted EPS for the three months ended September 30, 2021 because they were antidilutive due to the net loss. Less than 0.1 million shares of RSUs were not included in the computation of Diluted EPS for the nine months ended September 30, 2022 because they were antidilutive, while 0.3 million shares of RSUs were excluded from Diluted EPS for the nine months ended September 30, 2021 because they were antidilutive due to the net loss.

There were no antidilutive shares of PSUs ~~that could be converted to common shares~~ for both the three and nine months ended September 30, ~~2021, while approximately~~2022. There were 0.1 million and less than 0.1 million shares of PSUs ~~were not included~~excluded from Diluted EPS for both the three ~~months ended September 30, 2020 because they were antidilutive due to the net loss, while there were no shares of PSUs that could be converted to common shares for the~~and nine months ended September 30, 2021, ~~while 0.1 million shares of PSUs were not included for the nine months ended September 30, 2020~~respectively, because they were antidilutive due to the net loss.

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(6) Long-Term Debt

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

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


	September 30, 2022		December 31, 2021
Credit Facility Borrowings (1)	$	480,000	$	227,000
Second Lien Notes due 2026	150,000		150,000
	630,000		377,000
Unamortized discount on Second Lien Notes due 2026	(927)		(1,061)
Unamortized debt issuance cost on Second Lien Notes due 2026	(2,722)		(3,114)
Long-Term Debt, net	$	626,351	$	372,825

(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our consolidated balance sheet. As of September 30, ~~2021~~2022 and December 31, ~~2020,~~2021, we had ~~$2.8~~$9.1 million and ~~$1.4~~$3.6 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.

Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were ~~$198.0~~$480.0 million and ~~$230.0~~$227.0 million as of September 30, ~~2021~~2022 and December 31, ~~2020,~~2021, respectively. The Company is a party to a First Amended and Restated Senior Secured Revolving Credit Agreement with JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended (such agreement, the “Credit Agreement” and the borrowing facility provided thereby, the “Credit Facility”). In conjunction with an unscheduled redetermination of the borrowing base requested by SilverBow along with its ~~regularly scheduled semi-annual redetermination,~~administrative agent as part of the SandPoint and Sundance transactions in the second quarter of 2022, the Company entered into the ~~Seventh~~Tenth Amendment to the Credit Facility, effective ~~April 16, 2021~~June 22, 2022 (the ~~“Seventh~~“Tenth Amendment”), which among other things, ~~(i) redetermined~~increased the borrowing base under the Credit Facility to ~~$300~~$775.0 million ~~(from $310 million), (ii)~~from $525.0 million, effective upon the closing of the Sundance transaction on June 30, 2022; extended the maturity date for the Credit Agreement to October 19, 2026 (or to the extent earlier, the date that is 91 days prior to the scheduled maturity of ~~our Credit Facility~~the Company's Second Lien notes); increased the maximum credit amounts from ~~April 19, 2022~~$1 billion to ~~April 19, 2024; (iii) increased~~$2 billion; decreased the applicable margin used to calculate the interest rate under the Credit Facility by 50 basis points, with the specific applicable margins determined by reference to borrowing base utilization; (iv) reduced the permitted ratio of Total Debt to EBITDA (each as defined in the Credit Agreement) from 3.50 to 1.00 (a) to 3.25 to 1.00 for the fiscal quarters ending on or before December 31, 2021 and (b) to 3.00 to 1.00 commencing with the fiscal quarter ending March 31, 2022; (v) implemented a minimum rolling hedge requirement of 50% of reasonably anticipated projected production from proved developed producing reserves for a 24-month period, and (vi) increaseddecreased the mortgage coverage and title requirements from ~~85%~~90% to ~~90%.~~85%; amended the restricted payment basket allowing the Company to make dividends or other distribution or return of capital to the extent that the Company's total leverage does not exceed 1.25x and the utilization percentage as of the date of such dividend or distribution is less than 80% after giving effect to such restricted payment; and added two new lenders as parties to the Credit Agreement. Earlier in the second quarter, the Company entered into the Ninth Amendment to the Credit Facility, effective April 12, 2022, as part of the regular, semi-annual redetermination.Prior to the Tenth Amendment, the Ninth Amendment had previously, among other things, increased the borrowing base under the Credit Agreement from $460 million to $525 million.

~~The~~Effective upon the execution of the Tenth Amendment on June 22, 2022, the Credit Facility matures October 19, 2026 (or to the extent earlier, the date that is 91 days prior to the scheduled maturity of the Company's Second Lien notes), and provides for a maximum credit amount of ~~$600.0 million,~~$2.0 billion, subject to the current borrowing base of ~~$300.0 million as of September 30, 2021.~~$775.0 million. The borrowing base is regularly redetermined onin or about May and November of each calendar year and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders, in their discretion, in accordance with their oil and gas lending criteria at the time of the relevant redetermination. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to ~~$25~~$25.0 million, which reduces the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit. There were no outstanding letters of credit as of September 30, 2022, and no outstanding letters of credit as of December 31, 2021. Maintaining or increasing our borrowing base under our Credit Facility is dependent on many factors, including commodity prices, our hedge positions, changes in our lenders' lending criteria and our ability to raise capital to drill wells to replace produced reserves.

Interest under the Credit Facility accrues at the Company’s option either at an Alternate Base Rate plus the applicable margin (“ABR Loans”) or, the ~~LIBOR~~Adjusted Term Secured Overnight Financing Rate (“SOFR”) plus the applicable margin (“~~Eurodollar~~Term Benchmark Loans”) or Adjusted Daily Simple SOFR plus the applicable margin (“RFR Loans”). Effective ~~April 16, 2021,~~upon the execution of the Tenth Amendment on June 22, 2022, the applicable margin decreased by 50 basis points and ranged from ~~2.25%~~1.75% to ~~3.25%~~2.75% based on borrowing base utilization for ABR Loans and ~~3.25%~~2.75% to ~~4.25%~~3.75% based on borrowing base utilization for ~~Eurodollar~~Term Benchmark Loans and RFR Loans. The Alternate Base Rate and ~~LIBOR Rate~~SOFR are defined, and the applicable margins are set forth, in

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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,~~As of September 30, 2022, 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~~Company's weighted average interest rate on Credit Facility is subject to LIBOR rates but has a term that extends beyond the end of 2021 when LIBOR will be phased out. The Credit Agreement currently provides for options in the event LIBOR is discontinued. It is expected that the Credit Agreement will be amended at its upcoming fall redetermination to reference an alternative rate as established by JP Morgan, as Administrative Agent, and the Company.borrowings was 6.08%.

The obligations under the Credit Agreement are secured, subject to certain exceptions, by a first priority lien on substantially all assets of the Company and its subsidiary, including a first priority lien on properties attributed with at least ~~90%~~85% of estimated proved reserves of the Company and its ~~subsidiary.~~

~~Table~~subsidiary effective upon the execution of ~~Contents~~

the Tenth Amendment on June 22, 2022.

The Credit Agreement contains the following financial covenants:

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

•a current ratio, as defined in the Credit Agreement, which includes in the numerator available borrowings undrawn under the borrowing base, of not less than 1.00 to 1.00 as of the last day of each fiscal quarter.

As of September 30, ~~2021,~~2022, the Company was in compliance with all financial covenants under the Credit Agreement.

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

Total interest expense on the Credit Facility, which includes commitment fees and amortization of debt issuance costs, was ~~$2.8~~$8.3 million and ~~$2.9~~$2.8 million for the three months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively, and ~~$8.1~~$15.9 million and ~~$9.8~~$8.1 million for the nine months ended September 30, 2022 and 2021, respectively. The amount of commitment fee amortization included in interest expense, net was $0.3 million and ~~2020, respectively.~~

~~There was no capitalized interest on our unproved properties~~$0.1 million for ~~both~~ the three months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively, and $0.9 million and $0.3 million, for ~~both~~ the nine months ended September 30, ~~2021~~2022 and ~~2020,~~2021, 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.

Effective November 12, 2021, the Company entered into the Second Amendment to the Note Purchase Agreement, which extended the maturity date from December 15, 2024 to December 15, 2026 subject to paying down the principal amount of the Second Lien from $200.0 million to $150.0 million. The Company ~~has~~made the ~~ability, subject to~~$50.0 million redemption of the ~~satisfaction of certain conditions (including compliance~~Second Lien Notes on November 29, 2021. The Company accounted for this paydown as a debt modification and incurred approximately $0.1 million in third party fees in connection with the ~~Asset Coverage Ratio described below~~amendment. The unamortized debt issuance cost and discount on 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~~Notes will be amortized through the new maturity date of December 15, ~~2024.~~2026.

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

The Company has the right, to the extent permitted under the Credit Facility and subject to the terms and conditions of the Second Lien, to optionally prepay the notes, subject to a repayment fee of 1.0% of the principal amount of the Second Lien being prepaid through December 15, ~~2021;~~2022; 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

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debt, subject to, in certain circumstances, reinvestment periods. Management believes the probability of mandatory prepayment due to default is remote.

The obligations under the Second Lien are secured, subject to certain exceptions and other permitted liens (including the liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit Facility, and mortgage lien on substantially all assets of the Company and its subsidiary, including a mortgage lien on oil and gas properties attributed with at least ~~85%~~90% of estimated PV-9 (defined below), of proved reserves of the Company and its subsidiary and ~~85%~~90% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions by the administrative agent of the Credit Facility. PV-9 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 9%.

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

The Second Lien also contains a financial covenant measuring the ratio of total net debt-to-EBITDA, as defined in the Note Purchase Agreement, for the most recently completed four fiscal quarters, not to exceed ~~4.5~~3.25 to 1.0 as of the last day of each fiscal quarter. As of September 30, ~~2021,~~2022, the Company was in compliance with all financial covenants under the Second Lien.

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

As of September 30, ~~2021,~~2022, total net amounts recorded for the Second Lien were ~~$195.7~~$146.4 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $3.8 million and $4.6 million for ~~both~~ the three months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively, and ~~$13.8~~$10.7 million and ~~$14.1~~$13.8 million for the nine months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively.

Debt Issuance Costs. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings. During the nine months ended September 30, 2022 and 2021, the Company capitalized $7.2 million and $2.4 million, respectively, for debt issuance costs incurred in connection with ~~our semi-annual redetermination,~~ the ~~Company capitalized $2.4 million for expenses incurred under the Seventh Amendment~~amendments to our Credit Facility. Additionally, the Company wrote-off $0.4 million and $0.2 million in debt issuance costs during the nine months ended September 30, 2022 and 2021, respectively, related to ~~lenders which fully exited the~~changes under our Credit Facility.

(7) Acquisitions and Dispositions

Bay De Chene Disposition

Effective December 22, 2017, the Company closed a purchase and sale contract to sell the Company's wellbores and facilities in the Bay De Chene field and recorded a $16.3 million obligation related to the funding of certain plugging and abandonment costs. Of the $16.3 million original obligation, ~~$1.1~~$0.8 million and ~~$0.4~~$1.1 million was paid during the nine months ended September 30, 2022 and 2021, ~~and 2020,~~ respectively. ~~The~~There is no remaining obligation under this contract ~~is $0.5 million and is carried in the accompanying condensed consolidated balance sheet current liability in “Accounts payable and accrued liabilities”~~ as of September 30, ~~2021.~~2022.

August 2021 Acquisition

On August 3, 2021, the Company acquired the remaining working interest in 12 wells that SilverBow operates and additional ~~Eagle Ford La Mesa assets and 850 net acres~~acreage in ~~our~~ Webb ~~County Dry Gas play.~~County. The total aggregate consideration was approximately ~~$24~~$23.0 million, consisting of ~~$13.2~~$13.0 million in cash and 516,675 shares of common stock valued at approximately $10.0 million based on the Company's share price on the closing date. ~~The Company~~Management determined that substantially all the fair value of the gross assets acquired were

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concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. As a result, we allocated substantially all of the purchase price to proved oil and gas properties.

October 2021 Acquisition

On October 1, 2021, we closed on an all-stock transaction to acquire oil and gas assets in the Eagle Ford with a seller and its two affiliated entities. The acquired assets include working interests in oil and gas properties across Atascosa, Fayette, Lavaca, McMullen and Live Oak counties. After consideration of closing adjustments, we issued 1,341,990 shares of our common stock valued at approximately $35.6 million, based on the Company's share price on the closing date. The acquisition was subject to further customary post-closing adjustments. We incurred approximately $0.6 million in transaction costs for the year ended December 31, 2021. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. As a result, we allocated substantially all of the purchase price to proved oil and gas properties. ~~The issuance~~As part of the post-closing settlement of this acquisition, during the nine months ended September 30, 2022 we issued 489 new shares and received 41,375 shares back into treasury stock.

November 2021 Acquisition

On November 19, 2021, the Company closed on an acquisition of oil-weighted assets in the Eagle Ford. The acquired assets included wells and acreage in La Salle, McMullen, DeWitt and Lavaca counties. After consideration of closing adjustments, total aggregate consideration was approximately $77.4 million, consisting of $37.6 million in cash, 1,351,961 shares of our common stock valued at approximately $37.9 million based on the Company's share price on the closing date, and contingent consideration with an estimated fair value of $1.9 million. The contingent consideration consists of up to three earn-out payments of $1.6 million per year for each of 2022, 2023 and 2024, contingent upon the average monthly settlement price of WTI exceeding $70 per barrel for such year (the “2021 WTI Contingency Payout”). During the three and nine months ended September 30, 2022, the Company recorded gains of $0.7 million and losses of $0.8 million, respectively, related to the 2021 WTI Contingency Payout recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. For further discussion of the fair value related to the Company's contingent consideration, refer to Note 9 of these Notes to Consolidated Financial Statements. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. As a result, we allocated substantially all of the purchase price to proved oil and gas properties.

May 2022 Acquisition

On May 10, 2022, the Company closed the acquisition of certain oil and gas assets located in La Salle and McMullen Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date, from SandPoint Operating, LLC, a subsidiary of SandPoint Resources, LLC. After consideration of closing adjustments, total aggregate consideration was ~~completed~~approximately $67.5 million, consisting of $27.7 million in ~~reliance~~cash and 1,300,000 shares of our common stock valued at approximately $39.8 million based on the Company's share price on the closing date. We incurred approximately $0.5 million in transaction costs during the nine months ended September 30, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

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The following table represents the allocation of the total cost of the acquisition to the assets acquired and liabilities assumed (in thousands):


Total Cost
Cash consideration	$	27,709
Equity consideration	39,767
Total Consideration	67,476

Transaction costs	466

Total Cost of Transaction	$	67,942

Allocation of Total Cost
Assets
Oil and gas properties	$	84,611
Total assets	84,611

Liabilities
Fair value of commodity derivatives	16,511
Asset retirement obligations	158
Total Liabilities	$	16,669

Net Assets Acquired	$	67,942

June 2022 Acquisition

On June 30, 2022, the Company closed the acquisition of certain oil and gas assets located in Atascosa, La Salle, Live Oak and McMullen Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date, from Sundance Energy, Inc., and its affiliated entities Armadillo E&P, Inc. and SEA Eagle Ford, LLC. After consideration of closing adjustments, total aggregate consideration was approximately $346.1 million, consisting of $220.9 million in cash, 4,148,472 shares of our common stock valued at approximately $117.7 million based on the Company's share price on the closing date, accrued purchase price adjustments receivable of $1.0 million which is expected to be collected by the end of 2022 and contingent consideration with an estimated fair value of $8.6 million. The contingent consideration consists of up to two earn-out payments of $7.5 million each, contingent upon the ~~exemption~~average monthly settlement price of NYMEX West Texas Intermediate crude oil exceeding $95 per barrel for the period from April 13, 2022 through December 31, 2022 which would trigger a payment of $7.5 million in 2023 and $85 per barrel for 2023 which would trigger a payment of $7.5 million in 2024 (the “2022 WTI Contingency Payout”). During both the three and nine months ended September 30, 2022, the Company recorded gains of $5.4 million related to the 2022 WTI Contingency Payout recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. For further discussion of the fair value related to the Company's contingent consideration, refer to Note 9 of these Notes to Consolidated Financial Statements. The acquisition is subject to further customary post-closing adjustments. We incurred approximately $6.5 million in transaction costs during the nine months ended September 30, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

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The following table represents the allocation of the total cost of the acquisition to the assets acquired and liabilities assumed (in thousands):


Total Cost
Cash consideration	$	220,866
Equity consideration	117,651
Fair value of contingent consideration	8,566
Accrued purchase price adjustments receivable	(1,000)
Total Consideration	346,083

Transaction costs	6,545

Total Cost of Transaction	$	352,628

Allocation of Total Cost
Assets
Other current assets	$	4,202
Oil and gas properties	397,448
Right of use assets	890
Total assets	402,540

Liabilities
Accounts payable and accrued liabilities	12,811
Fair value of commodity derivatives	33,767
Non-current lease liability	890
Asset retirement obligations	2,444
Total Liabilities	$	49,912

Net Assets Acquired	$	352,628

August 2022 Acquisition

On August 15, 2022, the Company closed the acquisition of certain oil and gas assets in Webb County, Texas. After consideration of closing adjustments, total consideration was approximately $31.8 million. The acquisition is subject to further customary post-closing adjustments. We did not incur any significant transaction costs during the nine months ended September 30, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

2022 Non-strategic Dispositions

During 2022, the Company closed on multiple dispositions of non-strategic oil and gas assets. After consideration of closing adjustments, total proceeds from the ~~registration requirements of~~dispositions were approximately $4.4 million. The transactions are subject to further customary post-closing adjustments. There was no gain or loss recognized in connection with the ~~Securities Act.~~dispositions.

(8) Price-Risk Management Activities

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

During the three months ended September 30, ~~2021~~2022 and ~~2020,~~2021, the Company recorded losses of ~~$88.6~~$1.3 million and ~~losses of $12.9~~$88.6 million, respectively, on its commodity derivatives. During the nine months ended September 30, 2022 and 2021, ~~and~~the Company

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~~2020,~~recorded losses of $162.5 million and $152.9 million, respectively, on its commodity derivatives. During the three and nine months ended September 30, 2022, the Company recorded ~~losses~~gains of ~~$152.9~~$6.1 million and ~~gains of $66.9~~$4.7 million, ~~respectively.~~respectively, related to valuation changes on the 2021 WTI Contingency Payout and 2022 WTI Contingency Payout. The Company made cash payments of ~~$29.0~~$182.1 million and ~~collected cash payments of $76.1~~$29.0 million for settled derivative contracts during the nine months ended September 30, 2022 and 2021, ~~and 2020,~~ respectively. ~~Included in our collected cash payments during the nine months ended September 30, 2020 was $38.3 million for monetized derivative contracts.~~

At September 30, ~~2021~~2022 and December 31, ~~2020,~~2021, there ~~were less than $0.1~~was $4.4 million and ~~$0.8~~$0.9 million, respectively, in receivables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts receivable, net” and were subsequently collected in October ~~2021~~2022 and January ~~2021,~~2022, respectively. At September 30, ~~2021~~2022 and December 31, ~~2020,~~2021, we also had ~~$13.6~~$19.5 million and ~~$0.8~~$6.4 million, respectively, in payables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts payable and accrued liabilities” and were subsequently paid in October ~~2021~~2022 and January ~~2021,~~2022, 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.~~model. At September 30, ~~2021,~~2022, there was ~~$0.7~~$33.2 million and ~~less than $0.1~~$27.4 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and ~~$94.8~~$108.6 million and ~~$22.0~~$30.0 million in current and long-term unsettled derivative liabilities, respectively. At December 31, ~~2020,~~2021, there was ~~$4.8~~$2.8 million and ~~$0.3~~$0.2 million in current and long-term unsettled derivative assets, respectively, and ~~$8.2~~$47.5 million and ~~$2.9~~$8.6 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 condensed consolidated balance sheet. Under the right of set-off, there was a ~~$116.1~~$78.0 million net fair value liability at September 30, ~~2021,~~2022, and a ~~$6.0~~$53.0 million net fair value liability at December 31, ~~2020.~~2021. For further discussion related to the fair value of the Company's derivatives, refer to Note 9 of these Notes to Condensed Consolidated Financial Statements.

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The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of September 30, ~~2021:~~2022:

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


Oil Derivative Contracts (NYMEX WTI Settlements)	Total Volumes (Bbls)	Weighted-Average Price		Weighted-Average Collar Sub Floor Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
Swap Contracts
2022 Contracts
4Q22	559,876	$	74.00
2023 Contracts
1Q23	532,175	$	81.52
2Q23	494,575	$	80.75
3Q23	533,980	$	77.36
4Q23	569,300	$	78.26
2024 Contracts
1Q24	227,500	$	80.78
2Q24	249,500	$	80.47
3Q24	229,000	$	78.90
4Q24	217,000	$	77.76
Collar Contracts
2022 Contracts
4Q22	201,304					$	70.58	$	85.50
2023 Contracts
1Q23	171,707					$	47.37	$	66.00
2Q23	167,949					$	53.91	$	64.89
3Q23	72,847					$	59.27	$	66.26
4Q23	72,242					$	58.54	$	65.13
2024 Contracts
1Q24	137,700					$	51.61	$	65.86
2Q24	33,000					$	45.00	$	60.72
3-Way Collar Contracts
2022 Contracts
4Q22	13,280			$	42.21	$	52.94	$	62.14
2023 Contracts
1Q23	14,470			$	44.24	$	55.14	$	64.55
2Q23	13,260			$	44.19	$	55.04	$	64.53
3Q23	9,570			$	43.08	$	53.41	$	63.33
4Q23	8,970			$	43.08	$	53.38	$	63.35
2024 Contracts
1Q24	8,247			$	45.00	$	57.50	$	67.85
2Q24	7,757			$	45.00	$	57.50	$	67.85

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

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

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


Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Price		Weighted-Average Collar Sub Floor Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
Swap Contracts
2022 Contracts
4Q22	4,267,284	$	2.64
2023 Contracts
1Q23	981,000	$	6.74
2Q23	3,816,000	$	4.55
3Q23	4,816,000	$	4.57
4Q23	3,887,000	$	4.71
2024 Contracts
1Q24	891,000	$	4.50
2Q24	5,525,000	$	3.89
3Q24	5,060,000	$	3.94
4Q24	5,060,000	$	4.21
Collar Contracts
2022 Contracts
4Q22	10,972,376					$	3.42	$	4.16
2023 Contracts
1Q23	13,067,900					$	3.79	$	5.36
2Q23	11,231,250					$	3.22	$	3.96
3Q23	10,976,400					$	3.39	$	4.12
4Q23	11,525,000					$	3.82	$	4.70
2024 Contracts
1Q24	6,931,000					$	4.02	$	6.19
2Q24	1,913,000					$	4.20	$	5.13
3Q24	2,038,000					$	4.12	$	5.28
4Q24	2,025,000					$	4.35	$	5.73
3-Way Collar Contracts
2023 Contracts
1Q23	347,800			$	2.06	$	2.56	$	3.03
2Q23	310,400			$	2.04	$	2.54	$	3.01
3Q23	233,100			$	2.00	$	2.50	$	2.95
4Q23	219,200			$	2.00	$	2.50	$	2.94
2024 Contracts
1Q24	198,000			$	2.00	$	2.50	$	3.37
2Q24	188,000			$	2.00	$	2.50	$	3.37

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


Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes (MMBtu)	Weighted-Average Price
2022 Contracts
4Q22	6,140,000	$	(0.07)
2023 Contracts
1Q23	8,100,000	$	0.07
2Q23	8,190,000	$	(0.22)
3Q23	8,280,000	$	(0.19)
4Q23	8,280,000	$	(0.18)
2024 Contracts
1Q24	5,460,000	$	0.12
2Q24	5,460,000	$	(0.27)
3Q24	5,520,000	$	(0.23)
4Q24	5,520,000	$	(0.19)
Houston Ship Channel Fixed Price Contracts
2022 Contracts
4Q22	132,000	$	1.80
2023 Contracts
1Q23	180,000	$	2.64
2Q23	60,000	$	2.64

Oil Basis Swaps
(Argus Cushing (WTI) and Magellan East Houston)

Total Volumes (Bbls)

Weighted-Average Price

Calendar Monthly Roll Differential Swaps

2022 Contracts

4Q22

266,800

0.12


NGL Swaps (Mont Belvieu)	Total Volumes (Bbls)	Weighted-Average Price
2022 Contracts
4Q22	345,000	$	35.00
2023 Contracts
1Q23	292,500	$	34.04
2Q23	295,750	$	34.04
3Q23	299,000	$	33.75
4Q23	299,000	$	33.75
2024 Contracts
1Q24	127,400	$	29.39
2Q24	127,400	$	29.39
3Q24	128,800	$	29.39
4Q24	128,800	$	29.39

(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.~~Lien Notes. 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~~model. The fair value of the current and ~~are periodically verified against quotes from brokers.~~long-term 2021 WTI Contingency

Payout and 2022 WTI Contingency Payout, included within “Accounts payable and accrued liabilities” and “Other long-term liabilities” on the condensed consolidated balance sheets, respectively, is estimated using observable market data and a Monte Carlo pricing model. 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).

Fair Value on a Nonrecurring Basis. The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties acquired and assessed for classification as a business or an asset and asset retirement obligations. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value estimation when acquisitions occur or asset retirement obligations are recorded. These are considered Level 3 valuations (defined below).

Asset retirement obligations. The initial measurement of asset retirement obligations (“ARO”) at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments.

2022 and 2021 Acquisitions. The Company recognized the assets acquired in our 2022 and 2021 acquisitions at cost at a relative fair value basis (refer to Note 7 of these Notes to Consolidated Financial Statements). Fair value was determined using a discounted cash flow model. The underlying future commodity prices included in the Company’s estimated future cash flows of its proved oil and gas properties were determined using NYMEX forward strip prices as of the closing date of each acquisition. The estimated future cash flows also included management’s assumptions for the estimates of production from the crude oil and natural gas proved properties, future operating, development costs and income taxes of the acquired properties and risk adjusted discount rates.

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

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

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

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

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The following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of September 30, ~~2021~~2022 and December 31, ~~2020,~~2021, 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)		Total		Quoted Prices in Active markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
September 30, 2021
(in thousands)										(in thousands)	Total		Quoted Prices in Active markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
September 30, 2022										September 30, 2022
Assets	Assets									Assets
Natural Gas Derivatives										Natural Gas Derivatives	$	4,280	$	—	$	4,280	$	—
Natural Gas Basis Derivatives										Natural Gas Basis Derivatives	8,308		—		8,308		—
Oil Derivatives										Oil Derivatives	36,418		—		36,418		—

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

Oil Basis Derivatives		0.1		—		0.1		—

NGL Derivatives										NGL Derivatives	11,609		—		11,609		—
Liabilities	Liabilities									Liabilities
Natural Gas Derivatives	Natural Gas Derivatives	80.3		—		80.3		—		Natural Gas Derivatives	115,871		—		115,871		—
Natural Gas Basis Derivatives	Natural Gas Basis Derivatives	2.6		—		2.6		—		Natural Gas Basis Derivatives	1,675		—		1,675		—
Oil Derivatives	Oil Derivatives	26.3		—		26.3		—		Oil Derivatives	20,199		—		20,199		—
Oil Basis Derivatives	Oil Basis Derivatives	0.8		—		0.8		—		Oil Basis Derivatives	167		—		167		—
NGL Derivatives	NGL Derivatives	6.7		—		6.7		—		NGL Derivatives	656		—		656		—
December 31, 2020
2022 WTI Contingency Payout										2022 WTI Contingency Payout	3,121		—		3,121		—
2021 WTI Contingency Payout										2021 WTI Contingency Payout	2,591		—		2,591		—

December 31, 2021										December 31, 2021
Assets	Assets									Assets
Natural Gas Derivatives	Natural Gas Derivatives	1.5		—		1.5		—		Natural Gas Derivatives	$	1,159	$	—	$	1,159	$	—
Natural Gas Basis Derivatives	Natural Gas Basis Derivatives	1.1		—		1.1		—		Natural Gas Basis Derivatives	1,025		—		1,025		—
Oil Derivatives	Oil Derivatives	2.5		—		2.5		—		Oil Derivatives	371		—		371		—

Oil Basis Derivatives										Oil Basis Derivatives	3		—		3		—
NGL Derivatives										NGL Derivatives	449		—		449		—
Liabilities	Liabilities									Liabilities
Natural Gas Derivatives	Natural Gas Derivatives	4.0		—		4.0		—		Natural Gas Derivatives	31,801		—		31,801		—
Natural Gas Basis Derivatives	Natural Gas Basis Derivatives	0.4		—		0.4		—		Natural Gas Basis Derivatives	452		—		452		—
Oil Derivatives	Oil Derivatives	5.9		—		5.9		—		Oil Derivatives	21,330		—		21,330		—
Oil Basis Derivatives	Oil Basis Derivatives	0.8		—		0.8		—		Oil Basis Derivatives	514		—		514		—
NGL Derivatives										NGL Derivatives	1,941		—		1,941		—
2021 WTI Contingency Payout										2021 WTI Contingency Payout	1,841		—		1,841		—

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

(10) Asset Retirement Obligations

Liabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. Estimates for the initial recognition of asset retirement obligations are derived from historical costs as well as management's expectation of future cost environments and other unobservable inputs. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3 fair value measurements. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion,

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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.

~~Table of Contents~~

The following provides a roll-forward of our asset retirement obligations for the year ended December 31, ~~2020~~2021 and the nine months ended September 30, ~~2021~~2022 (in thousands):


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

~~Reductions due to plugged wells and facilities~~	~~(103)~~
~~Revisions in estimates~~	~~(5)~~
Asset Retirement Obligations as of December 31, 2020	$	4,974
Accretion expense	~~226~~306
Liabilities incurred for new wells, acquired wells and facilities construction	~~347~~1,120

Reductions due to plugged wells and facilities	(192)
Revisions in estimates	~~(157)~~(158)
Asset Retirement Obligations as of December 31, 2021	$	6,050
Accretion expense	366
Liabilities incurred for new wells, acquired wells and facilities construction	2,754
Reductions due to sold wells and facilities	(43)
Reductions due to plugged wells and facilities	(22)
Revisions in estimates	(321)
Asset Retirement Obligations as of September 30, ~~2021~~2022	$	~~5,198~~8,784

At both September 30, ~~2021~~2022 and December 31, ~~2020,~~2021, approximately $0.5 million ~~and $0.4 million, respectively,~~ of our asset retirement obligations were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets.

(11) Commitments and Contingencies

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

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

You should read the following discussion and analysis in conjunction with the Company's financial information and its condensed consolidated financial statements and accompanying notes included in this report and its audited consolidated financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, ~~2020.~~2021. The following information contains forward-looking statements; see “Forward-Looking Statements” ~~on page 36 of~~in this report.

Company Overview

SilverBow is an independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford and Austin Chalk located in South Texas where it has assembled approximately ~~143,000~~180,000 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.

Acquisitions Update

On September 15, 2022, SilverBow announced the addition of a new acreage block in the Dorado play in Webb County. Through a series of transactions, including bolt-on acquisitions, leasing and drill-to-earn agreements, the Company has assembled 7,500 net acres with current net production of approximately 30 million cubic feet per day (“MMcf/d”). Approximately $37.6 million of the total $45 million land and leasing spend in the aforementioned area occurred during the third quarter of 2022. The new block adds stacked pay, co-development inventory with over 50 net high rate of return drilling locations across the Austin Chalk and Eagle Ford formations.

On October 3, 2022, SilverBow announced the acquisition of oil and gas assets in the proven highly economic oil and condensate windows of DeWitt and Gonzales counties for a cash purchase price of $87 million, subject to customary closing adjustments. The Company added 5,200 net acres and net production from the acquired assets based on June 2022 production data of approximately 1,100 barrels of oil equivalent per day (“Boe/d”). The transaction was comprised of incremental working interest on SilverBow’s existing acreage as well as new adjacent acreage. This provides for extended laterals, additional inventory locations and more efficient development. The Company closed on the asset transaction on October 31, 2022.

Operational Results

Total production for the nine months ended September 30, ~~2021~~2022 increased 9%26% from the nine months ended September 30, ~~2020~~2021 to ~~203~~254 million cubic feet of natural gas equivalent per ~~day as SilverBow pursued a moderated growth strategy and did not have any curtailed production impacting results.~~day.

During the third quarter of ~~2021,~~2022, SilverBow drilled ~~six~~13 net wells and completed ~~11 wells~~ and brought online 11 ~~wells online. As expected,~~net wells. In its Webb County Gas area, the Company ~~concluded its mid-year liquids development program with the majority of completion activity focused in its La Salle Condensate~~completed and ~~McMullen Oil areas. As a result of strong well performance, oil production increased nearly 50% quarter-over-quarter. In the La Salle Condensate area, SilverBow~~ brought online a ~~Briggs Knolle~~ two-well pad which produced a 30-day average of ~~2,524 barrels of oil equivalent per day (“Boe/d”) (72% liquids),~~30 MMcf/d (100% gas). Of the two wells, one targeted the Austin Chalk formation and represents SilverBow's best performing Austin Chalk well to date. In its Central Oil area, the Company completed and brought online a ~~Briggs Knolle four-well~~two-well pad which ~~produced~~had been drilled by the previous operator prior to SilverBow taking ownership on June 30, 2022. Performance from the wells has exceeded expectations with a 30-day average of ~~4,202~~2,400 Boe/d ~~(78%~~(94% liquids)., however the drilling rig experienced operational delays prior to SilverBow taking ownership and, ultimately, a third well that was drilled on the pad had to be abandoned due to a mechanical failure. The Company also brought online a three-well pad in its Central Oil area early in the fourth quarter with initial results exceeding expectations.

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

2022 was at the midpoint of guidance. Gas volumes came in at the high-end of guidance, with NGL volumes exceeding guidance. Oil volumes were lower than anticipated due to the mechanical failure on the aforementioned two-well pad and resultant timing delays of the remaining wells drilled during the third quarter. However, as mentioned above, the performance to date from the wells in the Central Oil area remains strong and is exceeding expectations. The rig subsequently returned to expected efficiency levels by the end of July. The Company continues to drill and appraise the Austin Chalk and is reviewing early and encouraging results from its second Austin Chalk well in Webb County. The Fasken 201H, which came online in August, produced over 12 MMcf/d on average over thedoes not expect any other impact outside of first ~~60 days, and thus far is producing in-line with SilverBow's first Austin Chalk well at Rio Bravo. Both wells are exceeding offset type curves~~sales occurring later in the ~~area and are exhibiting some of the highest commercial economics~~year than what was originally planned. Factoring in the ~~Company's portfolio. SilverBow is also assessing~~changes to the ~~initial results of a third Webb County Austin Chalk well which started producing in October.~~

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

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

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

~~2021 Cost Reduction Initiatives:~~ SilverBow continues to focus on cost reduction measures in the areas that it can control. These initiatives include the use of regional sand in completions and improved utilization of existing facilities. As previously mentioned, the Company continues to improve its process for drilling, completing and equipping wells. SilverBow's procurement team takes a process-oriented approach to reducing the total delivered costs of purchased services by examining costs at their most granular level. Services are routinely sourced directly from the suppliers. The Company's LOE and workover expenses were $19.3 million or $0.35 per thousand cubic feet of gas equivalent (“Mcfe”)315-329 MMcfe/d (70% gas) for the ~~first nine months~~fourth quarter of ~~2021, as compared to $16.0 million or $0.32 per Mcfe~~2022 and 270-274 MMcfe/d (73% gas) for the same period in 2020. The increase in costs was due to incremental expenses related to Winter Storm Uri, higher salt water disposal, utilities and higher compression costs. These increases were partially mitigated by lower treating and labor costs.

SilverBow's net general and administrative (“net G&A”) costs were $14.9 million, or $0.27 per Mcfe, and cash G&A costs were $11.4 million (a non-GAAP financial measure calculated as net G&A costs less $3.5 million of share-based compensation), or $0.21 per Mcfe, for the first nine months of 2021, compared to net G&A costs of $17.9 million, or $0.36 per Mcfe, and cash G&A costs of $14.4 million (a non-GAAP financial measure calculated as net G&A costs less $3.5 million of share-based compensation), or $0.29 per Mcfe, for the nine months ended September 30, 2020.full year 2022, respectively.

SilverBow ~~reports cash G&A because management uses it as an indicator~~operated two drilling rigs for the entirety of ~~cost management~~the third quarter, and ~~operating efficiency~~the Company intends to continue at this pace for the remainder of 2022. At the beginning of October, SilverBow moved both its drilling rigs to its Webb County Gas area. This decision was based on ~~a comparable basis~~the continued strong Austin Chalk results in the Dorado play. Combining the third and fourth quarters, the Company will have drilled 16 wells at its Fasken property, with 15 of them targeting the Austin Chalk and 1 targeting the Upper Eagle Ford. The returns SilverBow is generating in the Austin Chalk warranted this shift and much of this development should benefit from ~~period to period and SilverBow believes this provides useful information to analysts and investors.~~strong winter gas prices. In addition, the ~~Company~~Company's non-op partner elected not to participate in 12 of the 16 wells which will add an incremental 4.5 net wells to SilverBow's 2022 development as it increases its working interest in those wells from 64% to 100%. Management believes ~~cash G&A expenses are used by analysts~~this near-term drilling opportunity will result in significant accretion to reserve PV-10 value and ~~others in valuation, comparison~~increased gas production beyond 2022, which more than offsets the lower near-term oil production from the recent scheduling changes. As a returns-focused company, SilverBow has continued to benefit from its ability to be nimble and ~~investment recommendations~~deploy capital where the economics make the largest impact.

SilverBow revised its 2022 capital budget to a range of ~~companies~~$320-$340 million. The 5% increase to the capital budget reflects the higher working interest captured across the aforementioned Webb County Gas wells drilled in the ~~oil~~fourth quarter and ~~gas industry to allow for analysis~~land and leasing spend of ~~G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A expenses should~~approximately $7.5 million. Inflationary pressures remain persistent in the current service market but had previously been factored into SilverBow's 2022 capital budget outlook and were not ~~be considered as an alternative to, or more meaningful than, total net G&A expenses.~~a primary driver of the updated range. With two fully utilized rigs, the Company has greater line of sight into upcoming activity levels and is addressing cost inflation through enhanced procurement initiatives, pre-ordering key materials and employing a range of short and long-term contracts. As always, SilverBow optimizes its drilling schedule based on commodity prices, returns on investment and strategically proving up additional inventory within the portfolio.

Liquidity and Capital Resources

SilverBow's primary use of cash has been to fund capital expenditures to develop its oil and gas properties, fund acquisitions and to repay Credit Facility borrowings. The Company uses cash generated from operating activities and borrowings under its Credit Facility as its primary source of liquidity. As of September 30, ~~2021, the Company’s~~2022, SilverBow’s liquidity consisted of ~~$1.0~~$1.9 million of cash-on-hand and ~~$102.0~~$295.0 million in available borrowings on its Credit Facility, which had a ~~$300~~$775.0 million borrowing base. Management believes the Company has sufficient liquidity to meet its obligations through the fourth quarter of ~~2022~~2023 and execute its long-term development plans. For more ~~details,~~information on its Credit Facility, see the Credit Facility section within Note 6 to SilverBow's condensed consolidated financial ~~statements for more information on its Credit Facility.~~

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

Contractual Commitments and Obligations

As of September 30, 2021 and December 31, 2020, the Company had approximately $16.0 million and $4.4 million, respectively, in net operating leases liabilities. The increase was primarily due to compression equipment leases and the Company's corporate office lease. ThereOther than as discussed below, there were no other material changes in SilverBow's contractual commitments during the nine months ended September 30, ~~2021~~2022 from amounts referenced under “Contractual Commitments and Obligations” in Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, ~~2020.~~2021.

Borrowings under our Credit Facility increased $253.0 million from December 31, 2021 primarily related to our acquisitions during the nine months ended September 30, 2022.

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Summary of ~~2021~~2022 Financial Results Through September 30, ~~2021~~2022

•Revenues and Net Income (Loss): The Company's oil and gas revenues were $554.4 million for the nine months ended September 30, 2022, compared to $255.9 million for the nine months ended September 30, ~~2021, compared~~2021. Revenues were higher due to ~~$123.9~~increased production volumes driven by acquisitions and overall higher commodity pricing. The Company's net income was $167.1 million for the nine months ended September 30, ~~2020. Revenues were higher due~~2022, compared to ~~increased production volumes and overall higher commodity pricing. The Company's~~a net loss ~~was~~of $27.5 million for the nine months ended September 30, ~~2021, compared to a net loss of $318.7 million for the nine months ended September 30, 2020.~~2021. The ~~decrease~~increase in net ~~loss~~income was primarily ~~due to~~driven by higher revenues due to increased production volumes and higher commodity ~~pricing along with no non-cash impairment write-down during the current period.~~pricing.

•Capital Expenditures: The Company's capital expenditures on an accrual basis were $224.8 million for the nine months ended September 30, 2022 compared to $109.9 million for the nine months ended September 30, ~~2021 compared to $75.7 million for the nine months ended September 30, 2020.~~2021. The expenditures for the nine months ended September 30, ~~2021~~2022 and ~~2020~~2021 were primarily attributable to drilling and completion activity.

•Working Capital: The Company had a working capital deficit of ~~$127.9~~$141.9 million at September 30, ~~2021~~2022 and a working capital deficit of ~~$23.1~~$65.8 million at December 31, ~~2020.~~2021. Included in our working capital deficit was a net liability of $75.4 million and $44.6 million at September 30, 2022 and December 31, 2021, respectively, related to the fair value of our current open derivative contracts. Additionally included in our working capital deficit was a liability of $2.9 million associated with the fair value of our 2021 WTI Contingency Payout and 2022 WTI Contingency Payout. The working capital computation does not include available liquidity through our Credit Facility.

•Cash Flows: For the nine months ended September 30, 2022, the Company generated cash from operating activities of $212.2 million which included negative impacts attributable to changes in working capital of $25.4 million. Cash used for property additions was $163.6 million while cash used in property acquisitions, including purchase price adjustments, was $293.9 million. This excluded $60.6 million attributable to a net increase of capital-related payables and accrued costs. The Company’s net borrowings on the Credit Facility were $253.0 million during the nine months ended September 30, 2022 which were primarily used to fund acquisitions during the nine months ended September 30, 2022.

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

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

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Results of Operations

Revenues — Three Months Ended September 30, ~~2021~~2022 and Three Months Ended September 30, ~~2020~~2021

Natural gas production was ~~77%~~70% and ~~71%~~77% of the Company's production volumes for the three months ended September 30, 2022 and 2021, ~~and 2020.~~respectively. Natural gas sales were ~~63%~~62% and ~~51%~~63% of oil and gas sales for the three months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively.

Crude oil production was ~~11%~~17% and ~~17%~~11% of the Company's production volumes for the three months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively. Crude oil sales were ~~25%~~30% and ~~39%~~25% of oil and gas sales for the three months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively.

NGL production was 13% and 12% of the Company's production volumes for ~~both~~ the three months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively. NGL sales were ~~12%~~8% and ~~10%~~12% of oil and gas sales for the three months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively.

The following table provides additional information regarding the Company's oil and gas sales, by area, excluding any effects of the Company's hedging activities, for the three months ended September 30, ~~2021~~2022 and ~~2020:~~2021:

Fields Three Months Ended September 30, 2021 Three Months Ended September 30, 2020
Oil and Gas Sales
(In Millions) Net Oil and Gas Production
Volumes (MMcfe) Oil and Gas Sales
(In Millions) Net Oil and Gas Production
Volumes (MMcfe)
Artesia Wells $ 30.9 4,807 $ 11.8 3,802
AWP 15.5 2,073 15.3 3,659
Fasken 37.2 9,012 13.0 6,500
Other (1)
15.6 3,638 5.6 2,848
Total $ 99.2 19,530 $ 45.7 16,809

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


Fields	Three Months Ended September 30, 2022			Three Months Ended September 30, 2021
	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)
Webb County Gas	$	106.1	13,514	$	44.9	10,858
Western Condensate	39.7		4,623	30.9		4,807
Southern Eagle Ford	29.3		3,913	9.8		2,336
Central Oil	59.6		4,727	12.1		1,333
Eastern Extension	7.3		682	—		—
Non Core	0.2		46	1.5		196
Total	$	242.2	27,505	$	99.2	19,530

The sales volumes increase from ~~2020~~2021 to ~~2021~~2022 was primarily due to ~~overall increased production as a result~~acquisitions in the second half of ~~increased drilling and completion activity during~~ 2021 and ~~return~~first half of ~~volumes that had been curtailed during 2020.~~2022, in addition to wells brought online as part of our full year 2021 capital program and the first half of 2022.

In the third quarter of ~~2021,~~2022, our ~~$53.5~~$142.9 million, or ~~117%~~144%, increase in oil, NGL and natural gas sales from the prior year period resulted from:

•Price variances that had an approximately ~~$50.8~~$90.6 million favorable impact on sales due to overall higher commodity pricing; and

•Volume variances that had an approximately ~~$2.8~~$52.3 million favorable impact on sales due to overall increased commodity production.

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The following table provides additional information regarding our oil and gas sales, by commodity type, as well as the effects of our hedging activities for derivative contracts held to settlement, for the three months ended September 30, ~~2021~~2022 and ~~2020~~2021 (in thousands, except per-dollar amounts):


		Three Months Ended September 30, 2021		Three Months Ended September 30, 2020			Three Months Ended September 30, 2022		Three Months Ended September 30, 2021
Production volumes:	Production volumes:					Production volumes:
Oil (MBbl) (1)	Oil (MBbl) (1)	368		472		Oil (MBbl) (1)	781		368
Natural gas (MMcf)	Natural gas (MMcf)	15,092		11,897		Natural gas (MMcf)	19,324		15,092
Natural gas liquids (MBbl) (1)	Natural gas liquids (MBbl) (1)	372		347		Natural gas liquids (MBbl) (1)	582		372
Total (MMcfe)	Total (MMcfe)	19,530		16,809		Total (MMcfe)	27,505		19,530

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	$	25,230	$	17,665	Oil	$	71,811	$	25,230
Natural gas	Natural gas	62,529		23,595		Natural gas	150,958		62,530
Natural gas liquids	Natural gas liquids	11,489		4,439		Natural gas liquids	19,412		11,489
Total	Total	$	99,249	$	45,699	Total	$	242,181	$	99,249

Average realized price:	Average realized price:					Average realized price:
Oil (per Bbl)	Oil (per Bbl)	$	68.54	$	37.45	Oil (per Bbl)	$	91.93	$	68.54
Natural gas (per Mcf)	Natural gas (per Mcf)	4.14		1.98		Natural gas (per Mcf)	7.81		4.14
Natural gas liquids (per Bbl)	Natural gas liquids (per Bbl)	30.92		12.79		Natural gas liquids (per Bbl)	33.34		30.92
Average per Mcfe	Average per Mcfe	$	5.08	$	2.72	Average per Mcfe	$	8.81	$	5.08

Price impact of cash-settled derivatives:	Price impact of cash-settled derivatives:					Price impact of cash-settled derivatives:
Oil (per Bbl)	Oil (per Bbl)	$	(17.18)	$	6.91	Oil (per Bbl)	$	(20.44)	$	(17.18)
Natural gas (per Mcf)	Natural gas (per Mcf)	(0.69)		0.39		Natural gas (per Mcf)	(3.47)		(0.69)
Natural gas liquids (per Bbl)	Natural gas liquids (per Bbl)	(7.07)		(0.01)		Natural gas liquids (per Bbl)	(1.86)		(7.07)
Average per Mcfe	Average per Mcfe	$	(0.99)	$	0.47	Average per Mcfe	$	(3.06)	$	(0.99)

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)	$	51.36	$	44.36	Oil (per Bbl)	$	71.49	$	51.36
Natural gas (per Mcf)	Natural gas (per Mcf)	3.46		2.37		Natural gas (per Mcf)	4.34		3.45
Natural gas liquids (per Bbl)	Natural gas liquids (per Bbl)	23.85		12.78		Natural gas liquids (per Bbl)	31.48		23.85
Average per Mcfe	Average per Mcfe	$	4.09	$	3.19	Average per Mcfe	$	5.75	$	4.09

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

For the three months ended September 30, ~~2021~~2022 and ~~2020,~~2021, the Company recorded net losses of ~~$88.6~~$1.3 million and ~~$12.9~~$88.6 million from our commodities derivatives activities, respectively. Additionally for the three months ended September 30, 2022, we recorded a net gain of $6.1 million related to valuation changes from our 2021 and 2022 WTI Contingency Payouts. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.

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Costs and Expenses — Three Months Ended September 30, ~~2021~~2022 and Three Months Ended September 30, ~~2020~~2021

The following table provides additional information regarding our expenses for the three months ended September 30, ~~2021~~2022 and ~~2020~~2021 (in thousands):


Costs and Expenses	Costs and Expenses	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020		Costs and Expenses	Three Months Ended September 30, 2022		Three Months Ended September 30, 2021
General and administrative, net	General and administrative, net	$	5,257	$	5,833	General and administrative, net	$	4,343	$	5,257
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	16,054		13,975		Depreciation, depletion, and amortization	41,501		16,054
Accretion of asset retirement obligations	Accretion of asset retirement obligations	77		90		Accretion of asset retirement obligations	166		77
Lease operating expenses	Lease operating expenses	6,978		5,211		Lease operating expenses	17,701		6,978
Workovers	Workovers	423		8		Workovers	284		423
Transportation and gas processing	Transportation and gas processing	5,913		5,094		Transportation and gas processing	9,662		5,913
Severance and other taxes	Severance and other taxes	4,908		2,512		Severance and other taxes	12,581		4,908
Interest expense, net	Interest expense, net	7,433		7,444		Interest expense, net	12,173		7,433

General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were ~~$0.27~~$0.16 and ~~$0.35~~$0.27 for the three months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively. The ~~decrease per Mcfe was due to higher production while the~~ decrease in costs was primarily due to ~~lower salaries~~increased supervision fees charged to wells we operate, which are recorded as a reduction of general and ~~burdens, professional fees and lower temporary labor fees.~~administrative expenses, during the three months ended September 30, 2022, while the decrease in per-Mcfe rate was due to an overall increase in production driven by our acquisitions. Included in general and administrative expenses is $1.2 million ~~and $1.1 million~~ in share-based compensation for both the three months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively.

Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were ~~$0.82~~$1.51 and ~~$0.83~~$0.82 for the three months ended September 30, 2022 and 2021, respectively. The increase in our per-Mcfe depreciation, depletion and amortization rate was primarily related to the acquisitions in the second half of 2021 and ~~2020, respectively.~~first half of 2022 and inflation on future development costs. The increase in costs is related to the increase in the per-Mcfe rate, coupled with an overall increase in production.

Lease Operating Expenses and Workovers. These expenses on a per-Mcfe basis were ~~$0.38~~$0.65 and ~~$0.31~~$0.38 for the three months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively. The increase in costs was primarily due to higher compression, ~~and~~labor, salt water disposal and chemical costs ~~partially offset~~driven by ~~lower treating costs.~~our acquisitions in the second half of 2021 and first half of 2022.

Transportation and Gas Processing. These expenses are related to natural gas and NGL sales. These expenses on a per-Mcfe basis were $0.35 and $0.30 for ~~both~~ the three months ended September 30, 2022 and 2021, ~~and 2020.~~respectively.

Severance and Other Taxes. These expenses on a per-Mcfe basis were ~~$0.25~~$0.46 and ~~$0.15~~$0.25 for the three months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately ~~4.9%~~5.2% and ~~5.5%~~4.9% for the three months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively.

Interest. Our gross interest cost was $12.2 million and $7.4 million for ~~both~~ the three months ended September 30, 2022 and 2021, ~~and 2020.~~respectively. The increase in gross interest is primarily due to higher borrowings. There were no capitalized interest costs for the three months ended September 30, ~~2021 or 2020.~~2022 and 2021.

Income Taxes. The Company recorded an income tax ~~benefit~~provision of ~~$(0.4) million and $(0.6)~~$6.1 million for the three months ended September 30, 2022 primarily attributable to a deferred federal income tax expense and deferred state income tax expense. The provision is a product of the overall forecasted annual effective tax rate applied to the year to date income. There was $0.4 million income tax benefit for the three months ended September 30, 2021 ~~and 2020, respectively. The benefit~~which was fully attributable to a current ~~state~~ income tax benefit.

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Results of Operations

Revenues — Nine Months Ended September 30, ~~2021~~2022 and Nine Months Ended September 30, ~~2020~~2021

Natural gas production was ~~79%~~75% and ~~77%~~79% of the Company's production volumes for the nine months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively. Natural gas sales were ~~67%~~63% and ~~59%~~67% of oil and gas sales for the nine months ended September 30, 2022 and 2021, ~~and 2020,~~ respectively.

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

~~NGL production was 11%~~14% and 10% of the Company's production volumes for the nine months ended September 30, 2022 and 2021, ~~and 2020,~~ respectively. ~~NGL~~Crude oil sales were ~~10%~~28% and 8%23% of oil and gas sales for the nine months ended September 30, 2022 and 2021, respectively.

NGL production was 11% of the Company's production volumes for both the nine months ended September 30, ~~2021~~2022 and ~~2020,~~2021. NGL sales were 9% and 10% of oil and gas sales for the nine months ended September 30, 2022 and 2021, respectively.

The following table provides additional information regarding the Company's oil and gas sales, by area, excluding any effects of the Company's hedging activities, for the nine months ended September 30, ~~2021~~2022 and ~~2020:~~2021:

Fields Nine Months Ended September 30, 2021 Nine Months Ended September 30, 2020
Oil and Gas Sales
(In Millions) Net Oil and Gas Production
Volumes (MMcfe) Oil and Gas Sales
(In Millions) Net Oil and Gas Production
Volumes (MMcfe)
Artesia Wells $ 61.1 11,550 $ 30.6 10,016
AWP 46.6 7,037 33.9 8,872
Fasken 99.0 25,567 44.2 23,676
Other (1)
49.1 10,967 15.2 7,904
Total $ 255.8 55,121 $ 123.9 50,468

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


Fields	Nine Months Ended September 30, 2022			Nine Months Ended September 30, 2021
	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)
Webb County Gas	$	253.5	37,386	$	127.1	31,070
Western Condensate	116.2		13,096	61.1		11,550
Southern Eagle Ford	64.1		9,236	27.6		7,341
Central Oil	94.6		7,251	37.6		4,675
Eastern Extension	24.5		2,242	—		—
Non Core	1.5		256	2.5		485
Total	$	554.4	69,467	$	255.9	55,121

The sales volumes increase from ~~2020~~2021 to ~~2021~~2022 was primarily due to ~~increased natural gas production partially offset by lower oil production~~acquisitions in the second half of 2021 and first half of 2022, in addition to wells brought online as ~~well as~~part of our full year 2021 capital program and the ~~return~~first half of ~~volumes that had been curtailed in 2020.~~2022.

In the ~~nine months ended September 30, 2021,~~third quarter of 2022, our ~~$131.9~~$298.6 million, or ~~106%~~117%, increase in oil, NGL and natural gas sales from the prior year period resulted from:

•Price variances that had an approximately ~~$127.3~~$214.8 million favorable impact on sales due to overall higher commodity pricing; and

•Volume variances that had an approximately ~~$4.6~~$83.8 million favorable impact on sales due to ~~higher natural gas and NGL~~overall increased commodity production.

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The following table provides additional information regarding our oil and gas sales, by commodity type, as well as the effects of our hedging activities for derivative contracts held to settlement, for the nine months ended September 30, ~~2021~~2022 and ~~2020~~2021 (in thousands, except per-dollar amounts):


		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020			Nine Months Ended September 30, 2022		Nine Months Ended September 30, 2021
Production volumes:	Production volumes:					Production volumes:
Oil (MBbl) (1)	Oil (MBbl) (1)	933		1,093		Oil (MBbl) (1)	1,611		933
Natural gas (MMcf)	Natural gas (MMcf)	43,594		39,018		Natural gas (MMcf)	51,829		43,594
Natural gas liquids (MBbl) (1)	Natural gas liquids (MBbl) (1)	988		815		Natural gas liquids (MBbl) (1)	1,329		988
Total (MMcfe)	Total (MMcfe)	55,121		50,468		Total (MMcfe)	69,467		55,121

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	$	58,587	$	40,979	Oil	$	155,566	$	58,587
Natural gas	Natural gas	172,234		73,170		Natural gas	351,626		172,234
Natural gas liquids	Natural gas liquids	25,030		9,772		Natural gas liquids	47,250		25,029
Total	Total	$	255,850	$	123,921	Total	$	554,442	$	255,850

Average realized price:	Average realized price:					Average realized price:
Oil (per Bbl)	Oil (per Bbl)	$	62.82	$	37.48	Oil (per Bbl)	$	96.58	$	62.82
Natural gas (per Mcf)	Natural gas (per Mcf)	3.95		1.88		Natural gas (per Mcf)	6.78		3.95
Natural gas liquids (per Bbl)	Natural gas liquids (per Bbl)	25.32		11.99		Natural gas liquids (per Bbl)	35.56		25.32
Average per Mcfe	Average per Mcfe	$	4.64	$	2.46	Average per Mcfe	$	7.98	$	4.64

Price impact of cash-settled derivatives:	Price impact of cash-settled derivatives:					Price impact of cash-settled derivatives:
Oil (per Bbl)		$	(16.57)	$	17.05
Oil (per Bbl)(2)						Oil (per Bbl)(2)	$	(28.60)	$	(16.57)
Natural gas (per Mcf)	Natural gas (per Mcf)	(0.29)		0.50		Natural gas (per Mcf)	(2.45)		(0.29)
Natural gas liquids (per Bbl)	Natural gas liquids (per Bbl)	(4.19)		—		Natural gas liquids (per Bbl)	(4.33)		(4.19)
Average per Mcfe	Average per Mcfe	$	(0.58)	$	0.76	Average per Mcfe	$	(2.57)	$	(0.58)

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)	$	46.25	$	54.54	Oil (per Bbl)	$	67.98	$	46.25
Natural gas (per Mcf)	Natural gas (per Mcf)	3.66		2.38		Natural gas (per Mcf)	4.33		3.66
Natural gas liquids (per Bbl)	Natural gas liquids (per Bbl)	21.13		11.99		Natural gas liquids (per Bbl)	31.23		21.13
Average per Mcfe	Average per Mcfe	$	4.06	$	3.22	Average per Mcfe	$	5.41	$	4.06

(2) Excludes approximately $3.6 million in settled oil hedges related to our Sundance acquisition.

For the nine months ended September 30, ~~2021~~2022 and ~~2020,~~2021, the Company recorded net losses of ~~$152.9~~$162.5 million and ~~net gains of $66.9~~$152.9 million from our derivatives activities, respectively. Additionally for the nine months ended September 30, 2022, we recorded a net gain of $4.7 million related to valuation changes from our 2021 and 2022 WTI Contingency Payouts. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.

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Costs and Expenses — Nine Months Ended September 30, ~~2021~~2022 and Nine Months Ended September 30, ~~2020~~2021

The following table provides additional information regarding our expenses for the nine months ended September 30, ~~2021~~2022 and ~~2020~~2021 (in thousands):


Costs and Expenses	Costs and Expenses	Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020		Costs and Expenses	Nine Months Ended September 30, 2022		Nine Months Ended September 30, 2021
General and administrative, net	General and administrative, net	$	14,872	$	17,926	General and administrative, net	$	14,840	$	14,872
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	45,485		51,130		Depreciation, depletion, and amortization	89,096		45,485
Accretion of asset retirement obligations	Accretion of asset retirement obligations	226		263		Accretion of asset retirement obligations	366		226
Lease operating expenses	Lease operating expenses	18,767		16,023		Lease operating expenses	37,095		18,767
Workovers	Workovers	512		8		Workovers	933		512
Transportation and gas processing	Transportation and gas processing	17,175		16,291		Transportation and gas processing	22,784		17,175
Severance and other taxes	Severance and other taxes	11,974		7,513		Severance and other taxes	30,183		11,974
Interest expense, net	Interest expense, net	21,888		23,876		Interest expense, net	26,632		21,888
Write-down of oil and gas properties		—		355,948

General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were ~~$0.27~~$0.21 and ~~$0.36~~$0.27 for the nine months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively. The decrease ~~per Mcfe~~in per-Mcfe rate was due to ~~higher~~an overall increase in production ~~while the decrease in costs was primarily due to lower salaries and burdens, professional fees and temporary labor fees.~~driven by our acquisitions. Included in general and administrative expenses is $3.9 million and $3.5 million in share-based compensation for ~~both~~ the nine months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively.

Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were ~~$0.83~~$1.28 and ~~$1.01~~$0.83 for the nine months ended September 30, 2022 and 2021, respectively. The increase in our per-Mcfe depreciation, depletion and amortization rate was primarily related to the acquisitions in the second half of 2021 and ~~2020, respectively.~~the first half of 2022 and inflation on future development costs. The ~~decrease on a per Mcfe basis was driven by reductions~~increase in costs is related to ~~our depletable base due to non-cash impairment write-downs~~the increase in the ~~previous year.~~per-Mcfe rate, coupled with an overall increase in production.

Lease Operating Expenses and Workovers. These expenses on a per-Mcfe basis were ~~$0.35~~$0.55 and ~~$0.32~~$0.35 for the nine months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively. The increase in costs was primarily due to higher compression, ~~and~~labor, salt water disposal and chemical costs ~~partially offset~~driven by ~~lower treating~~our acquisitions in the second half of 2021 and ~~labor costs.~~first half of 2022.

Transportation and Gas Processing. These expenses are related to natural gas and NGL sales. These expenses on a per-Mcfe basis were ~~$0.31~~$0.33 and ~~$0.32~~$0.31 for the nine months ended September 30, ~~2021~~2022 and ~~2020, respectively.~~2021.

Severance and Other Taxes. These expenses on a per-Mcfe basis were ~~$0.22~~$0.43 and ~~$0.15~~$0.22 for the nine months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately ~~4.7%~~5.4% and ~~6.1%~~4.7% for the nine months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively.

Interest. Our gross interest cost was ~~$21.9~~$26.6 million and ~~$23.9~~$21.9 million for the nine months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively. The ~~decrease~~increase in gross interest ~~cost~~ is primarily due to ~~decreased~~higher borrowings. There were no capitalized interest costs for the nine months ended September 30, ~~2021~~2022 and ~~2020.~~

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

Income Taxes. The Company recorded an income tax provision of $7.7 million for the nine months ended September 30, 2022 primarily attributable to a deferred federal income tax expense and deferred state income tax expense. The benefit is a product of ~~$(0.4)~~the overall forecasted annual effective tax rate applied to the year to date income. There was $0.4 million income tax benefit for the nine months ended September 30, 2021 which was fully attributable to a current state income tax benefit. In March and April 2020, the COVID-19 pandemic caused volatility in the market price for crude oil due to the disruption of global supply and demand. In response to these market conditions and given the decline in oil prices and economic outlook for our Company, during the quarter ended June 30, 2020, management determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other deferred tax assets and, accordingly, recorded a full valuation allowance as a discrete item in the second quarter to offset its net deferred tax assets in excess of deferred tax liabilities. This resulted in tax expenses of $21.2 million in the second quarter of 2020 and an income tax provision of $20.6 million and the nine months ended September 30, 2020.

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Critical Accounting Policies and New Accounting Pronouncements

There have been no changes in the critical accounting policies disclosed in our ~~2020~~2021 Annual Report on Form 10-K.

~~Forward-Looking Statements~~

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

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

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

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

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

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

~~• volatility in natural gas, oil and NGL prices;~~

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

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

~~• our borrowing capacity and future covenant compliance;~~

~~• operating results;~~

~~• asset disposition efforts or the timing or outcome thereof;~~

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

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

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

~~• impairment on our properties due to lower commodity prices;~~

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

~~• availability, cost and terms of capital;~~

~~• timing and successful drilling and completion of wells;~~

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

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

~~• competition in the oil and natural gas industry;~~

~~• general economic conditions;~~

~~• opportunities to monetize assets;~~

~~• our ability to execute on strategic initiatives;~~

~~• effectiveness of our risk management activities including hedging strategy;~~

~~• environmental liabilities;~~

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~~• counterparty credit risk;~~

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

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

~~• uncertainty regarding our future operating results; and~~

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

All forward-looking statements speak only as of the date they are made. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under "Risk Factors" in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2020 and in subsequent Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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

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

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

Interest Rate Risk. At September 30, ~~2021,~~2022, we had a combined ~~$398.0~~$630.0 million drawn under our Credit Facility and our Second Lien, which bear floating rates of interest and therefore are susceptible to interest rate fluctuations. These variable interest rate borrowings are also impacted by changes in short-term interest rates. A hypothetical one percentage point increase in interest rates on our borrowings outstanding under our Credit Facility and Second Lien at September 30, ~~2021~~2022 would increase our annual interest expense by ~~$4.0~~$6.3 million.

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Item 4. Controls and Procedures

Disclosure Controls and Procedures

We maintain disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, consisting of controls and other procedures designed to give reasonable assurance that information we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding such required disclosure. Our Chief Executive Officer and Chief Financial Officer have evaluated such disclosure controls and procedures as of the end of the period covered by this quarterly report on Form 10-Q and have determined that such disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the three months ended September 30, ~~2021~~2022 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

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

Item 1A. Risk Factors.

A description of our risk factors can be found in ~~“Item~~“Part I, Item 1A. Risk Factors” included in our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2020. There~~2021 and “Part II, Item 1A. Risk Factors” included in our Quarterly Report on Form 10-Q for the period ended March 31, 2022. Other than as provided below, there have been no material changes in our risk factors disclosed in the ~~2020~~2021 Annual Report on Form ~~10-K.~~10-K and Quarterly Report on Form 10-Q for the period ended March 31, 2022.

We may not be able to utilize a portion of our NOLs to offset future taxable income for U.S. federal income tax purposes, which could adversely affect our net income and cash flow.

As of December 31, 2021, we had federal NOLs of approximately $463 million, approximately $274 million of which will expire in varying amounts beginning in 2033 through 2037. Utilization of these NOLs depends on many factors, including our future taxable income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), imposes limitations on a corporation’s ability to utilize its NOLs if it experiences an ownership change (as determined under Section 382 of the Code). Generally, an ownership change occurs if one or more shareholders (or groups of shareholders), each of whom is deemed to own five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50 percent over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382. We believe we had an ownership change in August 2022 and, therefore, are subject to an annual limitation on the usage of our NOLs generated prior to the ownership change. However, we do not expect to have any of our NOLs expire before becoming available to be utilized by the Company. Management will continue to monitor the potential impact of Section 382 with respect to our NOLs. Additional changes in our future stock ownership or future regulatory changes could also limit our ability to utilize our NOLs. To the extent we are not able to offset future taxable income with our NOLs, our net income and cash flow may be adversely affected

Certain provisions of our Charter (as defined below), our Bylaws (as defined below) and the Rights Agreement may make it difficult for stockholders to change the composition of our Board and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.

Certain provisions of our Certificate of Incorporation, as amended, effective April 22, 2016 ( the “Charter”) and our Second Amended and Restated Bylaws, effective October 31, 2022 (the “Bylaws”) and our existing director nomination agreement may have the effect of delaying or preventing changes in control if our Board determines that such changes in control are not in the best interests of the Company and our stockholders. The provisions in our Charter and Bylaws and our existing director nomination agreement include, among other things, those that:

•provide for a classified board of directors;

•authorize our Board to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;

•establish advance notice procedures for nominating directors or presenting matters at stockholder meetings;

•provide SVP the right to nominate up to two of our directors; and

•limit the persons who may call special meetings of stockholders.

While these provisions have the effect of encouraging persons seeking to acquire control of the Company to negotiate with our Board, they could enable the Board to hinder or frustrate a transaction that some, or a majority, of the stockholders may believe to be in their best interests and, in that case, may prevent or discourage attempts to remove and replace incumbent directors. These provisions may frustrate or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our Board, which is responsible for appointing the members of our management. Furthermore, we have entered into a director nomination agreement with each of SVP, and other former holders of our senior notes that provides for certain continuing nomination rights subject to conditions on share ownership.

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Additionally, on September 20, 2022, the Board adopted the Rights Agreement and declared a dividend distribution of one Right for each outstanding share of Company common stock to holders of record on October 5, 2022. In the event that a person or group acquires beneficial ownership of 15% or more of the Company’s then-outstanding common stock, subject to certain exceptions, each Right would entitle its holder (other than such person or members of such group) to purchase additional shares of Company common stock at a substantial discount to the public market price. In addition, at any time after a person or group acquires beneficial ownership of 15% or more of the outstanding common stock, subject to certain exceptions, the Board may direct the Company to exchange the Rights (other than Rights owned by such person or certain related parties, which will have become null and void), in whole or in part, at an exchange ratio of one share of common stock per Right (subject to adjustment).While in effect, the Rights Agreement could make it more difficult for a third party to acquire control of the Company or a large block of the common stock of the Company without the approval of the Board. The Rights Agreement will expire on the earliest of (a) 5:00 p.m., New York City time, on the first business day after the 2023 annual stockholders’ meeting, (b) 5:00 p.m., New York City time, on June 30, 2023, (c) the time at which the Rights are redeemed and (d) the time at which the Rights are exchanged in full.

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

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

Except as previously disclosed in a Current Report on Form 8-K, no ~~other~~ unregistered sales of our common stock were made during the ~~three months~~quarterly period ended September 30, ~~2021.~~2022.

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Item 3. Defaults Upon Senior Securities.

~~Not applicable.~~None.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

~~Not applicable.~~On October 31, 2022, the Board adopted the Second Amended and Restated Bylaws of the Company (the “Bylaws”), which became effective the same day. Among other things, the amendments: (a) eliminate the requirement to have a stockholder list available for inspection at the stockholder meeting; (b) update the procedural mechanics with respect to adjourned meetings of stockholders; (c) provide for procedures and requirements with respect to stockholders’ right to act by written consent in lieu of a meeting (including procedures and requirements for stockholders to request a record date for such action); (d) enhance the procedural mechanics and disclosure requirements relating to business proposals submitted and director nominations made by stockholders, including by requiring: (i) certain additional background information regarding the proposing stockholders, proposed nominees or business and other persons related to such matter, (ii) a representation as to whether such stockholder intends or is part of a group which intends to deliver, in the same manner required of the Company under the Exchange Act, a proxy statement or form of proxy to holders of shares representing, in the case of nominations, at least 67% of the voting power of the Company’s outstanding stock entitled to vote generally in the election of directors, or in the case of other business, at least the percentage of the voting power of the Company’s outstanding stock required to approve or adopt such proposal and (iii) a representation that, immediately after soliciting the required percentage of stockholders described above, the stockholder submitting such matter will provide the Company with evidence confirming that the necessary steps have been taken to deliver a proxy statement and form of proxy to holders of the required percentage of the voting power of the Company’s stock entitled to vote generally in the election of directors; (e) require that a stockholder directly or indirectly soliciting proxies from other stockholders use a proxy card color other than white; and (f) opt out of Section 116 of the General Corporation Law of the State of Delaware by requiring that certain notices and other information or documents provided by stockholders to the Company pursuant to the Bylaws must be delivered in writing. The Bylaws also incorporate various other updates and technical, clarifying and conforming changes.

The preceding summary of the amendments to the Bylaws is qualified in its entirety by reference to, and should be read in connection with, the complete copy of the Second Amended and Restated Bylaws filed herewith as Exhibit 3.2.

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Item 6. Exhibits.

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


3.1			~~First Amended and Restated~~Conformed Copy of Certificate of Incorporation of SilverBow Resources, Inc., as amended, effective ~~May 5, 2017~~April 22, 2016 (incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.'s Quarterly Report on Form 10-Q filed May 8, 2017, File No. 001-08754).
~~3.2~~3.2*			~~First~~Second Amended and Restated Bylaws of SilverBow Resources, Inc., effective ~~May 5, 2017~~October 31, 2022.
3.3			Certificate of Designation, Preferences, and Rights of Series B Junior Participating Preferred Stock of the Company (incorporated by reference as Exhibit ~~3.2~~3.1 to SilverBow Resources, Inc.'s’s Current Report on Form ~~10-Q~~8-K filed ~~May 8, 2017,~~September 20, 2022, File No. 001-08754).
~~10.1~~4.1			~~Purchase~~Rights Agreement dated as of September 20, 2022, by and ~~Sale Agreement, effective August 1, 2021,~~ between the ~~SilverBow Resources, Inc.,~~Company and ~~SilverBow Resources Operating,~~American Stock Transfer & Trust Company, LLC, ~~and San Isidro Energy Company II, LLC.~~as rights agent, which includes as Exhibit B the Form of Rights Certificate (incorporated by reference as Exhibit ~~10.1~~4.1 to SilverBow Resources, Inc.’s Current Report on Form ~~S-3~~8-K filed ~~August 27, 2021,~~September 20, 2022, File No. ~~333-259122)~~001-08754).
31.1*			Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2*			Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32.1#			Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
101*			The following materials from SilverBow Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended September 30, ~~2021~~2022 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"~~“filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

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SIGNATURES

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

SILVERBOW RESOURCES, INC.
(Registrant)

Date:

November ~~4, 2021~~3, 2022

By:

/s/ Christopher M. Abundis

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

Date:

November ~~4, 2021~~3, 2022

By:

/s/ W. Eric Schultz

W. Eric Schultz
Controller

4251


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