UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

of the Securities Exchange Act of 1934

For the quarterly period ended June 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

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)			~~12,197,736~~22,306,506 Shares outstanding at July ~~30, 2021~~29, 2022

SILVERBOW RESOURCES, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 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	2634

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3744

Item 4.	Controls and Procedures	3845

Part II	OTHER INFORMATION

Item 1.	Legal Proceedings	3946
Item 1A.	Risk Factors	3946
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3946
Item 3.	Defaults Upon Senior Securities	3946
Item 4.	Mine Safety Disclosures	3947
Item 5.	Other Information	3947
Item 6.	Exhibits	3947

SIGNATURES		4149

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;

• 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;

• the benefits of 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”);

• risks related to the recently completed Sundance and SandPoint transactions, including the risk that the benefits of the transactions may not be fully realized or may take longer to realize than expected, that we will fail to successfully integrate the properties and assets into our business and that management attention will be diverted to integration-related issues;

• 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;

• 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, increased interest rates, a general economic slowdown or recession, political tensions and war;

• 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;

• 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 conflict in Ukraine, 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)


		June 30, 2021		December 31, 2020			June 30, 2022		December 31, 2021

ASSETS	ASSETS					ASSETS
Current Assets:	Current Assets:					Current Assets:
Cash and cash equivalents	Cash and cash equivalents	$	2,063	$	2,118	Cash and cash equivalents	$	9,408	$	1,121
Accounts receivable, net	Accounts receivable, net	25,957		25,850		Accounts receivable, net	110,093		49,777
Fair value of commodity derivatives	Fair value of commodity derivatives	736		4,821		Fair value of commodity derivatives	10,094		2,806

Other current assets	Other current assets	3,055		2,184		Other current assets	7,201		1,875
Total Current Assets	Total Current Assets	31,811		34,973		Total Current Assets	136,796		55,579
Property and Equipment:	Property and Equipment:					Property and Equipment:
Property and equipment, full cost method, including $24,312 and $28,090, respectively, of unproved property costs not being amortized at the end of each period		1,402,202		1,343,373
Property and equipment, full cost method, including $21,412 and $17,090, respectively, of unproved property costs not being amortized at the end of each period						Property and equipment, full cost method, including $21,412 and $17,090, respectively, of unproved property costs not being amortized at the end of each period	2,200,603		1,611,953
Less – Accumulated depreciation, depletion, amortization & impairment	Less – Accumulated depreciation, depletion, amortization & impairment	(830,749)		(801,279)		Less – Accumulated depreciation, depletion, amortization & impairment	(917,619)		(869,985)
Property and Equipment, Net	Property and Equipment, Net	571,453		542,094		Property and Equipment, Net	1,282,984		741,968
Right of Use Assets		16,609		4,366
Fair Value of Long-Term Commodity Derivatives		1		281
Right of use assets						Right of use assets	16,705		16,065
Fair value of long-term commodity derivatives						Fair value of long-term commodity derivatives	5,829		201

Other Long-Term Assets		3,069		1,421
Other long-term assets						Other long-term assets	10,041		5,641
Total Assets	Total Assets	$	622,943	$	583,135	Total Assets	$	1,452,355	$	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	$	23,887	$	26,991	Accounts payable and accrued liabilities	$	78,778	$	35,034
Fair value of commodity derivatives	Fair value of commodity derivatives	45,369		8,171		Fair value of commodity derivatives	136,185		47,453
Accrued capital costs	Accrued capital costs	12,114		7,324		Accrued capital costs	24,166		7,354
Accrued interest	Accrued interest	955		983		Accrued interest	1,420		697
Current lease liability	Current lease liability	6,029		3,473		Current lease liability	9,188		7,222
Undistributed oil and gas revenues	Undistributed oil and gas revenues	13,570		11,098		Undistributed oil and gas revenues	23,323		23,577

Total Current Liabilities	Total Current Liabilities	101,924		58,040		Total Current Liabilities	273,060		121,337
Long-Term Debt, Net		393,446		424,905
Non-Current Lease Liability		10,670		951
Deferred Tax Liabilities		303		303
Asset Retirement Obligations		4,586		4,533
Fair Value of Long-Term Commodity Derivatives		10,286		2,946
Other Long-Term Liabilities		490		424
Long-term debt, net						Long-term debt, net	640,175		372,825
Non-current lease liability						Non-current lease liability	7,788		9,090
Deferred tax liabilities						Deferred tax liabilities	7,721		6,516
Asset retirement obligations						Asset retirement obligations	8,375		5,526
Fair value of long-term commodity derivatives						Fair value of long-term commodity derivatives	36,913		8,585
Other long-term liabilities						Other long-term liabilities	5,066		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	0		0		Preferred stock, $0.01 par value, 10,000,000 shares authorized, none issued	—		—
Common stock, $0.01 par value, 40,000,000 shares authorized, 12,388,208 and 12,053,763 shares issued, respectively, and 12,196,978 and 11,936,679 shares outstanding, respectively		124		121
Common stock, $0.01 par value, 40,000,000 shares authorized, 22,652,048 and 16,822,845 shares issued, respectively, and 22,306,690 and 16,631,175 shares outstanding, respectively						Common stock, $0.01 par value, 40,000,000 shares authorized, 22,652,048 and 16,822,845 shares issued, respectively, and 22,306,690 and 16,631,175 shares outstanding, respectively	227		168
Additional paid-in capital	Additional paid-in capital	300,088		297,712		Additional paid-in capital	573,259		413,017
Treasury stock, held at cost, 191,230 and 117,084 shares, respectively		(2,975)		(2,372)
(Accumulated deficit) Retained earnings		(195,999)		(204,428)
Treasury stock, held at cost, 345,358 and 191,670 shares, respectively						Treasury stock, held at cost, 345,358 and 191,670 shares, respectively	(7,095)		(2,984)
Accumulated deficit						Accumulated deficit	(93,134)		(117,669)
Total Stockholders’ Equity	Total Stockholders’ Equity	101,238		91,033		Total Stockholders’ Equity	473,257		292,532
Total Liabilities and Stockholders’ Equity	Total Liabilities and Stockholders’ Equity	$	622,943	$	583,135	Total Liabilities and Stockholders’ Equity	$	1,452,355	$	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 June 30, 2021		Three Months Ended June 30, 2020			Three Months Ended June 30, 2022		Three Months Ended June 30, 2021
Revenues:	Revenues:					Revenues:
Oil and gas sales	Oil and gas sales	$	69,861	$	24,846	Oil and gas sales	$	182,605	$	69,861

Operating Expenses:	Operating Expenses:					Operating Expenses:
General and administrative, net	General and administrative, net	4,834		6,180		General and administrative, net	5,710		4,834
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	16,039		13,716		Depreciation, depletion, and amortization	26,441		16,039
Accretion of asset retirement obligations	Accretion of asset retirement obligations	74		88		Accretion of asset retirement obligations	101		74
Lease operating expenses	Lease operating expenses	5,515		5,000		Lease operating expenses	10,270		5,515
Workovers	Workovers	76		0		Workovers	2		76
Transportation and gas processing	Transportation and gas processing	6,206		4,554		Transportation and gas processing	6,769		6,206
Severance and other taxes	Severance and other taxes	3,577		2,037		Severance and other taxes	9,838		3,577
Write-down of oil and gas properties		0		260,342

Total Operating Expenses	Total Operating Expenses	36,321		291,917		Total Operating Expenses	59,131		36,321

Operating Income (Loss)		33,540		(267,071)
Operating Income						Operating Income	123,474		33,540

Non-Operating Income (Expense)	Non-Operating Income (Expense)					Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net	Gain (loss) on commodity derivatives, net	(46,067)		(8,458)		Gain (loss) on commodity derivatives, net	(22,406)		(46,067)
Interest expense, net	Interest expense, net	(7,436)		(8,026)		Interest expense, net	(7,902)		(7,436)
Other income (expense), net	Other income (expense), net	12		(1)		Other income (expense), net	(10)		12

Income (Loss) Before Income Taxes	Income (Loss) Before Income Taxes	(19,951)		(283,556)		Income (Loss) Before Income Taxes	93,156		(19,951)

Provision (Benefit) for Income Taxes	Provision (Benefit) for Income Taxes	0		22,420		Provision (Benefit) for Income Taxes	4,366		—

Net Income (Loss)	Net Income (Loss)	$	(19,951)	$	(305,976)	Net Income (Loss)	$	88,790	$	(19,951)

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

Basic Earnings (Loss) Per Share	Basic Earnings (Loss) Per Share	$	(1.64)	$	(25.69)	Basic Earnings (Loss) Per Share	$	5.05	$	(1.64)

Diluted Earnings (Loss) Per Share	Diluted Earnings (Loss) Per Share	$	(1.64)	$	(25.69)	Diluted Earnings (Loss) Per Share	$	4.95	$	(1.64)

Weighted-Average Shares Outstanding - Basic	Weighted-Average Shares Outstanding - Basic	12,190		11,910		Weighted-Average Shares Outstanding - Basic	17,581		12,190

Weighted-Average Shares Outstanding - Diluted	Weighted-Average Shares Outstanding - Diluted	12,190		11,910		Weighted-Average Shares Outstanding - Diluted	17,938		12,190

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)

Six Months Ended June 30, 2021 Six Months Ended June 30, 2020
Revenues:
Oil and gas sales $ 156,602 $ 78,222
Operating Expenses:
General and administrative, net 9,616 12,093
Depreciation, depletion, and amortization 29,431 37,156
Accretion of asset retirement obligations 148 173
Lease operating expenses 11,789 10,812
Workovers 90 0
Transportation and gas processing 11,262 11,197
Severance and other taxes 7,066 5,001
Write-down of oil and gas properties 0 355,948
Total Operating Expenses 69,402 432,380
Operating Income (Loss) 87,200 (354,158)
Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net (64,326) 79,829
Interest expense, net (14,454) (16,433)
Other income (expense), net 9 107
Income (Loss) Before Income Taxes 8,429 (290,655)
Provision (Benefit) for Income Taxes 0 21,179
Net Income (Loss) $ 8,429 $ (311,834)
Per Share Amounts:
Basic Earnings (Loss) Per Share $ 0.70 $ (26.28)
Diluted Earnings (Loss) Per Share $ 0.68 $ (26.28)
Weighted-Average Shares Outstanding - Basic 12,110 11,868
Weighted-Average Shares Outstanding - Diluted 12,379 11,868
See accompanying Notes to Condensed Consolidated Financial Statements.


	Six Months Ended June 30, 2022		Six Months Ended June 30, 2021
Revenues:
Oil and gas sales	$	312,261	$	156,602

Operating Expenses:
General and administrative, net	10,497		9,616
Depreciation, depletion, and amortization	47,595		29,431
Accretion of asset retirement obligations	200		148
Lease operating expenses	19,395		11,789
Workovers	649		90
Transportation and gas processing	13,121		11,262
Severance and other taxes	17,602		7,066

Total Operating Expenses	109,059		69,402

Operating Income	203,202		87,200

Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net	(162,648)		(64,326)
Interest expense, net	(14,459)		(14,454)
Other income (expense), net	52		9

Income (Loss) Before Income Taxes	26,147		8,429

Provision (Benefit) for Income Taxes	1,612		—

Net Income (Loss)	$	24,535	$	8,429

Per Share Amounts:

Basic Earnings (Loss) Per Share	$	1.43	$	0.70

Diluted Earnings (Loss) Per Share	$	1.40	$	0.68

Weighted-Average Shares Outstanding - Basic	17,146		12,110

Weighted-Average Shares Outstanding - Diluted	17,506		12,379

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)		0		0		(83)		0		(83)

Vesting of share-based compensation (105,108 shares)		1		(1)		0		0		0
Share-based compensation		0		1,335		0		0		1,335
Net Loss		0		0		0		(5,858)		(5,858)
Balance, March 31, 2020		$	120	$	294,250	$	(2,365)	$	99,096	$	391,101
Shares issued from warrant exercise (5 shares)		0		0		0		0		0
Purchase of treasury shares (1,098 shares)		0		0		(3)		0		(3)
Vesting of share-based compensation (49,665 shares)		0		0		0		0		0
Share-based compensation		0		1,229		0		0		1,229
Net Loss		0		0		0		(305,976)		(305,976)
Balance, June 30, 2020		$	120	$	295,479	$	(2,368)	$	(206,880)	$	86,351
													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)	0		0		(488)		0		(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)		0		0		0		Vesting of share-based compensation (283,113 shares)	2		(2)		—		—		—
Share-based compensation	Share-based compensation	0		1,131		0		0		1,131		Share-based compensation	—		1,131		—		—		1,131
Net Income	Net Income	0		0		0		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)	0		0		(115)		0		(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)		0		0		0		Vesting of share-based compensation (51,332 shares)	1		(1)		—		—		—

Share-based compensation	Share-based compensation	0		1,248		0		0		1,248		Share-based compensation	—		1,248		—		—		1,248
Net Loss	Net Loss	0		0		0		(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

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 acquisition (5,448,472 shares)												Issuance pursuant to acquisition (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

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)


		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020			Six Months Ended June 30, 2022		Six Months Ended June 30, 2021
Cash Flows from Operating Activities:	Cash Flows from Operating Activities:					Cash Flows from Operating Activities:
Net income (loss)	Net income (loss)	$	8,429	$	(311,834)	Net income (loss)	$	24,535	$	8,429
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	29,431		37,156		Depreciation, depletion, and amortization	47,595		29,431
Write-down of oil and gas properties		0		355,948

Accretion of asset retirement obligations	Accretion of asset retirement obligations	148		173		Accretion of asset retirement obligations	200		148
Deferred income taxes	Deferred income taxes	0		21,087		Deferred income taxes	1,205		—
Share-based compensation	Share-based compensation	2,260		2,437		Share-based compensation	2,714		2,260
(Gain) Loss on derivatives, net	(Gain) Loss on derivatives, net	64,326		(79,829)		(Gain) Loss on derivatives, net	162,648		64,326
Cash settlement (paid) received on derivatives	Cash settlement (paid) received on derivatives	(10,708)		67,496		Cash settlement (paid) received on derivatives	(90,603)		(10,708)
Settlements of asset retirement obligations	Settlements of asset retirement obligations	(166)		(15)		Settlements of asset retirement obligations	(54)		(166)
Write down of debt issuance cost	Write down of debt issuance cost	229		459		Write down of debt issuance cost	350		229
Other	Other	1,202		1,814		Other	1,668		1,202
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	(1,387)		14,293		(Increase) decrease in accounts receivable and other current assets	(34,422)		(1,387)
Increase (decrease) in accounts payable and accrued liabilities	Increase (decrease) in accounts payable and accrued liabilities	(502)		(10,137)		Increase (decrease) in accounts payable and accrued liabilities	(1,254)		(502)
Increase (decrease) in income taxes payable	Increase (decrease) in income taxes payable	0		92		Increase (decrease) in income taxes payable	304		—
Increase (decrease) in accrued interest	Increase (decrease) in accrued interest	(28)		(140)		Increase (decrease) in accrued interest	723		(28)
Net Cash Provided by (Used in) Operating Activities	Net Cash Provided by (Used in) Operating Activities	93,234		99,000		Net Cash Provided by (Used in) Operating Activities	115,609		93,234
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	(56,995)		(85,594)		Additions to property and equipment	(93,746)		(56,995)
Acquisition of oil and gas properties		(207)		(3,394)
Acquisition of oil and gas properties, net of purchase price adjustments						Acquisition of oil and gas properties, net of purchase price adjustments	(272,225)		(207)
Proceeds from the sale of property and equipment	Proceeds from the sale of property and equipment	0		4,752		Proceeds from the sale of property and equipment	2,532		—
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	(58,286)		(84,662)		Net Cash Provided by (Used in) Investing Activities	(364,189)		(58,286)
Cash Flows from Financing Activities:	Cash Flows from Financing Activities:					Cash Flows from Financing Activities:

Proceeds from bank borrowings	Proceeds from bank borrowings	123,000		50,000		Proceeds from bank borrowings	482,000		123,000
Payments of bank borrowings	Payments of bank borrowings	(155,000)		(59,000)		Payments of bank borrowings	(215,000)		(155,000)

Net proceeds from stock options exercised						Net proceeds from stock options exercised	39		—
Purchase of treasury shares	Purchase of treasury shares	(603)		(86)		Purchase of treasury shares	(2,965)		(603)
Payments of debt issuance costs	Payments of debt issuance costs	(2,400)		0		Payments of debt issuance costs	(7,207)		(2,400)
Net Cash Provided by (Used in) Financing Activities	Net Cash Provided by (Used in) Financing Activities	(35,003)		(9,086)		Net Cash Provided by (Used in) Financing Activities	256,867		(35,003)
Net Increase (Decrease) in Cash and Cash Equivalents	Net Increase (Decrease) in Cash and Cash Equivalents	(55)		5,252		Net Increase (Decrease) in Cash and Cash Equivalents	8,287		(55)
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	$	2,063	$	6,610	Cash and Cash Equivalents at End of Period	$	9,408	$	2,063
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	$	13,282	$	15,006	Cash paid during period for interest, net of amounts capitalized	$	12,228	$	13,282

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	$	1,307	$	(28,618)	Changes in capital accounts payable and capital accruals	$	20,882	$	1,307
Non-cash equity consideration for acquisitions						Non-cash equity consideration for acquisitions	$	(156,259)	$	—

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

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

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

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

~~On August 3, 2021, we acquired additional working interest in 12 wells that we currently operate and additional acreage in Webb County for total aggregate consideration of approximately $24 million.~~

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Through July ~~30, 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 June 30, ~~2021:~~2022:

Oil Derivative Contracts
(New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) Settlements)
Total Volumes
(Bbls)(1)
Weighted-Average Price
2021 Contracts
3Q21 30,000 $ 70.75
3Q21 (2)
12,000 $ 72.76
4Q21 81,250 $ 66.69
2022 Contracts
1Q22 45,000 $ 63.37
2Q22 45,500 $ 62.00
3Q22 46,000 $ 60.81
4Q22 46,000 $ 59.75


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	90,000	$	91.94
2Q23	91,000	$	88.82
3Q23	92,000	$	86.44
4Q23	92,000	$	84.40
2024 Contracts
1Q24	45,500	$	78.50
2Q24	45,500	$	78.50
3Q24	114,000	$	77.84
4Q24	102,000	$	77.09
Collar Contracts
2022 Contracts
3Q22	30,500			$	98.00	$	107.10
4Q22	46,000			$	90.00	$	103.80

~~(1) Bbl refers to one barrel~~

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

Total Volumes (Bbls)

Weighted-Average Price

2022 Contracts

3Q22

30,500

3.96


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
2023 Contracts
2Q23	1,820,000	$	4.62
3Q23	1,840,000	$	4.67
2024 Contracts
1Q24	145,000	$	5.34
2Q24	455,000	$	4.31
Collar Contracts
2022 Contracts
3Q22	340,000			$	6.00	$	7.36
4Q22	1,840,000			$	6.00	$	7.60
2023 Contracts
1Q23	1,800,000			$	6.00	$	7.76
4Q23	1,840,000			$	4.75	$	5.25

Table of ~~oil.~~Contents

~~(2) Transaction for a swap purchase to reduce overall hedge position.~~


Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes (MMBtu)	Weighted-Average Price
2023 Contracts
1Q23	900,000	$	0.007
2Q23	910,000	$	(0.186)
3Q23	920,000	$	(0.152)
4Q23	920,000	$	(0.148)
2024 Contracts
1Q24	1,820,000	$	0.144
2Q24	1,820,000	$	(0.263)
3Q24	1,840,000	$	(0.221)
4Q24	1,840,000	$	(0.202)

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
3Q21 610,000 $ 4.00
4Q21 1,240,000 $ 3.90
2022 Contracts
2Q22 3,795,000 $ 2.99
3Q22 4,140,000 $ 3.02
4Q22 2,760,000 $ 3.14
Collar Contracts
2022 Contracts
4Q22 1,380,000 $ 2.90 $ 3.34
2023 Contracts
1Q23 1,350,000 $ 2.95 $ 3.51
2Q23 2,275,000 $ 2.40 $ 2.84

NGL Swaps (Mont Belvieu) Total Volumes
(Bbls) Weighted-Average Price
2022 Contracts
1Q22 45,000 $ 26.32
2Q22 45,500 $ 26.32
3Q22 46,000 $ 26.32
4Q22 46,000 $ 26.32


NGL Swaps (Mont Belvieu)	Total Volumes (Bbls)	Weighted-Average Price
2023 Contracts
1Q23	45,500	$	32.92
2Q23	45,500	$	32.92
3Q23	46,000	$	32.92
4Q23	46,000	$	32.92

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

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

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

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

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

•estimates of future costs to develop and produce reserves,

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

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

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

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

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

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

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

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

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

•estimates on future lease obligations.

While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, reallocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas

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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 both the three months ended June 30, ~~2021~~2022 and ~~2020,~~2021, such internal costs when capitalized totaled $1.2 ~~million and $0.9 million, respectively.~~million. For the six months ended June 30, ~~2021~~2022 and ~~2020,~~2021, such internal costs when capitalized totaled ~~$2.3~~$2.2 million and ~~$2.0~~$2.3 million, respectively. Interest costs are also capitalized to unproved oil and natural gas ~~properties (refer to Note 6 of these Notes to Condensed Consolidated Financial Statements for further discussion on~~properties. There was no capitalized interest ~~costs).~~on our unproved properties for the three months ended June 30, 2022 and 2021 and the six months ended June 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):


		June 30, 2021		December 31, 2020			June 30, 2022		December 31, 2021
Property and Equipment	Property and Equipment					Property and Equipment
Proved oil and gas properties	Proved oil and gas properties	$	1,372,163	$	1,310,008	Proved oil and gas properties	$	2,173,225	$	1,588,978
Unproved oil and gas properties	Unproved oil and gas properties	24,312		28,090		Unproved oil and gas properties	21,412		17,090
Furniture, fixtures and other equipment	Furniture, fixtures and other equipment	5,727		5,275		Furniture, fixtures and other equipment	5,966		5,885
Less – Accumulated depreciation, depletion, amortization & impairment	Less – Accumulated depreciation, depletion, amortization & impairment	(830,749)		(801,279)		Less – Accumulated depreciation, depletion, amortization & impairment	(917,619)		(869,985)
Property and Equipment, Net	Property and Equipment, Net	$	571,453	$	542,094	Property and Equipment, Net	$	1,282,984	$	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.

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

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

Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be

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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~~ There was no impairment ~~write-down, on a pre-tax basis, of $260.3 million and $355.9 million~~ for the three months ended June 30, 2022 and 2021 and the six months ended June 30, ~~2020, respectively, on our oil~~2022 and ~~natural gas properties. There was 0 impairment for the three and six months ended June 30,~~ 2021.

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 June 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 June 30, 2022, our “Accounts receivable, net” balance included $80.3 million for oil and gas sales, $1.6 million due from joint interest owners, $26.0 million for purchase price adjustments related to our Sundance acquisition, $1.6 million for severance tax credit receivables and $0.7 million for other receivables. At December 31, 2021, our “Accounts receivable, net” balance included ~~$23.9~~$45.3 million for oil and gas sales, ~~$0.6~~$1.9 million due from joint interest owners, $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.

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Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the six months ended June 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 ~~$1.2~~$1.7 million and ~~$0.9~~$1.2 million for the three months ended June 30, ~~2021~~2022 and ~~2020,~~2021, respectively, and ~~$2.4~~$3.4 million and ~~$2.2~~$2.4 million for the six months ended June 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 $22.4 million and $21.2 million for the three and six months ended June 30, 2020, respectively, 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 $6.6 million and $5.5 million deferred tax liability that was recorded as of June 30, 2022 and December 31, 2021, respectively. We recorded an income tax provision of $4.4 million and $1.6 million for the three and six months ended June 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 six months ended June 30, 2022 is a product of the overall forecasted annual effective tax rate applied to the year to date income. There was no income tax expense or benefit for the three and six months ended June 30, 2021.

In the event we were to undergo an “ownership change” (as defined in Section 382 of the Internal Revenue Code of 1986, as amended), our ability to use net operating losses generated prior to the ownership change may be limited. 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. Based on currently available information, we do not believe an ownership change has occurred through June 30, 2022. However, our recent acquisitions involving the issuance of the Company's common stock and other transactions by stockholders, did increase the likelihood that the Company could experience an ownership change in the future. If a subsequent ownership change were to occur as a result of future transactions in the Company’s common stock, the Company’s use of remaining U.S. tax attributes may be limited.

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Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At June 30, 2022 and December 31, 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~~did not ~~currently expect the CARES Act to~~ have a material ~~effect~~impact on ~~its~~the Company's 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.

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 June 30, ~~2021~~2022 and ~~2020~~2021 and the six months ended June 30, ~~2021~~2022 and ~~2020~~2021 (in thousands):


		Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020			Three Months Ended June 30, 2022		Three Months Ended June 30, 2021		Six Months Ended June 30, 2022		Six Months Ended June 30, 2021
Oil, natural gas and NGLs sales:	Oil, natural gas and NGLs sales:									Oil, natural gas and NGLs sales:
Oil	Oil	$	15,890	$	5,265	$	33,356	$	23,315	Oil	$	44,014	$	15,890	$	83,755	$	33,356
Natural gas	Natural gas	46,791		18,103		109,705		49,574		Natural gas	123,296		46,791		200,668		109,705
NGLs	NGLs	7,180		1,478		13,541		5,333		NGLs	15,295		7,180		27,838		13,541
Total	Total	$	69,861	$	24,846	$	156,602	$	78,222	Total	$	182,605	$	69,861	$	312,261	$	156,602

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


		June 30, 2021		December 31, 2020			June 30, 2022		December 31, 2021
Trade accounts payable	Trade accounts payable	$	8,736	$	15,930	Trade accounts payable	$	9,948	$	9,688
Accrued operating expenses	Accrued operating expenses	2,873		2,491		Accrued operating expenses	12,319		4,192
Accrued compensation costs	Accrued compensation costs	2,579		3,771		Accrued compensation costs	2,774		7,029
Asset retirement obligations – current portion	Asset retirement obligations – current portion	515		441		Asset retirement obligations – current portion	528		524
Accrued non-income based taxes	Accrued non-income based taxes	2,517		1,819		Accrued non-income based taxes	12,687		3,314
Accrued corporate and legal fees	Accrued corporate and legal fees	143		150		Accrued corporate and legal fees	5,276		1,972
WTI contingency payouts - current portion						WTI contingency payouts - current portion	6,793		—
Payable for settled derivatives						Payable for settled derivatives	26,417		6,371
Other payables	Other payables	6,524		2,389		Other payables	2,036		1,944
Total accounts payable and accrued liabilities	Total accounts payable and accrued liabilities	$	23,887	$	26,991	Total accounts payable and accrued liabilities	$	78,778	$	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 six months ended June 30, ~~2021 and 2020,~~2022, we purchased ~~74,146 and 27,773~~112,497 treasury shares ~~respectively,~~ to satisfy withholding tax obligations arising upon the vesting of restricted shares and received 41,191 shares in

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conjunction with our post-closing settlement for a previously disclosed acquisition. For the six months ended June 30, 2021 we purchased 74,146 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares.

(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 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 June 30, ~~2021,~~2022, all of the Company’s leases were operating leases.

The initial asset and liability balances are recorded at the present value of the payment obligations over the lease term. If lease terms include options to extend the lease and it is reasonably certain that the Company will exercise that option, the lease term used for capitalization includes the expected renewal periods. Most leases do not provide an implicit interest rate. Unless the lease contract contains an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease inception to compute the fair value of the lease payments. The ROU asset balance and current and non-current lease liabilities are reported separately on the accompanying Condensed Consolidated Balance 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 June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020			Three Months Ended June 30, 2022		Three Months Ended June 30, 2021		Six Months Ended June 30, 2022		Six Months Ended June 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	$	1,491	$	118	$	1,820	$	2,302	Property, plant and equipment acquisitions - short-term leases	$	2,278	$	1,491	$	4,033	$	1,820
Property, plant and equipment acquisitions - operating leases	Property, plant and equipment acquisitions - operating leases	0		5		0		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	$	1,491	$	123	$	1,820	$	2,312	Total lease costs in property, plant and equipment additions	$	2,278	$	1,491	$	4,033	$	1,820

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		Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020			Three Months Ended June 30, 2022		Three Months Ended June 30, 2021		Six Months Ended June 30, 2022		Six Months Ended June 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	$	618	$	650	$	1,085	$	900	Lease operating expenses - short-term leases	$	1,032	$	618	$	1,964	$	1,085
Lease operating expenses - operating leases	Lease operating expenses - operating leases	1,106		1,433		2,270		2,870		Lease operating expenses - operating leases	2,102		1,106		3,954		2,270
General and administrative, net - operating leases	General and administrative, net - operating leases	178		179		351		359		General and administrative, net - operating leases	193		178		382		351
Total lease cost expensed	Total lease cost expensed	$	1,902	$	2,262	$	3,706	$	4,129	Total lease cost expensed	$	3,327	$	1,902	$	6,300	$	3,706

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


	June 30, ~~2021~~2022
Weighted-average remaining lease term (in years)	~~3.1~~2.6
Weighted-average discount rate	~~4.1~~4.3	%

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


		As of June 30, 2021			As of June 30, 2022
2021 (Remaining)		$	3,462
2022		6,443
2022 (Remaining)				2022 (Remaining)	$	5,156
2023	2023	5,642		2023	9,082
2024	2024	742		2024	1,750
2025	2025	742		2025	823
2026				2026	688
Thereafter	Thereafter	856		Thereafter	521
Total undiscounted lease payments	Total undiscounted lease payments	17,887		Total undiscounted lease payments	18,020
Present value adjustment	Present value adjustment	(1,188)		Present value adjustment	(1,044)
Net operating lease liabilities	Net operating lease liabilities	$	16,699	Net operating lease liabilities	$	16,976

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


		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020			Six Months Ended June 30, 2022		Six Months Ended June 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	$	2,618	$	3,225	Operating cash flows from operating leases	$	4,312	$	2,618
Investing cash flows from operating leases		$	0	$	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	$	3,902	$	5,758

(4) Share-Based Compensation

Share-Based Compensation Plans

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

The Company computes a deferred tax benefit for restricted stock 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 $1.7 million and $1.2 million for ~~both~~ the three months ended June 30, 2022 and 2021, and ~~2020~~$2.7 million and $2.3 ~~million and $2.4~~ million for the six months ended June 30, 2022 and 2021, ~~and 2020,~~

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respectively. Capitalized share-based compensation was less than $0.1 million for both the three months ended June 30, ~~2021~~2022 and ~~2020~~2021 and $0.1 million for both the six months ended June 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.

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At June 30, ~~2021,~~2022, we had ~~$0.4 million of~~no unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the six months ended June 30, ~~2021:~~2022:


		Shares	Wtd. Avg. Exer. Price			Shares	Wtd. Avg. Exer. Price
Options outstanding, beginning of period	Options outstanding, beginning of period	303,705	$	27.73	Options outstanding, beginning of period	276,009	$	28.12

Options forfeited		(3,896)	$	16.96

Options expired	Options expired	(23,800)	$	23.25	Options expired	(64,263)	$	33.48

Options exercised					Options exercised	(4,497)	$	26.96
Options outstanding, end of period	Options outstanding, end of period	276,009	$	28.12	Options outstanding, end of period	207,249	$	26.49
Options exercisable, end of period	Options exercisable, end of period	226,950	$	28.53	Options exercisable, end of period	207,249	$	26.49

Our outstanding stock option awards had ~~$0.1~~$0.6 million measurable aggregate intrinsic value at June 30, ~~2021.~~2022. At June 30, ~~2021,~~2022, the weighted-average remaining contract life of stock option awards outstanding was ~~4.6~~4.9 years and exercisable was ~~4.4~~4.9 years. The total intrinsic value of stock option awards exercisable was ~~less than $0.1~~$0.6 million ~~for the six months ended~~as of June 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).

As of June 30, ~~2021,~~2022, we had ~~$1.9~~$3.7 million unrecognized compensation expense related to our RSUs which is expected to be recognized over a weighted-average period of ~~1.0~~2.3 years.

The following table provides information regarding RSU activity for the six months ended June 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	172,866	$	25.38

RSUs forfeited	RSUs forfeited	(17,802)	$	11.09	RSUs forfeited	(8,734)	$	21.20
RSUs vested	RSUs vested	(310,645)	$	9.02	RSUs vested	(277,933)	$	8.86
RSUs outstanding, end of period	RSUs outstanding, end of period	346,647	$	8.71	RSUs outstanding, end of period	231,044	$	20.36

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 there are no outstanding awards as of June 30, 2021.~~

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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 June 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 June 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 June 30, 2022.

As of June 30, ~~2021,~~2022, we had ~~$2.2~~$4.5 million unrecognized compensation expense related to our PSUs based on the assumption of 100% target payout. The remaining weighted-average performance period is ~~1.3 years while 23,800 shares vested during~~2.3 years.

The following table provides information regarding performance-based stock unit activity for the six months ended June 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 six months ended June 30, ~~2021~~2022 and ~~2020~~2021 are discussed below.

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

Three Months Ended June 30, 2021 Three Months Ended June 30, 2020
Net Income (Loss) Shares Per Share
Amount Net Income (Loss) Shares Per Share
Amount
Basic EPS:
Net Income (Loss) and Share Amounts $ (19,951) 12,190 $ (1.64) $ (305,976) 11,910 $ (25.69)
Dilutive Securities:
RSU Awards 0 0
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions $ (19,951) 12,190 $ (1.64) $ (305,976) 11,910 $ (25.69)


		Six Months Ended June 30, 2021					Six Months Ended June 30, 2020						Three Months Ended June 30, 2022					Three Months Ended June 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	$	8,429	12,110	$	0.70	$	(311,834)	11,868	$	(26.28)	Net Income (Loss) and Share Amounts	$	88,790	17,581	$	5.05	$	(19,951)	12,190	$	(1.64)
Dilutive Securities:	Dilutive Securities:											Dilutive Securities:

Performance Based Stock Unit Awards												Performance Based Stock Unit Awards			171					—
RSU Awards	RSU Awards			269					0			RSU Awards			128					—

Stock Option Awards												Stock Option Awards			58					—
Diluted EPS:	Diluted EPS:											Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	Net Income (Loss) and Assumed Share Conversions	$	8,429	12,379	$	0.68	$	(311,834)	11,868	$	(26.28)	Net Income (Loss) and Assumed Share Conversions	$	88,790	17,938	$	4.95	$	(19,951)	12,190	$	(1.64)

1720

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~~Approximately~~


	Six Months Ended June 30, 2022					Six Months Ended June 30, 2021
	Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)		Shares	Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	24,535	17,146	$	1.43	$	8,429	12,110	$	0.70
Dilutive Securities:
Performance Based Stock Unit Awards			142					—
RSU Awards			188					269
Stock Option Awards			30					—
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	24,535	17,506	$	1.40	$	8,429	12,379	$	0.68

There were no antidilutive stock options for the three months ended June 30, 2022, while 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for ~~both~~ the three months ended June 30, 2021 ~~and 2020~~ because they were ~~antidilutive due to the net loss, while~~antidilutive. Less than 0.1 million and 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for the six months ended June 30, 2022 and 2021, respectively, because they were ~~antidilutive, while 0.3 million stock options to purchase shares were not included for the six months ended June 30, 2020 because they were antidilutive due to the net loss.~~antidilutive.

Less than ~~approximately~~ 0.1 million ~~and 0.2~~antidilutive shares of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended June 30, 2022, because they were antidilutive. Furthermore, less than 0.1 million antidilutive shares of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended June 30, 2021 ~~and 2020, respectively,~~ because they were antidilutive due to the net ~~loss, while~~loss. Less than 0.1 million and 0.1 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the six months ended June 30, 2022 and 2021, respectively, because they were antidilutive.

There were no antidilutive shares of PSUs that could be converted to common shares for both the three months ended June 30, 2022 and 2021. There were no antidilutive shares of PSUs for the six months ended June 30, 2022, while ~~0.2~~0.1 million shares of ~~RSUs~~PSUs that could be converted to common shares were not included in the computation of Diluted EPS for the six months ended June 30, ~~2020 because they were antidilutive due to the net loss.~~

There were 0 antidilutive shares of PSUs that could be converted to common shares for the three months ended June 30, 2021, while approximately 0.1 million shares of PSUs were not included for the three months ended June 30, 2020 because they were antidilutive due to the net loss, while 0.1 million shares of PSUs were not included for the six months ended June 30, 2021 because they were ~~antidilutive, while 0.1 million shares of PSUs were not included for the six months ended June 30, 2020 because they were antidilutive due to the net loss.~~antidilutive.

(6) Long-Term Debt

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

June 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 (1,157) (1,295)
Unamortized debt issuance cost on Second Lien Notes due 2024 (3,397) (3,800)
Long-Term Debt, net $ 393,446 $ 424,905


	June 30, 2022		December 31, 2021
Credit Facility Borrowings (1)	$	494,000	$	227,000
Second Lien Notes due 2026	150,000		150,000
	644,000		377,000
Unamortized discount on Second Lien Notes due 2026	(972)		(1,061)
Unamortized debt issuance cost on Second Lien Notes due 2026	(2,853)		(3,114)
Long-Term Debt, net	$	640,175	$	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 June 30, ~~2021~~2022 and December 31, ~~2020,~~2021, we had ~~$3.0~~$9.7 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~~$494.0 million and ~~$230.0~~$227.0 million as of June 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, 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

Table of ~~our Credit Facility~~Contents

extent earlier, the date that is 91 days prior to the scheduled maturity of 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 Credit Facility matures October 19, 2026, and provides for a maximum credit amount of ~~$600.0 million,~~$2.0 billion, subject to the current borrowing base of ~~$300.0~~$775.0 million as of June ~~30, 2021.~~22, 2022. 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 $6.1 million outstanding letters of credit as of June 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

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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,~~June 22, 2022, the applicable margin ranged from ~~2.25%~~1.75% to ~~3.25%~~2.75% for ABR Loans and ~~3.25%~~2.75% to ~~4.25%~~3.75% 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 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 June 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 provides for options in the event LIBOR is discontinued.~~borrowings was 5.25%.

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.~~subsidiary effective 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 June 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~~$4.4 million and ~~$3.5~~$2.8 million for the three months ended June 30, ~~2021~~2022 and ~~2020,~~2021, respectively, and ~~$5.3~~$7.6 million and ~~$6.9~~ $5.3

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million for the six months ended June 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 0 capitalized interest on our unproved properties~~$0.1 million for ~~both~~ the three months ended June 30, ~~2021~~2022 and ~~2020,~~2021, respectively, and $0.6 million and $0.2 million, for ~~both~~ the six months ended June 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.

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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 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%.

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 June 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.

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As of June 30, ~~2021,~~2022, total net amounts recorded for the Second Lien were ~~$195.4~~$146.2 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $3.5 million and $4.6 million for ~~both~~ the three months ended June 30, ~~2021~~2022 and ~~2020,~~2021, respectively, and ~~$9.2~~$6.9 million and ~~$9.5~~$9.2 million for the six months ended June 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 ~~three~~six months ended June 30, 2022 and 2021, ~~in connection with our semi-annual redetermination,~~ the Company capitalized $7.2 million and $2.4 million, respectively, for ~~expenses~~debt issuance costs incurred ~~under the Seventh Amendment to~~during our ~~Credit Facility.~~redeterminations. Additionally, the Company wrote-off $0.4 million and $0.2 million in debt issuance costs during the six months ended June 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 six months ended June 30, 2022 and 2021, ~~and 2020,~~ respectively. ~~The~~There is no remaining obligation under this contract ~~is $0.5~~as of June 30, 2022.

August 2021 Acquisition

On August 3, 2021, the Company acquired the remaining working interest in 12 wells that SilverBow operates and additional acreage in Webb county. The total aggregate consideration was approximately $23.0 million, consisting of $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. 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.

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 three 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. As part of the post-closing settlement of this acquisition, in the first quarter of 2022, we received 41,191 shares back to our Treasury from two of the entities, and we issued 489 new shares to one of the entities. In the second quarter of 2022, 19,448 shares were released from escrow to three of the entities and 184 shares returned back to our Treasury from one entity.

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 six months ended June 30, 2022, the Company recorded losses of $0.2 million and ~~is carried~~$1.5 million, respectively, related to the 2021 WTI Contingency Payout recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated ~~balance sheet current liability~~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 ~~“Accounts payable~~the proved oil and ~~accrued liabilities”~~gas properties and have therefore accounted for this transaction as ~~of June 30, 2021.~~

2024

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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 approximately $67.2 million, consisting of $29.0 million in cash, 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 and accrued purchase price adjustments receivable of $1.5 million. The acquisition is subject to further customary post-closing adjustments. We incurred approximately $0.4 million in transaction costs during the six months ended June 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.

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	$	28,972
Equity consideration	39,767
Accrued purchase price adjustments receivable	(1,501)
Total Consideration	67,238

Transaction costs	400

Total Cost of Transaction	$	67,638

Allocation of Total Cost
Assets
Oil and gas properties	$	84,307
Total assets	84,307

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

Net Assets Acquired	$	67,638

May 2022 Disposition

On May 16, 2022, the Company closed its disposition of non-strategic oil and gas assets located in Dimmit County, Texas. After consideration of closing adjustments, total proceeds from the sale were approximately $2.5 million. The transaction is subject to further customary post-closing adjustments. There was no gain or loss recognized in connection with the disposition.

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 $342.5 million, consisting of $242.3 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 $26.0 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

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two earn-out payments of $7.5 million each, contingent upon the 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”). 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 $5.3 million in transaction costs during the six months ended June 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.

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	$	242,298
Equity consideration	117,651
Fair value of contingent consideration	8,566
Accrued purchase price adjustments receivable	(26,000)
Total Consideration	342,515

Transaction costs	5,264

Total Cost of Transaction	$	347,779

Allocation of Total Cost
Assets
Other current assets	$	4,202
Oil and gas properties	392,645
Right of use assets	890
Total assets	397,737

Liabilities
Accounts payable and accrued liabilities	12,857
Fair value of commodity derivatives	33,767
Non-current lease liability	890
Asset retirement obligations	2,444
Total Liabilities	$	49,958

Net Assets Acquired	$	347,779

(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 June 30, ~~2021~~2022 and ~~2020,~~2021, the Company recorded losses of ~~$46.1~~$22.2 million and ~~losses of $8.5~~$46.1 million, respectively, on its commodity derivatives. During the six months ended June 30, ~~2021~~2022 and ~~2020,~~2021, the Company recorded losses of $161.2 million and $64.3 million, respectively, on its commodity derivatives. During the three and ~~gains~~six months ended June 30, 2022, the Company recorded losses of ~~$79.8~~$0.2 million ~~respectively.~~and $1.5 million, respectively, related to valuation

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changes on the 2021 WTI Contingency Payout. The Company made cash payments of ~~$10.7~~$90.6 million and ~~collected cash payments of $67.5~~$10.7 million for settled derivative contracts during the six months ended June 30, 2022 and 2021, ~~and 2020,~~ respectively. ~~Included in our collected cash payments during the six months ended June 30, 2020 was $38.3 million for monetized derivative contracts.~~

At June 30, ~~2021~~2022 and December 31, ~~2020,~~2021, there ~~were~~was $0.4 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 July ~~2021~~2022 and January ~~2021,~~2022, respectively. At June 30, ~~2021~~2022 and December 31, ~~2020,~~2021, we also had ~~$5.1~~$26.4 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 July ~~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 June 30, ~~2021,~~2022, there was ~~$0.7~~$10.1 million and ~~less than $0.1~~$5.8 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and ~~$45.4~~$136.2 million and ~~$10.3~~$36.9 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 ~~$54.9~~$157.2 million net fair value liability at June 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 June 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
3Q21 179,759 $ 51.19
4Q21 191,412 $ 53.60
2022 Contracts
1Q22 178,455 $ 45.77
2Q22 91,000 $ 54.00
3Q22 200,100 $ 47.05
4Q22 138,000 $ 53.20
2023 Contracts
1Q23 81,900 $ 55.70
Collar Contracts
2021 Contracts
3Q21 90,620 $ 34.34 $ 39.87
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 36,400 $ 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
3Q22	528,696	$	66.32
4Q22	559,876	$	74.00
2023 Contracts
1Q23	442,175	$	79.40
2Q23	403,575	$	78.93
3Q23	441,980	$	75.47
4Q23	477,300	$	77.07
2024 Contracts
1Q24	182,000	$	81.35
2Q24	113,750	$	81.80
3Q24	115,000	$	79.96
4Q24	115,000	$	78.36
Collar Contracts
2022 Contracts
3Q22	160,727					$	68.29	$	87.73
4Q22	155,304					$	64.83	$	80.08
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
3Q22	15,139			$	42.48	$	53.27	$	62.49
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

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
3Q21 330,000 $ 2.62
4Q21 290,000 $ 2.69
2022 Contracts
3Q22 2,100 $ 2.50
Collar Contracts
2021 Contracts
3Q21 8,185,175 $ 2.36 $ 2.82
4Q21 8,991,000 $ 2.61 $ 2.98
2022 Contracts
1Q22 8,465,000 $ 2.72 $ 3.36
2Q22 5,246,500 $ 2.15 $ 2.60
3Q22 4,899,000 $ 2.39 $ 2.72
4Q22 4,545,076 $ 2.41 $ 2.88
2023 Contracts
1Q23 4,297,000 $ 2.62 $ 3.11

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Natural Gas Basis Derivative Swaps
(East Texas Houston Ship Channel vs. NYMEX Settlements) Total Volumes
(MMBtu) Weighted-Average Price
2021 Contracts
3Q21 10,120,000 $ (0.022)
4Q21 11,040,000 $ (0.013)
2022 Contracts
1Q22 6,300,000 $ 0.052
2Q22 2,730,000 $ (0.063)
3Q22 2,760,000 $ (0.063)
4Q22 2,760,000 $ (0.063)


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
3Q22	6,066,226	$	3.72
4Q22	4,267,284	$	3.99
2023 Contracts
1Q23	981,000	$	6.74
2Q23	1,996,000	$	4.48
3Q23	2,976,000	$	4.51
4Q23	3,887,000	$	4.71
2024 Contracts
1Q24	746,000	$	4.34
2Q24	5,070,000	$	3.86
3Q24	5,060,000	$	3.94
4Q24	5,060,000	$	4.21
Collar Contracts
2022 Contracts
3Q22	8,315,300					$	2.86	$	3.29
4Q22	9,132,376					$	2.90	$	3.47
2023 Contracts
1Q23	11,267,900					$	3.43	$	4.98
2Q23	10,321,250					$	3.07	$	3.73
3Q23	10,056,400					$	3.24	$	3.89
4Q23	8,765,000					$	3.47	$	4.35
2024 Contracts
1Q24	5,111,000					$	3.67	$	5.54
2Q24	93,000					$	3.15	$	3.65
3Q24	198,000					$	2.90	$	3.33
4Q24	185,000					$	2.90	$	3.33
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

Oil Basis Swaps
(Argus Cushing (WTI) and Magellan East Houston) Total Volumes (Bbls) Weighted-Average Price
2021 Contracts
3Q21 262,200 $ 1.27
4Q21 241,500 $ 1.28
Calendar Monthly Roll Differential Swaps
2021 Contracts
3Q21 253,000 $ (0.34)
4Q21 241,500 $ (0.33)
2022 Contracts
1Q22 216,000 $ 0.09
2Q22 218,400 $ 0.09
3Q22 220,800 $ 0.09
4Q22 220,800 $ 0.09

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NGL Swaps (Mont Belvieu) Total Volumes
(Bbls) Weighted-Average Price
2021 Contracts
3Q21 192,324 $ 24.26
4Q21 192,324 $ 24.26
2022 Contracts
1Q22 45,000 $ 23.52


Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes (MMBtu)	Weighted-Average Price
2022 Contracts
3Q22	5,520,000	$	(0.04)
4Q22	5,520,000	$	(0.06)
2023 Contracts
1Q23	3,600,000	$	0.22
2Q23	3,640,000	$	(0.19)
3Q23	3,680,000	$	(0.17)
4Q23	3,680,000	$	(0.14)
2024 Contracts
1Q24	3,640,000	$	0.11
2Q24	3,640,000	$	(0.28)
3Q24	3,680,000	$	(0.23)
4Q24	3,680,000	$	(0.19)
Houston Ship Channel Fixed Price Contracts
2022 Contracts
3Q22	141,000	$	2.77
4Q22	132,000	$	2.74
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
3Q22	358,800	$	1.00
4Q22	266,800	$	0.19


NGL Swaps (Mont Belvieu)	Total Volumes (Bbls)	Weighted-Average Price
2022 Contracts
3Q22	283,500	$	34.06
4Q22	299,000	$	34.49
2023 Contracts
1Q23	202,500	$	34.63
2Q23	204,750	$	34.63
3Q23	207,000	$	34.22
4Q23	207,000	$	34.22
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 crude oil and natural gas proved properties, future operating and development costs 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.

The following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of June 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)
June 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)
June 30, 2022										June 30, 2022
Assets	Assets									Assets
Natural Gas Derivatives										Natural Gas Derivatives	$	7,798	$	—	$	7,798	$	—
Natural Gas Basis Derivatives										Natural Gas Basis Derivatives	2,888		—		2,888		—
Oil Derivatives										Oil Derivatives	2,402		—		2,402		—

Natural Gas Basis Derivatives		$	0.3	$	0	$	0.3	$	0

Oil Basis Derivatives		0.4		0		0.4		0

NGL Derivatives										NGL Derivatives	2,835		—		2,835		—
Liabilities	Liabilities									Liabilities
Natural Gas Derivatives	Natural Gas Derivatives	22.8		0		22.8		0		Natural Gas Derivatives	95,578		—		95,578		—
Natural Gas Basis Derivatives	Natural Gas Basis Derivatives	1.6		0		1.6		0		Natural Gas Basis Derivatives	2,077		—		2,077		—
Oil Derivatives	Oil Derivatives	25.7		0		25.7		0		Oil Derivatives	69,793		—		69,793		—
Oil Basis Derivatives	Oil Basis Derivatives	1.0		0		1.0		0		Oil Basis Derivatives	1,339		—		1,339		—
NGL Derivatives	NGL Derivatives	4.5		0		4.5		0		NGL Derivatives	4,311		—		4,311		—
December 31, 2020
2022 WTI Contingency Payout										2022 WTI Contingency Payout	8,566		—		8,566		—
2021 WTI Contingency Payout										2021 WTI Contingency Payout	3,293		—		3,293		—

December 31, 2021										December 31, 2021
Assets	Assets									Assets
Natural Gas Derivatives	Natural Gas Derivatives	1.5		0		1.5		0		Natural Gas Derivatives	$	1,159	$	—	$	1,159	$	—
Natural Gas Basis Derivatives	Natural Gas Basis Derivatives	1.1		0		1.1		0		Natural Gas Basis Derivatives	1,025		—		1,025		—
Oil Derivatives	Oil Derivatives	2.5		0		2.5		0		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		0		4.0		0		Natural Gas Derivatives	31,801		—		31,801		—
Natural Gas Basis Derivatives	Natural Gas Basis Derivatives	0.4		0		0.4		0		Natural Gas Basis Derivatives	452		—		452		—
Oil Derivatives	Oil Derivatives	5.9		0		5.9		0		Oil Derivatives	21,330		—		21,330		—
Oil Basis Derivatives	Oil Basis Derivatives	0.8		0		0.8		0		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, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the

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obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets. ~~This guidance requires us to record a liability for the fair value of our dismantlement and abandonment costs upon initial recording, excluding salvage values.~~

~~Table of Contents~~

The following provides a roll-forward of our asset retirement obligations for the year ended December 31, ~~2020~~2021 and the six months ended June 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	~~148~~306
Liabilities incurred for new wells, acquired wells and facilities construction	~~292~~1,120

Reductions due to plugged wells and facilities	~~(157)~~(192)
Revisions in estimates	~~(156)~~(158)
Asset Retirement Obligations as of December 31, 2021	$	6,050
Accretion expense	200
Liabilities incurred for new wells, acquired wells and facilities construction	2,716
Reductions due to sold wells and facilities	(43)
Reductions due to plugged wells and facilities	(19)

Asset Retirement Obligations as of June 30, ~~2021~~2022	$	~~5,101~~8,904

At both June 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 35 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 ~~Shale~~and Austin Chalk located in South Texas where it has assembled approximately ~~130,000~~176,000 net acres across five operating areas. SilverBow's acreage position in each of its operating areas is highly contiguous and designed for optimal and efficient horizontal well development. The Company has built a balanced portfolio of properties with a significant base of current production and reserves coupled with low-risk development drilling opportunities and meaningful upside from newer operating areas.

Being a committed and long-term operator in South Texas, SilverBow possesses a significant understanding of the reservoir characteristics, geology, landowners and competitive landscape in the region. The Company leverages this in-depth knowledge to continue to assemble high quality drilling inventory while continuously enhancing its operations to maximize returns on capital invested.

~~Operational Results~~Acquisitions Update

In the second quarter of 2022, SilverBow completed its transactions with SandPoint on May 10, 2022 and Sundance on June 30, 2022. In connection with the transaction with SandPoint, the acquired SandPoint oil and gas assets contributed 50 days of total production with SilverBow completing and bringing online one well that had been previously drilled by SandPoint. The well is operating above initial expectations and represents one of SilverBow's top 25 gas wells. The Sundance acquisition did not contribute to second quarter production and associated operational cash flows as it did not close until the last day of the second quarter. In conjunction with the closing of the acquisitions, the Company revised its 2022 capital budget to a range of $300-$330 million. SilverBow plans to drill and develop the acquired assets in the second half of 2022. As a result of the acquisitions and the addition of a second drilling rig, SilverBow expects to benefit from increased scale and greater operational efficiencies.

Operational Results

Total production for the six months ended June 30, ~~2021~~2022 increased 6%18% from the six months ended June 30, ~~2020~~2021 to ~~197~~232 million cubic feet of natural gas equivalent per day as SilverBow pursued a moderated growth strategy and did not have any curtailed production impacting results.

During the second quarter of ~~2021,~~2022, SilverBow drilled 10seven net wells and completed ~~one well~~ and brought ~~one well online. Drilling~~online 15 net wells. The Company completed and ~~completion (“D&C”) spending during~~brought online an eight-well pad in its Webb County Gas area. This was the ~~quarter was primarily related to drilling activity~~largest pad developed in SilverBow’s history, achieving excellent pad pumping efficiency and averaging 11 stages completed per day comprising 4.6 million pounds of sand per day. Two of the eight wells on this pad were located in the ~~liquids-rich La Salle Condensate area. As previously planned,~~Austin Chalk formation and are the best performing Austin Chalk wells the Company ~~accelerated activity of~~has drilled to date when normalized on a per lateral foot basis. SilverBow also completed and brought online a three-well pad in its ~~mid-year oil development program. Due to further reduced drilling cycle times~~Western Condensate area and ~~efficiencies, SilverBow was able to drill three additional wells~~a three-well pad in its Central Oil area during the second quarter. ~~Notably, the Company drilled a four well pad in approximately 25 days, or six days per well on average. First~~Both pads are currently outperforming expectations with initial production from the nine La Salle Condensate wells is expected in the third quarter of 2021. SilverBow is reviewing early data and appraising its Austin Chalk acreage through the one well completed in the second quarter.rates exceeding their respective type curves.

SilverBow ~~continues to further its capital and operational efficiencies across its operating areas. Year-to-date, the Company drilled 20% more lateral feet per day and reduced~~operated one drilling costs by 9% compared to 2020. On the completion side, SilverBow completed 17% more stages per day, pumped 8% more proppant per day and reduced completion costs by 2%. Taken altogether, D&C costs per lateral foot are 5% lower in 2021 as compared to 2020.

Production management remains a key focus area for the Company, and the maintenance and optimization projects executed during the first quarter of 2021 continue to support strong performance from the developed production base. Inrig throughout the second quarter, and as previously planned added a second rig in conjunction with the closing of ~~2021, further base production optimizations were realized~~the Sundance acquisition on June 30, 2022. The Company intends to continue drilling at a two rig pace through ~~expanded compression~~the second half of 2022, with one rig drilling primarily gas-weighted locations and ~~artificial lift installations. This~~one rig drilling primarily liquids-weighted locations. Capital and operating costs continue to face inflationary pressures as a result of high demand for products, materials and services provided by vendors in conjunction with overall supply chain disruptions and tight labor market conditions. SilverBow is addressing cost inflation through enhanced procurement initiatives, pre-ordering key materials and a focus on base production management is driving production uplifts with shallower declines. The continued outperformance of SilverBow's initial Austin Chalk well, which came online in February 2021, further supported its production base during the second quarter. As of the date of this report, the well is still producing above 10 million cubic feet of natural gas per day (“MMcf/d”) and has produced a cumulative 1.9 billion cubic feet (“Bcf”) over the first five months.

For the third quarter of 2021, SilverBow plans to drill six net wells across the McMullen Oil and Webb County Gas areas, and complete and bring online 11 net wells across the La Salle Condensate, McMullen Oil and Webb County Gas areas. The development program reflects the acceleration of liquids-rich wells planned earlier this year, as well as a balancing of high-rate gas wells to capture favorable prices heading into year-end. Not included in the well counts are three gross (one net) non-operated wells in the Webb Count Gas area, whichoperational efficiencies. With two fully utilized rigs, the Company has ~~elected to participate in during the third quarter~~greater line of ~~2021,~~sight into upcoming activity levels and ~~which adds approximately $5 million to the full year capital budget. By early fourth quarter 2021, SilverBow expects substantially all its D&C activity for the year to be incurred.~~

~~The Company has revised its capital budget for full year 2021 to~~is employing a range of ~~$115-$130 million.~~short and long-term contracts to secure equipment while maintaining cost discipline. As always, SilverBow optimizes its drilling schedule based on commodity prices, returns on investment and strategically proving up additional inventory at key focus areas such as the Austin Chalk. The ~~revised range will enable SilverBow to capitalize~~Company anticipates realizing cost efficiencies on ~~a favorable commodity price backdrop while generating greater cash flow.~~its recently acquired assets as they are fully integrated into SilverBow’s cost structure over the second half of the year.

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Through the first half of 2021, the Company maintained zero recordable incidents. Safety is core to SilverBow’s operations and the Company has demonstrated a commitment to delivering high-returns through its industry-leading safety environment.

~~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 $11.9 million or $0.33 per thousand cubic feet of gas equivalent (“Mcfe”) for the first six months of 2021, as compared to $10.8 million or $0.32 per Mcfe for the same period in 2020. The increase in costs was due to incremental expenses related to Winter Storm Uri, higher utilities and higher compression costs. These increases were partially mitigated by lower chemical, treating and salt water disposal costs.

SilverBow's net general and administrative (“net G&A”) costs were $9.6 million, or $0.27 per Mcfe, and cash G&A costs were $7.4 million (a non-GAAP financial measure calculated as net G&A costs less $2.3 million of share-based compensation), or $0.21 per Mcfe, for the first six months of 2021, compared to net G&A costs of $12.1 million, or $0.36 per Mcfe, and cash G&A costs of $9.7 million (a non-GAAP financial measure calculated as net G&A costs less $2.4 million of share-based compensation), or $0.29 per Mcfe, for the six months ended June 30, 2020.

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

Liquidity and Capital Resources

SilverBow's primary use of cash has been to fund capital expenditures to develop its oil and gas properties, fund acquisitions and to repay Credit Facility borrowings. As of June 30, ~~2021,~~2022, the Company’s liquidity consisted of ~~$2.1~~$9.4 million of cash-on-hand and ~~$102.0~~$274.9 million in available borrowings on its Credit Facility, which had a ~~$300~~$775.0 million borrowing ~~base.~~base, after factoring in approximately $6.1 million in letters of credit.

SilverBow along with its administrative agent requested an unscheduled redetermination of the borrowing base between scheduled redeterminations as part of the SandPoint and Sundance transactions. Effective June 22, 2022, SilverBow entered into the Tenth Amendment to its First Amended and Restated Senior Secured Revolving Credit Agreement governing its Credit Facility, in conjunction with its unscheduled redetermination. The Tenth Amendment, among other things, increased the borrowing base under the Credit Facility to $775.0 million 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; increased the maximum credit amounts from $1 billion to $2 billion; and decreased the applicable margin used to calculate the interest rate under the Credit Facility by 50 basis points. 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. Management believes the Company has sufficient liquidity to meet its obligations through the third 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.~~statements.

Contractual Commitments and Obligations

As of June 30, 2021 and December 31, 2020, the Company had approximately $16.7 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 six months ended June 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.

~~Off-Balance Sheet Arrangements~~Borrowings under our Credit Facility increased $267.0 million from December 31, 2021 primarily related to our acquisitions during the second quarter of 2022.

~~As of June 30, 2021, the Company had no off-balance sheet arrangements requiring disclosure pursuant to Item 303(a) of Regulation S-K.~~

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

•Revenues and Net Income (Loss): The Company's oil and gas revenues were $312.3 million for the six months ended June 30, 2022, compared to $156.6 million for the six months ended June 30, ~~2021, compared to $78.2 million for the six months ended June 30, 2020.~~2021. Revenues were higher due to increased production volumes driven by acquisitions and overall higher commodity pricing. The Company's net income was $24.5 million for the six months ended June 30, 2022, compared to net income of $8.4 million for the six months ended June 30, ~~2021, compared to a net loss of $311.8 million for the six months ended June 30, 2020.~~2021. The increase in net 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 year.~~partially offset by mark-to-market loss on our commodity derivatives.

•Capital Expenditures: The Company's capital expenditures on an accrual basis were $114.6 million for the six months ended June 30, 2022 compared to $58.7 million for the six months ended June 30, ~~2021 compared to $55.5 million for the six months ended June 30, 2020.~~2021. The expenditures for the six months ended June 30, ~~2021~~2022 and ~~2020~~2021 were primarily attributable to drilling and completion activity.

•Working Capital: The Company had a working capital deficit of ~~$70.1~~$136.3 million at June 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 $126.1 million and $44.6 million at June 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 $6.8 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 six months ended June 30, 2022, the Company generated cash from operating activities of $115.6 million which included negative impacts attributable to changes in working capital of $34.6 million. Cash used for property additions was $93.7 million while cash used in property acquisitions, including purchase price adjustments was $272.2 million. This excluded $20.9 million attributable to a net increase of capital-related payables and accrued costs. The Company’s net borrowings on the Credit Facility were $267.0 million during the six months ended June 30, 2022 which were primarily used to fund acquisitions in the second quarter of 2022.

For the six months ended June 30, 2021, the Company generated cash from operating activities of $93.2 million, of which $1.9 million was attributable to changes in working capital. Cash used for property additions was $57.0 million. This excluded $1.3 million attributable to a net increase of capital-related payables and accrued costs. Additionally, $1.1 million was paid during the six months ended June 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 six months ended June 30, 2021.

For the six months ended June 30, 2020, the Company generated cash from operating activities of $99.0 million, of which $4.1 million was attributable to changes in working capital. Cash used for property additions was $85.6 million. This included $28.6 million attributable to a net decrease of capital-related payables and accrued costs. Additionally, $0.4 million was paid during the six months ended June 30, 2020 for property abandonment obligations related to the sale of our former Bay De Chene field. The Company’s net repayments on the Credit Facility were $9.0 million during the six months ended June 30, 2020.

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Results of Operations

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

Natural gas production was 78% and 82% of the Company's production volumes for ~~both~~ the three months ended June 30, 2022 and 2021, ~~and 2020.~~respectively. Natural gas sales were ~~67%~~68% and ~~73%~~67% of oil and gas sales for the three months ended June 30, ~~2021~~2022 and ~~2020,~~2021, respectively.

Crude oil production was 8% and 10% of the Company's production volumes for both the three months ended June 30, 2021 and 2020, respectively. Crude oil sales were 23% and 21% of oil and gas sales for the three months ended June 30, 2021 and 2020, respectively.

~~NGL production was 10%~~11% and 8% of the Company's production volumes for the three months ended June 30, 2022 and 2021, ~~and 2020,~~ respectively. ~~NGL~~Crude oil sales were ~~10%~~24% and 6%23% of oil and gas sales for ~~both~~ the three months ended June 30, 2022 and 2021, respectively.

NGL production was 11% and ~~2020,~~10% of the Company's production volumes for the three months ended June 30, 2022 and 2021, respectively. NGL sales were 8% and 10% of oil and gas sales for the three months ended June 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 three months ended June 30, ~~2021~~2022 and ~~2020:~~2021:

Fields Three Months Ended June 30, 2021 Three Months Ended June 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 $ 15.7 3,491 $ 4.4 1,872
AWP 14.1 2,249 5.3 2,189
Fasken 28.8 9,754 12.8 7,511
Other (1)
11.2 3,873 2.3 1,312
Total $ 69.8 19,367 $ 24.8 12,884

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


Fields	Three Months Ended June 30, 2022			Three Months Ended June 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	$	90.5	12,421	$	34.8	11,805
Western Condensate	38.2		3,925	15.7		3,491
Southern Eagle Ford	24.1		3,152	7.2		2,427
Central Oil	20.1		1,315	11.6		1,457
Eastern Extension	9.1		763	—		—
Non Core	0.6		67	0.5		187
Total	$	182.6	21,643	$	69.8	19,367

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

In the second quarter of ~~2021,~~2022, our ~~$45.0~~$112.8 million, or ~~181%~~161%, increase in oil, NGL and natural gas sales from the prior year period resulted from:

•Price variances that had an approximately ~~$33.7~~$98.9 million favorable impact on sales due to overall higher commodity pricing; and

•Volume variances that had an approximately ~~$11.3~~$13.9 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 June 30, ~~2021~~2022 and ~~2020~~2021 (in thousands, except per-dollar amounts):


		Three Months Ended June 30, 2021		Three Months Ended June 30, 2020			Three Months Ended June 30, 2022		Three Months Ended June 30, 2021
Production volumes:	Production volumes:					Production volumes:
Oil (MBbl) (1)	Oil (MBbl) (1)	250		221		Oil (MBbl) (1)	400		250
Natural gas (MMcf)	Natural gas (MMcf)	15,879		10,624		Natural gas (MMcf)	16,918		15,879
Natural gas liquids (MBbl) (1)	Natural gas liquids (MBbl) (1)	332		156		Natural gas liquids (MBbl) (1)	387		332
Total (MMcfe)	Total (MMcfe)	19,367		12,884		Total (MMcfe)	21,643		19,367

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	$	15,890	$	5,265	Oil	$	44,014	$	15,890
Natural gas	Natural gas	46,791		18,103		Natural gas	123,296		46,791
Natural gas liquids	Natural gas liquids	7,180		1,478		Natural gas liquids	15,295		7,180
Total	Total	$	69,861	$	24,846	Total	$	182,605	$	69,861

Average realized price:	Average realized price:					Average realized price:
Oil (per Bbl)	Oil (per Bbl)	$	63.62	$	23.82	Oil (per Bbl)	$	109.94	$	63.62
Natural gas (per Mcf)	Natural gas (per Mcf)	2.95		1.70		Natural gas (per Mcf)	7.29		2.95
Natural gas liquids (per Bbl)	Natural gas liquids (per Bbl)	21.65		9.49		Natural gas liquids (per Bbl)	39.51		21.65
Average per Mcfe	Average per Mcfe	$	3.61	$	1.93	Average per Mcfe	$	8.44	$	3.61

Price impact of cash-settled derivatives:	Price impact of cash-settled derivatives:					Price impact of cash-settled derivatives:
Oil (per Bbl)		$	(20.49)	$	49.52
Oil (per Bbl)(2)						Oil (per Bbl)(2)	$	(42.96)	$	(20.49)
Natural gas (per Mcf)	Natural gas (per Mcf)	(0.13)		0.64		Natural gas (per Mcf)	(2.75)		(0.13)
Natural gas liquids (per Bbl)	Natural gas liquids (per Bbl)	(2.79)		—		Natural gas liquids (per Bbl)	(6.38)		(2.79)
Average per Mcfe	Average per Mcfe	$	(0.42)	$	1.38	Average per Mcfe	$	(3.06)	$	(0.42)

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)	$	43.13	$	73.34	Oil (per Bbl)	$	66.99	$	43.13
Natural gas (per Mcf)	Natural gas (per Mcf)	2.82		2.34		Natural gas (per Mcf)	4.54		2.82
Natural gas liquids (per Bbl)	Natural gas liquids (per Bbl)	18.86		9.49		Natural gas liquids (per Bbl)	33.13		18.86
Average per Mcfe	Average per Mcfe	$	3.19	$	3.31	Average per Mcfe	$	5.38	$	3.19

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

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

For the three months ended June 30, ~~2021~~2022 and ~~2020,~~2021, the Company recorded net losses of ~~$46.1~~$22.2 million and ~~$8.5~~$46.1 million from our derivatives activities, respectively. Additionally for the three months ended June 30, 2022, we recorded net losses of $0.2 million related to valuation changes from our 2021 WTI Contingency Payout. 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 June 30, ~~2021~~2022 and Three Months Ended June 30, ~~2020~~2021

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


Costs and Expenses	Costs and Expenses	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Costs and Expenses	Three Months Ended June 30, 2022		Three Months Ended June 30, 2021
General and administrative, net	General and administrative, net	$	4,834	$	6,180	General and administrative, net	$	5,710	$	4,834
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	16,039		13,716		Depreciation, depletion, and amortization	26,441		16,039
Accretion of asset retirement obligations	Accretion of asset retirement obligations	74		88		Accretion of asset retirement obligations	101		74
Lease operating expenses	Lease operating expenses	5,515		5,000		Lease operating expenses	10,270		5,515
Workovers	Workovers	76		—		Workovers	2		76
Transportation and gas processing	Transportation and gas processing	6,206		4,554		Transportation and gas processing	6,769		6,206
Severance and other taxes	Severance and other taxes	3,577		2,037		Severance and other taxes	9,838		3,577
Interest expense, net	Interest expense, net	7,436		8,026		Interest expense, net	7,902		7,436
Write-down of oil and gas properties		—		260,342

General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were ~~$0.25~~$0.26 and ~~$0.48~~$0.25 for the three months ended June 30, ~~2021~~2022 and ~~2020,~~2021, respectively. The ~~decrease per Mcfe was due to higher production while the decrease~~increase in costs was primarily due to ~~lower~~higher salaries and burdens ~~professional fees~~ and ~~lower temporary labor~~higher legal and professional fees. Included in general and administrative expenses is $1.7 million and $1.2 million in share-based compensation for ~~both of~~ the three months ended June 30, ~~2021~~2022 and ~~2020,~~2021, respectively.

Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were ~~$0.83~~$1.22 and ~~$1.06~~$0.83 for the three months ended June 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.~~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 ~~$0.29~~$0.47 and ~~$0.39~~$0.29 for the three months ended June 30, 2022 and 2021, ~~and 2020,~~ respectively. ~~The decrease per Mcfe was mainly due to increased production.~~ The increase in costs was primarily due to higher compression, ~~and~~ salt water disposal ~~costs, partially offset by lower treating~~ and ~~labor~~chemicals costs.

Transportation and Gas Processing. These expenses are related to natural gas and NGL sales. These expenses on a per-Mcfe basis were ~~$0.32~~$0.31 and ~~$0.35~~$0.32 for the three months ended June 30, ~~2021~~2022 and ~~2020,~~2021, respectively.

Severance and Other Taxes. These expenses on a per-Mcfe basis were ~~$0.18~~$0.45 and ~~$0.16~~$0.18 for the three months ended June 30, ~~2021~~2022 and ~~2020,~~2021, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately ~~5.1%~~5.4% and ~~8.2%~~5.1% for the three months ended June 30, ~~2021~~2022 and ~~2020,~~2021, respectively.

Interest. Our gross interest cost was ~~$7.4~~$7.9 million and ~~$8.0~~$7.4 million for the three months ended June 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 three months ended June 30, ~~2021 or 2020.~~2022 and 2021.

~~Write-down~~Income Taxes. The Company recorded an income tax provision of ~~oil and gas properties. Due to the effects of pricing and timing of projects,~~$4.4 million for the three months ended June 30, ~~2020, we reported~~2022 primarily attributable to a ~~non-cash impairment write-down, on~~deferred federal income tax expense and state deferred income tax expense. The provision is a ~~pre-tax basis,~~product of ~~$260.3 million on our oil and natural gas properties.~~the overall forecasted annual effective tax rate applied to the year to date income. There was no ~~impairment~~income tax expense or benefit for the three months ended June 30, 2021.

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Results of Operations

Revenues — Six Months Ended June 30, ~~2021~~2022 and Six Months Ended June 30, ~~2020~~2021

Natural gas production was ~~80%~~77% and ~~81%~~80% of the Company's production volumes for the six months ended June 30, ~~2021~~2022 and ~~2020,~~2021, respectively. Natural gas sales were ~~70%~~64% and ~~63%~~70% of oil and gas sales for the six months ended June 30, 2022 and 2021, ~~and 2020,~~ respectively.

Crude oil production was 12% and 10% of the Company's production volumes for the six months ended June 30, 2022 and 2021, respectively. Crude oil sales were 27% and 21% of oil and gas sales for the six months ended June 30, 2022 and 2021, respectively.

NGL production was 11% and 10% of the Company's production volumes for both the six months ended June 30, ~~2021~~2022 and ~~2020, respectively. Crude oil sales were 21% and 30% of oil and gas sales for the six months ended June 30, 2021 and 2020, respectively.~~

~~NGL production was 10% and 8% of the Company's production volumes for the six months ended June 30, 2021 and 2020, respectively.~~2021. NGL sales were 9% ~~and 7%~~ of oil and gas sales for both the six months ended June 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 six months ended June 30, ~~2021~~2022 and ~~2020:~~2021:

Fields Six Months Ended June 30, 2021 Six Months Ended June 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 $ 30.2 6,743 $ 18.8 6,215
AWP 31.1 4,964 18.6 5,214
Fasken 61.8 16,554 31.2 17,176
Other (1)
33.5 7,330 9.6 5,054
Total $ 156.6 35,591 $ 78.2 33,659

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


Fields	Six Months Ended June 30, 2022			Six Months Ended June 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	$	147.4	23,872	$	82.2	20,212
Western Condensate	76.5		8,474	30.2		6,743
Southern Eagle Ford	34.8		5,324	17.8		5,005
Central Oil	34.9		2,524	25.4		3,342
Eastern Extension	17.2		1,560	—		—
Non Core	1.5		208	1.0		289
Total	$	312.3	41,962	$	156.6	35,591

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, 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 ~~six months ended June 30, 2021,~~second quarter of 2022, our ~~$78.4~~$155.7 million, or ~~100%~~99%, increase in oil, NGL and natural gas sales from the prior year period resulted from:

•Price variances that had an approximately ~~$76.3~~$121.8 million favorable impact on sales due to overall higher commodity pricing; and

•Volume variances that had an approximately ~~$2.1~~$33.9 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 six months ended June 30, ~~2021~~2022 and ~~2020~~2021 (in thousands, except per-dollar amounts):


		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020			Six Months Ended June 30, 2022		Six Months Ended June 30, 2021
Production volumes:	Production volumes:					Production volumes:
Oil (MBbl) (1)	Oil (MBbl) (1)	565		622		Oil (MBbl) (1)	830		565
Natural gas (MMcf)	Natural gas (MMcf)	28,502		27,121		Natural gas (MMcf)	32,505		28,502
Natural gas liquids (MBbl) (1)	Natural gas liquids (MBbl) (1)	617		468		Natural gas liquids (MBbl) (1)	747		617
Total (MMcfe)	Total (MMcfe)	35,591		33,659		Total (MMcfe)	41,962		35,591

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	$	33,356	$	23,315	Oil	$	83,755	$	33,356
Natural gas	Natural gas	109,705		49,574		Natural gas	200,668		109,705
Natural gas liquids	Natural gas liquids	13,541		5,333		Natural gas liquids	27,838		13,541
Total	Total	$	156,602	$	78,222	Total	$	312,261	$	156,602

Average realized price:	Average realized price:					Average realized price:
Oil (per Bbl)	Oil (per Bbl)	$	59.09	$	37.51	Oil (per Bbl)	$	100.97	$	59.09
Natural gas (per Mcf)	Natural gas (per Mcf)	3.85		1.83		Natural gas (per Mcf)	6.17		3.85
Natural gas liquids (per Bbl)	Natural gas liquids (per Bbl)	21.95		11.40		Natural gas liquids (per Bbl)	37.29		21.95
Average per Mcfe	Average per Mcfe	$	4.40	$	2.32	Average per Mcfe	$	7.44	$	4.40

Price impact of cash-settled derivatives:	Price impact of cash-settled derivatives:					Price impact of cash-settled derivatives:
Oil (per Bbl)	Oil (per Bbl)	$	(16.17)	$	24.75	Oil (per Bbl)	$	(36.28)	$	(16.17)
Natural gas (per Mcf)	Natural gas (per Mcf)	(0.08)		0.55		Natural gas (per Mcf)	(1.84)		(0.08)
Natural gas liquids (per Bbl)	Natural gas liquids (per Bbl)	(2.45)		—		Natural gas liquids (per Bbl)	(6.25)		(2.45)
Average per Mcfe	Average per Mcfe	$	(0.36)	$	0.90	Average per Mcfe	$	(2.25)	$	(0.36)

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)	$	42.91	$	62.26	Oil (per Bbl)	$	64.69	$	42.91
Natural gas (per Mcf)	Natural gas (per Mcf)	3.77		2.38		Natural gas (per Mcf)	4.34		3.77
Natural gas liquids (per Bbl)	Natural gas liquids (per Bbl)	19.50		11.40		Natural gas liquids (per Bbl)	31.03		19.50
Average per Mcfe	Average per Mcfe	$	4.04	$	3.23	Average per Mcfe	$	5.19	$	4.04

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

For the six months ended June 30, ~~2021~~2022 and ~~2020,~~2021, the Company recorded net losses of ~~$64.3~~$161.2 million and ~~net gains of $79.8~~$64.3 million from our derivatives activities, respectively. Additionally for the six months ended June 30, 2022, we recorded net losses of $1.5 million related to valuation changes from our 2021 WTI Contingency Payout. 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 — Six Months Ended June 30, ~~2021~~2022 and Six Months Ended June 30, ~~2020~~2021

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


Costs and Expenses	Costs and Expenses	Six Months Ended June 30, 2021		Six Months Ended June 30, 2020		Costs and Expenses	Six Months Ended June 30, 2022		Six Months Ended June 30, 2021
General and administrative, net	General and administrative, net	$	9,616	$	12,093	General and administrative, net	$	10,497	$	9,616
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	29,431		37,156		Depreciation, depletion, and amortization	47,595		29,431
Accretion of asset retirement obligations	Accretion of asset retirement obligations	148		173		Accretion of asset retirement obligations	200		148
Lease operating expenses	Lease operating expenses	11,789		10,812		Lease operating expenses	19,395		11,789
Workovers	Workovers	90		—		Workovers	649		90
Transportation and gas processing	Transportation and gas processing	11,262		11,197		Transportation and gas processing	13,121		11,262
Severance and other taxes	Severance and other taxes	7,066		5,001		Severance and other taxes	17,602		7,066
Interest expense, net	Interest expense, net	14,454		16,433		Interest expense, net	14,459		14,454
Write-down of oil and gas properties		—		355,948

General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were ~~$0.27~~$0.25 and ~~$0.36~~$0.27 for the six months ended June 30, ~~2021~~2022 and ~~2020,~~2021, respectively. The ~~decrease per Mcfe was due to higher production while the decrease~~increase in costs was primarily due to ~~lower~~higher salaries and burdens ~~professional fees~~ and ~~temporary labor~~higher legal and professional fees. Included in general and administrative expenses is ~~$2.3~~$2.7 million and ~~$2.4~~$2.3 million in share-based compensation for the six months ended June 30, ~~2021~~2022 and ~~2020,~~2021, respectively.

Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were ~~$0.83~~$1.13 and ~~$1.10~~$0.83 for the six months ended June 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.~~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 ~~$0.33~~$0.48 and ~~$0.32~~$0.33 for the six months ended June 30, ~~2021~~2022 and ~~2020,~~2021, respectively. The increase in costs was primarily due to higher compression, chemicals and ~~salt water disposal costs, partially offset by lower treating and labor~~workover costs.

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

Severance and Other Taxes. These expenses on a per-Mcfe basis were ~~$0.20~~$0.42 and ~~$0.15~~$0.20 for the six months ended June 30, ~~2021~~2022 and ~~2020,~~2021, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately ~~4.5%~~5.6% and ~~6.4%~~4.5% for the ~~three~~six months ended June 30, ~~2021~~2022 and ~~2020,~~2021, respectively.

Interest. Our gross interest cost was $14.5 million ~~and $16.4 million~~ for both the six months ended June 30, 2022 and 2021, ~~and 2020,~~ respectively. ~~The decrease in gross interest cost is primarily due to decreased borrowings.~~ There were no capitalized interest costs for the six months ended June 30, ~~2021 or 2020.~~2022 and 2021.

~~Write-down~~Income Taxes. The Company recorded an income tax provision of ~~oil and gas properties. Due to the effects of pricing and timing of projects,~~$1.6 million for the six months ended June 30, ~~2020, we reported~~2022 primarily attributable to a ~~non-cash impairment write-down, on~~deferred federal income tax expense and state deferred income tax expense. The benefit is a ~~pre-tax basis,~~product of ~~$355.9 million on our oil and natural gas properties.~~the overall forecasted annual effective tax rate applied to the year to date income. There was no ~~impairment~~income tax expense or benefit for the six months ended June 30, 2021.

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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 allied producing countries with respect to oil production levels and announcements of potential changes in such levels;

~~• 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;~~

~~• 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;~~

~~• counterparty credit risk;~~

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

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~~• 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 June 30, ~~2021,~~2022, we had a combined ~~$398.0~~$644.0 million drawn under our Credit Facility and our Second Lien, which bear floating rates of interest and therefore are susceptible to interest rate fluctuations. These variable interest rate borrowings are also impacted by changes in short-term interest rates. A hypothetical one percentage point increase in interest rates on our borrowings outstanding under our Credit Facility and Second Lien at June 30, ~~2021~~2022 would increase our annual interest expense by ~~$4.0~~$6.4 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 June 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.~~2021 and “Part II, Item 1A. Risk Factors” included in our Quarterly Report on Form 10-Q for the period ended March 31, 2022. 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.

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

~~None.~~Except as previously disclosed in a Current Report on Form 8-K, no unregistered sales of our common stock were made during the quarterly period ended June 30, 2022.

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Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

On August 3, 2021, SilverBow acquired from San Isidro Energy Company II, LLC. additional working interest in 12 wells that SilverBow currently operates and additional Eagle Ford La Mesa assets and acreage in Webb County for total aggregate consideration of approximately $24 million, consisting of 516,675 shares of common stock (“Shares”) and $13 million in cash. The issuance of the Shares was completed in reliance upon the exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), provided by Section 4(a)(2) thereof as transactions by an issuer not involving any public offering. SilverBow has agreed to use reasonable efforts to prepare and file a registration statement under the Securities Act to permit resale of the Shares.Not applicable.

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Item 6. Exhibits.

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


3.1			First Amended and Restated Certificate of Incorporation of SilverBow Resources, Inc., effective May 5, 2017 (incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.'s Form 10-Q filed May 8, 2017, File No. 001-08754).
3.2			First Amended and Restated Bylaws of SilverBow Resources, Inc., effective May 5, 2017 (incorporated by reference as Exhibit 3.2 to SilverBow Resources, Inc.'s Form 10-Q filed May 8, 2017, File No. 001-08754).
10.1			~~Seventh~~Purchase and Sale Agreement, dated April 13, 2022, between SilverBow Resources, Inc. and SilverBow Resources Operating, LLC and Sundance Energy, Inc., Armadillo E&P, Inc. and SEA Eagle Ford, LLC (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed April 14, 2022, File No. 001-08754).
10.2			Voting Agreement, dated April 13, 2022, between SilverBow Resources, Inc. and SVMF 71 LLC (incorporated by reference as Exhibit 10.2 to SilverBow Resources, Inc.’s Form 8-K filed April 14, 2022, File No. 001-08754).
10.3			T hird Amendment to SilverBow Resources, Inc. 2016 Equity Incentive Plan, effective May 17, 2022 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed May 17, 2022, File No. 001-08754).
10.4			N inth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement ~~effective~~dated as of April ~~16, 2021,~~12, 2022, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Form 8-K filed April ~~19, 2021,~~13, 2022, File No. 001-08754).
~~10.2+~~10.5			~~Form~~T enth Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement dated as of ~~Cash Incentive Award Agreement – Officers 2021~~June 22, 2022, by and among SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto (incorporated by reference as Exhibit ~~10.4~~10.1 to SilverBow Resources, Inc.’s Form ~~10-Q~~8-K filed ~~May 6, 2021,~~June 24, 2022, File No. 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 June 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" for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

+Management contract or compensatory plan or arrangement.

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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:

August ~~5, 2021~~4, 2022

By:

/s/ Christopher M. Abundis

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

Date:

August ~~5, 2021~~4, 2022

By:

/s/ W. Eric Schultz

W. Eric Schultz
Controller

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Oil Derivative Contracts (New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) Settlements)	Total Volumes (Bbls)(1)	Weighted-Average Price
2021 Contracts
3Q21	30,000	$	70.75
3Q21 (2)	12,000	$	72.76
4Q21	81,250	$	66.69
2022 Contracts
1Q22	45,000	$	63.37
2Q22	45,500	$	62.00
3Q22	46,000	$	60.81
4Q22	46,000	$	59.75