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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

of the Securities Exchange Act of 1934

For the quarterly period ended ~~September~~March 3031, ~~2023~~2024

Commission File Number 1-8754

SILVERBOW RESOURCES, INC.

(Exact Name of Registrant as Specified in Its Charter)


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

920 Memorial City Way, Suite 850

Houston, Texas 77024

(281) 874-2700

(Address and telephone number of principal executive offices)

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


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

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


Yes			þ			No			o

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


Yes			þ			No			o

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

Large Accelerated Filer

Accelerated Filer

Non-Accelerated Filer

Smaller Reporting Company

Emerging Growth Company

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


o

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


Yes			o			No			þ

Indicate 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) 25,~~429~~538,~~610~~487 Shares outstanding at ~~October~~April 2726, ~~2023~~2024

SILVERBOW RESOURCES, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED ~~SEPTEMBER~~MARCH 3031, ~~2023~~2024

INDEX

		Page
Part I	FINANCIAL INFORMATION
Item 1.	Condensed Consolidated Financial Statements
	Condensed Consolidated Balance Sheets	6
	Condensed Consolidated Statements of Operations	7
	Condensed Consolidated Statements of Stockholders’ Equity	98
	Condensed Consolidated Statements of Cash Flows	109
	Notes to Condensed Consolidated Financial Statements	1110
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3530
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4536
Item 4.	Controls and Procedures	4637
Part II	OTHER INFORMATION
Item 1.	Legal Proceedings	4738
Item 1A.	Risk Factors	4738
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4838
Item 3.	Defaults Upon Senior Securities	4838
Item 4.	Mine Safety Disclosures	4939
Item 5.	Other Information	4939
Item 6.	Exhibits	4939
SIGNATURES		5140

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,” “should” 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:

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

• risks related to ~~the~~ recently ~~announced~~completed ~~acquisition~~acquisitions ~~of oil~~ and ~~gas~~integration ~~assets~~of ~~from~~these ~~Chesapeake Exploration~~acquisitions, ~~L.L.C.,~~including ~~Chesapeake~~the ~~Operating,~~acquisition ~~L.L.C., Chesapeake Energy Marketing, L.L.C. and Chesapeake Royalty, L.L.C.~~ (~~collectively,~~ the “~~Chesapeake~~South ~~Sellers~~Texas Acquisition”), including the risk that the transaction will not be completed on the timeline or terms currently contemplated, risks related to the ability to obtain any necessary consents or approvals, the risk that the benefits of ~~the~~oil ~~transaction may not be fully realized or may take longer to realize than expected, the risk that the costs of the acquisition will be significant~~ and ~~the~~gas ~~risk~~assets ~~that~~in ~~management~~South ~~attention will be diverted to transaction-related issues~~Texas;

•volatility ~~risks~~in ~~related~~oil, tonatural ~~recently~~gas ~~completed acquisitions~~ and ~~integration~~natural ofgas ~~these~~liquids ~~acquisitions~~prices;

•ability ~~volatility~~to inobtain ~~natural~~permits ~~gas, oil~~ and ~~natural~~government ~~gas liquids prices~~approvals;

•our borrowing capacity, future covenant compliance, cash flow and liquidity, including our ability to ~~obtain~~satisfy ~~permits~~our ~~and~~short ~~government~~or ~~approvals~~long-term liquidity needs;

•asset ~~our~~disposition ~~borrowing~~efforts ~~capacity,~~or ~~future~~the ~~covenant~~timing ~~compliance, cash flow and liquidity, including our ability to satisfy our short~~ or ~~long-term~~outcome ~~liquidity needs~~thereof;

•ongoing ~~asset~~and ~~disposition~~prospective ~~efforts~~joint orventures, their structures and substance, and the ~~timing~~likelihood of their finalization or ~~outcome~~the timing thereof;

•the ~~ongoing and prospective joint ventures~~amount, ~~their~~nature ~~structures~~ and ~~substance,~~timing ~~and the likelihood~~ of ~~their~~capital ~~finalization~~expenditures, orincluding ~~the~~future ~~timing~~development ~~thereof~~costs;

• ~~the amount~~timing, ~~nature~~cost and ~~timing~~amount of ~~capital~~future ~~expenditures,~~production ~~including~~of ~~future~~oil ~~development~~and ~~costs~~natural gas;

•availability ~~timing,~~of ~~cost~~drilling and ~~amount~~production ofequipment ~~future~~or ~~production~~availability of oil ~~and~~field ~~natural gas~~labor;

• availability, ofcost ~~drilling~~ and ~~production~~terms ~~equipment or availability~~ of ~~oil field labor~~capital;

•timing ~~availability,~~and ~~cost~~successful drilling and ~~terms~~completion of ~~capital~~wells;

•availability ~~timing~~ and ~~successful~~cost ~~drilling~~for transportation and ~~completion~~storage capacity of ~~wells~~oil and natural gas;

•costs ~~availability~~of ~~and~~exploiting ~~cost for transportation~~ and ~~storage~~developing ~~capacity~~our ofproperties ~~oil~~ and ~~natural~~conducting ~~gas~~other operations;

•competition ~~costs~~in ofthe ~~exploiting~~oil and ~~developing~~natural ~~our~~gas ~~properties and conducting other operations~~industry;

•general ~~competition~~economic and political conditions, including inflationary pressures, further increases in interest rates, a general economic slowdown or recession, instability in financial institutions, political tensions and war (including future developments in the ~~oil~~ongoing conflicts in Ukraine and ~~natural~~the ~~gas~~Middle ~~industry~~East);

•the ~~general~~severity ~~economic~~ and ~~political~~duration ~~conditions,~~of ~~including~~world ~~inflationary~~health ~~pressures~~events, ~~further~~including ~~increases~~health incrises ~~interest~~and ~~rates~~pandemics, arelated ~~general~~ economic ~~slowdown or recession~~repercussions, ~~instability~~including disruptions in ~~financial~~the ~~institutions,~~oil ~~political tensions~~ and ~~war~~gas ~~(including~~industry, ~~future~~supply ~~developments~~chain indisruptions, ~~the ongoing conflicts in Ukraine~~ and ~~the~~operational ~~Gaza Strip)~~challenges;

•opportunities ~~the~~to ~~severity~~monetize and duration of world health events, including health crises and pandemics, related economic repercussions, including disruptions in the oil and gas industry, supply chain disruptions, and operational challenges including remote work arrangements and protecting the health and well-being of our employeesassets;

•our ~~opportunities~~ability to ~~monetize~~execute ~~assets~~on strategic initiatives, including acquisitions;

•effectiveness of our ~~ability~~risk tomanagement ~~execute~~activities, onincluding ~~strategic~~hedging ~~initiatives~~strategy;

•counterparty ~~effectiveness~~and ofcredit ~~our~~market risk ~~management activities including hedging strategy~~;

•pending ~~counterparty~~legal and ~~credit~~environmental ~~market~~matters, ~~risk~~including potential impacts on our business related to climate change and related regulations;

•the impact of shareholder activism and any changes in composition of our Board of Directors (the “Board”);

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

•current and future governmental regulation and taxation of the oil and natural gas industry, including changes in connection with U.S. elections in 2024;

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

•uncertainty ~~pending~~regarding ~~legal and environmental matters, including potential impacts on~~ our ~~business~~future ~~related~~operating toresults; ~~climate change~~ and ~~related regulations;~~

•other ~~actions~~risks byand ~~third~~uncertainties ~~parties~~described in this Quarterly Report on Form 10-Q, ~~including~~our ~~customers~~Annual Report on Form 10-K for the year ended December 31, ~~service~~2023 ~~providers~~and our other filings with the Securities and ~~shareholders;~~Exchange Commission (“SEC”).

•Many ~~current~~of the foregoing risks and ~~future~~uncertainties, ~~governmental~~as ~~regulation~~well as risks and ~~taxation~~uncertainties that are currently unknown to us, are, and may be, exacerbated by geopolitical events and wars, increasing economic uncertainty, recessionary and inflationary pressures and any consequent worsening of the ~~oil~~global business and ~~natural~~economic ~~gas~~environment. ~~industry;~~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 on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2023, subsequent Quarterly Reports on Form 10-Q, or other SEC filings occur, or should underlying assumptions prove incorrect, actual results and plans could differ materially from those expressed in any forward-looking statements.

•All ~~developments~~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 ~~world~~or ~~oil~~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” and ~~natural~~in ~~gas~~other ~~markets~~disclosures in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2023 and in ~~oil~~subsequent Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and ~~natural~~our ~~gas~~other filings with the SEC. These cautionary statements qualify all forward-~~producing~~looking ~~countries;~~statements attributable to us or persons acting on our behalf.

• 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, 2022 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 geopolitical events and wars, increasing economic uncertainty, recessionary and inflationary pressures 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 on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2022, subsequent Quarterly Reports on Form 10-Q, or other SEC filings 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, 2022 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.

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PART I. FINANCIAL INFORMATION

Condensed Consolidated Balance Sheets (Unaudited)

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

	September 30, 2023		December 31, 2022
	March 31, 2024		December 31, 2023
ASSETS
Current Assets:
Cash and cash equivalents	$	1,~~697~~446	$	~~792~~969
Accounts receivable, net	80125,~~202~~459		89138,~~714~~343
Fair value of commodity derivatives	5089,~~189~~535		52116,549
Other current assets	35,~~825~~652		25,~~671~~590
Total Current Assets	~~135~~222,~~913~~092		~~145~~261,~~726~~451
Property and Equipment:
Property and equipment, full cost method, including $27,821 and $16,272, respectively, of unproved property costs not being amortized at the end of each period	2,861,267		2,529,223
Property and equipment, full cost method, including $30,899 and $28,375, respectively, of unproved property costs not being amortized at the end of each period	3,709,469		3,597,160
Less – Accumulated depreciation, depletion, amortization & impairment	(1,~~151~~315,~~141~~364)		(1,~~004~~223,~~044~~241)
Property and Equipment, Net	12,~~710~~394,~~126~~105		12,~~525~~373,~~179~~919
Right of use assets	1020,~~085~~658		12,~~077~~888
Fair value of long-term commodity derivatives	1429,~~180~~432		2455,~~172~~114
Deposit and other fees for oil and gas property transaction	52,564		—
Other long-term assets	28,876		31,090
Other long-term assets	7,581		9,208
Total Assets	$	2,695,163	$	2,734,462
Total Assets	$	1,930,449	$	1,716,362
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	74143,~~731~~684	$	6098,~~200~~816
Fair value of commodity derivatives	32,752		40,796
Deferred acquisition liability	50,000		50,000
Accrued capital costs	56,424		56,465
Fair value of commodity derivatives	26,333		5,509
Accrued interest	2,976		2,665
Accrued capital costs	42,114		31,900
Current lease liability	5,507		8,553
Current portion of long-term debt	37,500		28,125
Undistributed oil and gas revenues	22,462		27,160
Accrued interest	8,325		9,668
Total Current Liabilities	194,852		195,839
Current lease liability	7,765		4,001
Long-term debt, net	645,096		688,531
Undistributed oil and gas revenues	37,754		20,425
Non-current lease liability	4,604		3,775
Total Current Liabilities	353,475		248,444
Deferred tax liabilities	49,033		16,141
Long-term debt, net of current portion	1,039,469		1,173,766
Asset retirement obligations	9,840		9,171
Non-current lease liability	12,955		8,899
Fair value of long-term commodity derivatives	21,560		7,738
Deferred tax liabilities	94,077		99,227
Other long-term liabilities	922		3,588
Asset retirement obligations	11,913		11,584
Fair value of long-term commodity derivatives	8,110		2,504
Other long-term liabilities	—		710
Commitments and Contingencies (Note 11)
Stockholders' Equity:
Preferred stock, $0.01 par value, 10,000,000 shares authorized, none issued	—		—
Common stock, $0.01 par value, 40,000,000 shares authorized, 25,914,823 and 22,663,135 shares issued, respectively, and 25,429,517 and 22,309,740 shares outstanding, respectively	259		227
Common stock, $0.01 par value, 40,000,000 shares authorized, 26,027,103 and 25,914,956 shares issued, respectively, and 25,523,808 and 25,429,610 shares outstanding, respectively	260		259
Additional paid-in capital	~~677~~681,~~473~~099		~~576~~679,~~118~~202
Treasury stock, held at cost, 485,306 and 353,395 shares, respectively	(10,616)		(7,534)
Treasury stock, held at cost, 503,295 and 485,346 shares, respectively	(11,151)		(10,617)
Retained earnings	~~337~~504,~~426~~956		~~222~~520,~~768~~484
Total Stockholders’ Equity	1,~~004~~175,~~542~~164		~~791~~1,~~579~~189,328
Total Liabilities and Stockholders’ Equity	$	12,~~930~~695,~~449~~163	$	12,~~716~~734,~~362~~462
See accompanying Notes to Condensed Consolidated Financial Statements.

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Condensed Consolidated Statements of Operations (Unaudited)

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

	Three Months Ended September 30, 2023		Three Months Ended September 30, 2022
	Three Months Ended March 31, 2024		Three Months Ended March 31, 2023
Revenues:
Revenues	$	256,680	$	139,954
Oil and gas sales	$	173,963	$	242,181
Operating Expenses:
General and administrative, net	48,~~438~~791		47,~~343~~664
Depreciation, depletion, and amortization	5392,~~186~~103		4143,~~501~~998
Accretion of asset retirement obligations	~~254~~316		~~166~~224
Lease operating expenses	2231,~~678~~825		1720,~~701~~560
Workovers	~~672~~610		~~284~~779
Transportation and gas processing	1335,~~710~~199		911,~~662~~520
Severance and other taxes	1016,~~407~~212		129,~~581~~385
Total Operating Expenses	~~105~~185,~~345~~056		8694,~~238~~130
Operating Income	6871,~~618~~624		~~155~~45,~~943~~824
Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net	(5456,~~639~~078)		492,~~832~~249
Interest expense, net	(1936,~~811~~017)		(1216,~~173~~745)
Other income (expense), net	~~112~~156		5(24)
Income (Loss) Before Income Taxes	(520,~~720~~315)		~~148~~121,~~607~~304
Provision (Benefit) for Income Taxes	(~~949~~4,787)		626,~~066~~812
Net Income (Loss)	$	(415,~~771~~528)	$	~~142~~94,~~541~~492
Per Share Amounts:
Basic Earnings (Loss) Per Share	$	(0.2161)	$	64.3921
Diluted Earnings (Loss) Per Share	$	(0.2161)	$	64.2917
Weighted-Average Shares Outstanding - Basic	2225,~~985~~445		22,~~308~~440
Weighted-Average Shares Outstanding - Diluted	2225,~~985~~445		22,~~669~~634
See accompanying Notes to Condensed Consolidated Financial Statements.

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Condensed Consolidated Statements of Operations (Unaudited)

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

	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022
Revenues:
Oil and gas sales	$	440,317	$	554,442
Operating Expenses:
General and administrative, net	17,421		14,840
Depreciation, depletion, and amortization	147,037		89,096
Accretion of asset retirement obligations	718		366
Lease operating expenses	62,417		37,095
Workovers	2,263		933
Transportation and gas processing	37,001		22,784
Severance and other taxes	28,563		30,183
Total Operating Expenses	295,420		195,297
Operating Income	144,897		359,145
Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net	57,604		(157,816)
Interest expense, net	(54,746)		(26,632)
Other income (expense), net	117		57
Income (Loss) Before Income Taxes	147,872		174,754
Provision (Benefit) for Income Taxes	33,214		7,678
Net Income (Loss)	$	114,658	$	167,076
Per Share Amounts:
Basic Earnings (Loss) Per Share	$	5.06	$	8.85
Diluted Earnings (Loss) Per Share	$	5.02	$	8.69
Weighted-Average Shares Outstanding - Basic	22,677		18,885
Weighted-Average Shares Outstanding - Diluted	22,852		19,237
See accompanying Notes to Condensed Consolidated Financial Statements.

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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, 2021	$	168	$	413,017	$	(2,984)	$	(117,669)	$	292,532
Purchase of treasury shares (96,012 shares)	—		—		(2,462)		—		(2,462)
Treasury shares pursuant to purchase price adjustment (41,191 shares)	—		—		(1,146)		—		(1,146)
Vesting of share-based compensation (318,390 shares)	3		(3)		—		—		—
Issuance pursuant to acquisition (489 shares)	—		12		—		—		12
Share-based compensation	—		1,101		—		—		1,101
Net Loss	—		—		—		(64,255)		(64,255)
Balance, March 31, 2022	$	171	$	414,127	$	(6,592)	$	(181,924)	$	225,782
Stock options exercised (4,497 shares)	—		39		—		—		39
Purchase of treasury shares (16,485 shares)	—		—		(503)		—		(503)
Vesting of share-based compensation (57,355 shares)	1		(1)		—		—		—
Issuance pursuant to acquisition (5,448,472 shares)	55		157,338		—		—		157,393
Share-based compensation	—		1,756		—		—		1,756
Net Income	—		—		—		88,790		88,790
Balance, June 30, 2022	$	227	$	573,259	$	(7,095)	$	(93,134)	$	473,257
Stock options exercised (11,087 shares)	—		387		—		—		387
Purchase of treasury shares (7,853 shares)	—		—		(432)		—		(432)
Treasury shares pursuant to purchase price adjustment (184 shares)	—		—		(7)		—		(7)
Share-based compensation	—		1,239		—		—		1,239
Net income	—		—		—		142,541		142,541
Balance, September 30, 2022	$	227	$	574,885	$	(7,534)	$	49,407	$	616,985
Balance, December 31, 2022	$	227	$	576,118	$	(7,534)	$	222,768	$	791,579
Purchase of treasury shares (126,240 shares)	—		—		(2,945)		—		(2,945)
Vesting of share-based compensation (418,518 shares)	4		(4)		—		—		—
Share-based compensation	—		1,179		—		—		1,179
Net Income	—		—		—		94,492		94,492
Balance, March 31, 2023	$	231	$	577,293	$	(10,479)	$	317,260	$	884,305
Purchase of treasury shares (5,310 shares)	—		—		(121)		—		(121)
Balance, December 31, 2023	$	259	$	679,202	$	(10,617)	$	520,484	$	1,189,328
Vesting of share-based compensation (21,134 shares)	—		—		—		—		—
Purchase of treasury shares (17,949 shares)	—		—		(534)		—		(534)
Share-based compensation	—		1,524		—		—		1,524
Vesting of share-based compensation (112,147 shares)	1		(1)		—		—		—
Net Income	—		—		—		24,937		24,937
Share-based compensation	—		1,898		—		—		1,898
Balance, June 30, 2023	$	231	$	578,817	$	(10,600)	$	342,197	$	910,645
Net Loss	—		—		—		(15,528)		(15,528)
Purchase of treasury shares (361 shares)	—		—		(16)		—		(16)
Balance, March 31, 2024	$	260	$	681,099	$	(11,151)	$	504,956	$	1,175,164
Vesting of share-based compensation (1,225 shares)	—		—		—		—		—
Issuance of common stock (2,810,811 shares)	28		97,105		—		—		97,133
Share-based compensation	—		1,551		—		—		1,551
Net Loss	—		—		—		(4,771)		(4,771)
Balance, September 30, 2023	$	259	$	677,473	$	(10,616)	$	337,426	$	1,004,542
See accompanying Notes to Condensed Consolidated Financial Statements.

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Condensed Consolidated Statements of Cash Flows (Unaudited)

SilverBow Resources, Inc. and Subsidiary (in thousands)

	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022
	Three Months Ended March 31, 2024		Three Months Ended March 31, 2023
Cash Flows from Operating Activities:
Net income (loss)	$	~~114~~(15,~~658~~528)	$	~~167~~94,~~076~~492
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	~~147~~92,~~037~~103		8943,~~096~~998
Accretion of asset retirement obligations	~~718~~316		~~366~~224
Deferred income taxes	32(5,~~892~~150)		726,~~496~~612
Share-based compensation	41,~~043~~830		31,~~901~~124
(Gain) Loss on derivatives, net	~~(57~~56,~~604)~~078		~~157~~(92,~~816~~249)
Cash settlement (paid) received on derivatives	7038,~~670~~371		~~(182~~18,~~058)~~699
Settlements of asset retirement obligations	(~~481~~2)		(473)
Write down of debt issuance cost	—		350
Other, net	3,362		756
Other, net	2,028		(6,425)
Change in operating assets and liabilities:
(Increase) decrease in accounts receivable and other current assets	9(5,~~129~~374)		~~(47~~30,~~320)~~687
Increase (decrease) in accounts payable and accrued liabilities	(524,~~320)~~557		20(24,~~260~~504)
Increase (decrease) in income taxes payable	~~321~~465		~~(21)~~300
Increase (decrease) in accrued interest	~~311~~(1,343)		~~1,688~~(441)
Net Cash Provided by (Used in) Operating Activities	~~318~~189,~~402~~685		~~212~~99,~~178~~695
Cash Flows from Investing Activities:
Additions to property and equipment	(~~316~~80,~~003~~225)		(~~163~~111,~~567~~285)
Acquisition of oil and gas properties, net of purchase price adjustments	~~(382)~~11,821		(~~293~~1,~~880~~090)
Deposit and other fees for oil and gas property transaction	(51,163)		—
Proceeds from the sale of property and equipment	5,730		—
Proceeds from the sale of property and equipment	—		4,415
Net Cash Provided by (Used in) Investing Activities	(62,674)		(112,375)
Payments on property sale obligations	—		(750)
Net Cash Provided by (Used in) Investing Activities	(367,548)		(453,782)
Cash Flows from Financing Activities:
Proceeds from bank borrowings	~~334~~128,000		~~679~~121,000
Payments of bank borrowings	(~~378~~254,000)		(~~426~~104,000)
Net proceeds from issuances of common stock	97,133		—
Purchase of treasury shares	(534)		(2,945)
Net proceeds from stock options exercised	—		39
Net Cash Provided by (Used in) Financing Activities	(126,534)		14,055
Purchase of treasury shares	(3,082)		(3,404)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	477		1,375
Payments of debt issuance costs	—		(7,228)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	8,729		792
Net Cash Provided by (Used in) Financing Activities	50,051		242,407
Cash, Cash Equivalents and Restricted Cash at End of Period	$	9,206	$	2,167
Net Increase (Decrease) in Cash and Cash Equivalents	905		803
Cash and Cash Equivalents at Beginning of Period	792		1,121
Cash and Cash Equivalents at End of Period	$	1,697	$	1,924
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for interest, net of amounts capitalized	$	52,170	$	22,701
Cash paid during period for interest	$	34,072	$	16,434
Non-cash Investing and Financing Activities:
Changes in capital accounts payable and capital accruals	$	1329,~~363~~194	$	60(3,~~595~~097)
Accrued other fees for oil and gas property transaction	$	(1,401)	$	—
Non-cash equity consideration for acquisitions	$	—	$	(156,259)
See accompanying Notes to Condensed Consolidated Financial Statements.

109

Table of Contents

Notes to Condensed Consolidated Financial Statements (Unaudited)

SilverBow Resources, Inc. and Subsidiary

(1) General Information

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

Being a committed and long-term operator in South Texas, 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 in the effort 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 unaudited 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, ~~2022~~2023.

(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 and Austin Chalk 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.

Stockholder Rights Agreement. On September 20, 2022, the Board adopted a stockholder rights agreement (the “Rights Agreement”) and declared a dividend distribution of one right (each, a “Right” and together with all such rights distributed or issued pursuant to the Rights Agreement, dated as of September 20, 2022, by and between the Company and American Stock Transfer & Trust Company, LLC, as rights agent, the “Rights”) for each outstanding share of Company common stock to holders of record on October 5, 2022. In the event that a person or group acquires beneficial ownership of 15% or more of the Company’s then-outstanding common stock, subject to certain exceptions, each Right would entitle its holder (other than such person or members of such group) to purchase additional shares of Company common stock at a substantial discount to the public market price. In addition, at any time after a person or group acquires beneficial ownership of 15% or more of the outstanding common stock, subject to certain exceptions, the Board may direct the Company to exchange the Rights (other than Rights owned by such person or certain related parties, which will have become null and void), in whole or in part, at an exchange ratio of one share of common stock per Right (subject to adjustment). While in effect, the Rights Agreement could make it more difficult for a third party to acquire control of the Company or a large block of the common stock of the Company without the approval of the Board. On May 16, 2023, the Company and the rights agent entered into an Amendment to the Rights Agreement (the “Amendment”) that amended the Rights Agreement to extend the expiration date until the close of business on the first day following the date of the Company’s first annual meeting of its stockholders that occurs after (but not on) the date of the Amendment. The Rights Agreement, as amended, will expire on the earliest of (a) 5:00 p.m., New York City time, on the first business day after the 2024 annual stockholders’ meeting, (b) the time at which the Rights are redeemed and (c) the time at which the Rights are exchanged in full.

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

~~Through~~In ~~October~~April 312024, ~~2023,~~ the Company entered into ~~additional~~a ~~derivative~~non-cash ~~contracts~~exchange agreement with a third party to receive approximately 7,700 net acres and working interest in multiple wells in La Salle and McMullen counties. The ~~following~~Company ~~tables~~will ~~summarize~~transfer ~~the~~approximately ~~weighted-average~~5,100 ~~prices~~net asacres ~~well~~and asworking ~~future~~interest ~~production~~in ~~volumes~~13 ~~for~~wells ~~our~~in ~~future~~DeWitt, ~~derivative~~Lavaca ~~contracts~~and ~~entered~~McMullen ~~into~~counties. ~~after~~The ~~September 30,~~exchange ~~2023:~~is subject to customary purchase price adjustments.

Oil Derivative Contracts(NYMEX WTI Settlements)	Total Volumes(Bbls)	Weighted-Average Price
Swap Contracts
2024 Contracts
1Q24	91,000	$	83.40
2Q24	91,000	$	81.31
3Q24	92,000	$	79.63
4Q24	92,000	$	78.21
2025 Contracts
1Q25	90,000	$	76.52
2Q25	91,000	$	75.38
3Q25	92,000	$	74.56
4Q25	92,000	$	73.58
2026 Contracts
1Q26	157,500	$	68.01
2Q26	136,500	$	67.98
3Q26	110,400	$	67.94
4Q26	156,150	$	68.60

Through April 30, 2024, 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 March 31, 2024:

Oil Basis Swaps(Argus Cushing (WTI) and Magellan East Houston)	Total Volumes(MMBtu)	Weighted-Average Price
Oil Derivative Contracts(NYMEX WTI Settlements)	Total Volumes(Bbls)	Weighted-Average Price
2023 Contracts
Swap Contracts
4Q23	61,000	$	0.90
2024 Contracts
3Q24	92,000	$	80.47
4Q24	92,000	$	80.47
2025 Contracts
1Q25	90180,000	$	176.7500
2Q25	91182,000	$	1.75.18
3Q25	92184,000	$	174.7546
4Q25	92184,000	$	173.7585
Calendar Monthly Roll Differential Swaps
2023 Contracts
4Q23	61,000	$	2.40
2025 Contracts
1Q25	90,000	$	0.50
2Q25	91,000	$	0.50
3Q25	92,000	$	0.50
4Q25	92,000	$	0.50


Oil Basis Swaps (Argus Cushing (WTI) and Magellan East Houston)	Total Volumes (MMBtu)	Weighted-Average Price
2025 Contracts
1Q25	180,000	$	1.80
2Q25	182,000	$	1.80
3Q25	184,000	$	1.80
4Q25	184,000	$	1.80
Calendar Monthly Roll Differential Swaps
2025 Contracts
1Q25	180,000	$	0.50
2Q25	182,000	$	0.50
3Q25	184,000	$	0.50
4Q25	184,000	$	0.50


Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
Collar Contracts
2025 Contracts
4Q25	920,000	$	3.50	$	4.38

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Natural Gas Derivative Contracts(NYMEX Henry Hub Settlements)	Total Volumes(MMBtu)	Weighted-Average Price
Natural Gas Basis Derivative Swaps(East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes(MMBtu)	Weighted-Average Price
Swap Contracts
2024 Contracts
1Q24	1,820,000	$	3.66
4Q24	920,000	$	(0.49)
2Q24	2,430,000	$	3.31
3Q24	2,760,000	$	3.46
4Q24	2,760,000	$	3.75
2025 Contracts
1Q25	23,~~700~~600,000	$	4(0.2030)
2Q25	23,~~730~~640,000	$	3(0.7530)
3Q25	23,~~760~~680,000	$	3(0.8930)
4Q25	13,~~540~~680,000	$	4(0.1130)
2026 Contracts
1Q26	900,000	$	4.56
2Q26	910,000	$	3.53
3Q26	920,000	$	3.73
4Q26	920,000	$	4.19

Natural Gas Basis Derivative Swaps(East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes(MMBtu)	Weighted-Average Price
2024 Contracts
1Q24	910,000	$	(0.21)
2Q24	910,000	$	(0.21)
3Q24	920,000	$	(0.21)
4Q24	920,000	$	(0.21)
2025 Contracts
1Q25	900,000	$	(0.23)
2Q25	910,000	$	(0.23)
3Q25	920,000	$	(0.23)
4Q25	920,000	$	(0.23)

NGL Swaps (Mont Belvieu)	Total Volumes(Bbls)	Weighted-Average Price
2024 Contracts
1Q24	91,000	$	24.25
2Q24	91,000	$	24.25
3Q24	92,000	$	24.25
4Q24	92,000	$	24.25

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

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

13•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 (as defined below) impairment calculation,

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

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

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

•estimates of future costs to develop and produce reserves,

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

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

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

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

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

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

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

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

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

•estimates on future lease obligations.

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

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

Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, such internal costs capitalized totaled $1.~~4 million and $~~1.1 million, respectively. For the nine months ended September 30, 2023 and 2022, such internal costs capitalized totaled $4.1 million and $3.3 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. There was no capitalized interest on our unproved properties for both the three months ended September 30, 2023 and 2022 and the nine months ended September 30, 2023 and 2022.

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and $1.4 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. There was no capitalized interest on our unproved properties for both the three months ended March 31, 2024 and 2023.

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

	September 30, 2023		December 31, 2022
	March 31, 2024		December 31, 2023
Property and Equipment
Proved oil and gas properties	$	23,~~827~~671,~~145~~913	$	23,~~506~~562,~~853~~268
Unproved oil and gas properties	2730,~~821~~899		1628,~~272~~375
Furniture, fixtures and other equipment	6,~~301~~657		6,~~098~~517
Less – Accumulated depreciation, depletion, amortization & impairment	(1,~~151~~315,~~141~~364)		(1,~~004~~223,~~044~~241)
Property and Equipment, Net	$	12,~~710~~394,~~126~~105	$	12,~~525~~373,~~179~~919

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 drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10% and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”).

The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. There was no ceiling test write-down for either of the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022 or the nine months ended September 30,~~ 2023 ~~and 2022~~.

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 based on a broad range of reasonable and forward-looking information including historical losses, current economic conditions, future forecasts and contractual terms. The Company's credit losses based on these assessments are considered immaterial. At September 30, 2023, December 31, 2022 and December 31, 2021, we had an allowance of less than $0.1 million. The allowance has been deducted from the total “Accounts receivable, net” balance on the accompanying condensed consolidated balance sheets.13

At September 30, 2023, our “Accounts receivable, net” balance included $60.4 million for oil and gas sales, $1.9 million due from joint interest owners, $9.1 million for severance tax credit receivables and $8.8 million for other receivables. At December 31, 2022, our “Accounts receivable, net” balance included $70.9 million for oil and gas sales, $5.6 million due from joint interest owners, $4.3 million for severance tax credit receivables and $8.9 million for other receivables. At December 31, 2021, our “Accounts receivable, net” balance included $45.3 million for oil and gas sales, $1.9 million due from joint interest owners, $1.0 million for severance tax credit receivables and $1.5 million for other receivables.

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~~administrative,~~our ~~net,”~~oil onand ~~the~~natural ~~accompanying~~gas ~~condensed~~properties ~~consolidated~~will ~~statements~~occur ofin ~~operations~~the future. ~~The~~ ~~amount~~We ofcannot ~~supervision~~control ~~fees~~and ~~charged~~cannot ~~for~~predict ~~each~~what offuture ~~the~~prices ~~nine~~for ~~months~~oil ~~ended September 30, 2023~~ and ~~2022~~natural ~~did~~gas ~~not~~will ~~exceed~~be; ~~our~~therefore, ~~actual~~we ~~costs~~cannot ~~incurred.~~estimate ~~The~~the ~~total~~ amount of ~~supervision~~any ~~fees~~potential ~~charged~~future tonon-cash ~~the~~write-down ~~wells~~of weour ~~operated~~oil ~~was $3.0 million~~ and ~~$2.8~~natural ~~million~~gas ~~for~~properties ~~the~~due ~~three~~to ~~months~~decreases ~~ended~~in ~~September~~oil ~~30,~~or ~~2023~~natural ~~and~~gas ~~2022,~~prices. ~~respectively~~However, ~~and~~it ~~$8.6~~is ~~million~~reasonably ~~and~~possible ~~$6.1~~that ~~million~~we ~~for~~will ~~the~~record ~~nine~~Ceiling ~~months~~Test ~~ended~~write-downs ~~September~~in ~~30,~~future ~~2023 and 2022, respectively~~periods.

~~Income~~Accounts ~~Taxes~~Receivable, Net. ~~Deferred~~We ~~taxes~~assess ~~are determined based on~~ the ~~estimated~~collectability ~~future~~of ~~tax~~accounts ~~effects~~receivable ofbased ~~differences~~on ~~between~~a ~~the~~broad ~~financial~~range ~~statement~~of reasonable and ~~tax~~forward-looking ~~basis~~information ofincluding ~~assets~~historical ~~and liabilities~~losses, ~~given~~current ~~the~~economic ~~provisions~~conditions, offuture ~~the~~forecasts ~~enacted~~and ~~tax~~contractual ~~laws~~terms. The Company's ~~effective~~credit ~~tax~~losses ~~rate~~based ~~was~~on ~~approximately~~these ~~17%~~assessments ~~and~~are 4%considered ~~for~~immaterial. ~~the~~At ~~three months ended September 30~~March 31, ~~2023 and 2022~~2024, ~~respectively~~December 31, ~~and~~2023 ~~22%~~ and ~~4% for the nine months ended September 30~~December 31, ~~2023 and~~ 2022, ~~respectively.~~we ~~The~~had ~~Company recorded~~ an ~~income~~allowance ~~tax~~for ~~benefit~~credit oflosses ~~$0.9 million and income tax provision~~ of ~~$33.2~~less ~~million~~than ~~for the three and nine months ended September 30, 2023, respectively, and an income tax provision of~~ $60.1 million ~~and $7~~.7 ~~million for the three and nine months ended September 30, 2022, respectively.~~ The ~~tax~~allowance ~~impact~~ for ~~both~~credit ~~periods~~losses ~~was~~has abeen ~~product~~deducted offrom the ~~overall~~total ~~forecasted~~“Accounts ~~annual~~receivable, ~~effective~~net” ~~tax~~balance ~~rate~~on ~~applied to~~ the ~~year~~accompanying tocondensed ~~date~~consolidated ~~income~~balance sheets.

At March 31, 2024, our “Accounts receivable, net” balance included $92.2 million for oil and gas sales, $14.7 million due from joint interest owners, $2.8 million for severance tax credit receivables and $15.8 million for other receivables. At December 31, 2023, our “Accounts receivable, net” balance included $91.9 million for oil and gas sales, $7.0 million due from joint interest owners, $7.2 million for severance tax credit receivables, $18.1 million for accrued purchase price adjustments related to the South Texas Acquisition and $14.1 million for other receivables. At December 31, 2022, our “Accounts receivable, net” balance included $70.9 million for oil and gas sales, $5.6 million for joint interest owners, $4.3 million for severance tax credit receivables and $8.9 million for other receivables.

Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the three months ended March 31, 2024 and 2023 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $5.4 million and $2.7 million for the three months ended March 31, 2024 and 2023, 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. The Company's effective tax rate was approximately 24% and 22% for the three months ended March 31, 2024 and 2023, respectively. The Company recorded an income tax benefit of $4.8 million for the three months ended March 31, 2024 and an income tax provision of $26.8 million for the three months ended March 31, 2023, respectively. The tax impact for both periods was a product of the overall forecasted annual effective tax rate applied to the year-to-date income.

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

Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At ~~September~~March 3031, ~~2023~~2024 and December 31, ~~2022~~2023, 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.

Revenue Recognition. ~~Our~~Substantially ~~reported~~all ~~oil~~of ~~and~~our ~~gas~~revenues ~~sales~~ are ~~comprised~~derived offrom ~~revenues~~sales ~~from~~of 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 September 30, 2023 and 2022 and the nine months ended September 30, 2023 and 2022 (in thousands): 14

	Three Months Ended September 30, 2023		Three Months Ended September 30, 2022		Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022
Oil, natural gas and NGLs sales:
Oil	$	112,456	$	71,811	$	267,263	$	155,566
Natural gas	46,075		150,958		132,802		351,626
NGLs	15,432		19,412		40,252		47,250
Total	$	173,963	$	242,181	$	440,317	$	554,442

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The following table provides information regarding our revenues, including oil and gas sales, by product, reported on the condensed consolidated statements of operations for the three months ended March 31, 2024 and 2023 (in thousands):


	Three Months Ended March 31, 2024		Three Months Ended March 31, 2023
Revenues:
Oil	$	166,704	$	74,655
Natural gas	53,123		52,922
NGLs	36,218		12,377
Marketing	635		—
Total	$	256,680	$	139,954

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

	September 30, 2023		December 31, 2022
	March 31, 2024		December 31, 2023
Trade accounts payable	$	3052,~~708~~924	$	2332,~~660~~225
Accrued operating expenses	1126,~~266~~183		1023,~~572~~104
Accrued compensation costs	37,~~267~~281		410,~~814~~208
Asset retirement obligations – current portion	1,~~578~~597		1,~~284~~576
Accrued non-income based taxes	1310,~~303~~447		43,~~849~~870
Accrued corporate and legal fees	~~181~~119		~~388~~208
WTI contingency payouts - current portion	126,~~537~~759		114,~~600~~282
Payable for settled derivatives	32,~~549~~828		~~6,026~~967
Other payables	9,342		7,007
Other payables(1)	15,546		12,376
Total accounts payable and accrued liabilities	$	74143,~~731~~684	$	6098,~~200~~816

~~Cash~~(1) ~~and~~At ~~Cash~~March 31, ~~Equivalents.~~2024 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~~December 31, ~~which~~2023 atincluded ~~times~~in ~~exceed~~Other ~~federally~~Payables ~~insured~~is ~~limits~~$7.8 million ~~The~~in ~~Company~~payables ~~monitors~~related ~~the~~to ~~financial~~advances ~~condition~~from ofjoint ~~the~~interest ~~financial~~owners ~~institutions~~in ~~and~~connection ~~has~~with ~~experienced~~our noSouth ~~losses~~Texas ~~associated with these accounts~~Acquisition.

~~Treasury~~Cash ~~Stock.~~and ~~Our~~Cash ~~treasury~~Equivalents. ~~stock~~We ~~repurchases~~consider ~~are~~all ~~reported~~highly atliquid ~~cost~~instruments ~~and~~with ~~are~~an ~~included~~initial inmaturity ~~“Treasury~~of ~~stock,~~three ~~held~~months ator ~~cost”~~less onto ~~the~~be ~~accompanying~~cash ~~condensed consolidated balance sheets~~equivalents. ~~For~~These ~~the~~amounts ~~nine~~do ~~months~~not ~~ended~~include ~~September~~cash ~~30,~~balances ~~2023,~~that weare ~~purchased~~contractually ~~131,911~~restricted. ~~treasury~~The ~~shares~~Company tomaintains ~~satisfy~~cash ~~withholding~~and ~~tax~~cash ~~obligations~~equivalent ~~arising~~balances ~~upon~~with ~~the~~major ~~vesting~~financial ofinstitutions, ~~restricted~~which ~~shares.~~at ~~For~~times ~~the~~exceed ~~nine~~federally ~~months~~insured ~~ended~~limits. ~~September~~The ~~30,~~Company ~~2022,~~monitors wethe ~~purchased~~financial ~~120,350~~condition ~~treasury~~of ~~shares~~the tofinancial ~~satisfy~~institutions ~~withholding~~and ~~tax~~has ~~obligations~~experienced ~~arising~~no ~~upon~~losses ~~the~~associated ~~vesting~~with ofthese ~~restricted~~accounts. ~~shares~~The ~~and~~Company ~~received~~did ~~41,375~~not ~~shares~~have inany ~~conjunction~~cash ~~with~~equivalents ~~our~~at ~~post-closing~~March 31, ~~settlement~~2024 ~~for~~and aDecember 31, ~~previously disclosed acquisition~~2023.

~~New~~Restricted ~~Accounting Pronouncements~~Cash. InRestricted ~~June~~cash ~~2016,~~includes ~~the~~amounts ~~Financial~~held ~~Accounting~~in ~~Standards~~escrow Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Credit Losses - Measurement of Credit Losses on Financial Instruments. The standard changes how entities will measure credit losses for most financial assets, including accounts and notes receivables. The new standard replaces the existing incurred loss impairment methodology with a methodology that requires consideration of a broader range of reasonable and supportable forward-looking information to ~~estimate~~satisfy ~~all~~plugging ~~expected credit losses. The updated guidance is effective for the Company for annual~~ and ~~quarterly~~abandonment ~~reporting~~obligations ~~periods beginning after December 15, 2022,~~ and ~~the~~operational ~~Company~~maintenance ~~adopted the guidance on January 1, 2023~~projects. ~~The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements or disclosures.~~

InThe ~~March~~following ~~2020,~~table ~~the~~is ~~FASB~~a ~~issued~~reconciliation ~~ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation~~ of the ~~Effects~~total ofcash ~~Reference Rate Reform on Financial Reporting followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021,~~ and ~~ASU~~cash ~~2022-06,~~equivalents ~~Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, issued in December 2022. The guidance provides~~ and ~~clarifies~~restricted ~~optional~~cash expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The amendments within these ASUs were in ~~effect beginning March 12, 2020, and an entity may elect to apply~~ the ~~amendments~~accompanying ~~prospectively~~consolidated ~~through~~statements December 31, 2024. This guidance provides an optional practical expedient that allows qualifying modifications to be accounted for as a debt modification rather than be analyzed under existing guidance to determine if the modification should be accounted for as a debt extinguishment. The Company adopted this accounting pronouncement in conjunction with the execution of ~~the~~cash ~~Third~~flows ~~Amendment~~and totheir ~~the~~corresponding ~~Note~~balance ~~Purchase~~sheet ~~Agreement~~presentation (in June 2023 and elected to apply this optional expedient. See Note 6 – Long-Term Debt for further discussion of the Company’s accounting for its existing debt and related issuance costs. The adoption of this accounting standard did not have a material impact on the Company's condensed consolidated financial statements and related disclosures.thousands):

In August 2020, the FASB issued ASU No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The guidance simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. Additionally, the amendment requires the application of the if-converted method to calculate the impact of convertible instruments on diluted earnings per share (EPS). The guidance is effective for the Company for fiscal years beginning after December 15, 2022, and the Company adopted the


	March 31, 2024		December 31, 2023
Cash and cash equivalents	$	1,446	$	969
Current restricted cash (1)	2,200		2,200
Long-term restricted cash (2)	5,560		5,560
Total cash, cash equivalents and restricted cash	$	9,206	$	8,729

17(1) Current restricted cash is included in “Other Current Assets on the accompanying condensed consolidated balance sheets.

(2) Long-term restricted cash is included in “Other Long-Term Assets” on the accompanying condensed consolidated balance sheets.

Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock, held at cost” on the accompanying condensed consolidated balance sheets. For the three months ended March 31, 2024, we purchased 17,949 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. For the three months ended March 31, 2023, we purchased 126,240 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares.

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~~guidance~~New onAccounting ~~January~~Pronouncements. 1In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The ~~adoption~~guidance aims to improve the effectiveness of ~~this~~income ~~guidance~~tax ~~did~~disclosures ~~not~~primarily ~~have~~through aimprovements ~~material~~to ~~impact~~the income tax rate reconciliation disclosure along with information on income taxes paid. The guidance is effective for the Company’s ~~consolidated~~for ~~financial~~fiscal ~~statements~~years orbeginning ~~disclosures~~after December 15, 2024 with early adoption permitted. We are currently evaluating the impact of this standard.

In November 2023, the FASB issued ASU No. 2023-07, Improvements to Reportable Segment Disclosures. The guidance requires disclosures of certain general information related to the Company's segment. This includes information on the factors used to identify reportable segments, the types of products and services from which reportable segments generate revenues and whether operating segments have been aggregated. The new requirements will result in incremental disclosures in annual and interim reports. This guidance will apply to fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The new guidance must be applied retrospectively to all prior periods presented in the financial statements unless impracticable with early adoption permitted. We are currently evaluating the impact of this standard.

(3) Leases

The Company follows the FASB's Accounting Standards Codification Topic No. 842 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 condensed consolidated balance sheets. We have elected to not account for lease and non-lease components separately.

The Company has contractual agreements for its corporate office lease, vehicle fleet, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of ~~September~~March 3031, ~~2023~~2024, 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. The Company recognizes lease expense on a straight-line basis over the lease term.

As of ~~September~~March 3031, ~~2023~~2024, the Company's future cash payment obligation for its operating lease liabilities are as follows (in thousands):

	As of September 30, 2023
	As of March 31, 2024
2023 (Remaining)	$	2,667
2024 (Remaining)	$	7,077
2024	4,166
2025	7,987
2025	2,427
2026	2,968
2026	1,194
2027	1,997
2027	61
2028	1,402
Thereafter	~~475~~2,710
Total undiscounted lease payments	1024,~~990~~141
Present value adjustment	(~~879~~3,421)
Net operating lease liabilities	$	1020,~~111~~720

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(4) Share-Based Compensation

Share-Based Compensation Plans

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

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

The expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying condensed consolidated statements of operations was $1.58 million and $1.21 million for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022, respectively, and $4.0 million and $3.9 million for the nine months ended September 30,~~ 2023 ~~and 2022~~, respectively. Capitalized share-based compensation was less than $0.1 million for both the three months ended March 31, 2024 and 2023.

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the three months ended September 30, 2023 and 2022, and $0.2 million for both the nine months ended September 30, 2023 and 2022.

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

Stock Option Awards

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

At ~~September~~March 3031, ~~2023~~2024, we had no unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the ~~nine~~three months ended ~~September~~March 3031, ~~2023~~2024:

	Shares	Wtd. Avg. Exer. Price		Wtd. Avg. Remaining Contractual Term (years)	Aggregate Intrinsic Value (in thousands)
Options outstanding, beginning of period	196,162	$	26.46	3.4	$	525
Options granted	—	$	—
Options exercised	—	$	—
Options outstanding, end of period	196,162	$	26.46	3.1	$	1,506
Options exercisable, end of period	196,162	$	26.46	3.1	$	1,506

Our outstanding stock option awards had $1.8 million aggregate intrinsic value at September 30, 2023. At September 30, 2023, the weighted-average remaining contract life of stock option awards outstanding was 3.6 years and exercisable was 3.6 years. The total intrinsic value of stock option awards exercisable was $1.8 million as of September 30, 2023.

Restricted Stock Units

The Plans allow for the issuance of restricted stock unit awards that generally may not be sold or otherwise transferred until certain restrictions have lapsed. The compensation cost related to 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 ~~September~~March 3031, ~~2023~~2024, we had $510.14 million unrecognized compensation expense related to our RSUs which is expected to be recognized over a weighted-average period of 2.02 years.

The following table provides information regarding RSU activity for the ~~nine~~three months ended ~~September~~March 3031, ~~2023~~2024:

	RSUs	Wtd. Avg. Grant Price
RSUs outstanding, beginning of period	~~227~~285,~~114~~163	$	2124.1861
RSUs granted	~~195~~233,~~791~~168	$	2331.7508
RSUs forfeited	(14,~~424~~683)	$	2529.4408
RSUs vested	(~~137~~112,~~467~~147)	$	1723.7857
RSUs outstanding, end of period	~~284~~401,~~014~~501	$	2428.5860

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Performance-Based Stock Units

On ~~May~~February 2124, ~~2019~~2021, the Company granted 99161,~~500~~389 PSUs for which the number of shares earned ~~was~~is based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, ~~2019~~2021 to December 31, ~~2021~~2022. The awards ~~contained~~contain market conditions which ~~allowed~~allow a payout ranging between 0% ~~payout~~ and 200% of the target payout. The fair value as of the grant date was $1813.8613 per unit or ~~112~~157.96% of the stock price. The compensation expense for these awards ~~had~~is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of ~~three~~two years. In the first quarter of ~~2022~~2023, the Board and its Compensation Committee approved payout of these awards at ~~117~~188% of target. Accordingly, 97303,~~812~~410 shares were issued on February 2322, ~~2022~~2023.

19On 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 on an absolute and relative basis compared 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 awards have a cliff-vesting period of three years. All PSUs granted remain outstanding related to this award as of March 31, 2024.

On February 23, 2023, the Company granted 120,749 PSUs for which the number of shares earned is based on the TSR of the Company's common stock on an absolute and relative basis compared to the TSR of its selected peers during the performance period from January 1, 2023 to December 31, 2025. 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 $31.18 per unit or 136.28% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years. All PSUs granted remain outstanding related to this award as of March 31, 2024.

On February 21, 2024, the Company granted 132,930 PSUs for which the number of shares earned is based on the TSR of the Company's common stock on an absolute and relative basis compared to the TSR of its selected peers during the performance period from January 1, 2024 to December 31, 2026. 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 $34.99 per unit or 124.74% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years. All PSUs granted remain outstanding related to this award as of March 31, 2024.

On March 27, 2024, the Company granted 23,103 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, 2024 to December 31, 2026. 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 $46.18 per unit or 133.11% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years. All PSUs granted remain outstanding related to this award as of March 31, 2024.

As of March 31, 2024, we had $9.0 million unrecognized compensation expense related to our PSUs based on the assumption of 100% target payout. The remaining weighted-average performance period is 2.2 years.

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OnThe ~~February~~following ~~24,~~table ~~2021,~~provides ~~the~~information ~~Company~~regarding ~~granted 161,389 PSUs for which the number of shares earned is~~ performance-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 oractivity ~~157.6% of the stock price. The compensation expense~~ for ~~these awards is based on~~ the ~~per~~three ~~unit~~months ~~grant~~ended ~~date~~March 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. In the first quarter of 202331, ~~the Board and its Compensation Committee approved payout of these awards at 188% of target. Accordingly, 303,410 shares were issued on February 22, 2023.~~2024:

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 awards have a cliff-vesting period of three years. All PSUs granted remain outstanding related to this award as of September 30, 2023.


	PSUs	Wtd. Avg. Grant Price
Performance based stock units outstanding, beginning of period	242,860	$	33.84
Performance based stock units granted	156,033	$	36.65


Performance based stock units outstanding, end of period	398,893	$	34.94

On February 23, 2023, the Company granted 120,749 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, 2023 to December 31, 2025. 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 $31.18 per unit or 136.28% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years. All PSUs granted remain outstanding related to this award as of September 30, 2023.

As of September 30, 2023, we had $4.9 million unrecognized compensation expense related to our PSUs based on the assumption of 100% target payout. The remaining weighted-average performance period is 1.9 years.

The following table provides information regarding performance-based stock unit activity for the nine months ended September 30, 2023:

	PSUs	Wtd. Avg. Grant Price
Performance based stock units outstanding, beginning of period	283,500	$	23.18
Performance based stock units granted	120,749	$	31.18
Performance based stock units incremental shares granted	142,021	$	13.13
Performance based stock units vested	(303,410)	$	13.13
Performance based stock units outstanding, end of period	242,860	$	33.84

(5) Earnings Per Share

Basic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three ~~and nine~~ months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023 are discussed below.

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

Three Months Ended September 30, 2023

Three Months Ended September 30, 2022

Three Months Ended March 31, 2024

Three Months Ended March 31, 2023

Net Income (Loss)

Per ShareAmount

Net Income (Loss)

Per ShareAmount

Basic EPS:

Net Income (Loss) and Share Amounts

(415,~~771~~528)

2225,~~985~~445

(0.2161)

~~142~~94,~~541~~492

22,~~308~~440

64.3921

Dilutive Securities:

Performance Based Stock Unit Awards

—

~~169~~97

RSU Awards

—

~~137~~91

Stock Option Awards

—

556

Diluted EPS:

Net Income (Loss) and Assumed Share Conversions

(415,~~771~~528)

2225,~~985~~445

(0.2161)

~~142~~94,~~541~~492

22,~~669~~634

64.2917

	Nine Months Ended September 30, 2023					Nine Months Ended September 30, 2022
	Net Income (Loss)		Shares	Per ShareAmount		Net Income (Loss)		Shares	Per ShareAmount
Basic EPS:
Net Income (Loss) and Share Amounts	$	114,658	22,677	$	5.06	$	167,076	18,885	$	8.85
Dilutive Securities:
Performance Based Stock Unit Awards			67					141
RSU Awards			91					171
Stock Option Awards			17					40
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	114,658	22,852	$	5.02	$	167,076	19,237	$	8.69

The following is a table of antidilutive options and shares excluded from the computation of Diluted EPS for the periods indicated below (in thousands):

On September 18, 2023, the Company issued 2,810,811 shares of its common stock in a registered underwritten offering, for aggregate net proceeds, after offering expenses and fees, of approximately $97.1 million.


	Three Months Ended March 31, 2024	Three Months Ended March 31, 2023
Antidilutive Securities:
Stock Option Awards	87	137
Restricted Stock Unit Awards	10	9
Performance Based Stock Unit Awards	60	51

There were 0.2 million stock options that were not included in the computation of Diluted EPS for the three months ended September 30, 2023 because they were antidilutive due to the net loss, while there were no antidilutive stock options for the three months ended September 30, 2022. Additionally, there were less than 0.1 million stock options to purchase shares which were not included in the computation of Diluted EPS for both the nine months ended September 30, 2023 and 2022, because they were antidilutive.19

There were 0.2 million shares of RSUs that were not included in the computation of Diluted EPS for the three months ended September 30, 2023 because they were antidilutive due to the net loss and less than 0.1 million shares of RSUs that were not included in the computation of Diluted EPS for the three months ended September 30, 2022 because they were antidilutive. Additionally, there were less than 0.1 million shares of RSUs which were not included in the computation of Diluted EPS for both the nine months ended September 30, 2023 and 2022 because they were antidilutive.

There were 0.1 million shares of PSUs that were not included in the computation of Diluted EPS for the three months ended September 30, 2023 because they were antidilutive due to the net loss and no antidilutive shares of PSUs for the three months ended September 30, 2022. Additionally, there were no antidilutive shares of PSUs for both the nine months ended September 30, 2023 and 2022.

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(6) Long-Term Debt

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

	September 30, 2023		December 31, 2022
	March 31, 2024		December 31, 2023
Credit Facility Borrowings due 2026 (1)	$	~~498~~596,000	$	~~542~~722,000
Second Lien Notes due 2026	150,000		150,000
Second Lien Notes due 2028	500,000		500,000
	648,000		692,000
	1,096,000		1,222,000
Unamortized discount on Second Lien Notes due 2026	(738)		(882)
Unamortized discount on Second Lien Notes due 2028	(7,401)		(7,820)
Unamortized debt issuance cost on Second Lien Notes due 2026	(2,166)		(2,587)
Unamortized debt issuance cost on Second Lien Notes due 2028	(11,630)		(12,289)
Long-Term Debt, net	$	645,096	$	688,531
Total Debt	$	1,076,969	$	1,201,891
Less: Current portion of Second Lien Notes due 2028	37,500		28,125
Long-term debt, net	$	1,039,469	$	1,173,766

(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our condensed consolidated balance sheet. As of ~~September~~March 3031, ~~2023~~2024 and December 31, ~~2022~~2023, we had $722.07 million and $824.79 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.

Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $~~498~~596.0 million and $~~542~~722.0 million as of ~~September~~March 3031, ~~2023~~2024 and December 31, ~~2022~~2023, respectively. The Company is a party to a First Amended and Restated Senior Secured Revolving Credit Agreement with JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended (such agreement, the “Credit Agreement” and the borrowing facility provided thereby, the “Credit Facility”).

~~The~~In ~~Credit~~conjunction ~~Facility~~with ~~matures October 19, 2026 (or to~~ the ~~extent~~closing ~~earlier,~~of the ~~date~~South ~~that~~Texas isAcquisition 91described ~~days~~further ~~prior~~in toNote ~~the~~7, ~~scheduled maturity of~~ the Company's ~~Second~~executed ~~Lien~~the ~~notes),~~Eleventh ~~and~~Amendment ~~provides~~to ~~for~~the aCredit ~~maximum~~Agreement ~~credit~~on ~~amount~~November ~~of $2.0 billion~~30, ~~subject~~2023 to (the ~~current~~“Eleventh ~~borrowing~~Amendment”) ~~base~~which ofsecured $~~775~~425.0 million. ~~The borrowing base is regularly redetermined in or about May and November~~ of ~~each~~incremental ~~calendar~~commitments ~~year~~under ~~and~~its isCredit ~~subject~~Facility ~~to additional adjustments~~ from ~~time~~existing ~~to time, including for asset sales, elimination or reduction of hedge positions~~ and ~~incurrence~~new 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, inthereby ~~their~~increasing ~~discretion,~~lender incommitments ~~accordance with their oil~~ and ~~gas lending criteria at~~ the ~~time of the relevant redetermination. In conjunction with its regularly scheduled semi-annual redeterminations, the Company reaffirmed the~~ borrowing base ~~and elected commitment amount~~ under the Credit Facility atto $1.2 billion from $775.0 million~~, effective November 22, 2022, and again on March 20, 2023~~. The ~~Company~~Eleventh ~~may~~Amendment also ~~request~~permitted the issuance of ~~letters of credit under the Credit Agreement in an aggregate amount~~ up to $25350.0 million, ~~which~~principal ~~reduces the~~ amount of ~~available~~additional ~~borrowings~~Second ~~under~~Lien ~~the~~Notes ~~borrowing~~(as ~~base~~defined inbelow), ~~the~~resulting ~~amount~~in ofan ~~such~~aggregate ~~issued~~principal ~~and~~amount ~~outstanding letters~~ of ~~credit. There were no~~ outstanding ~~letters~~Second ofLien ~~credit~~Notes asnot ofto ~~September~~exceed $500.0 ~~30,~~million ~~2023,~~ and nomodified ~~outstanding~~certain ~~letters~~other ofterms ~~credit as~~ of ~~December 31,~~the ~~2022. Maintaining or increasing our borrowing base under our~~ Credit ~~Facility~~Agreement. ~~is dependent on many factors~~Additionally, ~~including~~the ~~commodity~~Company ~~prices,~~incurred ~~our~~approximately ~~hedge~~$20.0 million ~~positions, changes~~ in ~~our~~third ~~lenders'~~party ~~lending criteria~~ and ~~our~~legal ~~ability~~fees toin ~~raise~~connection ~~capital~~with tothe ~~drill wells to replace produced reserves~~amendment.

~~Interest~~The ~~under~~borrowing ~~the~~base ~~Credit~~is ~~Facility~~regularly ~~accrues~~redetermined aton ~~the~~or ~~Company’s~~about ~~option~~May ~~either~~and atNovember anof ~~Alternate~~each ~~Base~~calendar ~~Rate~~year ~~plus~~and ~~the~~is ~~applicable~~subject ~~margin~~to ~~(“ABR~~additional ~~Loans”),~~adjustments ~~the~~from ~~Adjusted~~time ~~Term~~to ~~Secured~~time, ~~Overnight~~including ~~Financing~~for ~~Rate~~asset ~~(“SOFR”)~~sales, ~~plus~~elimination ~~the~~or ~~applicable~~reduction ~~margin~~of ~~(“Term~~hedge ~~Benchmark~~positions ~~Loans”)~~and orincurrence ~~Adjusted~~of ~~Daily~~other ~~Simple~~debt. Additionally, ~~SOFR~~the ~~plus~~Company and the ~~applicable~~administrative ~~margin~~agent ~~(“RFR~~may ~~Loans”). The~~request ~~applicable~~an ~~margin~~unscheduled ~~ranges~~redetermination ~~from~~of ~~1.75%~~the toborrowing 2base between scheduled redeterminations.~~75%~~ ~~based~~The onamount of the borrowing base ~~utilization~~is ~~for~~determined ~~ABR~~by ~~Loans~~the ~~and~~lenders, ~~2.75%~~in totheir ~~3.75%~~discretion, ~~based~~in onaccordance ~~borrowing~~with ~~base~~their ~~utilization~~oil ~~for~~and ~~Term~~gas ~~Benchmark~~lending ~~Loans~~criteria ~~and~~at ~~RFR~~the ~~Loans.~~time ~~The~~of ~~Alternate~~the ~~Base~~relevant ~~Rate~~redetermination. ~~and~~The ~~SOFR~~Company ~~are~~may ~~defined,~~also ~~and~~request the ~~applicable~~issuance ~~margins~~of ~~are~~letters ~~set~~of ~~forth,~~credit inunder the Credit Agreement in an aggregate amount up to $25.0 ~~Undrawn~~million, ~~amounts~~which reduces the amount of available borrowings under the ~~Credit~~borrowing ~~Facility~~base ~~are~~in ~~subject~~the toamount aof ~~0.5%~~such ~~commitment~~issued ~~fee~~and outstanding letters of credit. To ~~the~~There ~~extent~~were ~~that~~no aoutstanding ~~payment~~letters ~~default~~of ~~exists~~credit ~~and~~as isof ~~continuing~~March 31, ~~all~~2024 ~~amounts~~and ~~outstanding~~December 31, 2023. Maintaining or increasing our borrowing base under ~~the~~our Credit Facility ~~will~~is ~~bear~~dependent ~~interest~~on atmany ~~2.0%~~factors, ~~per~~including ~~annum~~commodity ~~above~~prices, ~~the~~our ~~rate~~hedge positions, changes in our lenders' lending criteria and ~~margin~~our ~~otherwise~~ability ~~applicable~~to ~~thereto~~raise capital to drill wells to replace produced reserves. AsThe ofCredit ~~September 30~~Facility matures October 19, ~~2023~~2026, ~~the~~and ~~Company's~~provides ~~weighted~~for ~~average~~a ~~interest~~maximum ~~rate~~credit onamount ~~Credit~~of ~~Facility~~$2.0 billion, ~~borrowings~~subject ~~was~~to 8the current borrowing base of $1.~~67%~~2 billion.

Interest under the Credit Facility is payable quarterly and accrues at the Company’s option either at an Alternative Base Rate plus the applicable margin (“ABR Loans”), the Adjusted Term Secured Overnight Financing Rate (“SOFR”) plus the applicable margin (“Term Benchmark Loans”) or Adjusted Daily Simple SOFR plus the applicable margin (“RFR Loans”). The applicable margin ranged from 1.75% to 2.75% based on borrowing base utilization for ABR Loans and 2.75% to 3.75% based on borrowing base utilization for Term Benchmark Loans and RFR Loans. The Alternate Base Rate and 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. As of March 31, 2024, the Company's weighted average interest rate on Credit Facility borrowings was 8.42%.

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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 85% of estimated proved reserves of the Company and its subsidiary.

The Credit Agreement contains the following financial covenants:

•a ratio of total debt to earnings before interest, tax, depreciation and amortization (“EBITDA”), as defined in the Credit Agreement, for the most recently completed four fiscal quarters, not to exceed 3.00 to 1.00 as of the last day of each fiscal quarter; and

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

As of ~~September~~March 3031, ~~2023~~2024, 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 $1418.~~6 million and $8.~~3 million ~~for the three months ended September 30, 2023~~ and ~~2022, respectively, and~~ $3911.~~8 million and $15.~~9 million for the ~~nine~~three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, respectively. The amount of commitment fee amortization included in interest expense, net was $0.26 million and $0.3 million for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022, respectively, and $0.7 million and $0.9 million for the nine months ended September 30,~~ 2023 ~~and 2022~~, 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 Notes”) 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 Notes from $200.0 million to $150.0 million. The Company made the $50.0 million redemption of the Second Lien ~~notes~~Notes on November 29, 2021.

On June 14, 2023, the Company entered into the Third Amendment to the Note Purchase Agreement to effectuate the replacement of LIBOR with an adjusted term secured overnight financing rate plus a margin of 0.25% (“Term SOFR”). After the Third Amendment, interest under the Second Lien Notes is payable quarterly and accrues, based on the Company'’s election at the time of the borrowing, either at Term SOFR plus a margin of 7.5% (“Second Lien Term SOFR Loans”) or at an Alternate Base Rate which is based on the greater of (i) the prime rate; (ii) the greater of the federal funds effective rate or overnight bank funding rate, plus 0.5%; or (iii) Term SOFR plus 1% ~~(“Second Lien ABR Loans”)~~ plus a margin of 6.5%. Additionally, to the extent the Company were to default on the Second Lien Notes, this would potentially trigger a cross-default under our Credit Facility. ~~As of September 30, 2023, the Company's interest rate on Second Lien borrowings was 13.16%.~~

~~The~~Effective November 30, 2023, the Company ~~has~~entered into the ~~right,~~Fourth Amendment to the ~~extent~~Note ~~permitted~~Purchase ~~under~~Agreement (the ~~Credit~~“Fourth ~~Facility~~Amendment”), ~~and~~which ~~subject~~extended the maturity date from December 15, 2026 to ~~the~~December ~~terms~~15, 2028, and ~~conditions~~upsized of the outstanding Second Lien Notes by $350.0 million, with a $7.0 million discount, for net proceeds of $343.0 million, in connection with the closing of the South Texas Acquisition described further in Note 7. The Company evaluated the amendment on a lender-by-lender basis as to ~~optionally~~whether ~~prepay~~it represented a debt extinguishment or modification and wrote off approximately $0.2 million in previously unamortized debt issuance costs and $0.1 million in previously unamortized debt discount during the ~~notes~~year atended noDecember ~~premium~~31, 2023 which was included within “Interest expense, net” on the condensed consolidated statements of operations. Additionally, the Company incurred approximately $10.6 million in third party fees in connection with the amendment. The new debt issuance cost and discount on the Second Lien ~~contains~~Notes ~~customary~~will ~~mandatory~~be ~~prepayment~~amortized ~~obligations~~through ~~upon~~the ~~asset~~new ~~sales~~maturity ~~(including~~date ~~hedge~~of ~~terminations)~~December 15, ~~casualty~~2028. ~~events~~The ~~and~~Fourth ~~incurrences~~Amendment also (i) caused the maximum permitted ratio of ~~certain~~Total ~~debt,~~Net ~~subject~~Indebtedness to, EBITDA (each as defined in ~~certain~~the ~~circumstances,~~Note ~~reinvestment~~Purchase ~~periods.~~Agreement) ~~Management~~for ~~believes~~any fiscal quarter in which the ~~probability~~maximum ratio of ~~mandatory~~Total ~~prepayment~~Debt ~~due~~to EBITDA (each as defined in the Credit Agreement) under the Credit Agreement is less than 3.00 to ~~default~~1.00, to be reduced to a ratio that is ~~remote~~0.25 to 1.00 higher than that set forth in the Credit Agreement; (ii) amended the Minimum Asset

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 90% of estimated PV-9 (defined below), of proved reserves of the Company and its subsidiary and 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%.21

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

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Coverage Ratio (as defined in the Note Purchase Agreement) to be no less than (A) 1.10 to 1.00 through the fiscal quarter ending March 31, 2024 and (B) 1.25 to 1.00 thereafter, in each ~~date~~case of ~~determination~~clause (~~the~~A) ~~“Asset~~and ~~Coverage~~clause (B), tested on a quarterly basis; (iii) added a financial covenant whereby the Current Ratio” (as defined in the Note Purchase Agreement) shall not be less than 1.00 ~~PV-10~~to ~~value~~1.00; is(iv) decreased the ~~estimated~~mortgage ~~future~~coverage ~~net~~and ~~revenues~~title requirements from 90% to be85%; ~~generated~~and ~~from~~(v) modified certain other terms of the ~~production~~Note Purchase Agreement. Additionally, the Second Lien Notes implemented a quarterly requirement for repayment of ~~proved~~Notes, ~~reserves~~beginning ~~discounted~~on June 15, 2024, requiring the Company to ~~present~~redeem ~~value~~the ~~using~~Notes anin ~~annual~~quarterly ~~discount~~payments ~~rate~~of $9.4 million provided the ratio of ~~10%~~Total Indebtedness to EBITDA not exceed 2.25 to 1.00, subject to certain exceptions.

The Second Lien ~~also~~Notes contains acustomary ~~financial~~mandatory ~~covenant~~prepayment ~~measuring~~obligations ~~the~~upon ~~ratio~~asset ofsales ~~total~~(including ~~net~~hedge ~~debt-to-EBITDA~~terminations), ascasualty ~~defined~~events inand ~~the~~incurrences ~~Note~~of ~~Purchase~~certain ~~Agreement~~debt, ~~for~~subject ~~the~~to, ~~most~~in ~~recently~~certain ~~completed~~circumstances, ~~four~~reinvestment ~~fiscal~~periods. ~~quarters,~~Management ~~not~~believes tothe ~~exceed~~probability ~~3.25~~of mandatory prepayment due to 1default is remote.0 asAs of March 31, 2024, the ~~last~~Company’s ~~day~~interest ofrate ~~each~~on ~~fiscal~~the ~~quarter~~Second Lien Notes was 13.08%. As of ~~September~~March 3031, ~~2023~~2024, the Company was in compliance with all financial covenants under the Second Lien Notes.

The obligations under the Second Lien ~~contains~~Notes ~~certain~~are ~~customary representations~~secured, ~~warranties~~subject to certain exceptions and ~~covenants,~~other permitted liens (including ~~but~~the ~~not~~liens ~~limited~~created ~~to,~~under ~~limitations~~the onCredit ~~incurring~~Facility), ~~debt~~by ~~and~~a ~~liens~~perfected security interest, ~~limitations~~second onin ~~making~~priority ~~certain~~to ~~restricted~~the ~~payments,~~liens ~~limitations~~securing onour ~~investments~~Credit Facility, ~~limitations~~and mortgage lien on ~~asset~~substantially ~~sales~~all assets of the Company and ~~hedge~~its ~~unwinds~~subsidiary, ~~limitations~~including a mortgage lien on ~~transactions~~oil and gas properties attributed with ~~affiliates~~at ~~and~~least ~~limitations~~85% onof ~~modifying~~estimated ~~organizational~~PV-9 ~~documents~~(defined ~~and~~below), ~~material~~of ~~contracts.~~proved ~~The~~reserves ~~Second~~of ~~Lien~~the ~~contains~~Company ~~customary~~and ~~events~~its subsidiary and 85% of ~~default.~~the Ifbook anvalue ~~event~~attributed to the PV-9 of ~~default~~the ~~occurs~~non-proved oil and gas properties of the Company. PV-9 is ~~continuing,~~determined using commodity price assumptions by the ~~lenders~~administrative ~~may~~agent ~~declare~~of ~~all~~the ~~amounts~~Credit ~~outstanding~~Facility. ~~under~~PV-9 value is the ~~Second~~estimated ~~Lien~~future net revenues to be ~~immediately~~generated ~~due~~from ~~and~~the ~~payable~~production of proved reserves discounted to present value using an annual discount rate of 9%.

As of ~~September~~March 3031, ~~2023~~2024, total net amounts recorded for the Second Lien Notes were $~~147~~481.10 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien Notes totaled $517.27 million and $34.8 million for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022, respectively, and $14.9 million and $10.7 million for the nine months ended September 30,~~ 2023 ~~and 2022~~, respectively.

Debt Issuance Costs. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings. During the ~~nine~~three months ended ~~September~~March 3031, ~~2022,~~2024 ~~the~~and ~~Company~~2023 ~~capitalized~~there ~~$7.2 million for debt issuance costs incurred in connection with the amendments to our Credit Facility. There~~ were no capitalized costs incurred ~~during the nine months ended September 30, 2023~~.

(7) Acquisitions and Dispositions

~~November~~2023 ~~2021~~South Texas Acquisition

On November 1930, ~~2021~~2023, ~~the~~SilverBow ~~Company~~ closed onthe an acquisition of certain oil~~-weighted~~ ~~assets~~and ingas ~~the~~properties ~~Eagle~~from ~~Ford.~~entities ~~The~~affiliated ~~acquired~~with ~~assets~~Chesapeake ~~included~~Energy ~~wells~~Corporation, ~~and~~with ~~acreage~~consideration incomprised Laof ~~Salle,~~(i) ~~McMullen,~~cash ~~DeWitt~~paid ~~and~~at ~~Lavaca~~the ~~counties.~~closing ~~After~~of ~~consideration~~the ofSouth ~~closing~~Texas ~~adjustments~~Acquisition, ~~total~~(ii) ~~aggregate~~accrued ~~consideration~~purchase ~~was~~price ~~approximately~~adjustments ~~$77.4 million,~~receivable ~~consisting~~which ofwere ~~$37.6 million~~substantially collected in ~~cash,~~January 12024,~~351,961~~ ~~shares~~(iii) ofa ~~our~~deferred ~~common~~acquisition ~~stock~~liability ~~valued~~due ~~at approximately $37.9 million based~~ on the ~~Company's~~first ~~share~~anniversary ~~price~~of on the closing ~~date, and contingent consideration with an estimated fair value~~ of ~~$1.9 million.~~the ~~The~~South ~~contingent~~Texas ~~consideration~~Acquisition ~~consists~~and of(iv) upan ~~to three~~ earn-out ~~payments~~payment ~~of $1.6 million per year for each of 2022, 2023 and 2024,~~ contingent upon the average monthly settlement price of ~~WTI~~NYMEX ~~exceeding~~West ~~$70~~Texas ~~per~~Intermediate ~~barrel~~crude oil for ~~such~~the ~~year~~12 month period beginning December 2023 (the “~~2021~~2023 WTI Contingency Payout”). ~~During~~If the ~~three~~average ~~months~~monthly ~~ended~~settlement ~~September~~price ~~30,~~of ~~2023~~WTI ~~and~~during ~~2022,~~ the ~~Company~~12 ~~recorded~~month ~~losses~~period of(a) exceeds $~~0.9 million~~80 ~~and~~per ~~gains~~barrel, ofSilverBow ~~$0.7 million,~~shall ~~respectively,~~pay ~~and~~Chesapeake ~~losses~~an ofamount ~~$1.0 million~~equal ~~and~~to $~~0.8~~50 million, ~~respectively,~~or ~~for~~(b) ~~the~~is ~~nine~~between ~~months~~$75 ~~ended~~per ~~September~~barrel ~~30,~~and ~~2023~~$80 ~~and~~per ~~2022~~barrel, ~~related~~SilverBow toshall ~~the~~pay ~~2021~~Chesapeake ~~WTI~~an ~~Contingency~~amount ~~Payout~~equal ~~which~~to ~~are~~$25 million. ~~recorded~~If inthe ~~“Gain~~average ~~(loss)~~monthly onsettlement ~~commodity~~price ~~derivatives,~~of ~~net”~~WTI onduring the ~~consolidated~~12 ~~statements~~month ofperiod ~~operations.~~is Webelow ~~also recorded~~ $~~1.6 million~~75 inper ~~earn-out~~barrel, ~~consideration~~SilverBow ~~payable~~shall tonot ~~the~~owe ~~seller~~Chesapeake ~~related~~a tocontingent ~~the~~earn-out ~~2022~~payment. ~~calendar~~During ~~year~~the inthree ~~“Accounts~~months ~~payable~~ended ~~and~~March ~~accrued~~31, ~~liabilities”~~2024, on the ~~condensed~~Company ~~consolidated~~recorded ~~balance~~losses ~~sheet as~~ of ~~December 31, 2022~~$12.8 million ~~For~~related ~~further~~to ~~discussion~~valuation ofchanges in the ~~fair~~2023 ~~value~~WTI ~~related~~Contingency toPayout ~~the~~recorded ~~Company's~~in ~~contingent~~“Net ~~consideration,~~gain ~~refer~~(loss) toon ~~Note~~commodity 9derivatives” ofon ~~these~~the ~~Notes~~accompanying tocondensed ~~Consolidated~~consolidated ~~Financial~~statements ~~Statements~~of operations. 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~~the ~~transaction~~South Texas Acquisition as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. The South Texas Acquisition was funded with borrowings under the Company's Credit Facility, proceeds from the issuance of additional Second Lien Notes and cash on hand.

~~May 2022 Acquisition~~ 22

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 (collectively, “SandPoint”). After consideration of closing adjustments, total aggregate consideration was approximately $67.5 million, consisting of $27.7 million in cash and 1,300,000 shares of our common stock valued at approximately $39.8 million based on the Company's share price on the closing date. We incurred approximately $0.5 million in transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

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

Total Cost
Cash consideration	$	27583,~~709~~373
Equity consideration	39,767
Fair value of contingent consideration	16,933
Total Consideration	67,476
Deferred acquisition liability	50,000
Transaction costs	466
Total Consideration	650,306
Total Cost of Transaction	$	67,942
Transaction costs	10,916
Total Cost of Transaction	$	661,222
Allocation of Total Cost
Assets
Oil and gas properties	$	84,810
Accounts receivable, net	$	1,594
Total assets	84,810
Oil and gas properties	666,360
Right of use assets	187
Total assets	668,141
Liabilities
Accounts payable and accrued liabilities	~~199~~5,275
Fair value of commodity derivatives	16,511
Lease liability	187
Asset retirement obligations	~~158~~1,457
Total Liabilities	$6,919	~~16,868~~
Net Assets Acquired	$	67661,~~942~~222

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 (collectively, “Sundance”). After consideration of closing adjustments, total aggregate consideration was approximately $344.9 million, consisting of $220.9 million in cash, 4,148,472 shares of our common stock valued at approximately $117.7 million based on the Company's share price on the closing date, accrued purchase price adjustments receivable of $1.0 million and contingent consideration with an estimated fair value of $7.4 million. The contingent consideration consists of up to 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”). The contingent payout for the period of April 13, 2022 through December 31, 2022 did not materialize. During the nine months ended September 30, 2023, the Company recorded gains of $1.0 million related to valuation changes in the 2022 WTI Contingency Payout recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. Additionally, as part of our post-close settlement we settled the 2022 WTI Contingency during the second quarter of 2023. As such, we recorded a non-cash gain of $1.1 million during the nine months ended September 30, 2023, and we are no longer required to make a contingency payment related to the 2022 WTI Contingency Payout. We incurred approximately $6.8 million in transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

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

Total Cost
Cash consideration	$	220,866
Equity consideration	117,651
Fair value of contingent consideration	7,422
Accrued purchase price adjustments receivable	(1,000)
Total Consideration	344,939
Transaction costs	6,766
Total Cost of Transaction	$	351,705
Allocation of Total Cost
Assets
Other current assets	$	4,202
Oil and gas properties	397,401
Right of use assets	890
Total assets	402,493
Liabilities
Accounts payable and accrued liabilities	13,687
Fair value of commodity derivatives	33,767
Non-current lease liability	890
Asset retirement obligations	2,444
Total Liabilities	$	50,788
Net Assets Acquired	$	351,705

August 2022 Acquisition

On August 15, 2022, the Company closed the acquisition of certain oil and gas assets in Webb County, Texas. After consideration of closing adjustments, total consideration was approximately $31.2 million. We did not incur any significant transaction costs during the year ended December 31, 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.

October 2022 Acquisition

On October 31, 2022, the Company closed the acquisition of certain oil and gas assets in Dewitt and Gonzales Counties, Texas. After consideration of closing adjustments, total consideration was approximately $80.1 million. The acquisition is subject to further customary post-closing adjustments. We did not incur any significant transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

2022 Non-strategic Dispositions

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

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2023 Chesapeake Acquisition

During the third quarter of 2023, SilverBow executed a purchase and sale agreement for the acquisition of certain oil and gas assets in South Texas from Chesapeake Energy Corporation (the “Chesapeake South Texas Rich Properties”) for a purchase price of $700 million, comprised of a $650 million cash payment at the closing date and a $50 million deferred cash payment due 12 months post-close, subject to customary purchase price adjustments (the “Chesapeake Transaction”) pursuant to the purchase and sale agreement, dated as of August 11, 2023, between SilverBow, SilverBow Resources Operating, LLC and the Chesapeake Sellers (the “Purchase Agreement”). Chesapeake may also receive up to $50 million in contingent cash consideration based on future commodity prices. SilverBow paid a $50 million cash deposit into escrow in conjunction with the Purchase Agreement recorded in “Deposit and other fees for oil and gas property transaction” on the accompanying condensed consolidated balance sheet.

The Purchase Agreement contains certain termination rights, including, but not limited to, each party’s right to terminate the Purchase Agreement in the event a material breach by the other party has occurred and is not waived on or before September 25, 2023, which date has passed, and in any event if the Chesapeake Transaction has not been consummated on or before November 24, 2023; provided that such date may be automatically extended for an additional 15 days to December 9, 2023, in the event certain approvals and consents have not been obtained by such date. The Chesapeake Transaction has an effective date of February 1, 2023, and is expected to close by year-end 2023, subject to satisfaction or waiver of certain customary closing conditions, including the accuracy of the representations and warranties of each party, compliance by each party in all material respects with its covenants and the satisfaction of certain consent requirements.

(8) Price-Risk Management Activities

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

During the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, the Company recorded losses of $5342.7 million and ~~losses of $1.3 million, respectively, on its commodity derivatives. During the nine months ended September 30, 2023 and 2022, the Company recorded~~ gains of $5691.52 million ~~and losses of $162.5 million~~, respectively, on its commodity derivatives. During the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, the Company recorded losses of $013.94 million and gains of $6.1 ~~million, respectively, related to valuation changes on the 2021 WTI Contingency Payout and 2022 WTI Contingency Payout~~.0 ~~During the nine months ended September 30, 2023 and 2022, the Company recorded gains of $1.1~~ million ~~and gains of $4.7 million~~, respectively, related to valuation changes on ~~the~~our ~~2021~~ WTI Contingency ~~Payout and 2022 WTI Contingency Payout~~Payouts. The Company collected cash payments of $7038.74 million and ~~made cash payments of~~ $~~182~~18.17 million for settled derivative contracts during the ~~nine~~three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, respectively.

At ~~September~~March 3031, ~~2023~~2024 and December 31, ~~2022~~2023, there was $813.4 million and $613.95 million, respectively, in receivables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts receivable, net” and were subsequently collected in ~~October~~April ~~2023~~2024 and January ~~2023~~2024, respectively. At ~~September~~March 3031, ~~2023~~2024 and December 31, ~~2022~~2023, we also had $32.58 million and $61.0 million, respectively, in payables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts payable and accrued liabilities” and were subsequently paid in ~~October~~April ~~2023~~2024 and January ~~2023~~2024, 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. At ~~September~~March 3031, ~~2023~~2024, there was $5089.25 million and $1429.24 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $3226.83 million and $218.61 million in current and long-term unsettled derivative liabilities, respectively. At December 31, ~~2022~~2023, there was $52116.5 million and $2455.21 million in current and long-term unsettled derivative assets, respectively, and $405.85 million and $72.75 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 $10.1 million net fair value asset at September 30, 2023, and a $28.2 million net fair value asset at December 31, 2022. 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.23

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The ~~following~~Company ~~tables~~uses ~~summarize~~an ~~the~~International ~~weighted-average~~Swap ~~prices~~and asDerivatives ~~well~~Association asmaster ~~future~~agreement ~~production~~for ~~volumes~~our ~~for~~derivative contracts. This is an industry-standardized contract containing the general conditions of our ~~future~~derivative transactions including provisions relating to netting derivative ~~contracts~~settlement inpayments ~~place~~under certain circumstances (such as default). For reporting purposes, the Company has elected to not offset the asset and liability fair value amounts of ~~September~~its derivatives on the accompanying condensed consolidated balance sheet. Under the right of set-off, there was a $84.5 million net fair value asset at March 3031, 2024, and a $163.6 million net fair value asset at December 31, 2023:. 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.

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
2023 Contracts
4Q23	707,300	$	78.53
2024 Contracts
1Q24	728,000	$	77.67
2Q24	754,550	$	77.59
3Q24	779,620	$	76.48
4Q24	762,100	$	76.16
2025 Contracts
1Q25	666,000	$	71.60
2Q25	673,400	$	71.60
3Q25	680,800	$	71.60
4Q25	588,800	$	71.29
2026 Contracts
1Q26	315,000	$	69.40
2Q26	318,500	$	69.40
3Q26	322,000	$	69.40
4Q26	230,000	$	69.42
Collar Contracts
2023 Contracts
4Q23	302,242					$	65.89	$	74.54
2024 Contracts
1Q24	319,700					$	58.95	$	71.74
2Q24	215,000					$	61.08	$	73.57
3Q24	184,000					$	63.50	$	75.53
4Q24	184,000					$	63.00	$	75.35
2025 Contracts
1Q25	238,500					$	64.00	$	74.62
2Q25	227,500					$	60.80	$	72.22
2026 Contracts
1Q26	90,000					$	64.00	$	71.50
2Q26	91,000					$	64.00	$	71.50
3Q26	92,000					$	64.00	$	71.50
3-Way Collar Contracts
2023 Contracts
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

The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of March 31, 2024:


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
2024 Contracts
2Q24	1,209,550	$	77.40
3Q24	1,239,620	$	76.42
4Q24	1,222,100	$	75.97
2025 Contracts
1Q25	846,000	$	72.32
2Q25	855,400	$	72.20
3Q25	864,800	$	72.11
4Q25	772,800	$	71.82
2026 Contracts
1Q26	472,500	$	68.94
2Q26	455,000	$	68.98
3Q26	432,400	$	69.03
4Q26	386,150	$	69.09
Collar Contracts
2024 Contracts
2Q24	215,000					$	61.08	$	73.57
3Q24	184,000					$	63.50	$	75.53
4Q24	184,000					$	63.00	$	75.35
2025 Contracts
1Q25	238,500					$	64.00	$	74.62
2Q25	227,500					$	60.80	$	72.22
2026 Contracts
1Q26	90,000					$	64.00	$	71.50
2Q26	91,000					$	64.00	$	71.50
3Q26	92,000					$	64.00	$	71.50
3-Way Collar Contracts
2024 Contracts
2Q24	7,757			$	45.00	$	57.50	$	67.85

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Oil Basis Swaps(Argus Cushing (WTI) and Magellan East Houston)	Total Volumes(MMBtu)	Weighted-Average Price
2023 Contracts
4Q23	122,000	$	0.80
2024 Contracts
1Q24	364,000	$	1.47
2Q24	486,000	$	1.49
2Q24	364,000	$	1.47
3Q24	552,000	$	1.49
3Q24	368,000	$	1.47
4Q24	552,000	$	1.49
4Q24	368,000	$	1.47
2025 Contracts
1Q25	~~270~~360,000	$	1.75
2Q25	~~273~~364,000	$	1.75
3Q25	~~276~~368,000	$	1.75
4Q25	~~276~~368,000	$	1.75
Calendar Monthly Roll Differential Swaps
2023 Contracts
4Q23	122,000	$	2.44
2024 Contracts
1Q24	364,000	$	0.69
2Q24	486,000	$	0.71
2Q24	364,000	$	0.69
3Q24	552,000	$	0.72
3Q24	368,000	$	0.69
4Q24	552,000	$	0.72
4Q24	368,000	$	0.69
2025 Contracts
1Q25	~~270~~360,000	$	0.4043
2Q25	~~273~~364,000	$	0.4043
3Q25	~~276~~368,000	$	0.4043
4Q25	~~276~~368,000	$	0.4043

2925

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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
2023 Contracts
4Q23	5,727,000	$	4.20
2024 Contracts
1Q24	7,686,000	$	4.12
2Q24	15,390,000	$	3.60
2Q24	12,350,000	$	3.67
3Q24	16,100,000	$	3.71
3Q24	12,420,000	$	3.78
4Q24	16,100,000	$	4.04
4Q24	12,420,000	$	4.12
2025 Contracts
1Q25	913,~~450~~950,000	$	4.25
2Q25	914,~~555~~105,000	$	3.7172
3Q25	1116,~~960~~560,000	$	3.8386
4Q25	810,~~740~~590,000	$	4.1715
2026 Contracts
1Q26	910,~~680~~580,000	$	4.4849
2Q26	910,~~555~~465,000	$	3.56
3Q26	910,~~660~~580,000	$	3.74
4Q26	910,~~200~~120,000	$	4.1314
Collar Contracts
2023 Contracts
4Q23	12,445,000					$	3.87	$	4.80
2024 Contracts
1Q24	9,661,000					$	3.94	$	5.83
2Q24	4,643,000					$	3.64	$	4.28
3Q24	3,878,000					$	3.77	$	4.76
4Q24	3,865,000					$	4.01	$	5.34
2025 Contracts
1Q25	5,130,000					$	4.00	$	5.32
2Q25	4,914,000					$	3.25	$	3.98
3Q25	920,000					$	3.50	$	3.99
4Q25	920,000					$	3.75	$	4.65
3-Way Collar Contracts
2023 Contracts
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


Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes (MMBtu)	Weighted-Average Price
2024 Contracts
2Q24	16,380,000	$	(0.29)
3Q24	16,560,000	$	(0.25)
4Q24	16,560,000	$	(0.28)
2025 Contracts
1Q25	7,200,000	$	(0.09)
2Q25	7,280,000	$	(0.26)
3Q25	7,360,000	$	(0.23)
4Q25	7,360,000	$	(0.26)

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Natural Gas Basis Derivative Swaps(East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes(MMBtu)	Weighted-Average Price
NGL Swaps (Mont Belvieu)	Total Volumes(Bbls)	Weighted-Average Price
2023 Contracts
4Q23	13,800,000	$	(0.23)
2024 Contracts
1Q24	15,470,000	$	(0.02)
2Q24	491,400	$	25.92
2Q24	15,470,000	$	(0.29)
3Q24	496,800	$	25.92
3Q24	15,640,000	$	(0.26)
4Q24	496,800	$	25.92
4Q24	15,640,000	$	(0.28)
2025 Contracts
1Q25	5360,~~400,~~000	$	(023.~~09)~~88
2Q25	5364,~~460,~~000	$	(023.~~26)~~88
3Q25	5368,~~520,~~000	$	~~(0.~~23).88
4Q25	5368,~~520,~~000	$	(023.~~25)~~88

NGL Swaps (Mont Belvieu)	Total Volumes(Bbls)	Weighted-Average Price
2023 Contracts
4Q23	345,000	$	32.87
2024 Contracts
1Q24	400,400	$	26.30
2Q24	400,400	$	26.30
3Q24	404,800	$	26.30
4Q24	404,800	$	26.30
2025 Contracts
1Q25	270,000	$	24.17
2Q25	273,000	$	24.17
3Q25	276,000	$	24.17
4Q25	276,000	$	24.17

(9) Fair Value Measurements

Fair Value on a Recurring Basis. Our financial instruments consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien ~~notes~~Notes. The carrying amounts of cash and cash equivalents, restricted cash, 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. The fair value of the current and long-term 2021 WTI Contingency Payout and ~~2022~~2023 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 Notes 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.

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

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

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

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

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

32The following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of March 31, 2024 and December 31, 2023, 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.

The following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of September 30, 2023 and December 31, 2022, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these Notes to Condensed Consolidated Financial Statements.


	Fair Value Measurements at
(in thousands)	Total		Quoted Prices in Active markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
March 31, 2024
Assets
Natural Gas Derivatives	$	109,432	$	—	$	109,432	$	—
Natural Gas Basis Derivatives	4,671		—		4,671		—
Oil Derivatives	1,070		—		1,070		—
Oil Basis Derivatives	39		—		39		—
NGL Derivatives	3,755		—		3,755		—
Liabilities
Natural Gas Derivatives	635		—		635		—
Natural Gas Basis Derivatives	2,786		—		2,786		—
Oil Derivatives	26,752		—		26,752		—
Oil Basis Derivatives	857		—		857		—
NGL Derivatives	3,413		—		3,413		—
2023 WTI Contingency Payout	25,439		—		25,439		—
2021 WTI Contingency Payout	1,320		—		1,320		—

December 31, 2023
Assets
Natural Gas Derivatives	$	116,410	$	—	$	116,410	$	—
Natural Gas Basis Derivatives	6,111		—		6,111		—
Oil Derivatives	39,940		—		39,940		—
Oil Basis Derivatives	708		—		708		—
NGL Derivatives	8,494		—		8,494		—
Liabilities
Natural Gas Derivatives	641		—		641		—
Natural Gas Basis Derivatives	2,599		—		2,599		—
Oil Derivatives	3,302		—		3,302		—
Oil Basis Derivatives	921		—		921		—
NGL Derivatives	550		—		550		—
2023 WTI Contingency Payout	12,682		—		12,682		—
2021 WTI Contingency Payout	2,310		—		2,310		—

	Fair Value Measurements at
(in thousands)	Total		Quoted Prices inActive markets forIdentical Assets(Level 1)		Significant OtherObservable Inputs (Level 2)		SignificantUnobservableInputs(Level 3)
September 30, 2023
Assets
Natural Gas Derivatives	$	53,032	$	—	$	53,032	$	—
Natural Gas Basis Derivatives	5,395		—		5,395		—
Oil Derivatives	418		—		418		—
Oil Basis Derivatives	254		—		254		—
NGL Derivatives	5,270		—		5,270		—
Liabilities
Natural Gas Derivatives	5,346		—		5,346		—
Natural Gas Basis Derivatives	5,415		—		5,415		—
Oil Derivatives	41,908		—		41,908		—
Oil Basis Derivatives	858		—		858		—
NGL Derivatives	785		—		785		—
2021 WTI Contingency Payout	2,459		—		2,459		—
December 31, 2022
Assets
Natural Gas Derivatives	$	25,960	$	—	$	25,960	$	—
Natural Gas Basis Derivatives	26,023		—		26,023		—
Oil Derivatives	14,604		—		14,604		—
NGL Derivatives	10,134		—		10,134		—
Liabilities
Natural Gas Derivatives	28,579		—		28,579		—
Natural Gas Basis Derivatives	409		—		409		—
Oil Derivatives	19,442		—		19,442		—
NGL Derivatives	104		—		104		—
2022 WTI Contingency Payout	2,135		—		2,135		—
2021 WTI Contingency Payout	1,453		—		1,453		—

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~~28

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~~(10) Asset ~~for~~Retirement ~~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.~~Obligations

~~The~~Liabilities ~~following~~for ~~provides~~legal aobligations ~~roll-forward~~associated with the retirement obligations of ~~our~~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 ~~for~~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 ~~year~~assumptions ~~ended~~used, ~~December 31~~the Company has designated these liabilities as Level 3 fair value measurements. When a liability is initially recorded, ~~2022~~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 ~~nine~~capitalized ~~months~~cost ~~ended~~is ~~September~~amortized 30on a unit-of-production basis as part of depreciation, ~~2023~~depletion, (and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in ~~thousands):~~the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets.

Asset Retirement Obligations as of December 31, 2021	$	6,050
Accretion expense	534
Liabilities incurred for new wells, acquired wells and facilities construction	3,032
Reductions due to sold wells and facilities	(57)
Reductions due to plugged wells and facilities	(22)
Revisions in estimates	919
Asset Retirement Obligations as of December 31, 2022	$	10,456
Accretion expense	718
Liabilities incurred for new wells, acquired wells and facilities construction	313
Reductions due to plugged wells and facilities	(603)
Revisions in estimates	534
Asset Retirement Obligations as of September 30, 2023	$	11,418

The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2023 and the three months ended March 31, 2024 (in thousands):

At September 30, 2023 and December 31, 2022, approximately $1.6 million and $1.3 million of our asset retirement obligations, respectively, were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets.


Asset Retirement Obligations as of December 31, 2022	$	10,456
Accretion expense	985
Liabilities incurred for new wells, acquired wells and facilities construction	1,883

Reductions due to plugged wells and facilities	(718)
Revisions in estimates	554
Asset Retirement Obligations as of December 31, 2023	$	13,160
Accretion expense	316
Liabilities incurred for new wells, acquired wells and facilities construction	34



Asset Retirement Obligations as of March 31, 2024	$	13,510

At both March 31, 2024 and December 31, 2023, approximately $1.6 million of our asset retirement obligations, respectively, were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying condensed 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. During the second quarter of 2023, the Company entered into gas throughput agreements with separate parties in our Webb County gas area. The agreements provide for an annual average firm capacity of approximately 116,000 MMBtu/d over an eight-year term.

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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 unaudited 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, ~~2022~~2023. The following information contains forward-looking statements; see “Forward-Looking Statements” in this report.

Company Overview

SilverBow is anthe Eagle Ford's largest independent oil and gas company, headquartered in Houston~~, Texas~~. The Company's proven strategy to create value is focused on acquiring and developing assets in ~~the Eagle Ford and Austin Chalk located in~~ South Texas where it has assembled approximately ~~180~~220,000 net acres ~~across~~in ~~five~~the ~~operating~~Eagle ~~areas~~Ford and Austin Chalk. SilverBow's ~~acreage~~average ~~position~~operated ininterest ~~each~~is of82% ~~its~~which ~~operating~~allows ~~areas~~the isCompany ~~highly~~to ~~contiguous~~control ~~and~~how ~~designed~~it ~~for~~prioritizes ~~optimal~~development ~~and~~across ~~efficient~~its ~~horizontal~~acreage ~~well development~~position. ~~The~~SilverBow ~~Company~~is ~~has~~differentiated ~~built~~from its peers through a ~~balanced~~diverse portfolio of ~~properties~~assets ~~with~~that aprovides ~~significant~~commodity ~~base~~optionality. ofThe ~~current~~Company's ~~production~~results ~~and~~are ~~reserves~~enhanced ~~coupled~~ with ~~low-risk~~the ~~development~~Eagle ~~drilling~~Ford's ~~opportunities~~proximity ~~and~~to ~~meaningful~~premium ~~upside~~Gulf ~~from~~Coast ~~newer~~markets, ~~operating~~which ~~areas~~allows SilverBow to capture higher margins.

Operational Results and Strategy

~~Total~~Average net production for the ~~nine~~first ~~months~~quarter ~~ended~~of ~~September~~2024 ~~30, 2023~~ increased 3080% ~~from~~over the ~~nine~~prior ~~months~~year’s ~~ended~~comparable ~~September~~period 30to 91.4 MBoe/d. Oil production averaged 24.5 thousand barrels of oil per day, ~~2022~~up tonearly ~~330~~116% ~~million~~over ~~cubic~~the ~~feet~~comparable period. Production mix for the quarter consisted of 54% natural gas, ~~equivalent~~27% ~~per~~crude ~~day~~oil and 19% NGLs. The significant increase in production is primarily related to SilverBow's transformative South Texas Acquisition in late 2023 and continued gains in well productivity.

~~During~~In ~~the~~early ~~third quarter of 2023~~2024, ~~SilverBow~~the ~~drilled~~Company 10made ~~net~~significant ~~wells,~~changes ~~completed~~in 9reaction ~~net~~to ~~wells~~recent, ~~and~~low ~~brought~~natural ~~online~~gas ~~9 net wells~~prices. ~~The~~To ~~Company~~maximize ~~operated~~cash anflow, ~~average~~planned ofcapital ~~two~~investments ~~drilling~~in ~~rigs~~natural ~~during~~gas ~~the~~assets ~~quarter,~~were ~~primarily~~reduced onby ~~its~~$75 ~~Central~~million ~~Oil~~ and ~~Eastern~~such ~~Extension~~capital ~~areas,~~was ~~which~~shifted ~~reflect~~to ~~its oil~~liquids-~~focused~~rich development ~~program year-to-date~~. ~~SilverBow's~~As ~~team~~a ~~continues to increase operational efficiencies~~result, ~~completing~~first ~~10%~~quarter ~~more~~financial ~~stages~~and ~~per~~operating ~~day~~results ~~year-to-date~~reflected inbetter ~~2023~~than asexpected ~~compared~~production ~~to similar jobs for full year 2022,~~ and ~~averaging~~ ~~pumping~~cash ~~efficiencies~~flow ~~20%~~during ~~higher over~~ the ~~same~~period ~~time~~which ~~periods.~~allowed ~~Third~~SilverBow ~~quarter~~to ~~pumping~~reduce ~~efficiencies~~debt ~~were~~and ~~the~~lower ~~highest~~its ~~quarterly rate achieved year~~quarter-~~to-date~~end inleverage ~~2023~~ratio. ~~due~~Since ~~to decreases in downtime, leading to~~ the ~~increase~~closing ~~in completed stages per day. Drilling costs continue to benefit from greater efficiencies from high-grading~~ of ~~rigs~~the ~~and~~Company's ~~ongoing~~South ~~cost~~Texas ~~deflation,~~Acquisition ~~particularly~~in ~~across~~late ~~casing costs and rig rates~~2023, ~~resulting~~SilverBow inhas ~~drilling~~reduced ~~costs~~its ~~per~~total ~~lateral~~debt ~~foot~~by ~~approximately~~$178 ~~13%~~million ~~lower year-to-date in 2023~~ as ~~compared~~of toApril ~~full~~30, ~~year 2022~~2024.

InDuring ~~its Central Oil area,~~ the ~~Company~~first ~~recently~~quarter ~~brought online a four-well pad which produced a 30-day pad average~~ of 42024,~~349~~ ~~Boe/d~~SilverBow ~~(82%~~drilled ~~oil)~~12 ~~with~~net ~~average lateral lengths of 7~~wells,~~500~~ ~~feet.~~completed ~~Also~~12 innet ~~its~~wells ~~Central~~and ~~Oil area, SilverBow~~ brought online a12 ~~two-well~~net ~~pad which produced a 30-day pad average of 2,140 Boe/d (82% oil) with average lateral lengths of 9,140 feet~~wells. ~~Strong~~The ~~initial~~Company ~~performance~~operated ~~from~~three ~~these~~drilling ~~pads~~rigs ~~are~~during ~~in-line with expectations and support~~ the ~~Company's oil focused growth plans~~quarter. ~~Furthermore,~~First ~~SilverBow~~quarter ~~continues~~capital toinvestments ~~test~~were ~~optimal~~$109 ~~spacing~~million ~~and~~on ~~co-development~~an ~~potential~~accrual ~~of the Eagle Ford and Austin Chalk formations across its oil assets~~basis.

~~For~~Development ~~the~~drilling ~~remainder~~has ofbeen ~~2023,~~primarily ~~the~~focused ~~Company anticipates running one rig~~ on ~~its~~the ~~oil assets and one rig on its gas assets. SilverBow is re~~liquids-~~iterating~~rich ~~its~~acreage ~~full~~from ~~year~~the ~~2023~~South ~~capital~~Texas ~~budget~~Acquisition ~~guidance~~in ~~range~~late ~~of $400-$425 million~~2023. ~~Given~~Base ~~operational~~production and ~~cost~~operational ~~efficiencies~~cycle ~~realized~~times ~~year-to-date,~~on the Company’s ~~may~~new ~~elect~~assets toare ~~complete~~in-line ~~several~~with ~~wells~~expectations. atSilverBow ~~the~~plans ~~end~~to ofoperate ~~the~~three ~~year~~drilling ~~while~~rigs ~~remaining~~through ~~within~~May ~~its stated guidance range~~2024, ~~which~~then ~~would~~reduce beactivity ~~expected~~ to ~~contribute~~two ~~to higher production volumes into 2024~~rigs. The Company ~~aims~~plans to continue to optimize its drilling schedule based on commodity prices, returns on investment and strategically proving up ~~additional~~ inventory within its portfolio.

Liquidity and Capital Resources

SilverBow'’s primary use of cash has been to fund capital expenditures to develop its oil and gas properties, fund acquisitions and to repay Credit Facility borrowings. The Company uses cash generated from operating activities and borrowings under its Credit Facility as its primary ~~sources~~source of liquidity. As of March 31, 2024, the Company’s liquidity consisted of $1.4 million of cash-on-hand and $604 million of available borrowings under its Credit Facility, which had a $1.2 billion borrowing base. SilverBow’s 2024 capital budget range of $470 - $510 million is expected to be funded primarily from operating cash flow. Management believes the Company has robust liquidity to meet all near-term obligations and execute its long-term development plans. In the future, SilverBow may seek to access the debt and equity capital markets from time to time to raise additional capital, increase liquidity, fund acquisitions or refinance debt. For more information on its Credit Facility, see “Revolving Credit Facility” within Note 6 of our condensed consolidated financial statements included in Item 1 of this report.

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During the third quarter, SilverBow executed a purchase and sale agreement for the acquisition of certain oil and gas assets in South Texas from Chesapeake Energy Corporation (the “Chesapeake South Texas Rich Properties”) for a purchase price of $700 million, comprised of a $650 million cash payment at the closing date and a $50 million deferred cash payment due 12 months post-close, subject to customary purchase price adjustments (the “Chesapeake Transaction”) pursuant to the purchase and sale agreement, dated as of August 11, 2023, between SilverBow, SilverBow Resources Operating, LLC and the Chesapeake Sellers (the “Purchase Agreement”). Chesapeake may also receive up to $50 million in contingent cash consideration based on future commodity prices. SilverBow paid a $50 million cash deposit into escrow in conjunction with the Purchase Agreement recorded in “Deposit and other fees for oil and gas property transaction” on the accompanying condensed consolidated balance sheet.

The Chesapeake Transaction is expected to be funded with cash on hand, borrowings under the Company’s First Amended and Restated Senior Secured Revolving Credit Agreement, dated as of April 19, 2017, and amended as of June 22, 2022 (the “Credit Facility”), among the Company, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent for the lenders, and the Company’s amended second lien notes (“Second Lien Notes”) led by EIG. In conjunction with the Chesapeake Transaction, the Company has secured $425 million of incremental commitments under its Credit Facility from existing and new lenders, which, subject to the closing of the Chesapeake Transaction, will increase lender commitments under the Credit Facility to $1.2 billion, and the Second Lien Notes will be upsized by $350 million, which, subject to the closing of the Chesapeake Transaction, will increase lender commitments under the Second Lien Notes to $500 million and extend the maturity date for the Second Lien Notes to December 15, 2028.

On September 13, 2023, SilverBow priced a $148 million follow-on equity offering and used net proceeds to repay amounts outstanding on its Credit Facility. Strategic Value Partners, LLC participated in the follow-on as a selling shareholder. The base deal consisted of 4,000,000 shares of which approximately 70% were primary. As such, on September 18, 2023, the Company issued 2,810,811 shares of its common stock, for aggregate net proceeds, after expenses, of approximately $97 million, which was used to repay a portion of the amounts then outstanding under the Credit Facility. Borrowings under our Credit Facility decreased $44 million from December 31, 2022. As of September 30, 2023, the Company’s liquidity consisted of $1.7 million of cash-on-hand and $277 million in available borrowings on its Credit Facility, which had a $775 million borrowing base.

Management believes the Company has sufficient liquidity to meet all near-term obligations and execute its long-term development plans, including funding the Chesapeake Transaction. In the future, we may seek to access the debt and equity capital markets from time to time to raise additional capital, increase liquidity, fund acquisitions or refinance debt. For more information on its Credit Facility, see the Credit Facility section within Note 6 of our condensed consolidated financial statements included in Item 1 of this report.

Contractual Commitments and Obligations

Other than as discussed below, there were no other material changes in SilverBow'’s contractual commitments during the ~~nine~~three months ended ~~September~~March 3031, ~~2023~~2024 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, ~~2022. During the second quarter of~~ 2023~~, the Company entered into gas throughput agreements with separate parties in our Webb County gas area~~. ~~The agreements provide for an annual average firm capacity of approximately 116,000 MMBtu/d over an eight-year term.~~

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Summary of ~~2023~~2024 Financial Results Through ~~September~~March 3031, ~~2023~~2024

•Revenues and Net Income (Loss): The Company'’s oil and gas revenues were $~~440~~256.37 million for the ~~nine~~three months ended ~~September~~March 3031, ~~2023,~~2024 compared to $~~554~~140.40 million for the ~~nine~~three months ended ~~September~~March 3031, ~~2022~~2023. Revenues were ~~lower~~primarily ~~due~~impacted toby ~~overall~~increased ~~lower~~production ~~commodity~~volumes ~~pricing~~attributable ~~partially~~to ~~offset~~the bySouth ~~increased~~Texas ~~production volumes~~Acquisition. The Company'’s net ~~income~~loss was $~~114~~15.75 million for the ~~nine~~three months ended ~~September~~March 3031, ~~2023~~2024, compared to net income of $~~167~~94.15 million for the ~~nine~~three months ended ~~September~~March 3031, ~~2022~~2023. The decrease in net income was primarily driven by ~~lower~~a net loss on our commodity ~~pricing~~derivatives.

•Capital Expenditures: The Company'’s capital expenditures on an accrual basis were $~~329~~109.95 million for the ~~nine~~three months ended ~~September~~March 3031, ~~2023~~2024 compared to $~~224~~108.80 million for the ~~nine~~three months ended ~~September~~March 3031, ~~2022~~2023. The expenditures for the ~~nine~~three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023 were primarily attributable to drilling and completion activity.

•Working Capital: The Company had a working capital deficit of $58131.94 million at ~~September~~March 3031, ~~2023~~2024 and a working capital ~~deficit~~surplus of $5013.10 million at December 31, ~~2022~~2023. Included in our working capital was a net asset of $1763.42 million and $11111.80 million at ~~September~~March 3031, ~~2023~~2024 and December 31, ~~2022~~2023, respectively, related to the fair value of our current open derivative contracts. The working capital computation does not include available liquidity through our Credit Facility.

•Cash Flows: For the ~~nine~~three months ended ~~September~~March 3031, ~~2023~~2024, the Company generated cash from operating activities of $~~318~~189.47 million, of which $418.43 million was attributable to changes in working capital. Additionally, the Company collected cash settlements of $7038.74 million on derivatives during the ~~nine~~three months ended ~~September~~March 3031, ~~2023~~2024. Cash flows from operating activities also excluded $1329.42 million attributable to a net increase of capital-related payables and accrued costs. Cash used for property additions was $~~316~~80.02 million while ~~acquisition~~purchase ~~costs~~price ~~related~~adjustments ~~to our 2022 acquisitions totaled $0.4 million. The Company's deposit and other fees~~ related to ~~our~~the ~~oil~~South ~~and~~Texas ~~gas~~Acquisition ~~property transaction~~ totaled $5111.28 million ~~during the nine months ended September 30, 2023~~. The Company’s net repayments on the Credit Facility were $44126.0 million during the ~~nine~~three months ended ~~September~~March 3031, ~~2023~~2024. The Company's aggregate net proceeds, after offering expenses, from issuance of common stock in a public underwritten offering was approximately $97.1 million during the nine months ended September 30, 2023.

For the ~~nine~~three months ended ~~September~~March 3031, ~~2022~~2023, the Company generated cash from operating activities of $~~212~~99.27 million, of which ~~included~~$6.0 ~~negative~~million ~~impacts~~was attributable to changes in working capital ~~of $25~~.4 ~~million.~~ Cash used for property additions was $~~163~~111.63 million while purchase price adjustments related to our ~~2021~~2022 acquisitions totaled $~~293~~1.91 million. ~~This~~Cash ~~excluded~~flows from operating activities also included $603.61 million attributable to a net ~~increase~~decrease of capital-related payables and accrued costs. The Company’s net borrowings on the Credit Facility were $~~253~~17.0 million during the ~~nine~~three months ended ~~September~~March 3031, ~~2022 which were primarily used to fund acquisitions during the nine months ended September 30, 2022~~2023.

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Results of Operations

Revenues — Three Months Ended ~~September~~March 3031, ~~2023~~2024 and Three Months Ended ~~September~~March 3031, ~~2022~~2023

Natural gas production was 6154% and 7066% of the Company'’s production volumes for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, respectively. Natural gas sales were 2621% and 6238% of ~~oil~~revenues ~~and gas sales~~ for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, respectively.

Crude oil production was 2627% and 1722% of the Company'’s production volumes for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, respectively. Crude oil sales were 65% and 3053% of ~~oil~~revenues ~~and gas sales~~ for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, respectively.

NGL production was 1319% and 12% of the Company'’s production volumes for ~~both~~ the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, respectively. NGL sales were 914% and 89% of ~~oil~~revenues ~~and gas sales~~ for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, respectively.

The following table provides additional information regarding the Company'’s revenues associated with oil and gas sales, by area, excluding any effects of the Company'’s hedging activities, for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023:

Fields	Three Months Ended ~~September~~March 3031, ~~2023~~2024			Three Months Ended ~~September~~March 3031, ~~2022~~2023
	Oil and Gas Sales(In Millions)		Net Oil and Gas ProductionVolumes (~~MMcfe~~MBoe)	Oil and Gas Sales(In Millions)		Net Oil and Gas ProductionVolumes (~~MMcfe~~MBoe)
Webb County Gas	$	3330.10	142,~~445~~572	$	~~106~~39.14	132,~~514~~207
Western Condensate	26117.90		53,~~261~~456	3927.70		~~4,623~~874
Southern Eagle Ford	75.37		~~2,474~~345	295.35		~~3,913~~291
Central Oil	9263.48		81,~~968~~125	5960.60		41,~~727~~006
Eastern Extension	1339.60		~~1,637~~806	7.37		~~682~~172
Non Core	0.7		62	0.2		46
Non-Core	0.5		9	0.4		8
Total	$	~~174~~256.0	328,~~847~~313	$	~~242~~140.20	274,~~505~~558

The sales ~~volumes~~volume increase from ~~2022~~2023 to ~~2023~~2024 was primarily due to ~~acquisitions~~the inSouth ~~2022~~Texas Acquisition, in addition to wells brought online as part of our full year ~~2022~~2023 and ~~2023~~first quarter 2024 drilling programs. The production volume increase from our South Texas Acquisition was approximately 2,500 MBoe.

In the ~~third~~first quarter of ~~2023~~2024, our $68116.21 million, or 2883%, ~~decrease~~increase in oil, NGL and natural gas sales from the prior year period resulted from:

•Price variances that had an approximately $~~136~~22.37 million unfavorable impact on sales due to ~~overall~~ lower ~~commodity~~natural gas pricing; and

•Volume variances that had an approximately $68138.18 million favorable impact on sales due to overall increased ~~commodity~~ production volumes.

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The following table provides additional information regarding our revenues associated with oil and gas sales, by commodity type, as well as the effects of our hedging activities for derivative contracts held to settlement, for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023 (in thousands, except per-dollar amounts):

	Three Months Ended September 30, 2023		Three Months Ended September 30, 2022
	Three Months Ended March 31, 2024		Three Months Ended March 31, 2023
Production volumes:
Oil (MBbl) (1)	1,410		781
Oil (MBbl)	2,233		1,023
Natural gas (MMcf)	20,010		19,324
Natural gas (MMcf) (1)	27,093		17,974
Natural gas liquids (MBbl) (1)	729		582
Natural gas liquids (MBbl)	1,565		539
Total (MMcfe)	32,847		27,505
Total (MBoe)	8,313		4,558
Oil, natural gas and natural gas liquids sales:
Oil	$	~~112~~166,~~456~~704	$	7174,~~811~~655
Natural gas	4653,~~075~~123		~~150~~52,~~958~~922
Natural gas liquids	1536,~~432~~218		1912,~~412~~377
Total	$	~~173~~256,~~963~~045	$	~~242~~139,~~181~~954
Average realized price before impact of cash-settled derivatives:
Oil (per Bbl)	$	7974.7665	$	9173.9301
Natural gas (per Mcf)	21.3096		72.8194
Natural gas liquids (per Bbl)	2123.1615		3322.3495
Average per Mcfe	$	5.30	$	8.81
Average per Boe	$	30.80	$	30.71
Price impact of cash-settled derivatives:
Oil (per Bbl)	$	(30.4570)	$	~~(20~~0.~~44)~~92
Natural gas (per Mcf)	1.0031		(30.~~47)~~94
Natural gas liquids (per Bbl)	30.6816		(13.~~86)~~61
Average per Mcfe	$	0.54	$	(3.06)
Average per Boe	$	4.10	$	4.36
Average realized price including impact of cash-settled derivatives:
Oil (per Bbl)	$	7673.3095	$	7173.4993
Natural gas (per Mcf)	3.3027		43.3489
Natural gas liquids (per Bbl)	2423.8431		3126.4856
Average per Mcfe	$	5.84	$	5.75
Average per Boe	$	34.90	$	35.07

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

For the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, the Company recorded net losses of $5342.7 million and net gains of $191.32 million from our commodities derivatives activities, respectively. For the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, we also recorded a net loss of $013.94 million and a net gain of $6.1.0 million, respectively, related to valuation changes from our ~~2021~~2023 and ~~2022~~2021 WTI Contingency Payouts. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.

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Costs and Expenses — Three Months Ended ~~September~~March 3031, ~~2023~~2024 and Three Months Ended ~~September~~March 3031, ~~2022~~2023

The following table provides additional information regarding our expenses for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023 (in thousands):

Costs and Expenses	Three Months Ended ~~September~~March 3031, ~~2023~~2024		Three Months Ended ~~September~~March 3031, ~~2022~~2023
General and administrative, net	$	48,~~438~~791	$	47,~~343~~664
Depreciation, depletion, and amortization	5392,~~186~~103		4143,~~501~~998
Accretion of asset retirement obligations	~~254~~316		~~166~~224
Lease operating expenses	2231,~~678~~825		1720,~~701~~560
Workovers	~~672~~610		~~284~~779
Transportation and gas processing	1335,~~710~~199		911,~~662~~520
Severance and other taxes	1016,~~407~~212		129,~~581~~385
Interest expense, net	1936,~~811~~017		1216,~~173~~745
Provision (benefit) for income taxes	(~~949~~4,787)		626,~~066~~812

General and Administrative Expenses, Net. These expenses on a per-~~Mcfe~~Boe basis were $01.1406 and $01.1668 for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, respectively. The decrease in per-~~Mcfe~~Boe rate was due to an overall increase in production. Included in general and administrative expenses is $1.58 million and $1.21 million in share-based compensation for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, respectively.

Depreciation, Depletion and Amortization. These expenses on a per-~~Mcfe~~Boe basis were $111.6208 and $19.5165 for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, respectively. The increase in our per-~~Mcfe~~Boe depreciation, depletion and amortization rate was primarily related to the ~~acquisitions~~acquisition in ~~2022~~2023 and inflation on future development costs. The increase in costs is related to the increase in the per-~~Mcfe~~Boe rate, coupled with an overall increase in production.

Lease Operating Expenses and Workovers. These expenses on a per-~~Mcfe~~Boe basis were $03.7190 and $04.6568 for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, respectively. The decrease in per-Boe rate was due to an overall increase in production. The increase in costs was primarily due to higher labor, compression, salt water disposal and maintenance costs driven by our ~~acquisitions~~acquisition in ~~2022~~2023.

Transportation and Gas Processing. These expenses are related to oil, natural gas and NGL sales. These expenses on a per-~~Mcfe~~Boe basis were $04.4223 and $02.3553 for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, respectively. The increase in costs and in our per-Boe ~~Mcfe~~ rate was primarily attributable to additional transportation and processing agreements associated with our ~~acquisitions~~acquisition in ~~2022~~2023 along with increased contractual fees across portions of our properties.

Severance and Other Taxes. These expenses on a per-~~Mcfe~~Boe basis were $01.3295 and $02.4606 for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 6.03% and 56.27% for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, respectively. The increase in severance and other taxes was primarily attributable to a shift in commodity mix, specifically liquids, driven by our acquisition in 2023. The decrease in our per-Boe rate was due to the overall increase in production.

Interest. Our interest cost was $1936.80 million and $1216.27 million for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, respectively. The increase in interest is primarily due to higher borrowings and higher interest rates. There were no capitalized interest costs for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023.

Income Taxes. The Company recorded an income tax benefit of $04.98 million and an income tax provision of $626.18 million for the three months ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023, respectively. The ~~effective~~ tax ~~rate for the three months ended September 30, 2023 primarily related to the statutory federal tax rate plus the~~ impact ~~of the Texas Margin Tax. The tax impact~~ for both periods was a product of the overall forecasted annual effective tax rate applied to the year to date income or loss.

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Results of Operations

Revenues — Nine Months Ended September 30, 2023 and Nine Months Ended September 30, 2022

Natural gas production was 63% and 75% of the Company's production volumes for the nine months ended September 30, 2023 and 2022, respectively. Natural gas sales were 30% and 63% of oil and gas sales for the nine months ended September 30, 2023 and 2022, respectively.

Crude oil production was 24% and 14% of the Company's production volumes for the nine months ended September 30, 2023 and 2022, respectively. Crude oil sales were 61% and 28% of oil and gas sales for the nine months ended September 30, 2023 and 2022, respectively.

NGL production was 13% and 11% of the Company's production volumes for the nine months ended September 30, 2023 and 2022, respectively. NGL sales were 9% of oil and gas sales for both the nine months ended September 30, 2023 and 2022.

The following table provides additional information regarding the Company's oil and gas sales, by area, excluding any effects of the Company's hedging activities, for the nine months ended September 30, 2023 and 2022:

Fields	Nine Months Ended September 30, 2023			Nine Months Ended September 30, 2022
	Oil and Gas Sales(In Millions)		Net Oil and Gas ProductionVolumes (MMcfe)	Oil and Gas Sales(In Millions)		Net Oil and Gas ProductionVolumes (MMcfe)
Webb County Gas	$	96.7	41,425	$	253.5	37,386
Western Condensate	82.5		16,831	116.2		13,096
Southern Eagle Ford	17.6		6,357	64.1		9,236
Central Oil	206.7		20,826	94.6		7,251
Eastern Extension	35.4		4,588	24.5		2,242
Non Core	1.4		169	1.5		256
Total	$	440.3	90,196	$	554.4	69,467

The sales volumes increase from 2022 to 2023 was primarily due to acquisitions in the second half of 2022, in addition to wells brought online as part of our full year 2022 and 2023 drilling programs.

In the first nine months of 2023, our $114.1 million, or 21%, decrease in oil, NGL and natural gas sales from the prior year period resulted from:

•Price variances that had an approximately $361.0 million unfavorable impact on sales due to overall lower commodity pricing; and

•Volume variances that had an approximately $246.9 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 nine months ended September 30, 2023 and 2022 (in thousands, except per-dollar amounts):

	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022
Production volumes:
Oil (MBbl) (1)	3,569		1,611
Natural gas (MMcf)	57,109		51,829
Natural gas liquids (MBbl) (1)	1,945		1,329
Total (MMcfe)	90,196		69,467
Oil, natural gas and natural gas liquids sales:
Oil	$	267,263	$	155,566
Natural gas	132,802		351,626
Natural gas liquids	40,252		47,250
Total	$	440,317	$	554,442
Average realized price before impact of cash-settled derivatives:
Oil (per Bbl)	$	74.88	$	96.58
Natural gas (per Mcf)	2.33		6.78
Natural gas liquids (per Bbl)	20.69		35.56
Average per Mcfe	$	4.88	$	7.98
Price impact of cash-settled derivatives:
Oil (per Bbl)	$	(0.59)	$	(28.60)
Natural gas (per Mcf)	1.07		(2.45)
Natural gas liquids (per Bbl)	4.28		(4.33)
Average per Mcfe	$	0.75	$	(2.57)
Average realized price including impact of cash-settled derivatives:
Oil (per Bbl)	$	74.29	$	67.98
Natural gas (per Mcf)	3.40		4.33
Natural gas liquids (per Bbl)	24.97		31.23
Average per Mcfe	$	5.63	$	5.41

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

For the nine months ended September 30, 2023 and 2022, the Company recorded net gains of $56.5 million and net losses of $162.5 million from our commodities derivatives activities, respectively. For the nine months ended September 30, 2023 and 2022, we also recorded a net gain of $1.1 million and net gain of $4.7 million, respectively, related to valuation changes from our 2021 and 2022 WTI Contingency Payouts. Additionally, we settled the final post-close adjustment related to the Sundance acquisition during the second quarter of 2023. As part of the settlement, SilverBow is no longer required to make any contingency payments related to the 2022 WTI Contingency Payout. As such, we recorded a non-cash gain of $1.1 million during the nine months ended September 30, 2023. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.

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Costs and Expenses — Nine Months Ended September 30, 2023 and Nine Months Ended September 30, 2022

The following table provides additional information regarding our expenses for the nine months ended September 30, 2023 and 2022 (in thousands):

Costs and Expenses	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022
General and administrative, net	$	17,421	$	14,840
Depreciation, depletion, and amortization	147,037		89,096
Accretion of asset retirement obligations	718		366
Lease operating expenses	62,417		37,095
Workovers	2,263		933
Transportation and gas processing	37,001		22,784
Severance and other taxes	28,563		30,183
Interest expense, net	54,746		26,632
Provision (benefit) for income taxes	33,214		7,678

General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.19 and $0.21 for the nine months ended September 30, 2023 and 2022, respectively. The increase in costs was primarily due to higher legal and professional fees while the decrease in per-Mcfe rate was due to an overall increase in production. Included in general and administrative expenses is $4.0 million and $3.9 million in share-based compensation for the nine months ended September 30, 2023 and 2022, respectively.

Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were $1.63 and $1.28 for the nine months ended September 30, 2023 and 2022, respectively. The increase in our per-Mcfe depreciation, depletion and amortization rate was primarily related to the acquisitions in 2022 and inflation on future development costs. The increase in costs is related to the increase in the per-Mcfe rate, coupled with an overall increase in production.

Lease Operating Expenses and Workovers. These expenses on a per-Mcfe basis were $0.72 and $0.55 for the nine months ended September 30, 2023 and 2022, respectively. The increase in costs was primarily due to higher labor, compression, salt water disposal, maintenance and chemical costs driven by our acquisitions in 2022.

Transportation and Gas Processing. These expenses are related to oil, natural gas and NGL sales. These expenses on a per-Mcfe basis were $0.41 and $0.33 for the nine months ended September 30, 2023 and 2022, respectively. The increase in costs and in our per Mcfe rate was primarily attributable to additional transportation and processing agreements associated with our acquisitions in 2022 along with increased contractual fees across portions of our properties.

Severance and Other Taxes. These expenses on a per-Mcfe basis were $0.32 and $0.43 for the nine months ended September 30, 2023 and 2022, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 6.5% and 5.4% for the nine months ended September 30, 2023 and 2022, respectively.

Interest. Our interest cost was $54.7 million and $26.6 million for the nine months ended September 30, 2023 and 2022, respectively. The increase in interest is primarily due to higher borrowings and higher interest rates. There were no capitalized interest costs for the nine months ended September 30, 2023 and 2022.

Income Taxes. The Company recorded an income tax provision of $33.2 million and an income tax provision of $7.7 million for the nine months ended September 30, 2023 and 2022, respectively. The effective tax rate for the nine months ended September 30, 2023 primarily related to the statutory federal tax rate plus the impact of the Texas Margin Tax The tax impact for both periods was a product of the overall forecasted annual effective tax rate applied to the year to date income.

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Critical Accounting Policies and New Accounting Pronouncements

There have been no changes in the critical accounting policies disclosed in our ~~2022~~2023 Annual Report on Form 10-K.

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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 ~~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~~speculative purposes and only enter into derivative agreements with banks in our Credit Facility. For additional discussion related to our price risk management policy, refer to Note 8 of our condensed consolidated financial statements included in Item 1 of this report.

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

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

Interest Rate Risk. At ~~September~~March 3031, ~~2023~~2024, we had a combined $~~648~~1.01 ~~million~~billion drawn under our Credit Facility and our Second Lien Notes, 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 Notes at ~~September~~March 3031, ~~2023~~2024 would increase our annual interest expense by $611.50 million.

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Item 4. Controls and Procedures

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the three months ended ~~September~~March 3031, ~~2023~~2024 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.

NoIn ~~material~~the ~~legal~~ordinary ~~proceedings~~course of business, we are ~~pending~~party ~~other~~to ~~than~~various ~~ordinary~~legal actions, ~~routine~~which ~~litigation~~arise ~~incidental~~primarily tofrom our activities as operator of oil and natural gas wells. In our opinion, the ~~Company’s~~outcome ~~business~~of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.

Item 1A. Risk Factors.

A description of our risk factors can be found in “Part I, Item 1A. Risk Factors” included in our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2022~~2023. Other than as described below, there have been no material changes in our risk factors disclosed in the ~~2022~~2023 Annual Report on Form 10-K.

Risks Related to ~~the~~Ownership ~~Chesapeake~~of ~~Transaction~~Our Common Stock:

WeOur ~~may~~business ~~not~~could ~~consummate~~be ~~the~~affected ~~Chesapeake~~as ~~Transaction~~a result of activist investors.

~~The~~We ~~completion~~value ofconstructive ~~the~~input ~~Chesapeake~~from ~~Transaction~~investors isand ~~subject~~engage toin adialogue ~~number~~with ~~of closing conditions, some of which are out of~~ our ~~control,~~shareholders ~~including~~regarding ~~the~~strategy ~~material~~and performance. byOur ~~the~~Board ~~other party of all of the obligations, agreements~~ and ~~covenants~~senior ofmanagement ~~the~~are ~~transaction~~committed ~~agreement~~ to beacting ~~performed~~in ~~at or prior to~~ the ~~closing~~best ofinterests ~~the Chesapeake Transaction, including the receipt~~ of ~~any~~all ~~necessary consents or approvals. Additionally, although we have committed financing through our Credit Facility and Second Lien Notes for the purchase price, the completion~~ of ~~the Chesapeake Transaction is subject to~~ our ~~ability to secure this financing~~shareholders.

WeOn ~~also~~April ~~cannot~~10, be2024, Kimmeridge Energy Management Company, LLC, together with certain ~~when~~of ~~SilverBow~~its ~~and~~affiliates ~~the~~(collectively ~~Chesapeake~~“Kimmeridge”), ~~Sellers~~filed ~~will~~a bedefinitive ~~able~~proxy statement to ~~satisfy~~solicit ~~the~~proxies ~~other~~in ~~closing~~favor ~~conditions~~of orthe ~~whether~~election ~~those~~of ~~closing~~three ~~conditions~~director ~~will~~candidates beto ~~satisfied,~~the ~~including~~Board ~~consent~~at ~~from~~our ~~certain~~2024 ~~significant~~annual ~~landowners~~meeting of shareholders. If ~~any of~~ these ~~conditions~~director candidates are ~~not~~elected ~~satisfied,~~to ~~including~~ the ~~failure~~Board towith ~~obtain~~a ~~certain~~specific ~~consents~~agenda, ~~and~~it inmay ~~any~~adversely ~~event~~affect ifour ~~the~~ability ~~Chesapeake~~to ~~Transaction~~effectively ~~has~~implement ~~not~~our ~~been~~current ~~consummated~~business onstrategy or ~~before~~create ~~November~~value ~~24,~~for ~~2023;~~all ~~provided~~shareholders. ~~that~~Kimmeridge ~~such~~has ~~date~~also ~~may~~made bepublic ~~automatically~~statements ~~extended~~critical ~~for~~of anthe ~~additional~~Board 15and ~~days~~senior management. Responding to ~~December~~these 9,actions ~~2023~~by Kimmeridge and potential actions by other activist investors is costly and time-consuming, indisruptive to our operations and diverts the ~~event~~attention ~~certain~~of ~~approvals~~the Board and ~~consents~~senior ~~have~~management ~~not~~from ~~been~~the ~~obtained~~pursuit byof ~~such~~our ~~date~~business strategies, itwhich iscould ~~possible~~materially ~~that~~adversely ~~the~~affect ~~Purchase~~our ~~Agreement~~financial ~~may~~position, beoperating ~~terminated~~results or cash flows. ~~Although~~The ~~the~~contested ~~parties~~election ~~have~~with ~~agreed~~respect into the ~~Purchase~~Company’s ~~Agreement~~directors tohas ~~use~~required ~~commercially~~and ~~reasonable~~is ~~efforts,~~expected ~~subject~~ to ~~certain~~continue ~~limitations,~~to inrequire ~~regards~~us to ~~certain~~incur ~~closing~~substantial ~~conditions~~legal, ~~these~~public relations and other ~~conditions~~advisory fees and proxy solicitation expenses. Further, we may choose to ~~the~~initiate, ~~completion~~or may become subject to, litigation as a result of proposals by activist investors or proxy contests or matters relating thereto, which would serve as a further distraction to the ~~Chesapeake~~Board ~~Transaction~~and ~~may~~senior ~~fail~~management and could require us to beincur ~~satisfied~~significant additional costs.

IfAdditionally, ~~the~~perceived ~~Chesapeake~~uncertainties ~~Transaction~~as isto ~~delayed,~~our ~~not~~future ~~consummated~~direction oras ~~consummated~~a onresult ~~terms~~of ~~different~~investor ~~from~~activism ~~those~~or ~~currently~~changes ~~contemplated,~~to the ~~market~~composition ~~price~~of the Board may lead to the perception of ~~our~~a ~~common~~change ~~stock~~in ~~may~~the ~~decline.~~direction ~~Further~~of our business, ainstability ~~failed~~or ~~transaction~~lack of continuity which may ~~result~~be inexploited ~~negative~~by ~~publicity~~our competitors and/or aother ~~negative~~activist ~~impression~~investors ofand uscause inconcern ~~the~~to ~~investment~~our ~~community~~current or potential customers and ~~may~~make ~~affect~~it ~~our~~more ~~relationships~~difficult ~~with~~to ~~our~~attract ~~business~~and ~~partners~~retain qualified personnel. ~~Failure~~If customers choose to ~~complete~~delay, ~~the~~defer ~~Chesapeake~~or ~~Transaction~~reduce ~~could~~transactions ~~cause~~with us toor betransact inwith ~~breach~~our competitors instead of ~~the~~us ~~Purchase~~because ~~Agreement~~of any such issues, ~~could~~then ~~result~~our infinancial ~~litigation~~position, ~~and~~operating ~~other~~results ~~losses~~or tocash usflows ~~and~~could abe ~~decline~~materially inadversely affected. Further, the ~~market~~trading price of our ~~common~~shares ~~stock~~could experience periods of increased volatility as a result of investor activism.

We may not be able to achieve the expected benefits of the Chesapeake Transaction and may have difficulty integrating the Chesapeake Transaction.

Even if we consummate the Chesapeake Transaction, we may not be able to achieve the expected benefits of the Chesapeake Transaction. There can be no assurance that the Chesapeake Transaction will be beneficial to us. We may not be able to integrate and develop the Chesapeake South Texas Rich Properties without increases in costs, losses in revenues or other difficulties. Any unexpected costs or delays, including inability to reconcile post-acquisition adjustments, incurred in connection with the integration and development of the Chesapeake South Texas Rich Properties could have an adverse effect on our business, results of operations, financial condition and prospects, as well as the market price of our common stock.

Our assessment of the Chesapeake South Texas Rich Properties to date has been limited; and, even by the time of closing, it will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. In the course of our assessment, we will not receive an independent reserve engineer report related to the Chesapeake South Texas Rich Properties. We may incur costs or experience problems related to the Chesapeake South Texas Rich Properties in the Chesapeake Transaction, and we may not have adequate recourse against the Chesapeake Sellers. Although we have and will inspect the properties being sold to us, inspections may not reveal all title, structural or environmental problems. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. Our ability to make specified claims against the Chesapeake Sellers in the Chesapeake Transaction generally expires over time and we may be left with no recourse for liabilities and other problems associated with the Chesapeake Transaction that we do not discover prior to the expiration date related to such matters under the Purchase Agreement.

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The market price of our common stock may decline as a result of the Chesapeake Transaction if, among other things, the integration and development of the Chesapeake South Texas Rich Properties is unsuccessful or if the liabilities, expenses, title, environmental and other defects, or transaction costs related to the Chesapeake Transaction are greater than expected or the Chesapeake South Texas Rich Properties do not yield the anticipated returns. The market price of our common stock may decline if we do not achieve the perceived benefits of the Chesapeake Transaction as rapidly or to the extent anticipated by us or by securities market participants or if the effect of the Chesapeake Transaction, including the obligations incurred to finance the Chesapeake Transaction, on our business results of operations or financial condition or prospects is not consistent with our expectations or those of securities market participants.

Upon consummation of the Chesapeake Transaction, our overall level of debt obligations will increase, which could adversely affect us.

Upon consummation of the Chesapeake Transaction, our overall long-term debt will increase, and our level of debt obligations after completion of the Chesapeake Transaction could have adverse consequences on our business and future prospects, including the following:

•we may not be able to obtain financing in the future on acceptable terms or at all for working capital, capital expenditures, acquisitions, debt service requirements or other purposes;

•less-levered competitors could have a competitive advantage because they have lower debt service requirements;

•credit rating agencies could downgrade our credit ratings following the Chesapeake Transaction below currently expected levels; and

•we may be less able to take advantage of significant business opportunities and to react to changes in market or industry conditions than our competitors.

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

None.

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Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

During the quarter ended ~~September~~March 3031, ~~2023~~2024, no director or Section 16 officer adopted or terminated any Rule 10b5-1 trading arrangements or non-Rule 10b5-1 trading arrangements (in each case, as defined in Item 408 of Regulation S-K).

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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			Certificate of Incorporation of Swift Energy Company, effective April 22, 2016 (incorporated by reference Exhibit 3.1 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
3.2			Certificate of Amendment to Certificate of Incorporation, effective May 5, 2017 (incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed May 5, 2017, File No. 001-08754).
3.3			Second Amended and Restated Bylaws of SilverBow Resources, Inc., effective October 31, 2022 (incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed September 20, 2022, File No. 001-08754).
3.4			Certificate of Designation, Preferences, and Rights of Series B Junior Participating Preferred Stock of the Company (incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed September 20, 2022, File No. 001-08754).
10.1			Purchase and Sale Agreement, dated August 11, 2023, between SilverBow Resources Operating, LLC and Chesapeake Exploration, L.L.C., Chesapeake Operating, L.L.C., Chesapeake Energy Marketing, L.L.C. and Chesapeake Royalty, L.L.C. (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed August 14, 2023, File No. 001-08754).
10.1+*			Form of Restricted Stock Unit Agreement – Non-Employee Directors 2024.
10.2+*			Form of Restricted Stock Unit Agreement – Officers 2024.
10.3+*			Form of Performance Share Unit Agreement – Officers 2024.
31.1*			Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2*			Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32.1#			Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
101*			The following materials from SilverBow Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended ~~September~~March 3031, ~~2023~~2024 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.

50+ 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:

~~November~~May 2, ~~2023~~2024

By:

/s/ Christopher M. Abundis

Christopher M. AbundisExecutive Vice President,Chief Financial Officer and General Counsel

Date:

~~November~~May 2, ~~2023~~2024

By:

/s/ W. Eric Schultz

W. Eric SchultzVice President of Accounting and Controller

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