Form 8-K/A - Current report: [Amend]

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K/A

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(D)

OF THE SECURITIES EXCHANGE ACT OF 1934

Date of report (Date of earliest event reported): August 13, 2024 ( July 29, 2024)

Crescent Energy Company

(Exact Name of Registrant as Specified in Its Charter)

Delaware

001-41132

87-1133610

(State or Other Jurisdiction
of Incorporation)

(Commission
File Number)

(I.R.S. Employer
Identification Number)


600 Travis Street, Suite 7200
Houston Texas			77002
(Address of Principal Executive Offices)			(Zip Code)

(713) 332-7001

(Registrant’s Telephone Number, Including Area Code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:


☐			Written communication pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
☐			Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
☐			Pre-commencement communication pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
☐			Pre-commencement communication pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Class A Common Stock, par value $0.0001 per share

CRGY

The New York Stock Exchange

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§ 230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§ 240.12b-2 of this chapter).

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 or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Introductory Note

On August 2, 2024, Crescent Energy Company (the “Company”) filed a Current Report on Form 8-K (the “Original Report”) with the U.S. Securities and Exchange Commission. The Original Report disclosed the consummation of the previously announced acquisition contemplated by the Agreement and Plan of Merger (the “Merger Agreement”) dated as of May 15, 2024, by and among the Company, SilverBow Resources, Inc. (“SilverBow”), Artemis Acquisition Holdings Inc., a Delaware corporation and a direct wholly owned subsidiary of Crescent, Artemis Merger Sub Inc., a Delaware corporation and a direct wholly owned subsidiary of the Company, and Artemis Merger Sub II LLC, a Delaware limited liability company and a direct wholly owned subsidiary of Artemis Holdings, pursuant to which, following a series of transactions (collectively, the “Merger”), SilverBow became an indirect wholly owned subsidiary of the Company. The Merger was consummated on July 30, 2024.

This Current Report on Form 8-K/A amends the Original Report to include the financial statements required by Item 9.01(a) and the pro forma financial information required by Item 9.01(b). Except as provided herein, the disclosures made in the Original Report remain unchanged.

Item 8.01 Other Events

In addition to the financial statements and pro forma financial information included in Item 9.01 of this Current Report on Form 8-K/A, this Item 8.01 incorporates by reference the following:

•The reserves letter regarding estimated quantities of proved reserves of SilverBow Resources, Inc. as of December 31, 2023, prepared by H.J. Gruy and Associates, Inc., attached as Exhibit 99.1 hereto.

Item 9.01 Financial Statements and Exhibits.

(a) Financial Statements of Businesses Acquired

The following historical financial statements of the business acquired in the Merger are attached as Exhibit 99.2 and Exhibit 99.3 hereto.

•The audited consolidated financial statements of SilverBow Resources, Inc. as of December 31, 2023 and 2022 and for the years ended December 31, 2023, 2022 and 2021, and the related notes to the consolidated financial statements, attached as Exhibit 99.2 hereto and are incorporated herein by reference; and

•The unaudited condensed consolidated financial statements of SilverBow as of June 30, 2024 and December 31, 2023 and for the three- and six-month periods ended June 30, 2024 and 2023, and the related notes to the condensed consolidated financial statements, attached as Exhibit 99.3 hereto and are incorporated herein by reference.

(b) Pro Forma Financial Information

The following unaudited pro forma condensed combined financial information of the Company, giving effect to the Merger, is attached as Exhibit 99.4 hereto:

•The unaudited pro forma condensed combined financial statements of the Company as of June 30, 2024 and for the six months ended June 30, 2024 and for the year ended December 31, 2023, and the related notes to the pro forma condensed combined financial statements, attached as Exhibit 99.4 hereto and are incorporated herein by reference.

(d) Exhibits.


Exhibit No.						Description

23.1						Consent of H.J. Gruy and Associates, Inc.

23.2						Consent of BDO USA, P.C.

99.1						The reserves letter of H.J. Gruy and Associates, Inc. dated February 1, 2024.

99.2						Historical audited consolidated financial statements of SilverBow Resources, Inc. as of December 31, 2023 and 2022 and for the years ended December 31, 2023, 2022, and 2021.

99.3						Historical unaudited condensed consolidated financial statements of SilverBow Resources, Inc. as of June 30, 2024 and December 31, 2023 and for the three- and six-month periods ended June 30, 2024 and 2023.

99.4						Unaudited pro forma combined financial statements of Crescent Energy Company as of June 30, 2024 and for the six months ended June 30, 2024 and for the year ended December 31, 2023.

104						Cover Page Interactive Data File (embedded within Inline XBRL document).

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 hereunto duly authorized.

Date: August 13, 2024


CRESCENT ENERGY COMPANY


By:			/s/ Brandi Kendall
Name:			Brandi Kendall
Title:			Chief Financial Officer

Exhibit 23.1


H.J. GRUY AND ASSOCIATES, INC.
6575 West Loop South, Suite 670, Bellaire, Texas 77401 • TEL. (713) 739-1000

EXHIBIT 23.1

CONSENT OF H.J. GRUY AND ASSOCIATES, INC.

We hereby consent to the use of the name H.J. Gruy and Associates, Inc. and the incorporation by reference in (i) the Registration Statements on Form S-3 and (ii) the Registration Statements on Form S-8 of Crescent Energy Company of our report dated February 1, 2024 prepared for SilverBow Resources, Inc., and the information contained therein, included in the Current Report on Form 8-K filed on or about August 13, 2024.


H.J. GRUY AND ASSOCIATES, INC.



by:			/s/ Marilyn Wilson
Marilyn Wilson, P.E.
Chief Executive Officer

August 13, 2024

Houston, Texas

Exhibit 23.2

Consent of Independent Registered Public Accounting Firm

We hereby consent to the incorporation by reference in Registration Statements on Form S-3 (Nos. 333-269152 and 333-277702) and on Form S-8 (Nos. 333-261604 and 333-275472) of Crescent Energy Company, of our report dated February 29, 2024, relating to the consolidated financial statements of SilverBow Resources, Inc., which appears in this Current Report on Form 8-K/A.

/s/ BDO USA, P.C.

Houston, Texas

August 13, 2024

Exhibit 99.1


H.J. GRUY AND ASSOCIATES, INC.

6575 West Loop South, Suite 670, Bellaire, Texas 77401 • Phone (713) 739-1000

February 1, 2024

SilverBow Resources

920 Memorial City Way, Suite 850

Houston, Texas 77024

Re: Year-End 2023

S.E.C. Guideline Reserves

Independent Estimation

Ladies and Gentlemen:

At your request, we have independently prepared an estimate of the oil, natural gas, and natural gas liquid proved reserves and future net cash flows effective December 31, 2023, attributable to SilverBow Resources (SilverBow) net interests in certain oil and gas properties. The estimated reserves are located in the Continental United States. Based on information provided by SilverBow, the estimated reserves reported herein comprise all of the SilverBow proved reserves.

This report, completed on February 1, 2024 has been prepared for SilverBow, and is provided for inclusion in relevant U.S. Securities and Exchange Commission registration statements or other Securities and Exchange Commission filings. All proved reserves are estimated in compliance with the definitions contained in Securities and Exchange Commission Regulation S-X, Rule 210.4-10(a), and in our opinion, the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

The net reserves, future net cash flow, and discounted future net cash flow to the SilverBow interest in these properties, effective December 31, 2023, are estimated to be as follows:


	Proved Reserves
	Estimated Net Reserves			Estimated Future Net Cash Flow
	Oil (Barrels)	Gas (Mcf)	Natural Gas Liquids (Barrels)	Not Discounted	Discounted at 10 Percent Per Year
Proved Producing	40,738,200	731,156,200	38,702,100	$3,223,679,000	$1,880,690,000
Proved Nonproducing	—	4,919,100	—	$5,481,200	$1,970,900
Proved Undeveloped	54,219,600	941,863,700	32,533,500	$2,398,111,500	$789,660,200
Total Proved	94,957,800	1,677,939,000	71,235,600	$5,627,271,700	$2,672,321,100

The discounted future net cash flow summarized in the above table is computed using a discount rate of 10 percent per annum. Future net cash flow as presented herein is defined as the future cash inflow attributable to the evaluated interest less, if applicable, future operating costs, ad valorem taxes, and future capital expenditures. Future cash inflow is defined as gross cash inflow less, if applicable, royalties and severance taxes. Future cash inflow and future net cash flow stated in this report exclude consideration of state and federal income tax. Future costs of facility and well abandonments, and the restoration of producing properties to satisfy environmental standards are not deducted from cash flow.

This reserve report conforms to the term third party reports as stated in Regulation S-K, Item 1202. The assumptions, data, methods, and procedures used by H.J. Gruy and Associates, Inc. to conduct the independent reserve estimates are appropriate for the purposes of this report, and we have used all methods and procedures we consider necessary under the circumstances to prepare this report. The proved reserves estimates are in compliance with the applicable definitions contained in Securities and Exchange Commission Regulation S-X.

The processes, methods, and procedures employed by us to evaluate the necessary information, estimate reserves, support assumptions, and document methodologies are effective, and meet or exceed guideline standards. We used appropriate engineering, geologic, and evaluation principles that are consistent with practices routinely recognized in

the petroleum industry. Reserve estimates are based on extrapolation of established performance trends, material balance calculations, volumetric calculations, analogy with the performance of comparable wells, or a combination of these methods.

The primary economic assumptions in the reserves estimating process include the application of product prices, operating costs, and future capital expenditures that are not escalated and therefore remain constant for the projected life of each property. Product benchmark prices are based on an average of 2023 first-day-of-the-month prices in accordance with Regulation S-X guidelines. A price differential is applied to the oil, natural gas, and natural gas liquids benchmark prices to adjust for transportation, geographic property location, and quality or energy content. As a reference, the 12-month average benchmark price for oil is $78.10 per barrel, referenced to West Texas Intermediate (WTI) price at Cushing Oklahoma, and for natural gas is $2.752 per million British thermal units, referenced to Henry Hub gas price. The average adjusted prices, for oil, natural gas, and natural gas liquids, used to determine reserves are $76.79 per barrel, $2.30 per thousand standard cubic feet and $25.43 per barrel, respectively, over the projected lives of the assets.

Lease operating costs are based on historical operating expense records. For all properties, general and administrative overhead expenses have been included. Estimates of capital costs are included as required for workovers and development. SilverBow has informed us that the development activities included herein have been subjected to and received internal approvals required by SilverBow management.

In conducting this work, we relied on data supplied by SilverBow. The extent and character of ownership, oil and natural gas sales prices, operating costs, future capital expenditures, historical production, accounting, geological, and engineering data were accepted as represented, and we have assumed the authenticity of all documents submitted. No independent well tests, property inspections, or audits of operating statements were conducted by our staff in conjunction with this work. We did not verify or determine the extent, character, status, or liability, if any, of production imbalances, hedging activities, or any current or possible future detrimental environmental site conditions. In our judgment, there are no instances where current local, state, or federal regulations will materially impact the ability of SilverBow to recover the estimated proved reserves.

In order to estimate the proved reserves and future cash flows attributable to SilverBow, we have relied on geological, engineering, and economic data furnished by our client. Although we instructed our client to provide all pertinent data, and we made a reasonable effort to analyze it carefully with methods applied in the petroleum industry, there is no guarantee that the volumes of hydrocarbons or the cash flows projected will be realized.

Hydrocarbon reserves estimates contain inherent uncertainties. The estimation of reserves is based on the application of a wide range of technologies and the subjective interpretation of currently available data; therefore, the reserves discussed herein are considered estimates only and should not be construed as exact quantities. Future economic or operating conditions may affect recovery of estimated reserves and cash flows, and reserves of all categories may be subject to change as more performance data become available or as alternative estimating methods become applicable. Estimates of future net cash flow and discounted future net cash flow should not be interpreted to represent the fair market value for the estimated reserves.

H.J. Gruy and Associates, Inc. is a privately owned, independent consultancy, and compensation for our efforts is not contingent upon the outcome of our work. H.J. Gruy and Associates, Inc. and its employees have no direct financial interest in SilverBow Resources, or the properties, nor do we contemplate any future direct financial interest. Any distribution or publication of this work or any part thereof must include this letter in its entirety.

Yours very truly,

H.J. GRUY AND ASSOCIATES, INC.

Texas Registration Number F-000637

(Seal)

by: /s/ Marilyn Wilson

Marilyn Wilson, P.E.

Chief Executive Officer

CERTIFICATE OF QUALIFICATION

I, Marilyn Wilson, of 6575 West Loop South, Suite 670, Bellaire, Texas 77401, hereby certify:

1. I am Chief Executive Officer of H.J. Gruy and Associates, Inc, and I am the engineer responsible for the estimates of reserves, future production, and future income determined by H.J. Gruy and Associates, Inc. and preparation of the reserves report for SilverBow Resources effective December 31, 2023, and dated February 1, 2024, attached herewith.

2. I hold a Bachelor of Science Degree in Petroleum Engineering from Texas A&M University, and I am a Licensed Professional Engineer in the State of Texas, License Number 59498. I am a member of the Society of Petroleum Engineers, and I am a past President and member of the Society of Petroleum Evaluation Engineers. I have over 30 years of experience in the evaluation of oil and gas reserves.

3. Based on my educational and professional background, I meet or exceed the professional qualifications as a Reserves Estimator presented in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers.


H.J. GRUY AND ASSOCIATES, INC.
Texas Registration Number F-000637

by:			/s/ Marilyn Wilson
Marilyn Wilson, P.E.
Chief Executive Officer

Exhibit 99.2

Report of Independent Registered Public Accounting Firm

Stockholders and Board of Directors

SilverBow Resources, Inc.

Houston, Texas

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of SilverBow Resources, Inc. (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company's internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and our report dated February 29, 2024 expressed an unqualified opinion thereon.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate opinions on the critical audit matter or on the accounts or disclosures to which it relates.

Impact of Proved Oil and Natural Gas Reserves Estimation on Depreciation, Depletion and Amortization (“DD&A”) Expense and Full-Cost Ceiling Test Impairment Calculation Related to Proved Oil and Natural Gas Properties

As described in Note 1 to the consolidated financial statements, estimated proved oil and natural gas reserves volumes and associated future net cash flows directly impact the calculation of DD&A expense and the full-cost ceiling test impairment calculation. There are numerous uncertainties inherent in estimating proved oil and natural gas reserves volumes and associated future net cash flows including, among others, estimated future production volumes and timing of such production and amounts of lease operating expenses and capital expenditures. The accuracy of these estimates is dependent on the quality of available data and on engineering and geological interpretation and judgment. The estimation of oil and natural gas reserve volumes and associated future net cash flows requires management’s use of internal petroleum engineers and independent petroleum engineers and geologists (referred to as “management’s specialists”).

We have identified the impact of proved oil and natural gas reserves estimation on DD&A expense and full-cost ceiling test impairment calculation related to proved oil and natural gas properties as a critical audit matter. Certain inputs and assumptions, specifically the estimation and timing of future production volumes and amounts of lease operating expenses and capital expenditures all require a high degree of subjectivity and could have a material impact on the overall estimate of proved oil and natural gas reserve volumes and associated future cash flows and the related measurement of DD&A expense or the full-cost ceiling test impairment calculation. Auditing management’s judgment with respect to these inputs and assumptions involved a high degree of auditor judgment due to the nature and extent of audit effort required and the evaluation of the audit evidence obtained.

The primary procedures we performed to address this critical audit matter included:

•Testing the design, implementation and operating effectiveness of internal controls relating to management’s estimation of proved oil and natural gas reserves.

•Evaluating the professional qualifications of management’s specialists and their relationship to the Company, making inquiries of management’s specialists regarding the process followed and judgments used to assist in estimating the Company’s proved oil and natural gas reserves, and reading the report prepared by the independent petroleum engineers and geologists.

•Comparing estimated production volumes and production decline analyses for certain fields against results of actual production volumes and actual production decline analyses to determine the appropriateness of management’s estimates.

•Evaluating the estimates of lease operating expenses used in the reserve estimates compared to historical lease operating expenses.

•Comparing the estimates of future capital expenditures used in the reserve estimates for certain fields to amounts expended for recently drilled and completed wells in similar locations.

•Evaluating the Company’s evidence to support the amount of proved undeveloped properties reflected in the reserve estimates by examining historical conversion rates and support for the Company’s intent and ability to develop the proved undeveloped properties.

/s/ BDO USA, P.C.

We have served as the Company's auditor since 2016.

Houston, Texas

February 29, 2024

Consolidated Balance Sheets

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


	December 31, 2023		December 31, 2022
ASSETS
Current Assets:
Cash and cash equivalents	$	969	$	792
Accounts receivable, net	138,343		89,714
Fair value of commodity derivatives	116,549		52,549
Other current assets	5,590		2,671
Total Current Assets	261,451		145,726
Property and Equipment:
Property and Equipment, Full-Cost Method, including $28,375 and $16,272 of unproved property costs not being amortized	3,597,160		2,529,223
Less – Accumulated depreciation, depletion, amortization and impairment	(1,223,241)		(1,004,044)
Property and Equipment, Net	2,373,919		1,525,179
Right of use assets	12,888		12,077
Fair value of long-term commodity derivatives	55,114		24,172
Other long-term assets	31,090		9,208
Total Assets	$	2,734,462	$	1,716,362

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	98,816	$	60,200
Deferred acquisition liability	50,000		—
Fair value of commodity derivatives	5,509		40,796
Accrued capital costs	31,900		56,465
Current portion of long-term debt	28,125		—
Accrued interest	9,668		2,665
Current lease liability	4,001		8,553
Undistributed oil and gas revenues	20,425		27,160
Total Current Liabilities	248,444		195,839
Long-term debt, net of current portion	1,173,766		688,531
Non-current lease liability	8,899		3,775
Deferred tax liabilities, net	99,227		16,141
Asset retirement obligations	11,584		9,171
Fair value of long-term commodity derivatives	2,504		7,738
Other long-term liabilities	710		3,588
Commitments and Contingencies (Note 6)
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, 25,914,956 and 22,663,135 shares issued, respectively, and 25,429,610 and 22,309,740 shares outstanding, respectively	259		227
Additional paid-in capital	679,202		576,118
Treasury stock held, at cost, 485,346 and 353,395 shares, respectively	(10,617)		(7,534)
Retained earnings	520,484		222,768
Total Stockholders’ Equity	1,189,328		791,579
Total Liabilities and Stockholders’ Equity	$	2,734,462	$	1,716,362

See accompanying Notes to Consolidated Financial Statements.

Consolidated Statements of Operations

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


	Year Ended December 31,
	2023		2022		2021
Revenues:
Oil and gas sales	$	652,358	$	753,420	$	407,200

Operating Expenses:
General and administrative, net	24,520		21,395		21,799
Depreciation, depletion, and amortization	219,116		133,982		68,629
Accretion of asset retirement obligations	985		534		306
Lease operating expense	87,368		55,329		27,206
Workovers	2,694		1,655		514
Transportation and gas processing	59,032		32,989		24,145
Severance and other taxes	38,701		41,761		19,307
Total Operating Expenses	432,416		287,645		161,906

Operating Income (Loss)	219,942		465,775		245,294

Non-Operating Income (Expense)
Net gain (loss) on commodity derivatives	241,309		(73,885)		(123,018)
Interest expense	(80,119)		(41,948)		(29,129)
Other income (expense), net	197		95		10

Income (Loss) Before Income Taxes	381,329		350,037		93,157
Provision (Benefit) for Income Taxes	83,613		9,600		6,398
Net Income (Loss)	$	297,716	$	340,437	$	86,759

Per Share Amounts:
Basic: Net Income (Loss)	$	12.74	$	17.24	$	6.61
Diluted: Net Income (Loss)	$	12.63	$	16.94	$	6.42
Weighted Average Shares Outstanding - Basic	23,371		19,748		13,118
Weighted Average Shares Outstanding - Diluted	23,571		20,097		13,520

See accompanying Notes to Consolidated Financial Statements.

Consolidated Statements of Stockholders’ Equity

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


	Common Stock		Additional Paid- in Capital		Treasury Stock		Retained Earnings (Accumulated Deficit)		Total
Balance, January 1, 2021	$	121	$	297,712	$	(2,372)	$	(204,428)	$	91,033
Purchase of treasury shares (74,586 shares)	—		—		(612)		—		(612)
Vesting of share-based compensation (336,247 shares)	3		(3)		—		—		—
Issuance of common stock (1,222,209 shares)	12		26,944		—		—		26,956
Issuance pursuant to acquisitions (3,210,626 shares)	32		83,490		—		—		83,522
Share-based compensation	—		4,874		—		—		4,874
Net Income	—		—		—		86,759		86,759
Balance, December 31, 2021	$	168	$	413,017	$	(2,984)	$	(117,669)	$	292,532

Shares issued from option exercise (15,584 shares issued)	—		426		—		—		426
Purchase of treasury shares (120,350 shares)	—		—		(3,397)		—		(3,397)
Treasury shares pursuant to purchase price adjustment (41,375 shares)	—		—		(1,153)		—		(1,153)
Vesting of share-based compensation (375,745 shares)	4		(4)		—		—		—
Issuance pursuant to acquisitions (5,448,961 shares)	55		157,350		—		—		157,405
Share-based compensation	—		5,329		—		—		5,329
Net Income	—		—		—		340,437		340,437
Balance, December 31, 2022	$	227	$	576,118	$	(7,534)	$	222,768	$	791,579

Purchase of treasury shares (131,951 shares)	—		—		(3,083)		—		(3,083)
Vesting of share-based compensation (441,010 shares)	4		(4)		—		—		—
Issuance of common stock (2,810,811 shares)	28		97,281		—		—		97,309
Share-based compensation	—		5,807		—		—		5,807
Net Income	—		—		—		297,716		297,716
Balance, December 31, 2023	$	259	$	679,202	$	(10,617)	$	520,484	$	1,189,328

See accompanying Notes to Consolidated Financial Statements.

Consolidated Statements of Cash Flows

SilverBow Resources, Inc. (in thousands)


	Year Ended December 31, 2023		Year Ended December 31, 2022		Year Ended December 31, 2021
Cash Flows from Operating Activities:
Net income	$	297,716	$	340,437	$	86,759
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities—
Depreciation, depletion, and amortization	219,116		133,982		68,629
Accretion of asset retirement obligations	985		534		306
Deferred income tax expense (benefit)	83,086		9,625		6,212
Share-based compensation expense	5,526		5,086		4,645
(Gain) Loss on commodity derivatives, net	(241,309)		73,885		123,018
Cash settlements received (paid) on derivatives	88,679		(219,626)		(70,582)
Settlements of asset retirement obligations	(716)		(48)		(158)
Write-down of debt issuance cost	1,239		350		229
Other	3,528		3,010		2,877
Change in operating assets and liabilities—
(Increase) decrease in accounts receivable and other assets	(25,439)		(29,522)		(23,513)
Increase (decrease) in accounts payable and accrued liabilities	7,172		11,788		17,507
Increase (decrease) in income taxes payable	525		(229)		83
Increase (decrease) in accrued interest	7,003		1,969		(286)
Net Cash Provided by (Used in) Operating Activities	447,111		331,241		215,726
Cash Flows from Investing Activities:
Additions to property and equipment	(421,273)		(272,443)		(133,638)
Acquisition of oil and gas properties	(604,955)		(367,024)		(51,734)
Proceeds from the sale of property and equipment	713		4,347		—
Payments on property sale obligations	—		(750)		(1,084)
Net Cash Provided by (Used in) Investing Activities	(1,025,515)		(635,870)		(186,456)
Cash Flows from Financing Activities:
Proceeds from long-term debt	356,965		—		—
Payments of long-term debt	(14,250)		—		(50,000)
Proceeds from bank borrowings	672,000		841,000		335,000
Payments of bank borrowings	(492,000)		(526,000)		(338,000)
Net proceeds from issuances of common stock	97,309		—		26,956
Net proceeds from stock options exercised	—		39		—
Purchase of treasury shares	(3,083)		(3,397)		(612)
Payments of debt issuance costs	(30,600)		(7,342)		(3,611)
Net Cash Provided by (Used in) Financing Activities	586,341		304,300		(30,267)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	7,937		(329)		(997)
Cash, Cash Equivalents and Restricted Cash at Beginning of Year	792		1,121		2,118
Cash, Cash Equivalents and Restricted Cash at End of Year	$	8,729	$	792	$	1,121

Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest	$	68,116	$	36,994	$	27,221
Changes in capital accounts payable and capital accruals	$	(13,679)	$	54,372	$	(4,033)
Non-cash equity consideration for acquisitions	$	—	$	(156,252)	$	(83,522)
Non-cash deferred consideration for acquisitions	$	(50,000)	$	—	$	—
Non-cash contingent consideration for acquisitions	$	(16,933)	$	—	$	—

See accompanying Notes to Consolidated Financial Statements.

Notes to Consolidated Financial Statements

SilverBow Resources, Inc. and Subsidiary

1. Summary of Significant Accounting Policies

Recent Events. On November 30, 2023, SilverBow closed the acquisition of certain oil and gas properties from Chesapeake Energy Corporation, through its wholly owned subsidiaries Chesapeake Exploration, L.L.C., Chesapeake Operating, L.L.C., Chesapeake Energy Marketing, L.L.C. and Chesapeake Royalty, L.L.C. (collectively “Chesapeake”) (the “Chesapeake Transaction”) for total cost of $653.4 million. For further discussion related to this acquisition, refer to Note 9 of these Notes to Consolidated Financial Statements.

Principles of Consolidation. The accompanying consolidated financial statements include the accounts of SilverBow Resources and its wholly owned subsidiary, SilverBow Resources Operating LLC, (collectively, the “Company”, “SilverBow”, “we”, “our” or “us”) 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 consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying consolidated financial statements. We operate in and report our financial results and disclosures as one segment, which is the exploration, development and production of oil and natural gas.

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.

Subsequent Events. We have evaluated subsequent events requiring potential accrual or disclosure in our consolidated financial statements. There were no material subsequent events requiring additional disclosure in these Notes to Consolidated Financial Statements.

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause

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

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

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

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

•estimates of future costs to develop and produce reserves,

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

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

•estimates of our ownership in oil and gas 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 acquisitions,

•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 may 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 years ended December 31, 2023, 2022 and 2021, such internal costs when capitalized totaled $5.5 million, $4.3 million and $4.8 million,

respectively. There was no capitalized interest on our unproved properties for the years ended December 31, 2023, 2022 and 2021.

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


	December 31, 2023		December 31, 2022
Property and Equipment
Proved oil and gas properties	$	3,562,268	$	2,506,853
Unproved oil and gas properties	28,375		16,272
Furniture, fixtures, and other equipment	6,517		6,098
Less – Accumulated depreciation, depletion, amortization & impairment	(1,223,241)		(1,004,044)
Property and Equipment, Net	$	2,373,919	$	1,525,179

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

We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and 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.

The Company evaluates each acquisition of oil and gas properties to determine whether each should be accounted for as an acquisition of assets or business in accordance with Accounting Standards Update No. 2017-01: Business Combinations (Topic 805) Clarifying the Definition of a Business (“ASU 2017-01”). If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets, the set of transferred assets and activities are not a business combination.

A business combination may result in the recognition of a bargain purchase gain or goodwill based on the measurement of the fair value of the assets and liabilities acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. The initial accounting for business combinations may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is

obtained about the facts and circumstances that existed as of the acquisition dates. Asset acquisitions are recorded at the cost of acquiring the property. The results of operations of the oil and gas properties acquired in the Company’s acquisitions have been included in the consolidated financial statements since the closing dates of the respective acquisitions. See Note 9 for further discussion on recent acquisitions.

Full-Cost Ceiling Test. At the end of the 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 the years ended December 31, 2023, 2022 and 2021.

If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flow 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 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 or timing 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.

Revenue Recognition. Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices, consistent with contractual terms common in the oil and gas industry. These contracts typically provide for cash settlement within 25 days following each production month. 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. Our oil and gas sales are recognized based on the actual volumes sold to the purchasers.

The following table provides information regarding our oil and gas sales, by product, reported on the Consolidated Statements of Operations for years ended December 31, 2023, 2022 and 2021 (in thousands):


	Year Ended December 31, 2023		Year Ended December 31, 2022		Year Ended December 31, 2021
Oil, natural gas and NGLs sales:
Oil	$	402,728	$	239,247	$	98,607
Natural gas	187,340		451,863		267,687
NGLs	62,291		62,310		40,906
Total	$	652,358	$	753,420	$	407,200

Accounts Receivable, Net. We assess the collectibility 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 both December 31, 2023 and 2022, we had an allowance for credit losses of less than $0.1 million. The allowance

for credit losses has been deducted from the total “Accounts receivable, net” balance on the accompanying consolidated balance sheets.

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 receivable related to the Chesapeake Transaction and $14.2 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. At December 31, 2021, our “Accounts receivable, net” balance included $45.3 million for oil and gas sales, $1.9 million for joint interest owners, $1.0 million for severance tax credit receivables and $1.5 million for other receivables.

Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net”, on the accompanying consolidated statements of operations. The amount of supervision fees charged for each of the years ended December 31, 2023, 2022 and 2021 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $12.5 million, $8.8 million and $5.1 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit with a greater than 50% likelihood of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At December 31, 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.

We recorded an income tax provision of $83.6 million, $9.6 million and $6.4 million for the years ended December 31, 2023, 2022 and 2021. We continually monitor all positive and negative evidence related to our determination on the need for a valuation allowance. During the fourth quarter of 2022, the Company’s overall deferred tax position moved from a net deferred tax asset position into a net deferred tax liability position, exclusive of a valuation allowance. In addition, the Company determined it had a significant history of earnings over the prior three years and also considered the scheduled reversal of deferred tax liabilities (including the impact of available carryback and carryforward periods) and projected future taxable income in making this assessment. As such, during the fourth quarter of 2022, the Company’s management determined there was sufficient positive evidence that indicated the Company would more likely that not be able to fully utilize its deferred tax assets and as a result, removed the full valuation allowance. Our effective tax rate for 2022 differs from the statutory rate primarily due to the removal of the full valuation allowance. We recorded an income tax provision of $83.6 million which was primarily attributable to deferred federal and current and deferred state income tax expense of $82.9 million on income before taxes of $381.3 million and $0.7 million of non-deductible expenses for the year ended December 31, 2023. While the Company expects to realize the deferred tax assets, changes in future taxable income or in tax laws may alter this expectation and result in future increases to the valuation allowance.

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


	December 31, 2023		December 31, 2022
Trade accounts payable	$	32,225	$	23,660
Accrued operating expenses	23,104		10,572
Accrued compensation costs	10,208		4,814
Asset retirement obligations – current portion	1,576		1,284
Accrued non-income based taxes	3,870		4,849
WTI contingency liability - current portion	14,282		1,600
Accrued corporate and legal fees	208		388
Other payables(1)(2)	13,343		13,033
Total accounts payable and accrued liabilities	$	98,816	$	60,200

________________

(1)Included in Other Payables is $1.0 million and $6.0 million in payables for settled derivatives for the years ended December 31, 2023 and 2022, respectively.

(2)Included in Other Payables is $7.8 million in payables related to advances from joint interest owners in connection with our Chesapeake Transaction for the year ended December 31, 2023.

Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents.

Restricted Cash. Restricted cash includes amounts held in escrow accounts to satisfy plugging and abandonment obligations and operational maintenance projects. As of December 31, 2023, there was $2.2 million and $5.6 million, in current and long-term restricted cash, respectively. There was no restricted cash as of December 31, 2022.

The following table is a reconciliation of the total cash and cash equivalents and restricted cash in the accompanying consolidated statements of cash flows and their corresponding balance sheet presentation (in thousands):


	December 31, 2023		December 31, 2022
Cash and cash equivalents	$	969	$	792
Current restricted cash (1)	2,200		—
Long-term restricted cash (2)	5,560		—
Total cash, cash equivalents and restricted cash	$	8,729	$	792

________________

(1)Current restricted cash is included in “Other Current Assets” on the accompanying consolidated balance sheet.

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

Credit Risk Due to Certain Concentrations. We extend credit, primarily in the form of uncollateralized oil and gas sales and joint interest owners’ receivables, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly impact our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit. From certain customers we also obtain letters of credit or parent company guarantees, if applicable, to reduce risk of loss.

For the years ended December 31, 2023, 2022 and 2021, parties that accounted for 10% or more of our total oil and gas receipts were as follows:


	Year Ended December 31, 2023		Year Ended December 31, 2022		Year Ended December 31, 2021
Purchasers greater than 10%
Kinder Morgan	15	%	22	%	26	%
Shell Trading	11	%	12	%	12	%
Enterprise Products	29	%	*		*
Plains Marketing	*		11	%	10	%
Trafigura US	*		14	%	16	%
Twin Eagle	*		*		15	%

________________

*Oil and gas receipts less than 10%

Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock held, at cost” on the accompanying consolidated balance sheets. For the years ended December 31, 2023, 2022 and 2021, we purchased 131,951, 120,350 and 74,586 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. Additionally, for the year ended December 31, 2022, we received 41,375 shares in conjunction with our post-closing settlement for a previous acquisition.

Preferred Stock Purchase Rights. On September 20, 2022, the Board declared a dividend distribution of one preferred stock purchase right (each, a “Right”) for each outstanding share of our common stock. As of and after the Distribution Date (as defined in the Rights Agreement, as amended dated May 16, 2023, between the Company and American Stock Transfer & Trust Company (the “Rights Agreement”) governing the Rights), each right will become exercisable to purchase one one-thousandth of a share of Series B Junior Participating Preferred Stock, par value $0.01 per share (the “Preferred Stock”), at a purchase price of $160.00. This portion of a share of Preferred Stock would give the holder thereof approximately the same dividend, voting, and liquidation rights as would one share of Common Stock. Prior to exercise, the Right does not give its holder any dividend, voting or liquidation rights. The Rights will expire on the earliest of (a) 5:00 p.m., New York City time on the day after the 2024 annual shareholders’ meeting, (b) the time at which the Rights are redeemed (as described in the Rights Agreement), and (c) the time at which the Rights are exchanged in full.

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

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021, and ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, issued in December 2022. The guidance provides and clarifies optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The amendments within these ASUs were in effect beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through 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 Third Amendment to the Note Purchase Agreement in June 2023 and elected to apply this optional expedient. See Note 4 – 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 consolidated financial statements or disclosures.

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 guidance on January 1, 2023. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements or disclosures.

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The guidance aims to improve the effectiveness of income tax disclosures primarily through improvements to the income tax rate reconciliation disclosure along with information on income taxes paid. The guidance is effective for the Company for fiscal years beginning after December 15, 2024 with early adoption permitted. We are currently evaluating the impact of this standard; however, we do not expect it to have a material impact on our disclosures.

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 report 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.

ATM Program. On August 13, 2021, the Company entered into an equity distribution agreement pursuant to which the Company was permitted to sell, from time to time in the open market, shares of the Company’s common stock, having aggregate proceeds of up to $40.0 million (the “ATM Program”). The Company used the net proceeds from sales through the ATM Program for general corporate purposes, including, but not limited to, financing of capital expenditures, repayment or refinancing of outstanding debt, financing acquisitions or investments, financing other business opportunities, and general working capital purposes. During the year ended December 31, 2021, the Company sold 1,222,209 shares of common stock for net proceeds of $27.0 million after deducting sales agents’ commissions and other related expenses. There were no shares of common stock sold under the ATM Program during the years ended December 31, 2023 and 2022, and the ATM Program has been terminated.

2. 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 restricted stock grants using the treasury stock method. Diluted EPS also assumes conversion of performance-based restricted stock units 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.

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):


	Year Ended December 31, 2023					Year Ended December 31, 2022					Year Ended December 31, 2021
	Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)		Shares	Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	297,716	23,371	$	12.74	$	340,437	19,748	$	17.24	$	86,759	13,118	$	6.61
Dilutive Securities:
Restricted Stock Unit Awards			104					162					285
Performance Based Stock Unit Awards			76					149					117
Stock Option Awards			20					38					—
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	297,716	23,571	$	12.63	$	340,437	20,097	$	16.94	$	86,759	13,520	$	6.42

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 $97.3 million. The offering expenses and fees associated with the offering were immaterial.

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


	Year Ended December 31, 2023	Year Ended December 31, 2022	Year Ended December 31, 2021
Antidilutive Securities:
Stock Option Awards	—	1	286
Restricted Stock Unit Awards	8	5	—
Performance Based Stock Unit Awards	—	—	—

3. Provision (Benefit) for Income Taxes

Income (Loss) before taxes is as follows (in thousands):


	Year Ended December 31, 2023		Year Ended December 31, 2022		Year Ended December 31, 2021
Income (Loss) Before Income Taxes	$	381,329	$	350,037	$	93,157

The following is an analysis of the consolidated income tax provision (benefit) (in thousands):


	Year Ended December 31, 2023		Year Ended December 31, 2022		Year Ended December 31, 2021
Current:
Federal	$	—	$	—	$	—
State	527		(25)		186
Total current income tax provision (benefit)	527		(25)		186

Deferred:
Federal	80,634		7,188		5,500
State	2,452		2,437		712
Total deferred income tax provision (benefit)	83,086		9,625		6,212
Total tax provision (benefit)	$	83,613	$	9,600	$	6,398

Reconciliations of income taxes computed using the U.S. Federal statutory rate of (21%) to the effective income tax rate are as follows:


	Year Ended December 31, 2023		Year Ended December 31, 2022		Year Ended December 31, 2021
Federal Statutory Rate	21.0	%	21.0	%	21.0	%
State tax provisions (benefits), net of federal benefits	0.8	%	0.7	%	1.0	%
Non-deductible expenses	0.2	%	0.4	%	0.6	%
Other, net	(0.1)	%	(0.1)	%	0.6	%
Valuation allowance adjustments	—	%	(19.3)	%	(16.2)	%
Effective rate	21.9	%	2.7	%	7.0	%

The tax effects of temporary differences representing the net deferred tax asset (liability) at December 31, 2023 and 2022 were as follows (in thousands):


	December 31, 2023		December 31, 2022
Deferred tax assets:
Federal net operating loss (“NOL”) carryovers	$	142,694	$	130,296
Other carryover items	683		649
Asset retirement obligations	2,842		2,258
Share-based compensation	491		439
Lease liability	2,709		2,589
Interest	21,528		8,798
Other	1,253		963
Total deferred tax assets	$	172,200	$	145,992

Deferred tax liabilities:
Oil and gas exploration and development costs	$	(232,902)	$	(141,771)
Derivative contracts	(35,336)		(16,943)
Leased assets	(2,707)		(2,536)
Other	(482)		(883)
Total deferred tax liabilities	(271,427)		(162,133)
Net deferred tax asset (liabilities)	$	(99,227)	$	(16,141)
State net deferred tax liabilities	$	(5,905)	$	(3,453)
Federal net deferred tax liabilities	(93,322)		(12,688)
Net deferred tax asset (liabilities)	$	(99,227)	$	(16,141)

The Company’s NOL carryforward asset is attributable to Federal tax losses of $274.2 million generated from 2013 through 2017 and $405.3 million generated from 2018 through 2023. The losses generated before 2018 will expire between 2033 and 2037 if not utilized. The losses generated from 2018 through 2023 will not expire under the current tax code, but their usage will be limited to 80% of taxable income. In addition, the Company has a net interest expense carryforward of $102.5 million under Section 163(j) of the Code, which will not expire but the usage of which may be limited. We experienced an ownership change within the meaning of Section 382 during 2022 and our annual usage of losses up to the change date in 2022 may be limited; however, at this time, we do not expect any of the losses to expire unused. Should we experience another ownership change within the meaning of Section 382, our NOLs could be further limited.

Our U.S. federal and most state income tax returns from 2020 forward are subject to examination. For years prior to 2020 our U.S. federal returns are subject to examination to the extent of our net operating loss (NOL) carryforwards. Our Texas tax returns from 2018 forward are subject to examination. There are no material unresolved items related to periods previously audited by the taxing authorities. On August 15, 2022, President Biden signed the Inflation Reduction Act into law. Management has reviewed the tax provisions of this legislation and has determined that there are no provisions that would have a material impact on the Company.

4. Long-Term Debt

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


	December 31, 2023		December 31, 2022
Credit Facility Borrowings due 2026 (1)	$	722,000	$	542,000
Second Lien Notes due 2028	500,000		150,000
	1,222,000		692,000
Unamortized discount on Second Lien Notes	(7,820)		(882)
Unamortized debt issuance cost on Second Lien Notes	(12,289)		(2,587)
Total Debt	1,201,891		688,531
Less: Current portion of Second Lien Notes due 2028	28,125		—
Long-term debt, net	$	1,173,766	$	688,531

________________

(1)Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our consolidated balance sheet. As of December 31, 2023 and 2022, we had $24.9 million and $8.7 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.

The Company’s five-year maturity related to our Second Lien Notes due 2028 is as follows (in thousands):


Payments due	2024	2025	2026	2027	2028	Total
Second Lien Notes Due 2028	28,125	37,500	37,500	37,500	359,375	500,000

Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $722.0 million and $542.0 million as of December 31, 2023 and 2022, 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 through the Eleventh Amendment (as defined below) (such agreement, the “Credit Agreement” and the borrowing facility provided thereby, the “Credit Facility”).

In conjunction with the closing of the acquisition for certain oil and gas assets in South Texas from Chesapeake Energy Corporation described further in Note 9, the Company executed the Eleventh Amendment to the Credit Agreement on November 30, 2023 (the “Eleventh Amendment”) which secured $425.0 million of incremental commitments under its Credit Facility from existing and new lenders, thereby increasing lender commitments and the borrowing base under the Credit Facility to $1.2 billion from $775.0 million. The maturity date remained unchanged at October 19, 2026 and the maximum credit amounts remained unchanged at $2.0 billion. The Eleventh Amendment also permitted the issuance of up to $350.0 million principal amount of additional Second Lien Notes (as defined below), resulting in an aggregate principal amount of outstanding Second Lien Notes not to exceed $500.0 million and modified certain other terms of the Credit Agreement. Additionally, the Company incurred approximately $20.0 million in third party and legal fees in connection with the amendment.

The borrowing base is regularly redetermined on or about May and November of each calendar year and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders, in their discretion, in accordance with their oil and gas lending criteria at the time of the relevant redetermination. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to $25.0 million, which reduces the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit. There were no outstanding letters of credit as of December 31, 2023 and 2022. Maintaining or increasing our borrowing base under our Credit Facility is dependent on many factors, including commodity prices, our hedge positions, changes in our lenders’ lending criteria and our ability to raise capital to drill wells to replace produced reserves.

Interest under the Credit Facility 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”). Effective upon the execution of the Tenth Amendment to the Credit Agreement on June 22, 2022, the applicable margin decreased by 50 basis points and 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 0.50% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto. As of December 31, 2023, the Company’s weighted average interest rate on Credit Facility borrowings was 8.70%.

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

•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 December 31, 2023, 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 $55.7 million, $26.9 million and $11.3 million for the years ended December 31, 2023, 2022 and 2021, respectively. The amount of commitment fee amortization included in interest expense, net was $1.1 million, $1.2 million and $0.5 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Senior Secured Second Lien Notes. On December 15, 2017, the Company entered into a Note Purchase Agreement for Senior Secured Second Lien Notes (as amended, the “Note Purchase Agreement”, such second lien facility, the “Second Lien” and such notes, 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 from $200.0 million to $150.0 million. The Company made the $50.0 million redemption of the Second Lien 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 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, this would potentially trigger a cross-default under our Credit Facility.

Effective November 30, 2023, the Company entered into the Fourth Amendment to the Note Purchase Agreement (the “Fourth Amendment”), which extended the maturity date from December 15, 2026 to December 15, 2028, and upsized 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 certain oil and gas assets in South Texas from Chesapeake Energy Corporation described further in Note 9. The Company evaluated the amendment on a lender-by-lender basis as to whether 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 year ended December 31, 2023 which is included within “Interest expense, net” on the 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 Notes will be amortized through the new maturity date of December 15, 2028. The Fourth Amendment also (i) caused the maximum permitted ratio of Total Net Indebtedness to EBITDA (each as defined in the Note Purchase Agreement) for any fiscal quarter in which the maximum ratio of Total Debt to EBITDA (each as defined in the Credit Agreement) under the Credit Agreement is less than 3.00 to 1.00, to be reduced to a ratio that is 0.25 to 1.00 higher than that set forth in the Credit Agreement; (ii) amended the Minimum Asset 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 case of clause (A) and 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 to 1.00; (iv) decreased the mortgage coverage and title requirements from 90% to 85%; and (v) modified certain other terms of the Note Purchase Agreement. Additionally, the Second Lien Notes implemented a quarterly requirement for repayment of Notes, beginning on June 15, 2024, requiring the Company to redeem the Notes on each Interest Payment Date in an amount equal to $9.4 million provided the ratio of Total Indebtedness to EBITDA not exceed 2.25 to 1.00, subject to certain exceptions.

The Second Lien contains customary mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and incurrences of certain debt, subject to, in certain circumstances, reinvestment periods. Management believes the probability of mandatory prepayment due to default is remote. As of December 31, 2023, the Company’s interest rate on Second Lien borrowings was 13.13%. As of December 31, 2023, the Company was in compliance with all financial covenants under the Second Lien.

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 with at least 85% of estimated PV-9 (defined below) of proved reserves of the Company and its subsidiary and 85% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions by the administrative agent of the Credit Facility. PV-9 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 9%.

As of December 31, 2023, net amounts recorded for the Second Lien Notes were $479.9 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $24.4 million, $15.0 million and $17.8 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Debt Issuance Costs. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings. During the years ended December 31, 2023, 2022 and 2021, the Company capitalized $30.6 million, $7.3 million and $3.6 million, respectively, for debt issuance costs incurred in connection with the amendments to our Credit Facility and Second Lien Notes. Additionally, the Company wrote-off $1.2 million and $0.4 million and $0.2 million in debt issuance costs during the years ended December 31, 2023, 2022 and 2021, respectively, related to changes under our Credit Facility and Second Lien Notes.

5. Price-Risk Management Activities

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

During the years ended December 31, 2023, 2022 and 2021, the Company recorded gains of $235.8 million and losses of $78.0 million and $123.0 million, respectively, relating to our commodity derivative activities. The Company received net cash payments of $88.7 million, and made net cash payments of $219.6 million and $70.6 million for settled derivative contracts during the years ended December 31, 2023, 2022 and 2021, respectively. During the years ended December 31, 2023, 2022 and 2021, the Company recorded gains of $5.5 million, $4.1 million and less than $0.1 million, respectively, related to valuation changes on the 2021, 2022 and 2023 WTI (“West Texas Intermediate”) Contingency Payouts.

At December 31, 2023 and 2022, we had $13.5 million and $6.9 million, respectively, in receivables for settled derivatives which were included on the accompanying consolidated balance sheets in “Accounts receivable, net” and were subsequently collected in January 2024 and 2023, respectively. At December 31, 2023 and 2022, we also had $1.0 million and $6.0 million, respectively, in payables for settled derivatives which were included on the accompanying consolidated balance sheets in “Accounts payable and accrued liabilities” and were subsequently paid in January 2024 and 2023, 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 December 31, 2023 there was $116.5 million and $55.1 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $5.5 million and $2.5 million in current unsettled derivative liabilities and long-term unsettled derivative liabilities, respectively. At December 31, 2022, the Company had $52.5 million and $24.2 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $40.8 million and $7.7 million in current unsettled derivative liabilities 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 consolidated balance sheets. Under the right of set-off, there was a $163.6 million net fair value asset at December 31, 2023 and $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 10 of these Notes to Consolidated Financial Statements.

The following tables summarize the weighted average prices as well as future production volumes for our future derivative contracts in place as of December 31, 2023.

Oil Derivative Swaps


(New York Mercantile Exchange (“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
1Q24	1,092,000	$	77.39
2Q24	1,118,550	$	77.18
3Q24	1,147,620	$	76.29
4Q24	1,130,100	$	75.96
2025 Contracts
1Q25	756,000	$	72.18
2Q25	764,400	$	72.05
3Q25	772,800	$	71.95
4Q25	680,800	$	71.60
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
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
2024 Contracts
1Q24	8,247			$	45.00	$	57.50	$	67.85
2Q24	7,757			$	45.00	$	57.50	$	67.85

Oil Basis Swaps


(Argus Cushing (WTI) and Magellan East Houston)	Total Volumes (MMBtu)	Weighted-Average Price
2024 Contracts
1Q24	364,000	$	1.47
2Q24	364,000	$	1.47
3Q24	368,000	$	1.47
4Q24	368,000	$	1.47
2025 Contracts
1Q25	360,000	$	1.75
2Q25	364,000	$	1.75
3Q25	368,000	$	1.75
4Q25	368,000	$	1.75
Calendar Monthly Roll Differential Swaps
2024 Contracts
1Q24	364,000	$	0.69
2Q24	364,000	$	0.69
3Q24	368,000	$	0.69
4Q24	368,000	$	0.69
2025 Contracts
1Q25	360,000	$	0.43
2Q25	364,000	$	0.43
3Q25	368,000	$	0.43
4Q25	368,000	$	0.43

Natural Gas Derivative Swaps


(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
2024 Contracts
1Q24	9,506,000	$	4.03
2Q24	15,390,000	$	3.60
3Q24	16,100,000	$	3.71
4Q24	16,100,000	$	4.04
2025 Contracts
1Q25	13,950,000	$	4.25
2Q25	14,105,000	$	3.72
3Q25	16,560,000	$	3.86
4Q25	10,590,000	$	4.15
2026 Contracts
1Q26	10,580,000	$	4.49
2Q26	10,465,000	$	3.56
3Q26	10,580,000	$	3.74
4Q26	10,120,000	$	4.14
Collar Contracts
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
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
1Q24	16,380,000	$	(0.03)
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)

NGL Swaps


(Mont Belvieu)	Total Volumes (Bbls)	Weighted-Average Price
2024 Contracts
1Q24	491,400	$	25.92
2Q24	491,400	$	25.92
3Q24	496,800	$	25.92
4Q24	496,800	$	25.92
2025 Contracts
1Q25	360,000	$	23.88
2Q25	364,000	$	23.88
3Q25	368,000	$	23.88
4Q25	368,000	$	23.88

6. Commitments and Contingencies

We have gas transportation and processing minimum obligations amounting to $89.5 million for 2024, $102.0 million for 2025, $107.0 million for 2026, $104.6 million for 2027, $92.2 million for 2028 and $689.9 million in the aggregate. These gas transportation and processing minimum obligations represent gross future minimum transportation charges we are obligated to pay as of December 31, 2023. However, our consolidated financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property. Actual transportation under these contracts may exceed the minimum commitments previously stated. The Company incurred transportation expense related to these contracts of $14.0 million for the year ended December 31, 2023. Additionally, we have drilling commitments amounting to $4.8 million for 2024 and $2.1 million for 2025 and other contractual commitments related to tubing purchases amounting to $1.7 million for 2024.

In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as operator of oil and natural gas wells. In 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.

7. 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 awards (“RSUs”), performance-based stock units (“PSUs”) and stock options designed to generate future tax deductions by applying its effective tax rate to the expense recorded. For restricted stock units, 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 consolidated statements of operations was $5.5 million, $5.1 million and $4.6 million for the years ended December 31, 2023, 2022 and 2021, respectively. Capitalized share-based compensation was $0.3 million, $0.2 million and $0.2 million and for the years ended December 31, 2023, 2022 and 2021.

We view stock option awards and restricted stock unit awards 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.

Our shares available for future grant under the 2016 Plan and Inducement Plan were 563,127 and 140,446, respectively, at December 31, 2023.

Stock Option Awards

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

At December 31, 2023, we had no unrecognized compensation cost related to stock option awards. The following table represents stock option award activity for the years ended December 31, 2023, 2022 and 2021:


	Options Outstanding
	Options	Wtd. Avg. Exercise Price		Wtd. Avg. Remaining Contractual Term (years)	Aggregate Intrinsic Value (in thousands)
Balance outstanding, January 1, 2023	196,162	26.46		4.4	438
Options exercised	—	—
Options expired	—	—
Options outstanding, December 31, 2023	196,162	$	26.46	3.4	$	525
Options exercisable, December 31, 2023	196,162	$	26.46	3.4	$	525

The total intrinsic value of stock options exercised during the year ended December 31, 2022 was $0.3 million. There were no stock options exercised during the years ended year ended December 31, 2023 or 2021.

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

As of December 31, 2023, we had unrecognized compensation expense of $4.3 million related to our restricted stock units which is expected to be recognized over a weighted-average period of 1.8 years. The total fair value of shares vested during the years ended December 31, 2023, 2022 and 2021 were $3.4 million, $7.7 million and $2.6 million, respectively.

The following table provides information regarding restricted stock unit activity for the year ended December 31, 2023:


	Shares	Wtd. Avg. Grant Price
Restricted stock units outstanding, December 31, 2022	227,114	21.18
Restricted stock units granted	197,073	23.81
Restricted stock units forfeited	(1,424)	25.44
Restricted stock units vested	(137,600)	17.80
Restricted stock units outstanding, December 31, 2023	285,163	$	24.61

Performance-Based Stock Units

On May 21, 2019, the Company granted 99,500 PSUs for which the number of shares earned was 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 to December 31, 2021. The awards contained market conditions which allowed a payout ranging between 0% payout and 200% of the target payout. The fair value as of the grant date was $18.86 per unit or 112.9% of stock price. The awards had a cliff-vesting period of three years. In the first quarter of

2022, the Board and its Compensation Committee approved payout of these awards at 117% of target. Accordingly, 97,812 shares were issued on February 23, 2022.

On February 24, 2021, the Company granted 161,389 PSUs for which the number of shares earned is based on the TSR of the Company’s common stock relative to the TSR of its selected peers during the performance period from January 1, 2021 to December 31, 2022. The awards contained market conditions which allowed a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $13.13 per unit or 157.6% of the stock price. The compensation expense for these awards was based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level was calculated based on actual stock price performance achieved during the performance period. The awards had a cliff-vesting period of two years. In the first quarter of 2023, 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.

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 December 31, 2023.

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 December 31, 2023.

As of December 31, 2023, we had unrecognized compensation expense of $4.2 million related to our PSUs based on the assumption of 100.0% target payout. The remaining weighted-average performance period is 1.6 years.

The following table provides information regarding PSU activity for the year ended December 31, 2023:


	Shares	Wtd. Avg. Grant Price
PSUs outstanding, December 31, 2022	283,500	$	23.18
PSUs granted	120,749	$	31.18
PSUs incremental shares granted	142,021	$	13.13
PSUs vested	(303,410)	$	13.13
PSUs outstanding, December 31, 2023	242,860	$	33.84

Employee Savings Plan

We have a savings plan under Section 401(k) of the Internal Revenue Code. The Company contributed on behalf of eligible employees an amount up to 100% of the first 6% of compensation based on the contributions made by the eligible employees in 2023 and 2022. The Company’s plan contributions of $0.8 million, $0.6 million and $0.5 million for the years ended December 31, 2023, 2022 and 2021, respectively, were paid in cash during each pay period. These amounts were recorded as “General and administrative, net” on the accompanying consolidated statements of operations.

8. Leases

SilverBow Resources has contractual agreements for its corporate office lease, vehicle fleet, drilling rigs, 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. All of the Company’s leases are 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 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 elected for leases with an initial term of 12 months or less are not recorded on the balance sheet, and the Company does not account for lease and non-lease components separately. The Company recognizes lease expense on a straight-line basis over the lease term.

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


	Year Ended December 31, 2023		Year Ended December 31, 2022
Lease Costs Included in the Asset Additions in the Consolidated Balance Sheets
Property and equipment acquisitions - short-term leases	$	21,631	$	15,219
Property and equipment acquisitions - operating leases	—		—
Total lease costs in property, plant and equipment additions	$	21,631	$	15,219


	Year Ended December 31, 2023		Year Ended December 31, 2022
Lease Costs Included in the Consolidated Statements of Operations
Lease operating costs - short-term leases	$	13,228	$	6,275
Lease operating costs - operating leases	8,485		8,304
General and administrative, net - operating leases	808		754
Total lease cost expensed	$	22,521	$	15,333

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


	As of December 31, 2023		As of December 31, 2022
Weighted-average remaining lease term (in years)	5.0		2.5
Weighted-average discount rate	7.8	%	4.6	%

As of December 31, 2023, the Company’s future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands):


	As of December 31, 2023
2024	$	4,860
2025	3,296
2026	1,891
2027	1,367
2028	1,348
Thereafter	2,877
Total undiscounted lease payments	$	15,639
Present value adjustment	(2,739)
Net operating lease liabilities	$	12,900

Current lease liability	$	4,001
Non-current lease liability	$	8,899

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


	Year Ended December 31, 2023		Year Ended December 31, 2022
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows	$	9,531	$	9,052
Non-cash Investing and Financing Activities
Additions to ROU assets obtained from new operating lease liabilities	$	6,134	$	5,342

Rental and lease expense was $22.5 million, $14.6 million and $7.0 million for the years ended December 31, 2023, 2022 and 2021, respectively. The rental and lease expense primarily relates to compressor rentals and the lease of our office space in Houston, Texas. During 2021 the Company entered into a five-year lease agreement for office space in Houston, Texas. The operating lease commenced on May 18, 2021. On November 16, 2023, the Company amended the lease agreement for additional office space in Houston and extended the lease term through October 31, 2030. As of December 31, 2023, the minimum contractual obligations were approximately $8.4 million in the aggregate related to our office lease.

9. Acquisitions and Dispositions

August 2021 Acquisition

On August 3, 2021, the Company acquired the remaining working interest in 12 wells that SilverBow operates and additional acreage in Webb County. The total aggregate consideration was approximately $23.0 million, consisting of $13.0 million in cash and 516,675 shares of common stock valued at approximately $10.0 million based on the Company’s share price on the closing date. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

October 2021 Acquisition

On October 1, 2021, we closed on an all-stock transaction to acquire oil and gas assets in the Eagle Ford. The acquired assets include working interests in oil and gas properties across Atascosa, Fayette, Lavaca, McMullen and Live Oak counties. After consideration of closing adjustments, we issued 1,341,990 shares of our common stock valued at approximately $35.6 million, based on the Company’s share price on the closing date. The acquisition was

subject to further customary post-closing adjustments. We incurred approximately $0.6 million in transaction costs for the year ended December 31, 2021. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. As part of the post-closing settlement of this acquisition, during the year ended December 31, 2022 we issued 489 new shares and received 41,375 shares back into treasury stock.

November 2021 Acquisition

On November 19, 2021, the Company closed on an acquisition of oil-weighted assets in the Eagle Ford. The acquired assets included wells and acreage in La Salle, McMullen, DeWitt and Lavaca counties. After consideration of closing adjustments, total aggregate consideration was approximately $77.4 million, consisting of $37.6 million in cash, 1,351,961 shares of our common stock valued at approximately $37.9 million based on the Company’s share price on the closing date, and contingent consideration with an estimated fair value of $1.9 million. The contingent consideration consists of up to three earn-out payments of $1.6 million per year for each of 2022, 2023 and 2024, contingent upon the average monthly settlement price of WTI exceeding $70 per barrel for such year (the “2021 WTI Contingency Payout”). During the years ended December 31, 2023, 2022 and 2021, the Company recorded losses of $0.9 million, $1.2 million and less than $0.1 million, respectively, related to the 2021 WTI Contingency Payout recorded in “Net gain (loss) on commodity derivatives” on the consolidated statements of operations and recorded $1.6 million in earn-out consideration payable to the seller related to the 2023 and 2022 calendar year in “Accounts payable and accrued liabilities” on the consolidated balance sheets. For further discussion of the fair value related to the Company’s contingent consideration, refer to Note 10 of these Notes to Consolidated Financial Statements. We incurred approximately $0.3 million in transaction costs for the year ended December 31, 2021. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

May 2022 Acquisition

On May 10, 2022, the Company closed the acquisition of certain oil and gas assets located in La Salle and McMullen Counties, Texas, as well as assumed the seller’s commodity derivative contracts in place at the closing date, from SandPoint Operating, LLC, a subsidiary of SandPoint Resources, LLC (collectively, “SandPoint”). After consideration of closing adjustments, total aggregate consideration consisted of cash and 1,300,000 shares of our common stock based on the Company’s share price on the closing date. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

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


Total Cost
Cash consideration	$	27,709
Equity consideration	39,767
Total Consideration	67,476
Transaction costs	466
Total Cost of Transaction	$	67,942

Allocation of Total Cost
Assets
Oil and gas properties	$	84,810
Total assets	84,810

Liabilities
Accounts payable and accrued liabilities	199
Fair value of commodity derivatives	16,511
Asset retirement obligations	158
Total Liabilities	$	16,868
Net Assets Acquired	$	67,942

June 2022 Acquisition

On June 30, 2022, the Company closed the acquisition of certain oil and gas assets located in Atascosa, La Salle, Live Oak and McMullen Counties, Texas, as well as assumed the seller’s commodity derivative contracts in place at the closing date, from Sundance Energy, Inc., and its affiliated entities Armadillo E&P, Inc. and SEA Eagle Ford, LLC (collectively, “Sundance”). After consideration of closing adjustments, total aggregate consideration consisted of cash, 4,148,472 shares of our common stock based on the Company’s share price on the closing date, accrued purchase price adjustments receivable and contingent consideration. 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 year ended December 31, 2023, the Company recorded gains of $1.0 million related valuation changes in the 2022 WTI Contingency Payout recorded in “Net gain (loss) on commodity derivatives” on the accompanying 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 year ended December 31, 2023, and we are no longer required to make a contingency payment related to the 2022 WTI Contingency Payout. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

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


Total Cost
Cash consideration	$	219,866
Equity consideration	117,651
Fair value of contingent consideration	7,422
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 cash 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 cash consideration was approximately $80.1 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.

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 $4.3 million. There was no gain or loss recognized in connection with the dispositions.

2023 Chesapeake Acquisition

On November 30, 2023, SilverBow closed the acquisition of certain oil and gas properties from Chesapeake, with consideration comprised of (i) cash paid at the closing of the Chesapeake Transaction, (ii) accrued purchase price adjustments receivable which were substantially collected in January 2024, (iii) a deferred acquisition liability due on the first anniversary of the closing of the Chesapeake Transaction and (iv) an earn-out payment contingent upon the average monthly settlement price of NYMEX West Texas Intermediate crude oil for the 12 month period beginning December 2023 (the “2023 WTI Contingency Payout”). If the average monthly settlement price of WTI during the 12 month period (a) exceeds $80 per barrel, SilverBow shall pay Chesapeake an amount equal to $50 million or (b) is between $75 per barrel and $80 per barrel, SilverBow shall pay Chesapeake an amount equal to $25 million. If the average monthly settlement price of WTI during the 12 month period is below $75 per barrel, SilverBow shall not owe Chesapeake a contingent earn-out payment. During the year ended December 31, 2023, the Company recorded gains of $4.3 million related to valuation changes in the 2023 WTI Contingency Payout recorded in “Net gain (loss) on commodity derivatives” on the accompanying consolidated 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 the Chesapeake Transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. The Chesapeake Transaction was funded with borrowings under the Company’s Credit Facility, proceeds from the issuance of additional Second Lien Notes and cash on hand.

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


Total Cost
Cash consideration	$	594,588
Accrued purchase price adjustments receivable	(18,100)
Fair value of contingent consideration	16,933
Deferred acquisition liability	50,000
Total Consideration	643,421
Transaction costs	10,003
Total Cost of Transaction	$	653,424

Allocation of Total Cost
Assets
Oil and gas properties	$	657,921
Right of use assets	187
Total assets	658,108

Liabilities
Accounts payable and accrued liabilities	3,040
Lease liability	187
Asset retirement obligations	1,457
Total Liabilities	4,684
Net Assets Acquired	$	653,424

10. Fair Value Measurements

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

The fair values of our derivative swap 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, 2022 WTI Contingency Payout and 2023 WTI Contingency Payout, included within “Accounts payable and accrued liabilities” and “Other long-term liabilities” on the consolidated balance sheets, 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 (collectively “Debt Facilities”) 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 on a relative fair value basis (refer to Note 9 of these Notes to Consolidated Financial Statements). Fair value was determined using a discounted cash flow model. The underlying future commodity prices included in the Company’s estimated future cash flows of its proved oil and gas properties were determined using NYMEX forward strip prices as of the closing date of each acquisition. The estimated future cash flows also included management’s assumptions for the estimates of crude oil and natural gas proved properties, future operating and development costs 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.

The following table presents our assets and liabilities that are measured on a recurring basis as of December 31, 2023 and 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 5 of these Notes to 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)
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		—

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 consolidated balance sheets in “Fair value of commodity derivatives” and “Fair value of long-term commodity derivatives,” respectively.

11. Asset Retirement Obligations

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

Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying consolidated balance sheets.

The following provides a roll-forward of our asset retirement obligations (in thousands):


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	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

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

Supplementary Information (unaudited)

SilverBow Resources, Inc. and Subsidiary

Oil and Gas Operations

Capitalized Costs. The following table presents our aggregate capitalized costs relating to oil and natural gas producing activities and the related depreciation, depletion, and amortization (in thousands):


	Total
December 31, 2023
Proved oil and gas properties	$	3,562,268
Unproved oil and gas properties	28,375
Total	3,590,643
Accumulated depreciation, depletion, amortization and impairment	(1,218,958)
Net capitalized costs	$	2,371,685

December 31, 2022
Proved oil and gas properties	$	2,506,853
Unproved oil and gas properties	16,272
Total	2,523,125
Accumulated depreciation, depletion, amortization and impairment	(1,000,086)
Net capitalized costs	$	1,523,039

There were $28.4 million and $16.3 million of unproved property costs at December 31, 2023 and 2022, respectively, excluded from the amortizable base. We evaluate the majority of these unproved costs within a two- to four-year time frame.

Capitalized asset retirement obligations have been included in the Proved oil and gas properties as of December 31, 2023 and 2022.

Costs Incurred. The following table sets forth costs incurred related to our oil and natural gas operations (in thousands) for the periods indicated:


	Year Ended December 31, 2023		Year Ended December 31, 2022		Year Ended December 31, 2021
Lease acquisitions and prospect costs	$	19,836	$	20,276	$	7,241
Exploration	—		—		—
Development (1) (3)	388,598		308,240		122,712
Acquisition of property(4)	659,797		592,945		138,016
Total acquisition, exploration, and development (2)	$	1,068,231	$	921,461	$	267,969

________________

(1) Facility construction costs and capital costs have been included in development costs, and totaled $30.1 million, $23.8 million and $9.2 million for the years ended December 31, 2023, 2022 and 2021, respectively.

(2) Includes capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately $5.5 million, $4.3 million and $4.8 million for the years ended December 31, 2023, 2022 and 2021, respectively. There was no capitalized interest on unproved properties for the years ended December 31, 2023, 2022 and 2021.

(3) Includes asset retirement obligations incurred, including revisions, of approximately $0.3 million, $1.2 million and $0.1 million for the years ended December 31, 2023, 2022 and 2021, respectively.

(4) Includes $156.3 million and $83.5 million in equity consideration for acquisitions of property for the years ended December 31, 2022 and 2021. Also includes $1.5 million, $2.7 million and $0.7 million in asset retirement obligations assumed in connection with acquisitions of property for the years ended December 31, 2023, 2022 and 2021, respectively.

Supplementary Reserves Information. The following information presents estimates of our proved oil and natural gas reserves. Reserves were prepared in accordance with SEC rules by H.J. Gruy and Associates, Inc. (“Gruy”) as of December 31, 2023, 2022 and 2021. Proved reserves, as of December 31, 2023, 2022 and 2021, were based upon the preceding 12-months’ average price based on closing prices on the first business day of each month, or prices defined by existing contractual arrangements which are held constant, for that year’s reserves calculation. The 12-month 2023 average adjusted prices after differentials used in our calculations were $2.30 per Mcf of natural gas, $76.79 per barrel of oil, and $25.43 per barrel of NGL compared to $6.14 per Mcf of natural gas, $94.36 per barrel of oil, and $34.76 per barrel of NGL for the 12-month average 2022 prices and $3.75 per Mcf of natural gas, $63.98 per barrel of oil, and $25.29 per barrel of NGL for 2021.


	Total	Natural Gas	Oil	NGL
Estimates of Proved Reserves	(Boe)	(Mcf)	(Bbls)	(Bbls)
Proved reserves as of December 31, 2020	184,402,513	948,094,943	12,531,501	13,855,188
Extensions, discoveries, and other additions (3)	59,895,777	324,625,474	3,930,631	1,860,900
Revisions of previous estimates (1)	(33,078,574)	(199,625,710)	(1,644,367)	1,836,746
Purchases of minerals in place (4)	37,760,832	142,794,045	10,942,051	3,019,773
Production	(13,018,813)	(60,509,606)	(1,461,657)	(1,472,222)
Proved reserves as of December 31, 2021	235,961,735	1,155,379,146	24,298,159	19,100,385
Extensions, discoveries, and other additions (3)	94,539,189	514,492,260	5,423,639	3,366,839
Revisions of previous estimates (1)	(456,014)	561,425	(1,097,823)	548,238
Purchases of minerals in place (4)	59,245,115	126,849,989	26,393,737	11,709,713
Sales of minerals in place	(442,746)	(772,177)	(194,839)	(119,211)
Production	(16,409,985)	(70,958,470)	(2,633,679)	(1,949,894)
Proved reserves as of December 31, 2022	372,437,294	1,725,552,173	52,189,194	32,656,070
Extensions, discoveries, and other additions (3)	43,686,640	119,845,187	16,354,678	7,357,764
Revisions of previous estimates (1)	(91,345,586)	(420,648,210)	(12,874,771)	(8,362,781)
Purchases of minerals in place (4)	142,738,313	333,089,681	44,635,572	42,587,795
Production	(21,666,699)	(79,899,894)	(5,346,813)	(3,003,236)
Proved reserves as of December 31, 2023	445,849,962	1,677,938,937	94,957,860	71,235,612

Proved developed reserves (2)
December 31, 2020	84,358,235	415,390,459	6,962,826	8,163,666
December 31, 2021	109,705,103	525,736,580	9,692,076	12,390,263
December 31, 2022	158,796,480	695,481,580	23,360,025	19,522,859
December 31, 2023	202,119,513	736,075,384	40,738,215	38,702,068

Proved undeveloped reserves
December 31, 2020	100,044,279	532,704,484	5,568,676	5,691,522
December 31, 2021	126,256,632	629,642,566	14,606,082	6,710,122
December 31, 2022	213,640,813	1,030,070,593	28,829,169	13,133,211
December 31, 2023	243,730,448	941,863,553	54,219,645	32,553,544

________________

(1) Revisions of previous estimates are related to upward or downward variations based on current engineering information for production rates, volumetrics, reservoir pressure and commodity pricing. The downward revisions for 2023 include approximately 9.9 MMboe due to performance revisions, 5.0 MMboe due to demonstrated changes in operating expenses, 56.7 MMboe attributable to the reclassification of PUDs to unproved primarily due to negative changes in commodity pricing and changes in the Company’s five-year development plan and a Company-wide negative commodity sales price revision of 19.2 MMboe. The downward revisions for 2022 include approximately 7.9 MMboe due to performance

revisions, 1.5 MMboe due to demonstrated changes in operating expenses and 0.5 MMboe attributable to the reclassification of PUDs to unproved due to changes in the Company’s five-year development plan, partially offset by positive revision of 6.0 MMboe due to incremental interest related to non-consent participation of a working interest partner in our Webb County Gas operating area and a Company-wide positive commodity sales price revisions of 3.4 MMboe. The downward revisions for 2021 include approximately 28.4 MMboe attributable to the reclassification of PUDs to unproved due to changes in the Company’s five-year development plan, 10.5 MMboe due to performance revisions, and 1.1 MMboe due to demonstrated changes in operating expenses, partially offset by Company-wide positive commodity sales price revisions of 7.0 MMboe.

(2) At December 31, 2023, 2022 and 2021, 45%, 43% and 46% of our reserves were proved developed.

(3) The 2023 additions were due to discovery and extensions of 43.7 MMboe attributable to drilling results of 35.3 MMboe and leasing of adjacent acreage of 8.4 MMboe. Similarly, the 2022 additions were due to discovery and extensions of 94.5 MMboe attributable to drilling results of 26.6 MMboe and leasing of adjacent acreage of 68.0 MMboe. Similarly, the 2021 additions were due to discovery and extensions of 59.9 MMboe attributable to drilling results of 55.3 MMboe and leasing of adjacent acreage of 4.6 MMboe.

(4) Purchases of minerals in place for 2023 are 142.7 MMboe and relate to our November 2023 Acquisition. Purchases of minerals in place for 2022 are 59.3 MMboe and relate to our May 2022 Acquisition of 14.2 MMboe, June 2022 Acquisition of 33.7 MMboe, August 2022 Acquisition of 4.3 MMboe and October 2022 Acquisition of 7.1 MMboe. Purchases of minerals in place for 2021 are 37.8 MMboe and relate to our August 2021 Acquisition of 18.9 MMboe, October 2021 Acquisition of 7.5 MMboe, November 2021 Acquisition of 9.1 MMboe and several smaller acquisitions totaling 2.2 MMboe.

Standardized Measure of Discounted Future Net Cash Flows. The Standardized Measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows (in thousands):


	As of December 31,
	2023		2022		2021
Future gross revenues	$	12,969,683	$	16,660,470	$	6,370,628
Future production costs	(4,847,117)		(4,039,248)		(1,853,856)
Future development costs (1)	(2,664,248)		(2,063,508)		(753,046)
Future net cash flows before income taxes	5,458,318		10,557,714		3,763,726
Future income taxes	(735,545)		(1,953,345)		(584,613)
Future net cash flows after income taxes	4,722,773		8,604,369		3,179,113
Discount at 10% per annum	(2,403,331)		(4,564,123)		(1,620,651)
Standardized Measure of discounted future net cash flows relating to proved oil and natural gas reserves	$	2,319,442	$	4,040,246	$	1,558,462

________________

(1) These amounts include future costs related to plugging and abandoning the Company’s wells.

The Standardized Measure of discounted future net cash flows from production of proved reserves as of December 31, 2023, 2022 and 2021, were developed as follows:

1. Estimates were made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions.

2. The estimated future gross revenues of proved reserves were based on the preceding 12-months’ average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements.

3. The future gross revenues were reduced by estimated future costs to develop and to produce the proved reserves, including asset retirement obligation costs, based on year-end cost estimates and the estimated effect of future income taxes.

4. Future income taxes were computed by applying the statutory tax rate to future net cash flows reduced by the tax basis of the properties, the estimated permanent differences applicable to future oil and natural gas producing activities and tax carry forwards.

The Standardized Measure of discounted future net cash flows is not intended to present the fair market value of our oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, an allowance for return on investment, and the risks inherent in reserves estimates.

The following are the principal sources of changes in the Standardized Measure of discounted future net cash flows (in thousands) for the years ended December 31, 2023, 2022 and 2021:


	2023		2022		2021
Beginning balance	$	4,040,246	$	1,558,462	$	512,952

Revisions to reserves proved in prior years:
Net changes in prices, net of production costs	(2,933,837)		1,852,439		781,786
Net changes in future development costs	(50,504)		(208,188)		1,569
Net changes due to revisions in quantity estimates	(1,132,376)		(4,218)		(43,379)
Accretion of discount	496,401		181,678		52,627
Changing in timing and other	53,531		(176,112)		29,303
Total revisions	(3,566,785)		1,645,599		821,906

New field discoveries and extensions, net of future production and development costs	340,307		968,093		400,008
Purchase of reserves	1,166,443		1,051,869		345,300
Sales of minerals in place	—		(5,209)		—
Sales of oil and gas produced, net of production costs	(464,199)		(621,686)		(336,028)
Previously estimated development costs incurred	224,052		108,566		59,318
Net change in income taxes	579,378		(665,448)		(244,994)
Net change in Standardized Measure of discounted future net cash flows	(1,720,804)		2,481,784		1,045,510
Ending balance	$	2,319,442	$	4,040,246	$	1,558,462

Exhibit 99.3

Table of Contents

PART I. FINANCIAL INFORMATION

Condensed Consolidated Balance Sheets (Unaudited)

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


	June 30, 2024		December 31, 2023
ASSETS
Current Assets:
Cash and cash equivalents	$	1,865	$	969
Accounts receivable, net	134,571		138,343
Fair value of commodity derivatives	66,077		116,549
Other current assets	7,034		5,590
Total Current Assets	209,547		261,451
Property and Equipment:
Property and equipment, full cost method, including $33,925 and $28,375, respectively, of unproved property costs not being amortized at the end of each period	3,827,149		3,597,160
Less – Accumulated depreciation, depletion, amortization & impairment	(1,408,139)		(1,223,241)
Property and Equipment, Net	2,419,010		2,373,919
Right of use assets	19,405		12,888
Fair value of long-term commodity derivatives	20,917		55,114
Other long-term assets	26,673		31,090
Total Assets	$	2,695,552	$	2,734,462
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	169,342	$	98,816
Deferred acquisition liability	50,000		50,000
Fair value of commodity derivatives	23,550		5,509
Accrued capital costs	37,157		31,900
Current portion of long-term debt	37,500		28,125
Accrued interest	7,657		9,668
Current lease liability

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