sbow-20240331

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

of the Securities Exchange Act of 1934

For the quarterly period ended March 31, 2024

Commission File Number 1-8754

SILVERBOW RESOURCES, INC.

(Exact Name of Registrant as Specified in Its Charter)


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

920 Memorial City Way, Suite 850

Houston, Texas 77024

(281) 874-2700

(Address and telephone number of principal executive offices)

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


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

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


Yes			þ			No			o

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


Yes			þ			No			o

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

Large Accelerated Filer

Accelerated Filer

Non-Accelerated Filer

Smaller Reporting Company

Emerging Growth Company

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


o

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


Yes			o			No			þ

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

of common stock, as of the latest practicable date.


Common Stock ($.01 Par Value) (Class of Stock)			25,538,487 Shares outstanding at April 26, 2024

SILVERBOW RESOURCES, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2024

INDEX


		Page
Part I	FINANCIAL INFORMATION

Item 1.	Condensed Consolidated Financial Statements

	Condensed Consolidated Balance Sheets	6

	Condensed Consolidated Statements of Operations	7

	Condensed Consolidated Statements of Stockholders’ Equity	8

	Condensed Consolidated Statements of Cash Flows	9

	Notes to Condensed Consolidated Financial Statements	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36

Item 4.	Controls and Procedures	37

Part II	OTHER INFORMATION

Item 1.	Legal Proceedings	38
Item 1A.	Risk Factors	38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 3.	Defaults Upon Senior Securities	38
Item 4.	Mine Safety Disclosures	39
Item 5.	Other Information	39
Item 6.	Exhibits	39

SIGNATURES		40

Forward-Looking Statements

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

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

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

•risks related to recently completed acquisitions and integration of these acquisitions, including the acquisition (the “South Texas Acquisition”) of oil and gas assets in South Texas;

•volatility in oil, natural gas and natural gas liquids prices;

•ability to obtain permits and government approvals;

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

•asset disposition efforts or the timing or outcome thereof;

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

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

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

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

•availability, cost and terms of capital;

•timing and successful drilling and completion of wells;

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

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

•competition in the oil and natural gas industry;

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

•the severity and duration of world health events, including health crises and pandemics, related economic repercussions, including disruptions in the oil and gas industry, supply chain disruptions, and operational challenges;

•opportunities to monetize assets;

•our ability to execute on strategic initiatives, including acquisitions;

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

•counterparty and credit market risk;

•pending legal and environmental matters, including potential impacts on our business related to climate change and related regulations;

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

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

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

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

•uncertainty regarding our future operating results; and

•other risks and uncertainties described in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2023 and our other filings with the Securities and Exchange Commission (“SEC”).

Many of the foregoing risks and uncertainties, as well as risks and uncertainties that are currently unknown to us, are, and may be, exacerbated by geopolitical events and wars, increasing economic uncertainty, recessionary and inflationary pressures and any consequent worsening of the global business and economic environment. New factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of the risks or uncertainties described in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2023, subsequent Quarterly Reports on Form 10-Q, or other SEC filings occur, or should underlying assumptions prove incorrect, actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements speak only as of the date they are made. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” and in other disclosures in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2023 and in subsequent Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and our other filings with the SEC. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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

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PART I. FINANCIAL INFORMATION

Condensed Consolidated Balance Sheets (Unaudited)

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


	March 31, 2024		December 31, 2023

ASSETS
Current Assets:
Cash and cash equivalents	$	1,446	$	969
Accounts receivable, net	125,459		138,343
Fair value of commodity derivatives	89,535		116,549

Other current assets	5,652		5,590
Total Current Assets	222,092		261,451
Property and Equipment:
Property and equipment, full cost method, including $30,899 and $28,375, respectively, of unproved property costs not being amortized at the end of each period	3,709,469		3,597,160
Less – Accumulated depreciation, depletion, amortization & impairment	(1,315,364)		(1,223,241)
Property and Equipment, Net	2,394,105		2,373,919
Right of use assets	20,658		12,888
Fair value of long-term commodity derivatives	29,432		55,114


Other long-term assets	28,876		31,090
Total Assets	$	2,695,163	$	2,734,462
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	143,684	$	98,816
Deferred acquisition liability	50,000		50,000
Fair value of commodity derivatives	26,333		5,509
Accrued capital costs	42,114		31,900
Current portion of long-term debt	37,500		28,125
Accrued interest	8,325		9,668
Current lease liability	7,765		4,001
Undistributed oil and gas revenues	37,754		20,425
Total Current Liabilities	353,475		248,444
Long-term debt, net of current portion	1,039,469		1,173,766
Non-current lease liability	12,955		8,899
Deferred tax liabilities	94,077		99,227
Asset retirement obligations	11,913		11,584
Fair value of long-term commodity derivatives	8,110		2,504
Other long-term liabilities	—		710
Commitments and Contingencies (Note 11)
Stockholders' Equity:
Preferred stock, $0.01 par value, 10,000,000 shares authorized, none issued	—		—
Common stock, $0.01 par value, 40,000,000 shares authorized, 26,027,103 and 25,914,956 shares issued, respectively, and 25,523,808 and 25,429,610 shares outstanding, respectively	260		259
Additional paid-in capital	681,099		679,202
Treasury stock, held at cost, 503,295 and 485,346 shares, respectively	(11,151)		(10,617)
Retained earnings	504,956		520,484
Total Stockholders’ Equity	1,175,164		1,189,328
Total Liabilities and Stockholders’ Equity	$	2,695,163	$	2,734,462
See accompanying Notes to Condensed Consolidated Financial Statements.

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Condensed Consolidated Statements of Operations (Unaudited)

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


	Three Months Ended March 31, 2024		Three Months Ended March 31, 2023
Revenues	$	256,680	$	139,954

Operating Expenses:
General and administrative, net	8,791		7,664
Depreciation, depletion, and amortization	92,103		43,998
Accretion of asset retirement obligations	316		224
Lease operating expenses	31,825		20,560
Workovers	610		779
Transportation and gas processing	35,199		11,520
Severance and other taxes	16,212		9,385

Total Operating Expenses	185,056		94,130

Operating Income	71,624		45,824

Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net	(56,078)		92,249
Interest expense, net	(36,017)		(16,745)
Other income (expense), net	156		(24)

Income (Loss) Before Income Taxes	(20,315)		121,304

Provision (Benefit) for Income Taxes	(4,787)		26,812

Net Income (Loss)	$	(15,528)	$	94,492

Per Share Amounts:

Basic Earnings (Loss) Per Share	$	(0.61)	$	4.21

Diluted Earnings (Loss) Per Share	$	(0.61)	$	4.17

Weighted-Average Shares Outstanding - Basic	25,445		22,440

Weighted-Average Shares Outstanding - Diluted	25,445		22,634

See accompanying Notes to Condensed Consolidated Financial Statements.

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Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

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


	Common Stock		Additional Paid-In Capital		Treasury Stock		Retained Earnings (Accumulated Deficit)		Total
Balance, December 31, 2022	$	227	$	576,118	$	(7,534)	$	222,768	$	791,579

Purchase of treasury shares (126,240 shares)	—		—		(2,945)		—		(2,945)

Vesting of share-based compensation (418,518 shares)	4		(4)		—		—		—

Share-based compensation	—		1,179		—		—		1,179
Net Income	—		—		—		94,492		94,492
Balance, March 31, 2023	$	231	$	577,293	$	(10,479)	$	317,260	$	884,305














Balance, December 31, 2023	$	259	$	679,202	$	(10,617)	$	520,484	$	1,189,328

Purchase of treasury shares (17,949 shares)	—		—		(534)		—		(534)

Vesting of share-based compensation (112,147 shares)	1		(1)		—		—		—

Share-based compensation	—		1,898		—		—		1,898
Net Loss	—		—		—		(15,528)		(15,528)
Balance, March 31, 2024	$	260	$	681,099	$	(11,151)	$	504,956	$	1,175,164











See accompanying Notes to Condensed Consolidated Financial Statements.

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Condensed Consolidated Statements of Cash Flows (Unaudited)

SilverBow Resources, Inc. and Subsidiary (in thousands)


	Three Months Ended March 31, 2024		Three Months Ended March 31, 2023
Cash Flows from Operating Activities:
Net income (loss)	$	(15,528)	$	94,492
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	92,103		43,998

Accretion of asset retirement obligations	316		224
Deferred income taxes	(5,150)		26,612
Share-based compensation	1,830		1,124
(Gain) Loss on derivatives, net	56,078		(92,249)
Cash settlement (paid) received on derivatives	38,371		18,699
Settlements of asset retirement obligations	(2)		(3)

Other, net	3,362		756
Change in operating assets and liabilities:
(Increase) decrease in accounts receivable and other current assets	(5,374)		30,687
Increase (decrease) in accounts payable and accrued liabilities	24,557		(24,504)
Increase (decrease) in income taxes payable	465		300
Increase (decrease) in accrued interest	(1,343)		(441)
Net Cash Provided by (Used in) Operating Activities	189,685		99,695
Cash Flows from Investing Activities:
Additions to property and equipment	(80,225)		(111,285)
Acquisition of oil and gas properties, net of purchase price adjustments	11,821		(1,090)

Proceeds from the sale of property and equipment	5,730		—



Net Cash Provided by (Used in) Investing Activities	(62,674)		(112,375)
Cash Flows from Financing Activities:

Proceeds from bank borrowings	128,000		121,000
Payments of bank borrowings	(254,000)		(104,000)


Purchase of treasury shares	(534)		(2,945)

Net Cash Provided by (Used in) Financing Activities	(126,534)		14,055
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	477		1,375
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	8,729		792
Cash, Cash Equivalents and Restricted Cash at End of Period	$	9,206	$	2,167
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for interest	$	34,072	$	16,434

Non-cash Investing and Financing Activities:
Changes in capital accounts payable and capital accruals	$	29,194	$	(3,097)



See accompanying Notes to Condensed Consolidated Financial Statements.

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Notes to Condensed Consolidated Financial Statements (Unaudited)

SilverBow Resources, Inc. and Subsidiary

(1) General Information

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

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

The condensed consolidated financial statements are unaudited and certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The unaudited condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2023.

(2) Summary of Significant Accounting Policies

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

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

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

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

In April 2024, the Company entered into a non-cash exchange agreement with a third party to receive approximately 7,700 net acres and working interest in multiple wells in La Salle and McMullen counties. The Company will transfer approximately 5,100 net acres and working interest in 13 wells in DeWitt, Lavaca and McMullen counties. The exchange is subject to customary purchase price adjustments.

Through April 30, 2024, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after March 31, 2024:


Oil Derivative Contracts (NYMEX WTI Settlements)	Total Volumes (Bbls)	Weighted-Average Price
Swap Contracts
2024 Contracts
3Q24	92,000	$	80.47
4Q24	92,000	$	80.47
2025 Contracts
1Q25	180,000	$	76.00
2Q25	182,000	$	75.18
3Q25	184,000	$	74.46
4Q25	184,000	$	73.85


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


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

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Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes (MMBtu)	Weighted-Average Price
2024 Contracts
4Q24	920,000	$	(0.49)
2025 Contracts
1Q25	3,600,000	$	(0.30)
2Q25	3,640,000	$	(0.30)
3Q25	3,680,000	$	(0.30)
4Q25	3,680,000	$	(0.30)

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

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

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

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

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

•estimates of future costs to develop and produce reserves,

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

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

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

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

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

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

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

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

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

•estimates on future lease obligations.

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

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

Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended March 31, 2024 and 2023, such internal costs capitalized totaled $1.1 million

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

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


	March 31, 2024		December 31, 2023
Property and Equipment
Proved oil and gas properties	$	3,671,913	$	3,562,268
Unproved oil and gas properties	30,899		28,375
Furniture, fixtures and other equipment	6,657		6,517
Less – Accumulated depreciation, depletion, amortization & impairment	(1,315,364)		(1,223,241)
Property and Equipment, Net	$	2,394,105	$	2,373,919

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

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

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

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

The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. There was no ceiling test write-down for either of the three months ended March 31, 2024 and 2023.

If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, it is possible that non-cash write-downs of

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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 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 Ceiling Test write-downs in future periods.

Accounts Receivable, Net. We assess the collectability of accounts receivable based on a broad range of reasonable and forward-looking information including historical losses, current economic conditions, future forecasts and contractual terms. The Company's credit losses based on these assessments are considered immaterial. At March 31, 2024, December 31, 2023 and December 31, 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 condensed consolidated balance sheets.

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

Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the three months ended March 31, 2024 and 2023 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $5.4 million and $2.7 million for the three months ended March 31, 2024 and 2023, respectively.

Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. The Company's effective tax rate was approximately 24% and 22% for the three months ended March 31, 2024 and 2023, respectively. The Company recorded an income tax benefit of $4.8 million for the three months ended March 31, 2024 and an income tax provision of $26.8 million for the three months ended March 31, 2023, respectively. The tax impact for both periods was a product of the overall forecasted annual effective tax rate applied to the year-to-date income.

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

Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At March 31, 2024 and 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.

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

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


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

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


	March 31, 2024		December 31, 2023
Trade accounts payable	$	52,924	$	32,225
Accrued operating expenses	26,183		23,104
Accrued compensation costs	7,281		10,208
Asset retirement obligations – current portion	1,597		1,576
Accrued non-income based taxes	10,447		3,870
Accrued corporate and legal fees	119		208
WTI contingency payouts - current portion	26,759		14,282
Payable for settled derivatives	2,828		967
Other payables(1)	15,546		12,376
Total accounts payable and accrued liabilities	$	143,684	$	98,816

(1) At March 31, 2024 and December 31, 2023 included in Other Payables is $7.8 million in payables related to advances from joint interest owners in connection with our South Texas Acquisition.

Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted. The Company maintains cash and cash equivalent balances with major financial institutions, which at times exceed federally insured limits. The Company monitors the financial condition of the financial institutions and has experienced no losses associated with these accounts. The Company did not have any cash equivalents at March 31, 2024 and December 31, 2023.

Restricted Cash. Restricted cash includes amounts held in escrow accounts to satisfy plugging and abandonment obligations and operational maintenance projects.

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):


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

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

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

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

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New Accounting Pronouncements. 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.

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

(3) Leases

The Company follows the FASB's Accounting Standards Codification Topic No. 842 and elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that allows an entity to carry forward historical accounting treatment for land easements on existing agreements. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the condensed consolidated balance sheets. We have elected to not account for lease and non-lease components separately.

The Company has contractual agreements for its corporate office lease, vehicle fleet, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of March 31, 2024, all of the Company’s leases were operating leases.

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

As of March 31, 2024, the Company's future cash payment obligation for its operating lease liabilities are as follows (in thousands):


	As of March 31, 2024
2024 (Remaining)	$	7,077
2025	7,987
2026	2,968
2027	1,997
2028	1,402
Thereafter	2,710
Total undiscounted lease payments	24,141
Present value adjustment	(3,421)
Net operating lease liabilities	$	20,720

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(4) Share-Based Compensation

Share-Based Compensation Plans

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

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

The expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying condensed consolidated statements of operations was $1.8 million and $1.1 million for the three months ended March 31, 2024 and 2023, respectively. Capitalized share-based compensation was less than $0.1 million for both the three months ended March 31, 2024 and 2023.

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

Stock Option Awards

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

At March 31, 2024, we had no unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the three months ended March 31, 2024:


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


Options exercised	—	$	—
Options outstanding, end of period	196,162	$	26.46	3.1	$	1,506
Options exercisable, end of period	196,162	$	26.46	3.1	$	1,506

Restricted Stock Units

The Plans allow for the issuance of restricted stock unit awards that generally may not be sold or otherwise transferred until certain restrictions have lapsed. The compensation cost related to restricted stock awards is based on the grant date fair value and is typically expensed over the requisite service period (generally one to five years).

As of March 31, 2024, we had $10.4 million unrecognized compensation expense related to our RSUs which is expected to be recognized over a weighted-average period of 2.2 years.

The following table provides information regarding RSU activity for the three months ended March 31, 2024:


	RSUs	Wtd. Avg. Grant Price
RSUs outstanding, beginning of period	285,163	$	24.61
RSUs granted	233,168	$	31.08


RSUs forfeited	(4,683)	$	29.08
RSUs vested	(112,147)	$	23.57
RSUs outstanding, end of period	401,501	$	28.60

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Performance-Based Stock Units

On February 24, 2021, the Company granted 161,389 PSUs for which the number of shares earned is based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2021 to December 31, 2022. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $13.13 per unit or 157.6% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of two years. 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 on an absolute and relative basis compared to the TSR of its selected peers during the performance period from January 1, 2022 to December 31, 2024. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $36.47 per unit or 150.93% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years. All PSUs granted remain outstanding related to this award as of March 31, 2024.

On February 23, 2023, the Company granted 120,749 PSUs for which the number of shares earned is based on the TSR of the Company's common stock on an absolute and relative basis compared to the TSR of its selected peers during the performance period from January 1, 2023 to December 31, 2025. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $31.18 per unit or 136.28% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years. All PSUs granted remain outstanding related to this award as of March 31, 2024.

On February 21, 2024, the Company granted 132,930 PSUs for which the number of shares earned is based on the TSR of the Company's common stock on an absolute and relative basis compared to the TSR of its selected peers during the performance period from January 1, 2024 to December 31, 2026. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $34.99 per unit or 124.74% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years. All PSUs granted remain outstanding related to this award as of March 31, 2024.

On March 27, 2024, the Company granted 23,103 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2024 to December 31, 2026. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $46.18 per unit or 133.11% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years. All PSUs granted remain outstanding related to this award as of March 31, 2024.

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

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The following table provides information regarding performance-based stock unit activity for the three months ended March 31, 2024:


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


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

(5) Earnings Per Share

Basic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three months ended March 31, 2024 and 2023 are discussed below.

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


	Three Months Ended March 31, 2024					Three Months Ended March 31, 2023
	Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)		Shares	Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	(15,528)	25,445	$	(0.61)	$	94,492	22,440	$	4.21
Dilutive Securities:
Performance Based Stock Unit Awards			—					97
RSU Awards			—					91
Stock Option Awards			—					6
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	(15,528)	25,445	$	(0.61)	$	94,492	22,634	$	4.17

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


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

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(6) Long-Term Debt

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


	March 31, 2024		December 31, 2023
Credit Facility Borrowings due 2026 (1)	$	596,000	$	722,000
Second Lien Notes due 2028	500,000		500,000
	1,096,000		1,222,000
Unamortized discount on Second Lien Notes due 2028	(7,401)		(7,820)
Unamortized debt issuance cost on Second Lien Notes due 2028	(11,630)		(12,289)
Total Debt	$	1,076,969	$	1,201,891
Less: Current portion of Second Lien Notes due 2028	37,500		28,125
Long-term debt, net	$	1,039,469	$	1,173,766

(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our condensed consolidated balance sheet. As of March 31, 2024 and December 31, 2023, we had $22.7 million and $24.9 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.

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

In conjunction with the closing of the South Texas Acquisition described further in Note 7, 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 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 March 31, 2024 and December 31, 2023. 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. The Credit Facility matures October 19, 2026, and provides for a maximum credit amount of $2.0 billion, subject to the current borrowing base of $1.2 billion.

Interest under the Credit Facility is payable quarterly and accrues at the Company’s option either at an Alternative Base Rate plus the applicable margin (“ABR Loans”), the Adjusted Term Secured Overnight Financing Rate (“SOFR”) plus the applicable margin (“Term Benchmark Loans”) or Adjusted Daily Simple SOFR plus the applicable margin (“RFR Loans”). The applicable margin ranged from 1.75% to 2.75% based on borrowing base utilization for ABR Loans and 2.75% to 3.75% based on borrowing base utilization for Term Benchmark Loans and RFR Loans. The Alternate Base Rate and SOFR are defined, and the applicable margins are set forth, in the Credit Agreement. Undrawn amounts under the Credit Facility are subject to a 0.5% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. As of March 31, 2024, the Company's weighted average interest rate on Credit Facility borrowings was 8.42%.

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

The Credit Agreement contains the following financial covenants:

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

•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 March 31, 2024, the Company was in compliance with all financial covenants under the Credit Agreement.

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

Total interest expense on the Credit Facility, which includes commitment fees and amortization of debt issuance costs, was $18.3 million and $11.9 million for the three months ended March 31, 2024 and 2023, respectively. The amount of commitment fee amortization included in interest expense, net was $0.6 million and $0.3 million for the three months ended March 31, 2024 and 2023, respectively.

Senior Secured Second Lien Notes. On December 15, 2017, the Company entered into a Note Purchase Agreement for Senior Secured Second Lien Notes (as amended, the “Note Purchase Agreement,” and such second lien facility the “Second Lien Notes”) among the Company as issuer, U.S. Bank National Association as agent and collateral agent, and certain holders that are a party thereto, and issued notes in an initial principal amount of $200.0 million, with a $2.0 million discount, for net proceeds of $198.0 million.

Effective November 12, 2021, the Company entered into the Second Amendment to the Note Purchase Agreement, which extended the maturity date from December 15, 2024 to December 15, 2026 subject to paying down the principal amount of the Second Lien Notes from $200.0 million to $150.0 million. The Company made the $50.0 million redemption of the Second Lien Notes on November 29, 2021.

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

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 the South Texas Acquisition described further in Note 7. 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 was included within “Interest expense, net” on the condensed consolidated statements of operations. Additionally, the Company incurred approximately $10.6 million in third party fees in connection with the amendment. The new debt issuance cost and discount on the Second Lien 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

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Coverage Ratio (as defined in the Note Purchase Agreement) to be no less than (A) 1.10 to 1.00 through the fiscal quarter ending March 31, 2024 and (B) 1.25 to 1.00 thereafter, in each 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 in quarterly payments of $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 Notes 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 March 31, 2024, the Company’s interest rate on the Second Lien Notes was 13.08%. As of March 31, 2024, the Company was in compliance with all financial covenants under the Second Lien Notes.

The obligations under the Second Lien Notes are secured, subject to certain exceptions and other permitted liens (including the liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit Facility, and mortgage lien on substantially all assets of the Company and its subsidiary, including a mortgage lien on oil and gas properties attributed with at least 85% 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 March 31, 2024, total net amounts recorded for the Second Lien Notes were $481.0 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien Notes totaled $17.7 million and $4.8 million for the three months ended March 31, 2024 and 2023, respectively.

Debt Issuance Costs. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings. During the three months ended March 31, 2024 and 2023 there were no capitalized costs incurred.

(7) Acquisitions and Dispositions

2023 South Texas Acquisition

On November 30, 2023, SilverBow closed the acquisition of certain oil and gas properties from entities affiliated with Chesapeake Energy Corporation, with consideration comprised of (i) cash paid at the closing of the South Texas Acquisition, (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 South Texas Acquisition 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 three months ended March 31, 2024, the Company recorded losses of $12.8 million related to valuation changes in the 2023 WTI Contingency Payout recorded in “Net gain (loss) on commodity derivatives” on the accompanying condensed 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 South Texas Acquisition as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. The South Texas Acquisition was funded with borrowings under the Company's Credit Facility, proceeds from the issuance of additional Second Lien Notes and cash on hand.

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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	$	583,373

Fair value of contingent consideration	16,933
Deferred acquisition liability	50,000
Total Consideration	650,306

Transaction costs	10,916
Total Cost of Transaction	$	661,222

Allocation of Total Cost
Assets
Accounts receivable, net	$	1,594
Oil and gas properties	666,360
Right of use assets	187
Total assets	668,141

Liabilities
Accounts payable and accrued liabilities	5,275
Lease liability	187
Asset retirement obligations	1,457
Total Liabilities	6,919
Net Assets Acquired	$	661,222

(8) Price-Risk Management Activities

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

During the three months ended March 31, 2024 and 2023, the Company recorded losses of $42.7 million and gains of $91.2 million, respectively, on its commodity derivatives. During the three months ended March 31, 2024 and 2023, the Company recorded losses of $13.4 million and gains of $1.0 million, respectively, related to valuation changes on our WTI Contingency Payouts. The Company collected cash payments of $38.4 million and $18.7 million for settled derivative contracts during the three months ended March 31, 2024 and 2023, respectively.

At March 31, 2024 and December 31, 2023, there was $13.4 million and $13.5 million, respectively, in receivables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts receivable, net” and were subsequently collected in April 2024 and January 2024, respectively. At March 31, 2024 and December 31, 2023, we also had $2.8 million and $1.0 million, respectively, in payables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts payable and accrued liabilities” and were subsequently paid in April 2024 and January 2024, respectively.

The fair values of our swap contracts are computed using observable market data whereas our collar contracts are valued using a Black-Scholes pricing model. At March 31, 2024, there was $89.5 million and $29.4 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $26.3 million and $8.1 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2023, there was $116.5 million and $55.1 million in current and long-term unsettled derivative assets, respectively, and $5.5 million and $2.5 million in current and long-term unsettled derivative liabilities, respectively.

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The Company uses an International Swap and Derivatives Association master agreement for our derivative contracts. This is an industry-standardized contract containing the general conditions of our derivative transactions including provisions relating to netting derivative settlement payments under certain circumstances (such as default). For reporting purposes, the Company has elected to not offset the asset and liability fair value amounts of its derivatives on the accompanying condensed consolidated balance sheet. Under the right of set-off, there was a $84.5 million net fair value asset at March 31, 2024, and a $163.6 million net fair value asset at December 31, 2023. For further discussion related to the fair value of the Company's derivatives, refer to Note 9 of these Notes to Condensed Consolidated Financial Statements.

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


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

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Oil Basis Swaps (Argus Cushing (WTI) and Magellan East Houston)	Total Volumes (MMBtu)	Weighted-Average Price
2024 Contracts
2Q24	486,000	$	1.49
3Q24	552,000	$	1.49
4Q24	552,000	$	1.49
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
2Q24	486,000	$	0.71
3Q24	552,000	$	0.72
4Q24	552,000	$	0.72
2025 Contracts
1Q25	360,000	$	0.43
2Q25	364,000	$	0.43
3Q25	368,000	$	0.43
4Q25	368,000	$	0.43

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Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Price		Weighted-Average Collar Sub Floor Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
Swap Contracts
2024 Contracts
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
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
2Q24	188,000			$	2.00	$	2.50	$	3.37


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

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NGL Swaps (Mont Belvieu)	Total Volumes (Bbls)	Weighted-Average Price
2024 Contracts
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

(9) Fair Value Measurements

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

The fair values of our derivative contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model. The fair value of the current and long-term 2021 WTI Contingency Payout and 2023 WTI Contingency Payout, included within “Accounts payable and accrued liabilities” and “Other long-term liabilities” on the condensed consolidated balance sheets, respectively, is estimated using observable market data and a Monte Carlo pricing model. These are considered Level 2 valuations (defined below).

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

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

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

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

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

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

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

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

The following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of March 31, 2024 and December 31, 2023, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company’s derivatives, refer to Note 8 of these Notes to Condensed Consolidated Financial Statements.


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

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

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

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(10) Asset Retirement Obligations

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

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


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

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



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

At both March 31, 2024 and December 31, 2023, approximately $1.6 million of our asset retirement obligations, respectively, were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets.

(11) Commitments and Contingencies

In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as 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.

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

You should read the following discussion and analysis in conjunction with the Company’s financial information and its unaudited condensed consolidated financial statements and accompanying notes included in this report and its audited consolidated financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2023. The following information contains forward-looking statements; see “Forward-Looking Statements” in this report.

Company Overview

SilverBow is the Eagle Ford's largest independent oil and gas company, headquartered in Houston. The Company's proven strategy to create value is focused on acquiring and developing assets in South Texas where it has assembled approximately 220,000 net acres in the Eagle Ford and Austin Chalk. SilverBow's average operated interest is 82% which allows the Company to control how it prioritizes development across its acreage position. SilverBow is differentiated from its peers through a diverse portfolio of assets that provides commodity optionality. The Company's results are enhanced with the Eagle Ford's proximity to premium Gulf Coast markets, which allows SilverBow to capture higher margins.

Operational Results and Strategy

Average net production for the first quarter of 2024 increased 80% over the prior year’s comparable period to 91.4 MBoe/d. Oil production averaged 24.5 thousand barrels of oil per day, up nearly 116% over the comparable period. Production mix for the quarter consisted of 54% natural gas, 27% crude oil and 19% NGLs. The significant increase in production is primarily related to SilverBow's transformative South Texas Acquisition in late 2023 and continued gains in well productivity.

In early 2024, the Company made significant changes in reaction to recent, low natural gas prices. To maximize cash flow, planned capital investments in natural gas assets were reduced by $75 million and such capital was shifted to liquids-rich development. As a result, first quarter financial and operating results reflected better than expected production and cash flow during the period which allowed SilverBow to reduce debt and lower its quarter-end leverage ratio. Since the closing of the Company's South Texas Acquisition in late 2023, SilverBow has reduced its total debt by $178 million as of April 30, 2024.

During the first quarter of 2024, SilverBow drilled 12 net wells, completed 12 net wells and brought online 12 net wells. The Company operated three drilling rigs during the quarter. First quarter capital investments were $109 million on an accrual basis.

Development drilling has been primarily focused on the liquids-rich acreage from the South Texas Acquisition in late 2023. Base production and operational cycle times on the Company’s new assets are in-line with expectations. SilverBow plans to operate three drilling rigs through May 2024, then reduce activity to two rigs. The Company plans to continue to optimize its drilling schedule based on commodity prices, returns on investment and strategically proving up inventory within its portfolio.

Liquidity and Capital Resources

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

Contractual Commitments and Obligations

Other than as discussed below, there were no other material changes in SilverBow’s contractual commitments during the three months ended March 31, 2024 from amounts referenced under “Contractual Commitments and Obligations” in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2023.

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Summary of 2024 Financial Results Through March 31, 2024

•Revenues and Net Income (Loss): The Company’s oil and gas revenues were $256.7 million for the three months ended March 31, 2024 compared to $140.0 million for the three months ended March 31, 2023. Revenues were primarily impacted by increased production volumes attributable to the South Texas Acquisition. The Company’s net loss was $15.5 million for the three months ended March 31, 2024, compared to net income of $94.5 million for the three months ended March 31, 2023. The decrease in net income was primarily driven by a net loss on our commodity derivatives.

•Capital Expenditures: The Company’s capital expenditures on an accrual basis were $109.5 million for the three months ended March 31, 2024 compared to $108.0 million for the three months ended March 31, 2023. The expenditures for the three months ended March 31, 2024 and 2023 were primarily attributable to drilling and completion activity.

•Working Capital: The Company had a working capital deficit of $131.4 million at March 31, 2024 and a working capital surplus of $13.0 million at December 31, 2023. Included in our working capital was a net asset of $63.2 million and $111.0 million at March 31, 2024 and December 31, 2023, respectively, related to the fair value of our current open derivative contracts. The working capital computation does not include available liquidity through our Credit Facility.

•Cash Flows: For the three months ended March 31, 2024, the Company generated cash from operating activities of $189.7 million, of which $18.3 million was attributable to changes in working capital. Additionally, the Company collected cash settlements of $38.4 million on derivatives during the three months ended March 31, 2024. Cash flows from operating activities also excluded $29.2 million attributable to a net increase of capital-related payables and accrued costs. Cash used for property additions was $80.2 million while purchase price adjustments related to the South Texas Acquisition totaled $11.8 million. The Company’s net repayments on the Credit Facility were $126.0 million during the three months ended March 31, 2024.

For the three months ended March 31, 2023, the Company generated cash from operating activities of $99.7 million, of which $6.0 million was attributable to changes in working capital. Cash used for property additions was $111.3 million while purchase price adjustments related to our 2022 acquisitions totaled $1.1 million. Cash flows from operating activities also included $3.1 million attributable to a net decrease of capital-related payables and accrued costs. The Company’s net borrowings on the Credit Facility were $17.0 million during the three months ended March 31, 2023.

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Results of Operations

Revenues — Three Months Ended March 31, 2024 and Three Months Ended March 31, 2023

Natural gas production was 54% and 66% of the Company’s production volumes for the three months ended March 31, 2024 and 2023, respectively. Natural gas sales were 21% and 38% of revenues for the three months ended March 31, 2024 and 2023, respectively.

Crude oil production was 27% and 22% of the Company’s production volumes for the three months ended March 31, 2024 and 2023, respectively. Crude oil sales were 65% and 53% of revenues for the three months ended March 31, 2024 and 2023, respectively.

NGL production was 19% and 12% of the Company’s production volumes for the three months ended March 31, 2024 and 2023, respectively. NGL sales were 14% and 9% of revenues for the three months ended March 31, 2024 and 2023, respectively.

The following table provides additional information regarding the Company’s revenues associated with oil and gas sales, by area, excluding any effects of the Company’s hedging activities, for the three months ended March 31, 2024 and 2023:


Fields	Three Months Ended March 31, 2024			Three Months Ended March 31, 2023
	Oil and Gas Sales (In Millions)		Net Oil and Gas Production Volumes (MBoe)	Oil and Gas Sales (In Millions)		Net Oil and Gas Production Volumes (MBoe)
Webb County Gas	$	30.0	2,572	$	39.4	2,207
Western Condensate	117.0		3,456	27.0		874
Southern Eagle Ford	5.7		345	5.5		291
Central Oil	63.8		1,125	60.0		1,006
Eastern Extension	39.0		806	7.7		172
Non-Core	0.5		9	0.4		8
Total	$	256.0	8,313	$	140.0	4,558

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

In the first quarter of 2024, our $116.1 million, or 83%, increase in oil, NGL and natural gas sales from the prior year period resulted from:

•Price variances that had an approximately $22.7 million unfavorable impact on sales due to lower natural gas pricing; and

•Volume variances that had an approximately $138.8 million favorable impact on sales due to overall increased production volumes.

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The following table provides additional information regarding our revenues associated with oil and gas sales, by commodity type, as well as the effects of our hedging activities for derivative contracts held to settlement, for the three months ended March 31, 2024 and 2023 (in thousands, except per-dollar amounts):


	Three Months Ended March 31, 2024		Three Months Ended March 31, 2023
Production volumes:
Oil (MBbl)	2,233		1,023
Natural gas (MMcf) (1)	27,093		17,974
Natural gas liquids (MBbl)	1,565		539
Total (MBoe)	8,313		4,558

Oil, natural gas and natural gas liquids sales:
Oil	$	166,704	$	74,655
Natural gas	53,123		52,922
Natural gas liquids	36,218		12,377
Total	$	256,045	$	139,954

Average realized price before impact of cash-settled derivatives:
Oil (per Bbl)	$	74.65	$	73.01
Natural gas (per Mcf)	1.96		2.94
Natural gas liquids (per Bbl)	23.15		22.95
Average per Boe	$	30.80	$	30.71

Price impact of cash-settled derivatives:
Oil (per Bbl)	$	(0.70)	$	0.92
Natural gas (per Mcf)	1.31		0.94
Natural gas liquids (per Bbl)	0.16		3.61
Average per Boe	$	4.10	$	4.36

Average realized price including impact of cash-settled derivatives:
Oil (per Bbl)	$	73.95	$	73.93
Natural gas (per Mcf)	3.27		3.89
Natural gas liquids (per Bbl)	23.31		26.56
Average per Boe	$	34.90	$	35.07

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

For the three months ended March 31, 2024 and 2023, the Company recorded net losses of $42.7 million and net gains of $91.2 million from our commodities derivatives activities, respectively. For the three months ended March 31, 2024 and 2023, we also recorded a net loss of $13.4 million and a net gain of $1.0 million, respectively, related to valuation changes from our 2023 and 2021 WTI Contingency Payouts. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.

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Costs and Expenses — Three Months Ended March 31, 2024 and Three Months Ended March 31, 2023

The following table provides additional information regarding our expenses for the three months ended March 31, 2024 and 2023 (in thousands):


Costs and Expenses	Three Months Ended March 31, 2024		Three Months Ended March 31, 2023
General and administrative, net	$	8,791	$	7,664
Depreciation, depletion, and amortization	92,103		43,998
Accretion of asset retirement obligations	316		224
Lease operating expenses	31,825		20,560
Workovers	610		779
Transportation and gas processing	35,199		11,520
Severance and other taxes	16,212		9,385
Interest expense, net	36,017		16,745
Provision (benefit) for income taxes	(4,787)		26,812

General and Administrative Expenses, Net. These expenses on a per-Boe basis were $1.06 and $1.68 for the three months ended March 31, 2024 and 2023, respectively. The decrease in per-Boe rate was due to an overall increase in production. Included in general and administrative expenses is $1.8 million and $1.1 million in share-based compensation for the three months ended March 31, 2024 and 2023, respectively.

Depreciation, Depletion and Amortization. These expenses on a per-Boe basis were $11.08 and $9.65 for the three months ended March 31, 2024 and 2023, respectively. The increase in our per-Boe depreciation, depletion and amortization rate was primarily related to the acquisition in 2023 and inflation on future development costs. The increase in costs is related to the increase in the per-Boe rate, coupled with an overall increase in production.

Lease Operating Expenses and Workovers. These expenses on a per-Boe basis were $3.90 and $4.68 for the three months ended March 31, 2024 and 2023, respectively. The decrease in per-Boe rate was due to an overall increase in production. The increase in costs was primarily due to higher labor, compression, salt water disposal and maintenance costs driven by our acquisition in 2023.

Transportation and Gas Processing. These expenses are related to oil, natural gas and NGL sales. These expenses on a per-Boe basis were $4.23 and $2.53 for the three months ended March 31, 2024 and 2023, respectively. The increase in costs and in our per-Boe rate was primarily attributable to additional transportation and processing agreements associated with our acquisition in 2023 along with increased contractual fees across portions of our properties.

Severance and Other Taxes. These expenses on a per-Boe basis were $1.95 and $2.06 for the three months ended March 31, 2024 and 2023, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 6.3% and 6.7% for the three months ended March 31, 2024 and 2023, respectively. The increase in severance and other taxes was primarily attributable to a shift in commodity mix, specifically liquids, driven by our acquisition in 2023. The decrease in our per-Boe rate was due to the overall increase in production.

Interest. Our interest cost was $36.0 million and $16.7 million for the three months ended March 31, 2024 and 2023, respectively. The increase in interest is primarily due to higher borrowings and higher interest rates. There were no capitalized interest costs for the three months ended March 31, 2024 and 2023.

Income Taxes. The Company recorded an income tax benefit of $4.8 million and an income tax provision of $26.8 million for the three months ended March 31, 2024 and 2023, respectively. The tax impact for both periods was a product of the overall forecasted annual effective tax rate applied to the year to date income or loss.

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Critical Accounting Policies and New Accounting Pronouncements

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

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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

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

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

Interest Rate Risk. At March 31, 2024, we had a combined $1.1 billion drawn under our Credit Facility and our Second Lien Notes, which bear floating rates of interest and therefore are susceptible to interest rate fluctuations. These variable interest rate borrowings are also impacted by changes in short-term interest rates. A hypothetical one percentage point increase in interest rates on our borrowings outstanding under our Credit Facility and Second Lien Notes at March 31, 2024 would increase our annual interest expense by $11.0 million.

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Item 4. Controls and Procedures

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the three months ended March 31, 2024 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

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 our 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.

Item 1A. Risk Factors.

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

Risks Related to Ownership of Our Common Stock:

Our business could be affected as a result of activist investors.

We value constructive input from investors and engage in dialogue with our shareholders regarding strategy and performance. Our Board and senior management are committed to acting in the best interests of all of our shareholders.

On April 10, 2024, Kimmeridge Energy Management Company, LLC, together with certain of its affiliates (collectively “Kimmeridge”), filed a definitive proxy statement to solicit proxies in favor of the election of three director candidates to the Board at our 2024 annual meeting of shareholders. If these director candidates are elected to the Board with a specific agenda, it may adversely affect our ability to effectively implement our current business strategy or create value for all shareholders. Kimmeridge has also made public statements critical of the Board and senior management. Responding to these actions by Kimmeridge and potential actions by other activist investors is costly and time-consuming, disruptive to our operations and diverts the attention of the Board and senior management from the pursuit of our business strategies, which could materially adversely affect our financial position, operating results or cash flows. The contested election with respect to the Company’s directors has required and is expected to continue to require us to incur substantial legal, public relations and other advisory fees and proxy solicitation expenses. Further, we may choose to initiate, or may become subject to, litigation as a result of proposals by activist investors or proxy contests or matters relating thereto, which would serve as a further distraction to the Board and senior management and could require us to incur significant additional costs.

Additionally, perceived uncertainties as to our future direction as a result of investor activism or changes to the composition of the Board may lead to the perception of a change in the direction of our business, instability or lack of continuity which may be exploited by our competitors and/or other activist investors and cause concern to our current or potential customers and make it more difficult to attract and retain qualified personnel. If customers choose to delay, defer or reduce transactions with us or transact with our competitors instead of us because of any such issues, then our financial position, operating results or cash flows could be materially adversely affected. Further, the trading price of our shares could experience periods of increased volatility as a result of investor activism.

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

None.

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Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

During the quarter ended March 31, 2024, no director or Section 16 officer adopted or terminated any Rule 10b5-1 trading arrangements or non-Rule 10b5-1 trading arrangements (in each case, as defined in Item 408 of Regulation S-K).

Item 6. Exhibits.

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


3.1			Certificate of Incorporation of Swift Energy Company, effective April 22, 2016 (incorporated by reference Exhibit 3.1 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
3.2			Certificate of Amendment to Certificate of Incorporation, effective May 5, 2017 (incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed May 5, 2017, File No. 001-08754).
3.3			Second Amended and Restated Bylaws of SilverBow Resources, Inc., effective October 31, 2022 (incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed September 20, 2022, File No. 001-08754).
3.4			Certificate of Designation, Preferences, and Rights of Series B Junior Participating Preferred Stock of the Company (incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed September 20, 2022, File No. 001-08754).
10.1+*			Form of Restricted Stock Unit Agreement – Non-Employee Directors 2024.
10.2+*			Form of Restricted Stock Unit Agreement – Officers 2024.
10.3+*			Form of Performance Share Unit Agreement – Officers 2024.
31.1*			Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2*			Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32.1#			Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
101*			The following materials from SilverBow Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 2024 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets (Unaudited), (ii) the Condensed Consolidated Statements of Operations (Unaudited), (iii) the Consolidated Statements of Stockholders Equity (Unaudited), (iv) the Condensed Consolidated Statements of Cash Flows (Unaudited), and (v) Notes to the Condensed Consolidated Financial Statements.
104			Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

*Filed herewith

# Furnished herewith. Not considered to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

+ Management contract or compensatory plan or arrangement

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SIGNATURES

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

SILVERBOW RESOURCES, INC.
(Registrant)

Date:

May 2, 2024

By:

/s/ Christopher M. Abundis

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

Date:

May 2, 2024

By:

/s/ W. Eric Schultz

W. Eric Schultz
Vice President of Accounting and Controller