UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

of the Securities Exchange Act of 1934

For the quarterly period ended June 30, 2023

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	o	Accelerated Filer	þ	Non-Accelerated Filer	o	Smaller Reporting Company	o
Emerging Growth Company	o

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

1

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) 22,617,842 Shares outstanding at July 28, 2023

2

SILVERBOW RESOURCES, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2023

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	9
	Condensed Consolidated Statements of Cash Flows	10
	Notes to Condensed Consolidated Financial Statements	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	44
Part II	OTHER INFORMATION
Item 1.	Legal Proceedings	45
Item 1A.	Risk Factors	45
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 3.	Defaults Upon Senior Securities	45
Item 4.	Mine Safety Disclosures	46
Item 5.	Other Information	46
Item 6.	Exhibits	46
SIGNATURES		48

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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;

• volatility in natural gas, oil 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 Russia-Ukraine conflict);

• 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 including remote work arrangements and protecting the health and well-being of our employees;

• opportunities to monetize assets;

• our ability to execute on strategic initiatives;

• 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;

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

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

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

• uncertainty regarding our future operating results; and

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• other risks and uncertainties described in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2022 and our other filings with the Securities and Exchange Commission (“SEC”).

Many of the foregoing risks and uncertainties, as well as risks and uncertainties that are currently unknown to us, are, and may be, exacerbated by the ongoing Russia-Ukraine conflict, 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, our Annual Report on Form 10-K for the year ended December 31, 2022, subsequent Quarterly Reports on Form 10-Q, or other SEC filings occur, or should underlying assumptions prove incorrect, actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements speak only as of the date they are made. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2022 and in subsequent Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and our other filings with the SEC. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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

5

PART I. FINANCIAL INFORMATION

Condensed Consolidated Balance Sheets (Unaudited)

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

	June 30, 2023		December 31, 2022
ASSETS
Current Assets:
Cash and cash equivalents	$	1,102	$	792
Accounts receivable, net	64,587		89,714
Fair value of commodity derivatives	72,590		52,549
Other current assets	3,935		2,671
Total Current Assets	142,214		145,726
Property and Equipment:
Property and equipment, full cost method, including $26,344 and $16,272, respectively, of unproved property costs not being amortized at the end of each period	2,756,694		2,529,223
Less – Accumulated depreciation, depletion, amortization & impairment	(1,097,935)		(1,004,044)
Property and Equipment, Net	1,658,759		1,525,179
Right of use assets	9,435		12,077
Fair value of long-term commodity derivatives	21,903		24,172
Other long-term assets	8,159		9,208
Total Assets	$	1,840,470	$	1,716,362
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	60,143	$	60,200
Fair value of commodity derivatives	9,711		40,796
Accrued capital costs	44,047		56,465
Accrued interest	2,755		2,665
Current lease liability	5,966		8,553
Undistributed oil and gas revenues	18,463		27,160
Total Current Liabilities	141,085		195,839
Long-term debt, net	722,904		688,531
Non-current lease liability	3,571		3,775
Deferred tax liabilities	50,073		16,141
Asset retirement obligations	9,619		9,171
Fair value of long-term commodity derivatives	2,032		7,738
Other long-term liabilities	541		3,588
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, 23,102,787 and 22,663,135 shares issued, respectively, and 22,617,842 and 22,309,740 shares outstanding, respectively	231		227
Additional paid-in capital	578,817		576,118
Treasury stock, held at cost, 484,945 and 353,395 shares, respectively	(10,600)		(7,534)
Retained earnings	342,197		222,768
Total Stockholders’ Equity	910,645		791,579
Total Liabilities and Stockholders’ Equity	$	1,840,470	$	1,716,362
See accompanying Notes to Condensed Consolidated Financial Statements.

6

Condensed Consolidated Statements of Operations (Unaudited)

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

	Three Months Ended June 30, 2023		Three Months Ended June 30, 2022
Revenues:
Oil and gas sales	$	126,400	$	182,605
Operating Expenses:
General and administrative, net	5,318		5,710
Depreciation, depletion, and amortization	49,853		26,441
Accretion of asset retirement obligations	240		101
Lease operating expenses	19,180		10,270
Workovers	811		2
Transportation and gas processing	11,771		6,769
Severance and other taxes	8,771		9,838
Total Operating Expenses	95,944		59,131
Operating Income	30,456		123,474
Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net	19,993		(22,406)
Interest expense, net	(18,190)		(7,902)
Other income (expense), net	29		(10)
Income (Loss) Before Income Taxes	32,288		93,156
Provision (Benefit) for Income Taxes	7,351		4,366
Net Income (Loss)	$	24,937	$	88,790
Per Share Amounts:
Basic Earnings (Loss) Per Share	$	1.10	$	5.05
Diluted Earnings (Loss) Per Share	$	1.10	$	4.95
Weighted-Average Shares Outstanding - Basic	22,615		17,581
Weighted-Average Shares Outstanding - Diluted	22,674		17,938
See accompanying Notes to Condensed Consolidated Financial Statements.

7

Condensed Consolidated Statements of Operations (Unaudited)

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

	Six Months Ended June 30, 2023		Six Months Ended June 30, 2022
Revenues:
Oil and gas sales	$	266,354	$	312,261
Operating Expenses:
General and administrative, net	12,982		10,497
Depreciation, depletion, and amortization	93,850		47,595
Accretion of asset retirement obligations	464		200
Lease operating expenses	39,740		19,395
Workovers	1,590		649
Transportation and gas processing	23,292		13,121
Severance and other taxes	18,156		17,602
Total Operating Expenses	190,074		109,059
Operating Income	76,280		203,202
Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net	112,243		(162,648)
Interest expense, net	(34,935)		(14,459)
Other income (expense), net	4		52
Income (Loss) Before Income Taxes	153,592		26,147
Provision (Benefit) for Income Taxes	34,163		1,612
Net Income (Loss)	$	119,429	$	24,535
Per Share Amounts:
Basic Earnings (Loss) Per Share	$	5.30	$	1.43
Diluted Earnings (Loss) Per Share	$	5.27	$	1.40
Weighted-Average Shares Outstanding - Basic	22,527		17,146
Weighted-Average Shares Outstanding - Diluted	22,654		17,506
See accompanying Notes to Condensed Consolidated Financial Statements.

8

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

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

	Common Stock		Additional Paid-In Capital		Treasury Stock		Retained Earnings (Accumulated Deficit)		Total
Balance, December 31, 2021	$	168	$	413,017	$	(2,984)	$	(117,669)	$	292,532
Purchase of treasury shares (96,012 shares)	—		—		(2,462)		—		(2,462)
Treasury shares pursuant to purchase price adjustment (41,191 shares)	—		—		(1,146)		—		(1,146)
Vesting of share-based compensation (318,390 shares)	3		(3)		—		—		—
Issuance pursuant to acquisition (489 shares)	—		12		—		—		12
Share-based compensation	—		1,101		—		—		1,101
Net Loss	—		—		—		(64,255)		(64,255)
Balance, March 31, 2022	$	171	$	414,127	$	(6,592)	$	(181,924)	$	225,782
Stock options exercised (4,497 shares)	—		39		—		—		39
Purchase of treasury shares (16,485 shares)	—		—		(503)		—		(503)
Vesting of share-based compensation (57,355 shares)	1		(1)		—		—		—
Issuance pursuant to acquisition (5,448,472 shares)	55		157,338		—		—		157,393
Share-based compensation	—		1,756		—		—		1,756
Net Income	—		—		—		88,790		88,790
Balance, June 30, 2022	$	227	$	573,259	$	(7,095)	$	(93,134)	$	473,257
Balance, December 31, 2022	$	227	$	576,118	$	(7,534)	$	222,768	$	791,579
Purchase of treasury shares (126,240 shares)	—		—		(2,945)		—		(2,945)
Vesting of share-based compensation (418,518 shares)	4		(4)		—		—		—
Share-based compensation	—		1,179		—		—		1,179
Net Income	—		—		—		94,492		94,492
Balance, March 31, 2023	$	231	$	577,293	$	(10,479)	$	317,260	$	884,305
Purchase of treasury shares (5,310 shares)	—		—		(121)		—		(121)
Vesting of share-based compensation (21,134 shares)	—		—		—		—		—
Share-based compensation	—		1,524		—		—		1,524
Net Income	—		—		—		24,937		24,937
Balance, June 30, 2023	$	231	$	578,817	$	(10,600)	$	342,197	$	910,645
See accompanying Notes to Condensed Consolidated Financial Statements.

9

Condensed Consolidated Statements of Cash Flows (Unaudited)

SilverBow Resources, Inc. and Subsidiary (in thousands)

	Six Months Ended June 30, 2023		Six Months Ended June 30, 2022
Cash Flows from Operating Activities:
Net income (loss)	$	119,429	$	24,535
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	93,850		47,595
Accretion of asset retirement obligations	464		200
Deferred income taxes	33,932		1,205
Share-based compensation	2,575		2,714
(Gain) Loss on derivatives, net	(112,243)		162,648
Cash settlement (paid) received on derivatives	47,481		(90,603)
Settlements of asset retirement obligations	(411)		(54)
Write down of debt issuance cost	—		350
Other	1,312		1,668
Change in operating assets and liabilities:
(Increase) decrease in accounts receivable and other current assets	26,297		(34,422)
Increase (decrease) in accounts payable and accrued liabilities	(21,916)		(1,254)
Increase (decrease) in income taxes payable	229		304
Increase (decrease) in accrued interest	89		723
Net Cash Provided by (Used in) Operating Activities	191,088		115,609
Cash Flows from Investing Activities:
Additions to property and equipment	(221,464)		(93,746)
Acquisition of oil and gas properties, net of purchase price adjustments	(248)		(272,225)
Proceeds from the sale of property and equipment	—		2,532
Payments on property sale obligations	—		(750)
Net Cash Provided by (Used in) Investing Activities	(221,712)		(364,189)
Cash Flows from Financing Activities:
Proceeds from bank borrowings	210,000		482,000
Payments of bank borrowings	(176,000)		(215,000)
Net proceeds from stock options exercised	—		39
Purchase of treasury shares	(3,066)		(2,965)
Payments of debt issuance costs	—		(7,207)
Net Cash Provided by (Used in) Financing Activities	30,934		256,867
Net Increase (Decrease) in Cash and Cash Equivalents	310		8,287
Cash and Cash Equivalents at Beginning of Period	792		1,121
Cash and Cash Equivalents at End of Period	$	1,102	$	9,408
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for interest, net of amounts capitalized	$	33,340	$	12,228
Non-cash Investing and Financing Activities:
Changes in capital accounts payable and capital accruals	$	3,485	$	20,882
Non-cash equity consideration for acquisitions	$	—	$	(156,259)
See accompanying Notes to Condensed Consolidated Financial Statements.

10

Notes to Condensed Consolidated Financial Statements (Unaudited)

SilverBow Resources, Inc. and Subsidiary

(1)           General Information

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

The condensed consolidated financial statements included herein are unaudited and certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2022.

(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.

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

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Through July 31, 2023, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after June 30, 2023:

Oil Derivative Contracts (NYMEX WTI Settlements)	Total Volumes (Bbls)	Weighted-Average Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
Swap Contracts
2024 Contracts
1Q24	273,000	$	75.11
2Q24	273,000	$	75.11
3Q24	276,000	$	75.11
4Q24	276,000	$	75.11
2025 Contracts
1Q25	270,000	$	70.60
2Q25	273,000	$	70.60
3Q25	276,000	$	70.60
4Q25	276,000	$	70.60
Collar Contracts
2023 Contracts
4Q23	92,000			$	70.00	$	80.40
2024 Contracts
1Q24	91,000			$	65.00	$	79.10
2Q24	91,000			$	65.00	$	79.10
3Q24	92,000			$	65.00	$	79.10
4Q24	92,000			$	65.00	$	79.10
2025 Contracts
2Q25	136,500			$	61.33	$	73.97
2026 Contracts
1Q26	90,000			$	64.00	$	71.50
2Q26	91,000			$	64.00	$	71.50
3Q26	92,000			$	64.00	$	71.50

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Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
Swap Contracts
2025 Contracts
3Q25	920,000	$	3.75
4Q25	920,000	$	4.16
Collar Contracts
2024 Contracts
1Q24	1,820,000			$	3.25	$	4.29
2Q24	1,820,000			$	3.00	$	3.31
3Q24	920,000			$	3.00	$	3.65
4Q24	920,000			$	3.25	$	4.40
2025 Contracts
2Q25	4,004,000			$	3.25	$	3.97
3Q25	920,000			$	3.25	$	3.99
4Q25	920,000			$	3.75	$	4.65

Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes (MMBtu)	Weighted-Average Price
2024 Contracts
1Q24	910,000	$	0.075
2Q24	910,000	$	(0.261)
3Q24	920,000	$	(0.234)
4Q24	920,000	$	(0.276)
2025 Contracts
1Q25	900,000	$	0.023
2Q25	910,000	$	(0.315)
3Q25	920,000	$	(0.240)
4Q25	920,000	$	(0.274)

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

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

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

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

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

•estimates of future costs to develop and produce reserves,

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

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

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

13

•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 both the three months ended June 30, 2023 and 2022, such internal costs capitalized totaled $1.2 million. For the six months ended June 30, 2023 and 2022, such internal costs capitalized totaled $2.6 million and $2.2 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 June 30, 2023 and 2022 and the six months ended June 30, 2023 and 2022.

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

	June 30, 2023		December 31, 2022
Property and Equipment
Proved oil and gas properties	$	2,724,110	$	2,506,853
Unproved oil and gas properties	26,344		16,272
Furniture, fixtures and other equipment	6,240		6,098
Less – Accumulated depreciation, depletion, amortization & impairment	(1,097,935)		(1,004,044)
Property and Equipment, Net	$	1,658,759	$	1,525,179

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

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

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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 June 30, 2023 and 2022 or the six months ended June 30, 2023 and 2022.

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

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

At June 30, 2023, our “Accounts receivable, net” balance included $45.2 million for oil and gas sales, $1.4 million due from joint interest owners, $7.6 million for severance tax credit receivables and $10.4 million for other receivables. At December 31, 2022, our “Accounts receivable, net” balance included $70.9 million for oil and gas sales, $5.6 million due from joint interest owners, $4.3 million for severance tax credit receivables and $8.9 million for other receivables.

Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the six months ended June 30, 2023 and 2022 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $2.9 million and $1.7 million for the three months ended June 30, 2023 and 2022, respectively, and $5.5 million and $3.4 million for the six months ended June 30, 2023 and 2022, 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 22% and 4% for the three months ended June 30, 2023 and 2022, respectively, and 22% and 6% for the six months ended June 30, 2023 and 2022, respectively. The Company recorded an income tax provision of $7.4 million and $34.2 million for the three and six months ended June 30, 2023, respectively, and an income tax provision of $4.4 million and $1.6 million for the three and six months ended June 30, 2022, 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.

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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 June 30, 2023 and December 31, 2022, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.

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

The following table provides information regarding our oil and gas sales, by product, reported on the Condensed Consolidated Statements of Operations for the three months ended June 30, 2023 and 2022 and the six months ended June 30, 2023 and 2022 (in thousands):

	Three Months Ended June 30, 2023		Three Months Ended June 30, 2022		Six Months Ended June 30, 2023		Six Months Ended June 30, 2022
Oil, natural gas and NGLs sales:
Oil	$	80,151	$	44,014	$	154,807	$	83,755
Natural gas	33,805		123,296		86,727		200,668
NGLs	12,443		15,295		24,820		27,838
Total	$	126,400	$	182,605	$	266,354	$	312,261

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

	June 30, 2023		December 31, 2022
Trade accounts payable	$	32,210	$	23,660
Accrued operating expenses	10,565		10,572
Accrued compensation costs	2,328		4,814
Asset retirement obligations – current portion	1,551		1,284
Accrued non-income based taxes	8,957		4,849
Accrued corporate and legal fees	260		388
WTI contingency payouts - current portion	975		1,600
Payable for settled derivatives	1,016		6,026
Other payables	2,281		7,007
Total accounts payable and accrued liabilities	$	60,143	$	60,200

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.

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Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock, held at cost” on the accompanying condensed consolidated balance sheets. For the six months ended June 30, 2023, we purchased 131,550 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. For the six months ended June 30, 2022, we purchased 112,497 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares and received 41,191 shares in conjunction with our post-closing settlement for a previously disclosed acquisition.

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

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021. The guidance provides and clarifies optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The amendments within these ASUs were in effect beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2024. As of June 30, 2023, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01.

In August 2020, the FASB issued ASU No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The guidance simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. Additionally, the amendment requires the application of the if-converted method to calculate the impact of convertible instruments on diluted earnings per share (EPS). The guidance is effective for the Company for fiscal years beginning after December 15, 2022, and the Company adopted the guidance on January 1, 2023. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements or disclosures.

(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 Consolidated Balance Sheets. We have elected to not account for lease and non-lease components separately.

The Company has contractual agreements for its corporate office lease, vehicle fleet, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of June 30, 2023, 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.

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As of June 30, 2023, the Company's future cash payment obligation for its operating lease liabilities are as follows (in thousands):

	As of June 30, 2023
2023 (Remaining)	$	4,730
2024	2,607
2025	1,422
2026	955
2027	61
Thereafter	472
Total undiscounted lease payments	10,247
Present value adjustment	(710)
Net operating lease liabilities	$	9,537

(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 $1.5 million and $1.7 million for the three months ended June 30, 2023 and 2022, respectively, and $2.6 million and $2.7 million for the six months ended June 30, 2023 and 2022, respectively. Capitalized share-based compensation was less than $0.1 million for both the three months ended June 30, 2023 and 2022, and $0.1 million for both the six months ended June 30, 2023 and 2022.

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

    Stock Option Awards

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

At June 30, 2023, we had no unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the six months ended June 30, 2023:

	Shares	Wtd. Avg. Exer. Price
Options outstanding, beginning of period	196,162	$	26.46
Options granted	—	$	—
Options exercised	—	$	—
Options outstanding, end of period	196,162	$	26.46
Options exercisable, end of period	196,162	$	26.46

Our outstanding stock option awards had $0.5 million measurable aggregate intrinsic value at June 30, 2023. At June 30, 2023, the weighted-average remaining contract life of stock option awards outstanding was 3.9 years and exercisable was 3.9 years. The total intrinsic value of stock option awards exercisable was $0.5 million as of June 30, 2023.

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Restricted Stock Units

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

As of June 30, 2023, we had $5.8 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 six months ended June 30, 2023:

	RSUs	Wtd. Avg. Grant Price
RSUs outstanding, beginning of period	227,114	$	21.18
RSUs granted	192,014	$	23.66
RSUs forfeited	(1,424)	$	25.44
RSUs vested	(136,242)	$	17.55
RSUs outstanding, end of period	281,462	$	24.61

Performance-Based Stock Units

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

On February 24, 2021, the Company granted 161,389 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2021 to December 31, 2022. The awards 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 relative to the TSR of its selected peers during the performance period from January 1, 2022 to December 31, 2024. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $36.47 per unit or 150.93% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years. All PSUs granted remain outstanding related to this award as of June 30, 2023.

On February 23, 2023, the Company granted 120,749 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2023 to December 31, 2025. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $31.18 per unit or 136.28% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years. All PSUs granted remain outstanding related to this award as of June 30, 2023.

As of June 30, 2023, we had $5.6 million unrecognized compensation expense related to our PSUs based on the assumption of 100% target payout. The remaining weighted-average performance period is 2.1 years.

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

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

(5)          Earnings Per Share

Basic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three and six months ended June 30, 2023 and 2022 are discussed below.

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

	Three Months Ended June 30, 2023					Three Months Ended June 30, 2022
	Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)		Shares	Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	24,937	22,615	$	1.10	$	88,790	17,581	$	5.05
Dilutive Securities:
Performance Based Stock Unit Awards			19					171
RSU Awards			33					128
Stock Option Awards			7					58
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	24,937	22,674	$	1.10	$	88,790	17,938	$	4.95

	Six Months Ended June 30, 2023					Six Months Ended June 30, 2022
	Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)		Shares	Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	119,429	22,527	$	5.30	$	24,535	17,146	$	1.43
Dilutive Securities:
Performance Based Stock Unit Awards			58					142
RSU Awards			62					188
Stock Option Awards			7					30
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	119,429	22,654	$	5.27	$	24,535	17,506	$	1.40

There were 0.1 million stock options to purchase shares which were not included in the computation of Diluted EPS for the three months ended June 30, 2023 because they were antidilutive, while there were no antidilutive stock options for the three months ended June 30, 2022. Additionally, there were 0.1 million and less than 0.1 million stock options to purchase

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shares which were not included in the computation of Diluted EPS for the six months ended June 30, 2023 and 2022, respectively, because they were antidilutive.

There were less than 0.1 million shares of RSUs that were not included in the computation of Diluted EPS for the three months ended June 30, 2023 and 2022 because they were antidilutive while less than 0.1 million shares of RSUs were not included in the computation of Diluted EPS for the six months ended June 30, 2023 and 2022 because they were antidilutive.

There were 0.1 million shares of PSUs excluded from Diluted EPS for the three months ended June 30, 2023 because they were antidilutive while there were no antidilutive shares of PSUs that could be converted to common shares for the three months ended June 30, 2022. Additionally, there were 0.1 million shares of PSUs that could be converted to common shares which were not included in the computation of Diluted EPS for the six months ended June 30, 2023 because they were antidilutive while there were no antidilutive shares of PSUs that could be converted to common shares for the six months ended June 30, 2022.

(6)          Long-Term Debt

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

	June 30, 2023		December 31, 2022
Credit Facility Borrowings due 2026 (1)	$	576,000	$	542,000
Second Lien Notes due 2026	150,000		150,000
	726,000		692,000
Unamortized discount on Second Lien Notes due 2026	(787)		(882)
Unamortized debt issuance cost on Second Lien Notes due 2026	(2,309)		(2,587)
Long-Term Debt, net	$	722,904	$	688,531

(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our consolidated balance sheet. As of June 30, 2023 and December 31, 2022, we had $7.6 million and $8.7 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.

Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $576.0 million and $542.0 million as of June 30, 2023 and December 31, 2022, respectively. The Company is a party to a First Amended and Restated Senior Secured Revolving Credit Agreement with JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended (such agreement, the “Credit Agreement” and the borrowing facility provided thereby, the “Credit Facility”).

The Credit Facility matures October 19, 2026 (or to the extent earlier, the date that is 91 days prior to the scheduled maturity of the Company's Second Lien notes), and provides for a maximum credit amount of $2.0 billion, subject to the current borrowing base of $775.0 million. The borrowing base is regularly redetermined in 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. In conjunction with its regularly scheduled semi-annual redeterminations, the Company reaffirmed the borrowing base and elected commitment amount under the Credit Facility at $775.0 million, effective November 22, 2022, and again on March 20, 2023. 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 June 30, 2023, and no outstanding letters of credit as of December 31, 2022. Maintaining or increasing our borrowing base under our Credit Facility is dependent on many factors, including commodity prices, our hedge positions, changes in our lenders' lending criteria and our ability to raise capital to drill wells to replace produced reserves.

Interest under the Credit Facility accrues at the Company’s option either at an Alternate 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 ranges 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

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interest at 2.0% per annum above the rate and margin otherwise applicable thereto. As of June 30, 2023, the Company's weighted average interest rate on Credit Facility borrowings was 8.48%.

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 June 30, 2023, the Company was in compliance with all financial covenants under the Credit Agreement.

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

Total interest expense on the Credit Facility, which includes commitment fees and amortization of debt issuance costs, was $13.2 million and $4.4 million for the three months ended June 30, 2023 and 2022, respectively, and $25.2 million and $7.6 million for the six months ended June 30, 2023 and 2022, respectively. The amount of commitment fee amortization included in interest expense, net was $0.2 million and $0.3 million for the three months ended June 30, 2023 and 2022, respectively, and $0.5 million and $0.6 million for the six months ended June 30, 2023 and 2022, respectively.

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

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

On June 14, 2023, the Company entered into the Third Amendment to the Note Purchase Agreement to effectuate the replacement of LIBOR with an adjusted term secured overnight financing rate plus a margin of 0.25% (“Term SOFR”). After the Third Amendment, interest under the Second Lien is payable quarterly and accrues, based on the Company's election at the time of the borrowing, either at Term SOFR plus a margin of 7.5% (“Second Lien Term SOFR Loans”) or at an Alternate Base Rate which is based on the greater of (i) the prime rate; (ii) the greater of the federal funds effective rate or overnight bank funding rate, plus 0.5%; or (iii) Term SOFR plus 1% (“Second Lien ABR Loans”) plus a margin of 6.5%. Additionally, to the extent the Company were to default on the Second Lien, this would potentially trigger a cross-default under our Credit Facility. As of June 30, 2023, the Company's interest rate on Second Lien borrowings was 12.75%.

The Company has the right, to the extent permitted under the Credit Facility and subject to the terms and conditions of the Second Lien, to optionally prepay the notes at no premium. Additionally, the Second Lien contains customary mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and incurrences of certain debt, subject to, in certain circumstances, reinvestment periods. Management believes the probability of mandatory prepayment due to default is remote.

The obligations under the Second Lien are secured, subject to certain exceptions and other permitted liens (including the liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit

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Facility, and mortgage lien on substantially all assets of the Company and its subsidiary, including a mortgage lien on oil and gas properties attributed with at least 90% of estimated PV-9 (defined below), of proved reserves of the Company and its subsidiary and 90% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions by the administrative agent of the Credit Facility. PV-9 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 9%.

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

The Second Lien also contains a financial covenant measuring the ratio of total net debt-to-EBITDA, as defined in the Note Purchase Agreement, for the most recently completed four fiscal quarters, not to exceed 3.25 to 1.0 as of the last day of each fiscal quarter. As of June 30, 2023, the Company was in compliance with all financial covenants under the Second Lien.

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

    As of June 30, 2023, total net amounts recorded for the Second Lien were $146.9 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $5.0 million and $3.5 million for the three months ended June 30, 2023 and 2022, respectively, and $9.8 million and $6.9 million for the six months ended June 30, 2023 and 2022, respectively.

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

(7)          Acquisitions and Dispositions

November 2021 Acquisition

On November 19, 2021, the Company closed on an acquisition of oil-weighted assets in the Eagle Ford. The acquired assets included wells and acreage in La Salle, McMullen, DeWitt and Lavaca counties. After consideration of closing adjustments, total aggregate consideration was approximately $77.4 million, consisting of $37.6 million in cash, 1,351,961 shares of our common stock valued at approximately $37.9 million based on the Company's share price on the closing date, and contingent consideration with an estimated fair value of $1.9 million. The contingent consideration consists of up to three earn-out payments of $1.6 million per year for each of 2022, 2023 and 2024, contingent upon the average monthly settlement price of WTI exceeding $70 per barrel for such year (the “2021 WTI Contingency Payout”). During the three months ended June 30, 2023 and 2022, the Company recorded losses of less than $0.1 million and $0.2 million, respectively, and losses of $0.1 million and $1.5 million, respectively, for the six months ended June 30, 2023 and 2022 related to the 2021 WTI Contingency Payout which are recorded in “Gain (loss) on commodity derivatives, net” on the consolidated statements of operations. We also recorded $1.6 million in earn-out consideration payable to the seller related to the 2022 calendar year in “Accounts payable and accrued liabilities” on the condensed consolidated balance sheet as of December 31, 2022. For further discussion of the fair value related to the Company's contingent consideration, refer to Note 9 of these Notes to Consolidated Financial Statements. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

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May 2022 Acquisition

On May 10, 2022, the Company closed the acquisition of certain oil and gas assets located in La Salle and McMullen Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date, from SandPoint Operating, LLC, a subsidiary of SandPoint Resources, LLC (collectively, “SandPoint”). After consideration of closing adjustments, total aggregate consideration was approximately $67.5 million, consisting of $27.7 million in cash and 1,300,000 shares of our common stock valued at approximately $39.8 million based on the Company's share price on the closing date. We incurred approximately $0.5 million in transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

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

Total Cost
Cash consideration	$	27,709
Equity consideration	39,767
Total Consideration	67,476
Transaction costs	466
Total Cost of Transaction	$	67,942
Allocation of Total Cost
Assets
Oil and gas properties	$	84,810
Total assets	84,810
Liabilities
Accounts payable and accrued liabilities	199
Fair value of commodity derivatives	16,511
Asset retirement obligations	158
Total Liabilities	$	16,868
Net Assets Acquired	$	67,942

June 2022 Acquisition

On June 30, 2022, the Company closed the acquisition of certain oil and gas assets located in Atascosa, La Salle, Live Oak and McMullen Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date, from Sundance Energy, Inc., and its affiliated entities Armadillo E&P, Inc. and SEA Eagle Ford, LLC (collectively, “Sundance”). After consideration of closing adjustments, total aggregate consideration was approximately $344.9 million, consisting of $220.9 million in cash, 4,148,472 shares of our common stock valued at approximately $117.7 million based on the Company's share price on the closing date, accrued purchase price adjustments receivable of $1.0 million and contingent consideration with an estimated fair value of $7.4 million. The contingent consideration consists of up to two earn-out payments of $7.5 million each, contingent upon the average monthly settlement price of NYMEX West Texas Intermediate crude oil exceeding $95 per barrel for the period from April 13, 2022 through December 31, 2022 which would trigger a payment of $7.5 million in 2023 and $85 per barrel for 2023 which would trigger a payment of $7.5 million in 2024 (the “2022 WTI Contingency Payout”). The contingent payout for the period of April 13, 2022 through December 31, 2022 did not materialize. During the six months ended June 30, 2023, the Company recorded gains of $1.0 million related to valuation changes in the 2022 WTI Contingency Payout recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. Additionally, as part of our post-close settlement we settled the 2022 WTI Contingency during the second quarter of 2023. As such, we recorded a non-cash gain of $1.1 million during the six months ended June 30, 2023, and we are no longer required to make a contingency payment related to the 2022 WTI Contingency Payout. We incurred approximately $6.8 million in transaction costs during the year ended December 31, 2022 related to the acquisition.

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Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

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

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

August 2022 Acquisition

On August 15, 2022, the Company closed the acquisition of certain oil and gas assets in Webb County, Texas. After consideration of closing adjustments, total consideration was approximately $31.2 million. We did not incur any significant transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

October 2022 Acquisition

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

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2022 Non-strategic Dispositions

During 2022, the Company closed on multiple dispositions of non-strategic oil and gas assets. After consideration of closing adjustments, total proceeds from the dispositions were approximately $4.3 million. The transactions are subject to further customary post-closing adjustments. There was no gain or loss recognized in connection with the dispositions.

(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 June 30, 2023 and 2022, the Company recorded gains of $18.9 million and losses of $22.2 million, respectively, on its commodity derivatives. During the six months ended June 30, 2023 and 2022, the Company recorded gains of $110.2 million and losses of $161.2 million, respectively, on its commodity derivatives. During the three months ended June 30, 2023 and 2022, the Company recorded losses of less than $0.1 million and losses of $0.2 million, respectively, related to valuation changes on the 2021 WTI Contingency Payout and 2022 WTI Contingency Payout. During the six months ended June 30, 2023 and 2022, the Company recorded gains of $0.9 million and losses of $1.5 million, respectively, related to valuation changes on the 2021 WTI Contingency Payout and 2022 WTI Contingency Payout. The Company collected cash payments of $47.5 million and made cash payments of $90.6 million for settled derivative contracts during the six months ended June 30, 2023 and 2022, respectively.

At June 30, 2023 and December 31, 2022, there was $10.0 million and $6.9 million, respectively, in receivables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts receivable, net” and were subsequently collected in July 2023 and January 2023, respectively. At June 30, 2023 and December 31, 2022, we also had $1.0 million and $6.0 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 July 2023 and January 2023, respectively.

The fair values of our swap contracts are computed using observable market data whereas our collar contracts are valued using a Black-Scholes pricing model. At June 30, 2023, there was $72.6 million and $21.9 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $9.7 million and $2.0 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2022, there was $52.5 million and $24.2 million in current and long-term unsettled derivative assets, respectively, and $40.8 million and $7.7 million in current and long-term unsettled derivative liabilities, respectively.

The Company uses an International Swap and Derivatives Association master agreement for our derivative contracts. This is an industry-standardized contract containing the general conditions of our derivative transactions including provisions relating to netting derivative settlement payments under certain circumstances (such as default). For reporting purposes, the Company has elected to not offset the asset and liability fair value amounts of its derivatives on the accompanying condensed consolidated balance sheet. Under the right of set-off, there was a $82.8 million net fair value asset at June 30, 2023, and a $28.2 million net fair value asset at December 31, 2022. For further discussion related to the fair value of the Company's derivatives, refer to Note 9 of these Notes to Condensed Consolidated Financial Statements.

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The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of June 30, 2023:

Oil Derivative Contracts (NYMEX WTI Settlements)	Total Volumes (Bbls)	Weighted-Average Price		Weighted-Average Collar Sub Floor Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
Swap Contracts
2023 Contracts
3Q23	533,980	$	77.36
4Q23	569,300	$	78.26
2024 Contracts
1Q24	227,500	$	80.78
2Q24	254,050	$	80.24
3Q24	273,620	$	76.89
4Q24	256,100	$	75.98
Collar Contracts
2023 Contracts
3Q23	210,847					$	64.55	$	72.82
4Q23	210,242					$	64.09	$	71.97
2024 Contracts
1Q24	228,700					$	56.54	$	68.82
2Q24	124,000					$	58.21	$	69.51
3Q24	92,000					$	62.00	$	71.95
4Q24	92,000					$	61.00	$	71.60
2025 Contracts
1Q25	238,500					$	64.00	$	74.62
2Q25	91,000					$	60.00	$	69.60
3-Way Collar Contracts
2023 Contracts
3Q23	9,570			$	43.08	$	53.41	$	63.33
4Q23	8,970			$	43.08	$	53.38	$	63.35
2024 Contracts
1Q24	8,247			$	45.00	$	57.50	$	67.85
2Q24	7,757			$	45.00	$	57.50	$	67.85

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Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Price		Weighted-Average Collar Sub Floor Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
Swap Contracts
2023 Contracts
3Q23	4,816,000	$	4.57
4Q23	3,887,000	$	4.71
2024 Contracts
1Q24	2,711,000	$	5.15
2Q24	7,800,000	$	3.95
3Q24	7,820,000	$	4.03
4Q24	7,820,000	$	4.35
2025 Contracts
1Q25	900,000	$	5.01
2Q25	910,000	$	4.12
3Q25	920,000	$	4.27
4Q25	920,000	$	4.70
Collar Contracts
2023 Contracts
3Q23	11,896,400					$	3.43	$	4.23
4Q23	12,445,000					$	3.87	$	4.80
2024 Contracts
1Q24	7,841,000					$	4.10	$	6.19
2Q24	2,823,000					$	4.05	$	4.91
3Q24	2,958,000					$	4.00	$	5.10
4Q24	2,945,000					$	4.24	$	5.63
2025 Contracts
1Q25	5,130,000					$	4.00	$	5.32
2Q25	910,000					$	3.25	$	4.03
3-Way Collar Contracts
2023 Contracts
3Q23	233,100			$	2.00	$	2.50	$	2.95
4Q23	219,200			$	2.00	$	2.50	$	2.94
2024 Contracts
1Q24	198,000			$	2.00	$	2.50	$	3.37
2Q24	188,000			$	2.00	$	2.50	$	3.37

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Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes (MMBtu)	Weighted-Average Price
2023 Contracts
3Q23	14,720,000	$	(0.21)
4Q23	13,800,000	$	(0.23)
2024 Contracts
1Q24	11,830,000	$	0.01
2Q24	11,830,000	$	(0.32)
3Q24	11,960,000	$	(0.27)
4Q24	11,960,000	$	(0.31)
2025 Contracts
1Q25	1,800,000	$	0.04
2Q25	1,820,000	$	(0.29)
3Q25	1,840,000	$	(0.24)
4Q25	1,840,000	$	(0.29)

NGL Swaps (Mont Belvieu)	Total Volumes (Bbls)	Weighted-Average Price
2023 Contracts
3Q23	345,000	$	32.87
4Q23	345,000	$	32.87
2024 Contracts
1Q24	127,400	$	29.39
2Q24	127,400	$	29.39
3Q24	128,800	$	29.39
4Q24	128,800	$	29.39

(9)           Fair Value Measurements

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

The fair values of our derivative contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model. The fair value of the current and long-term 2021 WTI Contingency Payout and 2022 WTI Contingency Payout, included within “Accounts payable and accrued liabilities” and “Other long-term liabilities” on the condensed consolidated balance sheets, respectively, is estimated using observable market data and a Monte Carlo pricing model. These are considered Level 2 valuations (defined below).

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

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

Asset retirement obligations. The initial measurement of asset retirement obligations (“ARO”) at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the

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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 Consolidated Financial Statements). Fair value was determined using a discounted cash flow model. The underlying future commodity prices included in the Company’s estimated future cash flows of its proved oil and gas properties were determined using NYMEX forward strip prices as of the closing date of each acquisition. The estimated future cash flows also included management’s assumptions for the estimates of production from the crude oil and natural gas proved properties, future operating, development costs and income taxes of the acquired properties and risk adjusted discount rates.

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

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

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

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

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

	Fair Value Measurements at
(in thousands)	Total		Quoted Prices in Active markets for Identical Assets (Level 1)		Significant Other Observable Inputs  (Level 2)		Significant Unobservable Inputs (Level 3)
June 30, 2023
Assets
Natural Gas Derivatives	$	59,049	$	—	$	59,049	$	—
Natural Gas Basis Derivatives	2,486		—		2,486		—
Oil Derivatives	21,229		—		21,229		—
NGL Derivatives	11,729		—		11,729		—
Liabilities
Natural Gas Derivatives	1,076		—		1,076		—
Natural Gas Basis Derivatives	4,354		—		4,354		—
Oil Derivatives	6,313		—		6,313		—
2021 WTI Contingency Payout	1,515		—		1,515		—
December 31, 2022
Assets
Natural Gas Derivatives	$	25,960	$	—	$	25,960	$	—
Natural Gas Basis Derivatives	26,023		—		26,023		—
Oil Derivatives	14,604		—		14,604		—
NGL Derivatives	10,134		—		10,134		—
Liabilities
Natural Gas Derivatives	28,579		—		28,579		—
Natural Gas Basis Derivatives	409		—		409		—
Oil Derivatives	19,442		—		19,442		—
NGL Derivatives	104		—		104		—
2022 WTI Contingency Payout	2,135		—		2,135		—
2021 WTI Contingency Payout	1,453		—		1,453		—

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

(10)           Asset Retirement Obligations

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.

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The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2022 and the six months ended June 30, 2023 (in thousands):

Asset Retirement Obligations as of December 31, 2021	$	6,050
Accretion expense	534
Liabilities incurred for new wells, acquired wells and facilities construction	3,032
Reductions due to sold wells and facilities	(57)
Reductions due to plugged wells and facilities	(22)
Revisions in estimates	919
Asset Retirement Obligations as of December 31, 2022	$	10,456
Accretion expense	464
Liabilities incurred for new wells, acquired wells and facilities construction	280
Reductions due to plugged wells and facilities	(412)
Revisions in estimates	382
Asset Retirement Obligations as of June 30, 2023	$	11,170

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

(11)        Commitments and Contingencies

    In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as an operator of oil and natural gas wells. In our management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations. During the second quarter of 2023, the Company entered into gas throughput agreements with separate parties in our Webb County gas area. The agreements provide for an annual average firm capacity of approximately 116,000 MMBtu/d over an eight-year term.

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

You should read the following discussion and analysis in conjunction with the Company's financial information and its condensed consolidated financial statements and accompanying notes included in this report and its audited consolidated financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2022. The following information contains forward-looking statements; see “Forward-Looking Statements” in this report.

Company Overview

SilverBow is an independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford and Austin Chalk located in South Texas where it has assembled approximately 180,000 net acres across five operating areas. SilverBow's acreage position in each of its operating areas is highly contiguous and designed for optimal and efficient horizontal well development. The Company has built a balanced portfolio of properties with a significant base of current production and reserves coupled with low-risk development drilling opportunities and meaningful upside from newer operating areas.

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

Operational Results and Strategy

    Total production for the six months ended June 30, 2023 increased 37% from the six months ended June 30, 2022 to 317 million cubic feet of natural gas equivalent per day.

During the second quarter of 2023, SilverBow drilled 13 net wells, completed 15 net wells and brought online 15 net wells. The Company operated two drilling rigs during the quarter, primarily on its Central Oil and Eastern Extension areas, which reflect its ongoing focus on oil development in the near-term. SilverBow's team continues to increase operational efficiencies year to date in 2023, completing 17% more stages per day as compared to similar jobs for full year 2022 and averaging pumping efficiencies 18% higher over the same time periods. Costs continue to trend lower year to date in 2023, with D&C costs per lateral foot 11% lower as compared to 2022.

In its Central Oil area, the Company completed and brought online four pads comprised of nine total wells. Three of these pads have achieved peak production rates with the other pad still increasing in rate. The three pads that have achieved peak production have 30-day production averages of 1,500 Boe/d (83% oil) with average lateral lengths of 5,110 feet. In its Eastern Extension area, SilverBow brought online a two-well pad which produced a 30-day average of 2,500 Boe/d (73% oil) with an average lateral length of 7,660 feet. Strong initial performance from these pads are in-line with expectations and support consistent results across the Company's oil development program. Furthermore, SilverBow recently completed an initial Austin Chalk test in its Eastern Extension area and is encouraged by early results. As expected, net gas production in the Company's Webb County Gas area was limited to contracted firm capacity levels during the quarter. SilverBow continues to plan for limited interruptible takeaway capacity until late 2023 as new pipelines come into service.

The Company's drilling program for 2023 remains focused on oil production growth this year with several oil wells targeting the Austin Chalk formation. SilverBow is lowering its full year 2023 capital budget range to $400-$425 million, focused on its Central Oil, Western Condensate and Eastern Extension areas, as a result of operational efficiencies and cost reductions identified year to date. The Company optimizes its drilling schedule based on commodity prices, returns on investment and strategically proving up additional inventory within its portfolio.

Liquidity and Capital Resources

SilverBow's primary use of cash has been to fund capital expenditures to develop its oil and gas properties, fund acquisitions and to repay Credit Facility borrowings. The Company uses cash generated from operating activities and borrowings under its Credit Facility as its primary sources of liquidity. As of June 30, 2023, SilverBow’s liquidity consisted of $1.1 million of cash-on-hand and $199.0 million in available borrowings on its Credit Facility, which had a $775.0 million borrowing base. Management believes the Company has sufficient liquidity to meet all near-term obligations and execute its long-term development plans. In the future, we may seek to access the debt and equity capital markets from time to time to raise additional capital, increase liquidity, fund acquisitions or refinance debt. For more information on its Credit Facility, see the Credit Facility section within Note 6 of our condensed consolidated financial statements included in Item 1 of this report.

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Contractual Commitments and Obligations

Other than as discussed below, there were no other material changes in SilverBow's contractual commitments during the six months ended June 30, 2023 from amounts referenced under “Contractual Commitments and Obligations” in Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2022. During the second quarter of 2023, the Company entered into gas throughput agreements with separate parties in our Webb County gas area. The agreements provide for an annual average firm capacity of approximately 116,000 MMBtu/d over an eight-year term. Borrowings under our Credit Facility increased $34.0 million from December 31, 2022.

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Summary of 2023 Financial Results Through June 30, 2023

•Revenues and Net Income (Loss): The Company's oil and gas revenues were $266.4 million for the six months ended June 30, 2023, compared to $312.3 million for the six months ended June 30, 2022. Revenues were lower due to overall lower commodity pricing partially offset by increased production volumes. The Company's net income was $119.4 million for the six months ended June 30, 2023, compared to net income of $24.5 million for the six months ended June 30, 2022. The increase in net income was primarily driven by a net gain on our commodity derivatives.

•Capital Expenditures: The Company's capital expenditures on an accrual basis were $225.5 million for the six months ended June 30, 2023 compared to $114.6 million for the six months ended June 30, 2022. The expenditures for the six months ended June 30, 2023 and 2022 were primarily attributable to drilling and completion activity.

•Working Capital: The Company had a working capital surplus of $1.1 million at June 30, 2023 and a working capital deficit of $50.1 million at December 31, 2022. Included in our working capital was a net asset of $62.9 million and $11.8 million at June 30, 2023 and December 31, 2022, 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 six months ended June 30, 2023, the Company generated cash from operating activities of $191.1 million, of which $4.7 million was attributable to changes in working capital. Cash used for property additions was $221.5 million while purchase price adjustments related to our 2022 acquisitions totaled $0.2 million. Cash flows from operating activities also excluded $3.5 million attributable to a net increase of capital-related payables and accrued costs. The Company’s net borrowings on the Credit Facility were $34.0 million during the six months ended June 30, 2023.

For the six months ended June 30, 2022, the Company generated cash from operating activities of $115.6 million which included negative impacts attributable to changes in working capital of $34.6 million. Cash used for property additions was $93.7 million while purchase price adjustments related to our 2021 acquisitions totaled $272.2 million. This excluded $20.9 million attributable to a net increase of capital-related payables and accrued costs. The Company’s net borrowings on the Credit Facility were $267.0 million during the six months ended June 30, 2022 which were primarily used to fund acquisitions in the second quarter of 2022.

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Results of Operations

Revenues — Three Months Ended June 30, 2023 and Three Months Ended June 30, 2022

Natural gas production was 64% and 78% of the Company's production volumes for the three months ended June 30, 2023 and 2022, respectively. Natural gas sales were 27% and 68% of oil and gas sales for the three months ended June 30, 2023 and 2022, respectively.

Crude oil production was 23% and 11% of the Company's production volumes for the three months ended June 30, 2023 and 2022, respectively. Crude oil sales were 63% and 24% of oil and gas sales for the three months ended June 30, 2023 and 2022, respectively.

NGL production was 13% and 11% of the Company's production volumes for the three months ended June 30, 2023 and 2022, respectively. NGL sales were 10% and 8% of oil and gas sales for the three months ended June 30, 2023 and 2022.

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

Fields	Three Months Ended June 30, 2023			Three Months Ended June 30, 2022
	Oil and Gas Sales (In Millions)		Net Oil and Gas Production Volumes (MMcfe)	Oil and Gas Sales (In Millions)		Net Oil and Gas Production Volumes (MMcfe)
Webb County Gas	$	24.2	13,739	$	90.5	12,421
Western Condensate	28.5		6,326	38.2		3,925
Southern Eagle Ford	4.8		2,136	24.1		3,152
Central Oil	54.2		5,819	20.1		1,315
Eastern Extension	14.2		1,922	9.1		763
Non Core	0.5		62	0.6		67
Total	$	126.4	30,004	$	182.6	21,643

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

    In the second quarter of 2023, our $56.2 million, or 31%, decrease in oil, NGL and natural gas sales from the prior year period resulted from:

•Price variances that had an approximately $164.7 million unfavorable impact on sales due to overall lower commodity pricing; and

•Volume variances that had an approximately $108.5 million favorable impact on sales due to overall increased commodity production.

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    The following table provides additional information regarding our oil and gas sales, by commodity type, as well as the effects of our hedging activities for derivative contracts held to settlement, for the three months ended June 30, 2023 and 2022 (in thousands, except per-dollar amounts):

	Three Months Ended June 30, 2023		Three Months Ended June 30, 2022
Production volumes:
Oil (MBbl) (1)	1,137		400
Natural gas (MMcf)	19,124		16,918
Natural gas liquids (MBbl) (1)	677		387
Total (MMcfe)	30,004		21,643
Oil, natural gas and natural gas liquids sales:
Oil	$	80,151	$	44,014
Natural gas	33,805		123,296
Natural gas liquids	12,443		15,295
Total	$	126,400	$	182,605
Average realized price before impact of cash-settled derivatives:
Oil (per Bbl)	$	70.51	$	109.94
Natural gas (per Mcf)	1.77		7.29
Natural gas liquids (per Bbl)	18.39		39.51
Average per Mcfe	$	4.21	$	8.44
Price impact of cash-settled derivatives:
Oil (per Bbl)	$	1.59	$	(42.96)
Natural gas (per Mcf)	1.26		(2.75)
Natural gas liquids (per Bbl)	5.46		(6.38)
Average per Mcfe	$	0.99	$	(3.06)
Average realized price including impact of cash-settled derivatives:
Oil (per Bbl)	$	72.11	$	66.99
Natural gas (per Mcf)	3.03		4.54
Natural gas liquids (per Bbl)	23.85		33.13
Average per Mcfe	$	5.20	$	5.38

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

For the three months ended June 30, 2023 and 2022, the Company recorded net gains of $18.9 million and net losses of $22.2 million from our commodities derivatives activities, respectively. For the three months ended June 30, 2023 and 2022, we also recorded a net loss of less than $0.1 million and net loss $0.2 million, respectively, related to valuation changes from our 2021 and 2022 WTI Contingency Payouts. Additionally, we settled the final post-close adjustment related to the Sundance acquisition during the second quarter of 2023. As part of the settlement, SilverBow is no longer required to make any contingency payments related to the 2022 WTI Contingency Payout. As such, we recorded a non-cash gain of $1.1 million during the three months ended June 30, 2023. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.

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Costs and Expenses — Three Months Ended June 30, 2023 and Three Months Ended June 30, 2022

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

Costs and Expenses	Three Months Ended June 30, 2023		Three Months Ended June 30, 2022
General and administrative, net	$	5,318	$	5,710
Depreciation, depletion, and amortization	49,853		26,441
Accretion of asset retirement obligations	240		101
Lease operating expenses	19,180		10,270
Workovers	811		2
Transportation and gas processing	11,771		6,769
Severance and other taxes	8,771		9,838
Interest expense, net	18,190		7,902
Provision (benefit) for income taxes	7,351		4,366

General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.18 and $0.26 for the three months ended June 30, 2023 and 2022, respectively. The decrease in costs was primarily due to increased supervision fees charges to wells we operate, which are recorded as a reduction of general and administrative expenses, while the decrease in per-Mcfe rate was due to an overall increase in production. Included in general and administrative expenses is $1.5 million and $1.7 million in share-based compensation for the three months ended June 30, 2023 and 2022, respectively.

Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were $1.66 and $1.22 for the three months ended June 30, 2023 and 2022, respectively. The increase in our per-Mcfe depreciation, depletion and amortization rate was primarily related to the acquisitions in 2022 and inflation on future development costs. The increase in costs is related to the increase in the per-Mcfe rate, coupled with an overall increase in production.

Lease Operating Expenses and Workovers. These expenses on a per-Mcfe basis were $0.67 and $0.47 for the three months ended June 30, 2023 and 2022, respectively. The increase in costs was primarily due to higher labor, compression, salt water disposal, maintenance and chemical costs driven by our acquisitions in 2022.

Transportation and Gas Processing. These expenses are related to oil, natural gas and NGL sales. These expenses on a per-Mcfe basis were $0.39 and $0.31 for the three months ended June 30, 2023 and 2022, respectively. The increase in costs and in our per Mcfe rate was primarily attributable to additional transportation and processing agreements associated with our acquisitions in 2022 along with increased contractual fees across portions of our properties.

Severance and Other Taxes. These expenses on a per-Mcfe basis were $0.29 and $0.45 for the three months ended June 30, 2023 and 2022, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 6.9% and 5.4% for the three months ended June 30, 2023 and 2022, respectively.

    Interest. Our gross interest cost was $18.2 million and $7.9 million for the three months ended June 30, 2023 and 2022, respectively. The increase in gross interest is primarily due to higher borrowings and higher interest rates. There were no capitalized interest costs for the three months ended June 30, 2023 and 2022.

Income Taxes. The Company recorded an income tax provision of $7.4 million and an income tax provision of $4.4 million for the three months ended June 30, 2023 and 2022, respectively. The effective tax rate for the three months ended June 30, 2023 primarily related to the statutory federal tax rate plus the impact of the Texas Margin Tax. The effective tax rate for the three months ended June 30, 2022 related to the effects of a valuation allowance previously established against the Company's net federal deferred tax assets in excess of deferred tax liabilities. The tax impact for both periods was a product of the overall forecasted annual effective tax rate applied to the year to date income or loss.

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Results of Operations

Revenues — Six Months Ended June 30, 2023 and Six Months Ended June 30, 2022

Natural gas production was 65% and 77% of the Company's production volumes for the six months ended June 30, 2023 and 2022, respectively. Natural gas sales were 33% and 64% of oil and gas sales for the six months ended June 30, 2023 and 2022, respectively.

Crude oil production was 23% and 12% of the Company's production volumes for the six months ended June 30, 2023 and 2022, respectively. Crude oil sales were 58% and 27% of oil and gas sales for the six months ended June 30, 2023 and 2022, respectively.

NGL production was 12% and 11% of the Company's production volumes for the six months ended June 30, 2023 and 2022, respectively. NGL sales were 9% of oil and gas sales for both the six months ended June 30, 2023 and 2022.

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

Fields	Six Months Ended June 30, 2023			Six Months Ended June 30, 2022
	Oil and Gas Sales (In Millions)		Net Oil and Gas Production Volumes (MMcfe)	Oil and Gas Sales (In Millions)		Net Oil and Gas Production Volumes (MMcfe)
Webb County Gas	$	63.5	26,980	$	147.4	23,872
Western Condensate	55.5		11,569	76.5		8,474
Southern Eagle Ford	10.3		3,883	34.8		5,324
Central Oil	114.2		11,858	34.9		2,524
Eastern Extension	21.9		2,951	17.2		1,560
Non Core	1.0		109	1.5		208
Total	$	266.4	57,350	$	312.3	41,962

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

    In the first six months of 2023, our $45.9 million, or 15%, decrease in oil, NGL and natural gas sales from the prior year period resulted from:

•Price variances that had an approximately $226.0 million unfavorable impact on sales due to overall lower commodity pricing; and

•Volume variances that had an approximately $180.1 million favorable impact on sales due to overall increased commodity production.

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The following table provides additional information regarding our oil and gas sales, by commodity type, as well as the effects of our hedging activities for derivative contracts held to settlement, for the six months ended June 30, 2023 and 2022 (in thousands, except per-dollar amounts):

	Six Months Ended June 30, 2023		Six Months Ended June 30, 2022
Production volumes:
Oil (MBbl) (1)	2,159		830
Natural gas (MMcf)	37,098		32,505
Natural gas liquids (MBbl) (1)	1,216		747
Total (MMcfe)	57,350		41,962
Oil, natural gas and natural gas liquids sales:
Oil	$	154,807	$	83,755
Natural gas	86,727		200,668
Natural gas liquids	24,820		27,838
Total	$	266,354	$	312,261
Average realized price before impact of cash-settled derivatives:
Oil (per Bbl)	$	71.70	$	100.97
Natural gas (per Mcf)	2.34		6.17
Natural gas liquids (per Bbl)	20.41		37.29
Average per Mcfe	$	4.64	$	7.44
Price impact of cash-settled derivatives:
Oil (per Bbl)	$	1.27	$	(36.28)
Natural gas (per Mcf)	1.11		(1.84)
Natural gas liquids (per Bbl)	4.64		(6.25)
Average per Mcfe	$	0.86	$	(2.25)
Average realized price including impact of cash-settled derivatives:
Oil (per Bbl)	$	72.97	$	64.69
Natural gas (per Mcf)	3.45		4.34
Natural gas liquids (per Bbl)	25.05		31.03
Average per Mcfe	$	5.50	$	5.19

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

For the six months ended June 30, 2023 and 2022, the Company recorded net gains of $110.2 million and net losses of $161.2 million from our commodities derivatives activities, respectively. For the six months ended June 30, 2023 and 2022, we also recorded a net gain of $0.9 million and net loss of $1.5 million, respectively, related to valuation changes from our 2021 and 2022 WTI Contingency Payouts. Additionally, we settled the final post-close adjustment related to the Sundance acquisition during the second quarter of 2023. As part of the settlement, SilverBow is no longer required to make any contingency payments related to the 2022 WTI Contingency Payout. As such, we recorded a non-cash gain of $1.1 million during the six months ended June 30, 2023. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.

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Costs and Expenses — Six Months Ended June 30, 2023 and Six Months Ended June 30, 2022

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

Costs and Expenses	Six Months Ended June 30, 2023		Six Months Ended June 30, 2022
General and administrative, net	$	12,982	$	10,497
Depreciation, depletion, and amortization	93,850		47,595
Accretion of asset retirement obligations	464		200
Lease operating expenses	39,740		19,395
Workovers	1,590		649
Transportation and gas processing	23,292		13,121
Severance and other taxes	18,156		17,602
Interest expense, net	34,935		14,459
Provision (benefit) for income taxes	34,163		1,612

General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.23 and $0.25 for the six months ended June 30, 2023 and 2022, respectively. The increase in costs was primarily due to higher legal and professional fees. Included in general and administrative expenses is $2.6 million and $2.7 million in share-based compensation for the six months ended June 30, 2023 and 2022, respectively.

Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were $1.64 and $1.13 for the six months ended June 30, 2023 and 2022, respectively. The increase in our per-Mcfe depreciation, depletion and amortization rate was primarily related to the acquisitions in 2022 and inflation on future development costs. The increase in costs is related to the increase in the per-Mcfe rate, coupled with an overall increase in production.

Lease Operating Expenses and Workovers. These expenses on a per-Mcfe basis were $0.72 and $0.48 for the six months ended June 30, 2023 and 2022, respectively. The increase in costs was primarily due to higher labor, compression, salt water disposal, maintenance and chemical costs driven by our acquisitions in 2022.

Transportation and Gas Processing. These expenses are related to oil, natural gas and NGL sales. These expenses on a per-Mcfe basis were $0.41 and $0.31 for the six months ended June 30, 2023 and 2022, respectively. The increase in costs and in our per Mcfe rate was primarily attributable to additional transportation and processing agreements associated with our acquisitions in 2022 along with increased contractual fees across portions of our properties.

Severance and Other Taxes. These expenses on a per-Mcfe basis were $0.32 and $0.42 for the six months ended June 30, 2023 and 2022, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 6.8% and 5.6% for the six months ended June 30, 2023 and 2022, respectively.

    Interest. Our gross interest cost was $34.9 million and $14.4 million for the six months ended June 30, 2023 and 2022, respectively. The increase in gross interest is primarily due to higher borrowings and higher interest rates. There were no capitalized interest costs for the six months ended June 30, 2023 and 2022.

Income Taxes. The Company recorded an income tax provision of $34.2 million and an income tax provision of $1.6 million for the six months ended June 30, 2023 and 2022, respectively. The effective tax rate for the six months ended June 30, 2023 primarily related to the statutory federal tax rate plus the impact of the Texas Margin Tax. The effective tax rate for the six months ended June 30, 2022 related to the effects of a valuation allowance previously established against the Company's net federal deferred tax assets in excess of deferred tax liabilities. 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 2022 Annual Report on Form 10-K.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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

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

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

Interest Rate Risk. At June 30, 2023, we had a combined $726.0 million drawn under our Credit Facility and our Second Lien, which bear floating rates of interest and therefore are susceptible to interest rate fluctuations. These variable interest rate borrowings are also impacted by changes in short-term interest rates. A hypothetical one percentage point increase in interest rates on our borrowings outstanding under our Credit Facility and Second Lien at June 30, 2023 would increase our annual interest expense by $7.1 million.

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Item 4. Controls and Procedures

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the three months ended June 30, 2023 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

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

Item 1A. Risk Factors.

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

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.    

(c) Trading Plans

During the quarter ended June 30, 2023, no director or Section 16 officer adopted or terminated any Rule 10b5-1 trading arrangements or non-Rule 10b5-1 trading arrangements (in each case, as defined in Item 408 of Regulation S-K).

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Item 6. Exhibits.

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

3.1	Certificate of Incorporation of Swift Energy Company, effective April 22, 2016 (incorporated by reference Exhibit 3.1 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
3.2	Certificate of Amendment to Certificate of Incorporation, effective May 5, 2017 (incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed May 5, 2017, File No. 001-08754).
3.3	Second Amended and Restated Bylaws of SilverBow Resources, Inc., effective October 31, 2022 (incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed September 20, 2022, File No. 001-08754).
3.4	Certificate of Designation, Preferences, and Rights of Series B Junior Participating Preferred Stock of the Company (incorporated by reference as Exhibit 3.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed September 20, 2022, File No. 001-08754).
4.1	Amendment to Rights Agreement, dated May 16, 2023, by and between the Company and American Stock Transfer & Trust Company, LLC, as rights agent (incorporated by reference as Exhibit 4.2 to the Form 8-K filed with the SEC on May 16, 2023, File No. 001-08754).
10.1	Third Amendment to Note Purchase Agreement dated as of June 14, 2023, by and among SilverBow Resources, Inc., as issuer, U.S. Bank Trust Company, National Association (as successor-in-interest to U.S. Bank National Association), as agent and collateral agent, the guarantors party thereto and certain holders party thereto (incorporated by reference as Exhibit 10.1 to the Form 8-K filed with the SEC on June 20, 2023, File No. 001-08754).
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32.1#	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
101*	The following materials from SilverBow Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 2023 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets (Unaudited), (ii) the Condensed Consolidated Statements of Operations (Unaudited), (iii) the Consolidated Statements of Stockholders Equity (Unaudited), (iv) the Condensed Consolidated Statements of Cash Flows (Unaudited), and (v) Notes to the Condensed Consolidated Financial Statements.
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

*Filed herewith

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

+ Management contract or compensatory plan or arrangement

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SIGNATURES

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

		SILVERBOW RESOURCES, INC.   (Registrant)
Date:	August 3, 2023	By:	/s/ Christopher M. Abundis
			Christopher M. Abundis Executive Vice President, Chief Financial Officer and General Counsel
Date:	August 3, 2023	By:	/s/ W. Eric Schultz
			W. Eric Schultz Vice President of Accounting and Controller

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