10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

of the Securities Exchange Act of 1934

For the quarterly period ended September 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) 25,429,610 Shares outstanding at October 27, 2023

2

SILVERBOW RESOURCES, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 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	35
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	46
Part II	OTHER INFORMATION
Item 1.	Legal Proceedings	47
Item 1A.	Risk Factors	47
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	48
Item 3.	Defaults Upon Senior Securities	48
Item 4.	Mine Safety Disclosures	49
Item 5.	Other Information	49
Item 6.	Exhibits	49
SIGNATURES		51

3

Forward-Looking Statements

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

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

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

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

• 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 conflicts in Ukraine and the Gaza Strip);

• 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;

4

• 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

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

Many of the foregoing risks and uncertainties, as well as risks and uncertainties that are currently unknown to us, are, and may be, exacerbated by geopolitical events and wars, increasing economic uncertainty, recessionary and inflationary pressures and any consequent worsening of the global business and economic environment. New factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of the risks or uncertainties described in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2022, subsequent Quarterly Reports on Form 10-Q, or other SEC filings occur, or should underlying assumptions prove incorrect, actual results and plans could differ materially from those expressed in any forward-looking statements.

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

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

5

PART I. FINANCIAL INFORMATION

Condensed Consolidated Balance Sheets (Unaudited)

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

	September 30, 2023		December 31, 2022
ASSETS
Current Assets:
Cash and cash equivalents	$	1,697	$	792
Accounts receivable, net	80,202		89,714
Fair value of commodity derivatives	50,189		52,549
Other current assets	3,825		2,671
Total Current Assets	135,913		145,726
Property and Equipment:
Property and equipment, full cost method, including $27,821 and $16,272, respectively, of unproved property costs not being amortized at the end of each period	2,861,267		2,529,223
Less – Accumulated depreciation, depletion, amortization & impairment	(1,151,141)		(1,004,044)
Property and Equipment, Net	1,710,126		1,525,179
Right of use assets	10,085		12,077
Fair value of long-term commodity derivatives	14,180		24,172
Deposit and other fees for oil and gas property transaction	52,564		—
Other long-term assets	7,581		9,208
Total Assets	$	1,930,449	$	1,716,362
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	74,731	$	60,200
Fair value of commodity derivatives	32,752		40,796
Accrued capital costs	56,424		56,465
Accrued interest	2,976		2,665
Current lease liability	5,507		8,553
Undistributed oil and gas revenues	22,462		27,160
Total Current Liabilities	194,852		195,839
Long-term debt, net	645,096		688,531
Non-current lease liability	4,604		3,775
Deferred tax liabilities	49,033		16,141
Asset retirement obligations	9,840		9,171
Fair value of long-term commodity derivatives	21,560		7,738
Other long-term liabilities	922		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, 25,914,823 and 22,663,135 shares issued, respectively, and 25,429,517 and 22,309,740 shares outstanding, respectively	259		227
Additional paid-in capital	677,473		576,118
Treasury stock, held at cost, 485,306 and 353,395 shares, respectively	(10,616)		(7,534)
Retained earnings	337,426		222,768
Total Stockholders’ Equity	1,004,542		791,579
Total Liabilities and Stockholders’ Equity	$	1,930,449	$	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 September 30, 2023		Three Months Ended September 30, 2022
Revenues:
Oil and gas sales	$	173,963	$	242,181
Operating Expenses:
General and administrative, net	4,438		4,343
Depreciation, depletion, and amortization	53,186		41,501
Accretion of asset retirement obligations	254		166
Lease operating expenses	22,678		17,701
Workovers	672		284
Transportation and gas processing	13,710		9,662
Severance and other taxes	10,407		12,581
Total Operating Expenses	105,345		86,238
Operating Income	68,618		155,943
Non-Operating Income (Expense)
Gain (loss) on commodity derivatives, net	(54,639)		4,832
Interest expense, net	(19,811)		(12,173)
Other income (expense), net	112		5
Income (Loss) Before Income Taxes	(5,720)		148,607
Provision (Benefit) for Income Taxes	(949)		6,066
Net Income (Loss)	$	(4,771)	$	142,541
Per Share Amounts:
Basic Earnings (Loss) Per Share	$	(0.21)	$	6.39
Diluted Earnings (Loss) Per Share	$	(0.21)	$	6.29
Weighted-Average Shares Outstanding - Basic	22,985		22,308
Weighted-Average Shares Outstanding - Diluted	22,985		22,669
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)

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

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
Stock options exercised (11,087 shares)	—		387		—		—		387
Purchase of treasury shares (7,853 shares)	—		—		(432)		—		(432)
Treasury shares pursuant to purchase price adjustment (184 shares)	—		—		(7)		—		(7)
Share-based compensation	—		1,239		—		—		1,239
Net income	—		—		—		142,541		142,541
Balance, September 30, 2022	$	227	$	574,885	$	(7,534)	$	49,407	$	616,985
Balance, December 31, 2022	$	227	$	576,118	$	(7,534)	$	222,768	$	791,579
Purchase of treasury shares (126,240 shares)	—		—		(2,945)		—		(2,945)
Vesting of share-based compensation (418,518 shares)	4		(4)		—		—		—
Share-based compensation	—		1,179		—		—		1,179
Net Income	—		—		—		94,492		94,492
Balance, March 31, 2023	$	231	$	577,293	$	(10,479)	$	317,260	$	884,305
Purchase of treasury shares (5,310 shares)	—		—		(121)		—		(121)
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
Purchase of treasury shares (361 shares)	—		—		(16)		—		(16)
Vesting of share-based compensation (1,225 shares)	—		—		—		—		—
Issuance of common stock (2,810,811 shares)	28		97,105		—		—		97,133
Share-based compensation	—		1,551		—		—		1,551
Net Loss	—		—		—		(4,771)		(4,771)
Balance, September 30, 2023	$	259	$	677,473	$	(10,616)	$	337,426	$	1,004,542
See accompanying Notes to Condensed Consolidated Financial Statements.

9

Condensed Consolidated Statements of Cash Flows (Unaudited)

SilverBow Resources, Inc. and Subsidiary (in thousands)

	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022
Cash Flows from Operating Activities:
Net income (loss)	$	114,658	$	167,076
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization	147,037		89,096
Accretion of asset retirement obligations	718		366
Deferred income taxes	32,892		7,496
Share-based compensation	4,043		3,901
(Gain) Loss on derivatives, net	(57,604)		157,816
Cash settlement (paid) received on derivatives	70,670		(182,058)
Settlements of asset retirement obligations	(481)		(47)
Write down of debt issuance cost	—		350
Other, net	2,028		(6,425)
Change in operating assets and liabilities:
(Increase) decrease in accounts receivable and other current assets	9,129		(47,320)
Increase (decrease) in accounts payable and accrued liabilities	(5,320)		20,260
Increase (decrease) in income taxes payable	321		(21)
Increase (decrease) in accrued interest	311		1,688
Net Cash Provided by (Used in) Operating Activities	318,402		212,178
Cash Flows from Investing Activities:
Additions to property and equipment	(316,003)		(163,567)
Acquisition of oil and gas properties, net of purchase price adjustments	(382)		(293,880)
Deposit and other fees for oil and gas property transaction	(51,163)		—
Proceeds from the sale of property and equipment	—		4,415
Payments on property sale obligations	—		(750)
Net Cash Provided by (Used in) Investing Activities	(367,548)		(453,782)
Cash Flows from Financing Activities:
Proceeds from bank borrowings	334,000		679,000
Payments of bank borrowings	(378,000)		(426,000)
Net proceeds from issuances of common stock	97,133		—
Net proceeds from stock options exercised	—		39
Purchase of treasury shares	(3,082)		(3,404)
Payments of debt issuance costs	—		(7,228)
Net Cash Provided by (Used in) Financing Activities	50,051		242,407
Net Increase (Decrease) in Cash and Cash Equivalents	905		803
Cash and Cash Equivalents at Beginning of Period	792		1,121
Cash and Cash Equivalents at End of Period	$	1,697	$	1,924
Supplemental Disclosures of Cash Flow Information:
Cash paid during period for interest, net of amounts capitalized	$	52,170	$	22,701
Non-cash Investing and Financing Activities:
Changes in capital accounts payable and capital accruals	$	13,363	$	60,595
Accrued other fees for oil and gas property transaction	$	(1,401)	$	—
Non-cash equity consideration for acquisitions	$	—	$	(156,259)
See accompanying Notes to Condensed Consolidated Financial Statements.

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, 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.

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.

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

11

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

Through October 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 September 30, 2023:

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

Oil Basis Swaps (Argus Cushing (WTI) and Magellan East Houston)	Total Volumes (MMBtu)	Weighted-Average Price
2023 Contracts
4Q23	61,000	$	0.90
2025 Contracts
1Q25	90,000	$	1.75
2Q25	91,000	$	1.75
3Q25	92,000	$	1.75
4Q25	92,000	$	1.75
Calendar Monthly Roll Differential Swaps
2023 Contracts
4Q23	61,000	$	2.40
2025 Contracts
1Q25	90,000	$	0.50
2Q25	91,000	$	0.50
3Q25	92,000	$	0.50
4Q25	92,000	$	0.50

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Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Price
Swap Contracts
2024 Contracts
1Q24	1,820,000	$	3.66
2Q24	2,430,000	$	3.31
3Q24	2,760,000	$	3.46
4Q24	2,760,000	$	3.75
2025 Contracts
1Q25	2,700,000	$	4.20
2Q25	2,730,000	$	3.75
3Q25	2,760,000	$	3.89
4Q25	1,540,000	$	4.11
2026 Contracts
1Q26	900,000	$	4.56
2Q26	910,000	$	3.53
3Q26	920,000	$	3.73
4Q26	920,000	$	4.19

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

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

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

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

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

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

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

•estimates of future costs to develop and produce reserves,

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

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

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

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

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

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

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

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

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

•estimates on future lease obligations.

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

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

Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended September 30, 2023 and 2022, such internal costs capitalized totaled $1.4 million and $1.1 million, respectively. For the nine months ended September 30, 2023 and 2022, such internal costs capitalized totaled $4.1 million and $3.3 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. There was no capitalized interest on our unproved properties for both the three months ended September 30, 2023 and 2022 and the nine months ended September 30, 2023 and 2022.

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

	September 30, 2023		December 31, 2022
Property and Equipment
Proved oil and gas properties	$	2,827,145	$	2,506,853
Unproved oil and gas properties	27,821		16,272
Furniture, fixtures and other equipment	6,301		6,098
Less – Accumulated depreciation, depletion, amortization & impairment	(1,151,141)		(1,004,044)
Property and Equipment, Net	$	1,710,126	$	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.

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

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

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

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

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

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

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

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

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administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the nine months ended September 30, 2023 and 2022 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $3.0 million and $2.8 million for the three months ended September 30, 2023 and 2022, respectively, and $8.6 million and $6.1 million for the nine months ended September 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 17% and 4% for the three months ended September 30, 2023 and 2022, respectively, and 22% and 4% for the nine months ended September 30, 2023 and 2022, respectively. The Company recorded an income tax benefit of $0.9 million and income tax provision of $33.2 million for the three and nine months ended September 30, 2023, respectively, and an income tax provision of $6.1 million and $7.7 million for the three and nine months ended September 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.

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

Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At September 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 September 30, 2023 and 2022 and the nine months ended September 30, 2023 and 2022 (in thousands):

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

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

	September 30, 2023		December 31, 2022
Trade accounts payable	$	30,708	$	23,660
Accrued operating expenses	11,266		10,572
Accrued compensation costs	3,267		4,814
Asset retirement obligations – current portion	1,578		1,284
Accrued non-income based taxes	13,303		4,849
Accrued corporate and legal fees	181		388
WTI contingency payouts - current portion	1,537		1,600
Payable for settled derivatives	3,549		6,026
Other payables	9,342		7,007
Total accounts payable and accrued liabilities	$	74,731	$	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.

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 nine months ended September 30, 2023, we purchased 131,911 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. For the nine months ended September 30, 2022, we purchased 120,350 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares and received 41,375 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, and ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, issued in December 2022. The guidance provides and clarifies optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The amendments within these ASUs were in effect beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2024. This guidance provides an optional practical expedient that allows qualifying modifications to be accounted for as a debt modification rather than be analyzed under existing guidance to determine if the modification should be accounted for as a debt extinguishment. The Company adopted this accounting pronouncement in conjunction with the execution of the Third Amendment to the Note Purchase Agreement in June 2023 and elected to apply this optional expedient. See Note 6 – Long-Term Debt for further discussion of the Company’s accounting for its existing debt and related issuance costs. The adoption of this accounting standard did not have a material impact on the Company's condensed consolidated financial statements and related disclosures.

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

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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 condensed consolidated balance sheets. We have elected to not account for lease and non-lease components separately.

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

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

	As of September 30, 2023
2023 (Remaining)	$	2,667
2024	4,166
2025	2,427
2026	1,194
2027	61
Thereafter	475
Total undiscounted lease payments	10,990
Present value adjustment	(879)
Net operating lease liabilities	$	10,111

(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 $1.2 million for the three months ended September 30, 2023 and 2022, respectively, and $4.0 million and $3.9 million for the nine months ended September 30, 2023 and 2022, respectively. Capitalized share-based compensation was less than $0.1 million for both

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

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

    Stock Option Awards

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

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

Restricted Stock Units

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

As of September 30, 2023, we had $5.1 million unrecognized compensation expense related to our RSUs which is expected to be recognized over a weighted-average period of 2.0 years.

The following table provides information regarding RSU activity for the nine months ended September 30, 2023:

	RSUs	Wtd. Avg. Grant Price
RSUs outstanding, beginning of period	227,114	$	21.18
RSUs granted	195,791	$	23.75
RSUs forfeited	(1,424)	$	25.44
RSUs vested	(137,467)	$	17.78
RSUs outstanding, end of period	284,014	$	24.58

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.

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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 September 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 September 30, 2023.

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

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

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

(5)          Earnings Per Share

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

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

	Three Months Ended September 30, 2023					Three Months Ended September 30, 2022
	Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)		Shares	Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	(4,771)	22,985	$	(0.21)	$	142,541	22,308	$	6.39
Dilutive Securities:
Performance Based Stock Unit Awards			—					169
RSU Awards			—					137
Stock Option Awards			—					55
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	(4,771)	22,985	$	(0.21)	$	142,541	22,669	$	6.29

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

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

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

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

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

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(6)          Long-Term Debt

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

	September 30, 2023		December 31, 2022
Credit Facility Borrowings due 2026 (1)	$	498,000	$	542,000
Second Lien Notes due 2026	150,000		150,000
	648,000		692,000
Unamortized discount on Second Lien Notes due 2026	(738)		(882)
Unamortized debt issuance cost on Second Lien Notes due 2026	(2,166)		(2,587)
Long-Term Debt, net	$	645,096	$	688,531

(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our condensed consolidated balance sheet. As of September 30, 2023 and December 31, 2022, we had $7.0 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 $498.0 million and $542.0 million as of September 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 September 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 interest at 2.0% per annum above the rate and margin otherwise applicable thereto. As of September 30, 2023, the Company's weighted average interest rate on Credit Facility borrowings was 8.67%.

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

The Credit Agreement contains the following financial covenants:

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

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

As of September 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 $14.6 million and $8.3 million for the three months ended September 30, 2023 and 2022, respectively, and $39.8 million and $15.9 million for the nine months ended September 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 September 30, 2023 and 2022, respectively, and $0.7 million and $0.9 million for the nine months ended September 30, 2023 and 2022, respectively.

    Senior Secured Second Lien Notes. On December 15, 2017, the Company entered into a Note Purchase Agreement for Senior Secured Second Lien Notes (as amended, the “Note Purchase Agreement,” and such second lien facility the “Second Lien”) 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 September 30, 2023, the Company's interest rate on Second Lien borrowings was 13.16%.

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 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

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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 September 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 September 30, 2023, total net amounts recorded for the Second Lien were $147.1 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $5.2 million and $3.8 million for the three months ended September 30, 2023 and 2022, respectively, and $14.9 million and $10.7 million for the nine months ended September 30, 2023 and 2022, respectively.

Debt Issuance Costs. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings. During the nine months ended September 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 nine months ended September 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 September 30, 2023 and 2022, the Company recorded losses of $0.9 million and gains of $0.7 million, respectively, and losses of $1.0 million and $0.8 million, respectively, for the nine months ended September 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.

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.

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

Total Cost
Cash consideration	$	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 nine months ended September 30, 2023, the Company recorded gains of $1.0 million related to valuation changes in the 2022 WTI Contingency Payout recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. Additionally, as part of our post-close settlement we settled the 2022 WTI Contingency during the second quarter of 2023. As such, we recorded a non-cash gain of $1.1 million during the nine months ended September 30, 2023, and we are no longer required to make a contingency payment related to the 2022 WTI Contingency Payout. We incurred approximately $6.8 million in transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

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

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

August 2022 Acquisition

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

October 2022 Acquisition

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

2022 Non-strategic Dispositions

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

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2023 Chesapeake Acquisition

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

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

(8)          Price-Risk Management Activities

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

During the three months ended September 30, 2023 and 2022, the Company recorded losses of $53.7 million and losses of $1.3 million, respectively, on its commodity derivatives. During the nine months ended September 30, 2023 and 2022, the Company recorded gains of $56.5 million and losses of $162.5 million, respectively, on its commodity derivatives. During the three months ended September 30, 2023 and 2022, the Company recorded losses of $0.9 million and gains of $6.1 million, respectively, related to valuation changes on the 2021 WTI Contingency Payout and 2022 WTI Contingency Payout. During the nine months ended September 30, 2023 and 2022, the Company recorded gains of $1.1 million and gains of $4.7 million, respectively, related to valuation changes on the 2021 WTI Contingency Payout and 2022 WTI Contingency Payout. The Company collected cash payments of $70.7 million and made cash payments of $182.1 million for settled derivative contracts during the nine months ended September 30, 2023 and 2022, respectively.

At September 30, 2023 and December 31, 2022, there was $8.4 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 October 2023 and January 2023, respectively. At September 30, 2023 and December 31, 2022, we also had $3.5 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 October 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 September 30, 2023, there was $50.2 million and $14.2 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $32.8 million and $21.6 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 $10.1 million net fair value asset at September 30, 2023, and a $28.2 million net fair value asset at December 31, 2022. For further discussion related to the fair value of the Company's derivatives, refer to Note 9 of these Notes to Condensed Consolidated Financial Statements.

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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 September 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
4Q23	707,300	$	78.53
2024 Contracts
1Q24	728,000	$	77.67
2Q24	754,550	$	77.59
3Q24	779,620	$	76.48
4Q24	762,100	$	76.16
2025 Contracts
1Q25	666,000	$	71.60
2Q25	673,400	$	71.60
3Q25	680,800	$	71.60
4Q25	588,800	$	71.29
2026 Contracts
1Q26	315,000	$	69.40
2Q26	318,500	$	69.40
3Q26	322,000	$	69.40
4Q26	230,000	$	69.42
Collar Contracts
2023 Contracts
4Q23	302,242					$	65.89	$	74.54
2024 Contracts
1Q24	319,700					$	58.95	$	71.74
2Q24	215,000					$	61.08	$	73.57
3Q24	184,000					$	63.50	$	75.53
4Q24	184,000					$	63.00	$	75.35
2025 Contracts
1Q25	238,500					$	64.00	$	74.62
2Q25	227,500					$	60.80	$	72.22
2026 Contracts
1Q26	90,000					$	64.00	$	71.50
2Q26	91,000					$	64.00	$	71.50
3Q26	92,000					$	64.00	$	71.50
3-Way Collar Contracts
2023 Contracts
4Q23	8,970			$	43.08	$	53.38	$	63.35
2024 Contracts
1Q24	8,247			$	45.00	$	57.50	$	67.85
2Q24	7,757			$	45.00	$	57.50	$	67.85

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Oil Basis Swaps (Argus Cushing (WTI) and Magellan East Houston)	Total Volumes (MMBtu)	Weighted-Average Price
2023 Contracts
4Q23	122,000	$	0.80
2024 Contracts
1Q24	364,000	$	1.47
2Q24	364,000	$	1.47
3Q24	368,000	$	1.47
4Q24	368,000	$	1.47
2025 Contracts
1Q25	270,000	$	1.75
2Q25	273,000	$	1.75
3Q25	276,000	$	1.75
4Q25	276,000	$	1.75
Calendar Monthly Roll Differential Swaps
2023 Contracts
4Q23	122,000	$	2.44
2024 Contracts
1Q24	364,000	$	0.69
2Q24	364,000	$	0.69
3Q24	368,000	$	0.69
4Q24	368,000	$	0.69
2025 Contracts
1Q25	270,000	$	0.40
2Q25	273,000	$	0.40
3Q25	276,000	$	0.40
4Q25	276,000	$	0.40

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Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Price		Weighted-Average Collar Sub Floor Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
Swap Contracts
2023 Contracts
4Q23	5,727,000	$	4.20
2024 Contracts
1Q24	7,686,000	$	4.12
2Q24	12,350,000	$	3.67
3Q24	12,420,000	$	3.78
4Q24	12,420,000	$	4.12
2025 Contracts
1Q25	9,450,000	$	4.25
2Q25	9,555,000	$	3.71
3Q25	11,960,000	$	3.83
4Q25	8,740,000	$	4.17
2026 Contracts
1Q26	9,680,000	$	4.48
2Q26	9,555,000	$	3.56
3Q26	9,660,000	$	3.74
4Q26	9,200,000	$	4.13
Collar Contracts
2023 Contracts
4Q23	12,445,000					$	3.87	$	4.80
2024 Contracts
1Q24	9,661,000					$	3.94	$	5.83
2Q24	4,643,000					$	3.64	$	4.28
3Q24	3,878,000					$	3.77	$	4.76
4Q24	3,865,000					$	4.01	$	5.34
2025 Contracts
1Q25	5,130,000					$	4.00	$	5.32
2Q25	4,914,000					$	3.25	$	3.98
3Q25	920,000					$	3.50	$	3.99
4Q25	920,000					$	3.75	$	4.65
3-Way Collar Contracts
2023 Contracts
4Q23	219,200			$	2.00	$	2.50	$	2.94
2024 Contracts
1Q24	198,000			$	2.00	$	2.50	$	3.37
2Q24	188,000			$	2.00	$	2.50	$	3.37

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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
4Q23	13,800,000	$	(0.23)
2024 Contracts
1Q24	15,470,000	$	(0.02)
2Q24	15,470,000	$	(0.29)
3Q24	15,640,000	$	(0.26)
4Q24	15,640,000	$	(0.28)
2025 Contracts
1Q25	5,400,000	$	(0.09)
2Q25	5,460,000	$	(0.26)
3Q25	5,520,000	$	(0.23)
4Q25	5,520,000	$	(0.25)

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

(9)           Fair Value Measurements

Fair Value on a Recurring Basis. Our financial instruments consist of cash and cash equivalents, 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).

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

Acquisitions. The Company recognized the assets acquired in our acquisitions at cost at a relative fair value basis (refer to Note 7 of these Notes to 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 September 30, 2023 and December 31, 2022, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these Notes to Condensed Consolidated Financial Statements.

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

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

(10)           Asset Retirement Obligations

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

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obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets.

The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2022 and the nine months ended September 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	718
Liabilities incurred for new wells, acquired wells and facilities construction	313
Reductions due to plugged wells and facilities	(603)
Revisions in estimates	534
Asset Retirement Obligations as of September 30, 2023	$	11,418

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

(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 nine months ended September 30, 2023 increased 30% from the nine months ended September 30, 2022 to 330 million cubic feet of natural gas equivalent per day.

During the third quarter of 2023, SilverBow drilled 10 net wells, completed 9 net wells and brought online 9 net wells. The Company operated an average of two drilling rigs during the quarter, primarily on its Central Oil and Eastern Extension areas, which reflect its oil-focused development program year-to-date. SilverBow's team continues to increase operational efficiencies, completing 10% more stages per day year-to-date in 2023 as compared to similar jobs for full year 2022, and averaging pumping efficiencies 20% higher over the same time periods. Third quarter pumping efficiencies were the highest quarterly rate achieved year-to-date in 2023 due to decreases in downtime, leading to the increase in completed stages per day. Drilling costs continue to benefit from greater efficiencies from high-grading of rigs and ongoing cost deflation, particularly across casing costs and rig rates, resulting in drilling costs per lateral foot approximately 13% lower year-to-date in 2023 as compared to full year 2022.

In its Central Oil area, the Company recently brought online a four-well pad which produced a 30-day pad average of 4,349 Boe/d (82% oil) with average lateral lengths of 7,500 feet. Also in its Central Oil area, SilverBow brought online a two-well pad which produced a 30-day pad average of 2,140 Boe/d (82% oil) with average lateral lengths of 9,140 feet. Strong initial performance from these pads are in-line with expectations and support the Company's oil focused growth plans. Furthermore, SilverBow continues to test optimal spacing and co-development potential of the Eagle Ford and Austin Chalk formations across its oil assets.

For the remainder of 2023, the Company anticipates running one rig on its oil assets and one rig on its gas assets. SilverBow is re-iterating its full year 2023 capital budget guidance range of $400-$425 million. Given operational and cost efficiencies realized year-to-date, the Company may elect to complete several wells at the end of the year while remaining within its stated guidance range, which would be expected to contribute to higher production volumes into 2024. The Company aims to optimize its drilling schedule based on commodity prices, returns on investment and strategically proving up additional inventory within its portfolio.

Liquidity and Capital Resources

SilverBow's primary use of cash has been to fund capital expenditures to develop its oil and gas properties, fund acquisitions and to repay Credit Facility borrowings. The Company uses cash generated from operating activities and borrowings under its Credit Facility as its primary sources of liquidity.

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

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

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

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

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

Contractual Commitments and Obligations

Other than as discussed below, there were no other material changes in SilverBow's contractual commitments during the nine months ended September 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.

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Summary of 2023 Financial Results Through September 30, 2023

•Revenues and Net Income (Loss): The Company's oil and gas revenues were $440.3 million for the nine months ended September 30, 2023, compared to $554.4 million for the nine months ended September 30, 2022. Revenues were lower due to overall lower commodity pricing partially offset by increased production volumes. The Company's net income was $114.7 million for the nine months ended September 30, 2023, compared to net income of $167.1 million for the nine months ended September 30, 2022. The decrease in net income was primarily driven by lower commodity pricing.

•Capital Expenditures: The Company's capital expenditures on an accrual basis were $329.9 million for the nine months ended September 30, 2023 compared to $224.8 million for the nine months ended September 30, 2022. The expenditures for the nine months ended September 30, 2023 and 2022 were primarily attributable to drilling and completion activity.

•Working Capital: The Company had a working capital deficit of $58.9 million at September 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 $17.4 million and $11.8 million at September 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 nine months ended September 30, 2023, the Company generated cash from operating activities of $318.4 million, of which $4.4 million was attributable to changes in working capital. Additionally, the Company collected cash settlements of $70.7 million on derivatives during the nine months ended September 30, 2023. Cash flows from operating activities also excluded $13.4 million attributable to a net increase of capital-related payables and accrued costs. Cash used for property additions was $316.0 million while acquisition costs related to our 2022 acquisitions totaled $0.4 million. The Company's deposit and other fees related to our oil and gas property transaction totaled $51.2 million during the nine months ended September 30, 2023. The Company’s net repayments on the Credit Facility were $44.0 million during the nine months ended September 30, 2023. The Company's aggregate net proceeds, after offering expenses, from issuance of common stock in a public underwritten offering was approximately $97.1 million during the nine months ended September 30, 2023.

For the nine months ended September 30, 2022, the Company generated cash from operating activities of $212.2 million which included negative impacts attributable to changes in working capital of $25.4 million. Cash used for property additions was $163.6 million while purchase price adjustments related to our 2021 acquisitions totaled $293.9 million. This excluded $60.6 million attributable to a net increase of capital-related payables and accrued costs. The Company’s net borrowings on the Credit Facility were $253.0 million during the nine months ended September 30, 2022 which were primarily used to fund acquisitions during the nine months ended September 30, 2022.

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Results of Operations

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

Natural gas production was 61% and 70% of the Company's production volumes for the three months ended September 30, 2023 and 2022, respectively. Natural gas sales were 26% and 62% of oil and gas sales for the three months ended September 30, 2023 and 2022, respectively.

Crude oil production was 26% and 17% of the Company's production volumes for the three months ended September 30, 2023 and 2022, respectively. Crude oil sales were 65% and 30% of oil and gas sales for the three months ended September 30, 2023 and 2022, respectively.

NGL production was 13% of the Company's production volumes for both the three months ended September 30, 2023 and 2022. NGL sales were 9% and 8% of oil and gas sales for the three months ended September 30, 2023 and 2022.

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

Fields	Three Months Ended September 30, 2023			Three Months Ended September 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	$	33.1	14,445	$	106.1	13,514
Western Condensate	26.9		5,261	39.7		4,623
Southern Eagle Ford	7.3		2,474	29.3		3,913
Central Oil	92.4		8,968	59.6		4,727
Eastern Extension	13.6		1,637	7.3		682
Non Core	0.7		62	0.2		46
Total	$	174.0	32,847	$	242.2	27,505

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 drilling programs.

    In the third quarter of 2023, our $68.2 million, or 28%, decrease in oil, NGL and natural gas sales from the prior year period resulted from:

•Price variances that had an approximately $136.3 million unfavorable impact on sales due to overall lower commodity pricing; and

•Volume variances that had an approximately $68.1 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 three months ended September 30, 2023 and 2022 (in thousands, except per-dollar amounts):

	Three Months Ended September 30, 2023		Three Months Ended September 30, 2022
Production volumes:
Oil (MBbl) (1)	1,410		781
Natural gas (MMcf)	20,010		19,324
Natural gas liquids (MBbl) (1)	729		582
Total (MMcfe)	32,847		27,505
Oil, natural gas and natural gas liquids sales:
Oil	$	112,456	$	71,811
Natural gas	46,075		150,958
Natural gas liquids	15,432		19,412
Total	$	173,963	$	242,181
Average realized price before impact of cash-settled derivatives:
Oil (per Bbl)	$	79.76	$	91.93
Natural gas (per Mcf)	2.30		7.81
Natural gas liquids (per Bbl)	21.16		33.34
Average per Mcfe	$	5.30	$	8.81
Price impact of cash-settled derivatives:
Oil (per Bbl)	$	(3.45)	$	(20.44)
Natural gas (per Mcf)	1.00		(3.47)
Natural gas liquids (per Bbl)	3.68		(1.86)
Average per Mcfe	$	0.54	$	(3.06)
Average realized price including impact of cash-settled derivatives:
Oil (per Bbl)	$	76.30	$	71.49
Natural gas (per Mcf)	3.30		4.34
Natural gas liquids (per Bbl)	24.84		31.48
Average per Mcfe	$	5.84	$	5.75

(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 September 30, 2023 and 2022, the Company recorded net losses of $53.7 million and $1.3 million from our commodities derivatives activities, respectively. For the three months ended September 30, 2023 and 2022, we also recorded a net loss of $0.9 million and net gain $6.1 million, respectively, related to valuation changes from our 2021 and 2022 WTI Contingency Payouts. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.

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

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

Costs and Expenses	Three Months Ended September 30, 2023		Three Months Ended September 30, 2022
General and administrative, net	$	4,438	$	4,343
Depreciation, depletion, and amortization	53,186		41,501
Accretion of asset retirement obligations	254		166
Lease operating expenses	22,678		17,701
Workovers	672		284
Transportation and gas processing	13,710		9,662
Severance and other taxes	10,407		12,581
Interest expense, net	19,811		12,173
Provision (benefit) for income taxes	(949)		6,066

General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.14 and $0.16 for the three months ended September 30, 2023 and 2022, respectively. 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 $1.2 million in share-based compensation for the three months ended September 30, 2023 and 2022, respectively.

Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were $1.62 and $1.51 for the three months ended September 30, 2023 and 2022, respectively. The increase in our per-Mcfe depreciation, depletion and amortization rate was primarily related to the acquisitions in 2022 and inflation on future development costs. The increase in costs is related to the increase in the per-Mcfe rate, coupled with an overall increase in production.

Lease Operating Expenses and Workovers. These expenses on a per-Mcfe basis were $0.71 and $0.65 for the three months ended September 30, 2023 and 2022, respectively. The increase in costs was primarily due to higher labor, compression, salt water disposal and maintenance 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 $0.42 and $0.35 for the three months ended September 30, 2023 and 2022, respectively. The increase in costs and in our per Mcfe rate was primarily attributable to additional transportation and processing agreements associated with our acquisitions in 2022 along with increased contractual fees across portions of our properties.

Severance and Other Taxes. These expenses on a per-Mcfe basis were $0.32 and $0.46 for the three months ended September 30, 2023 and 2022, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 6.0% and 5.2% for the three months ended September 30, 2023 and 2022, respectively.

    Interest. Our interest cost was $19.8 million and $12.2 million for the three months ended September 30, 2023 and 2022, respectively. The increase in interest is primarily due to higher borrowings and higher interest rates. There were no capitalized interest costs for the three months ended September 30, 2023 and 2022.

Income Taxes. The Company recorded an income tax benefit of $0.9 million and an income tax provision of $6.1 million for the three months ended September 30, 2023 and 2022, respectively. The effective tax rate for the three months ended September 30, 2023 primarily related to the statutory federal tax rate plus the impact of the Texas Margin Tax. The tax impact for both periods was a product of the overall forecasted annual effective tax rate applied to the year to date income or loss.

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Results of Operations

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

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

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

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

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

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

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

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

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

•Volume variances that had an approximately $246.9 million favorable impact on sales due to overall increased commodity production.

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

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

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

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

42

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

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

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

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

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

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

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

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

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

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

43

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.

44

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 September 30, 2023, we had a combined $648.0 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 September 30, 2023 would increase our annual interest expense by $6.5 million.

45

Item 4. Controls and Procedures

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

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

46

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. Other than as described below, there have been no material changes in our risk factors disclosed in the 2022 Annual Report on Form 10-K.

Risks Related to the Chesapeake Transaction

We may not consummate the Chesapeake Transaction.

The completion of the Chesapeake Transaction is subject to a number of closing conditions, some of which are out of our control, including the material performance by the other party of all of the obligations, agreements and covenants of the transaction agreement to be performed at or prior to the closing of the Chesapeake Transaction, including the receipt of any necessary consents or approvals. Additionally, although we have committed financing through our Credit Facility and Second Lien Notes for the purchase price, the completion of the Chesapeake Transaction is subject to our ability to secure this financing.

We also cannot be certain when SilverBow and the Chesapeake Sellers will be able to satisfy the other closing conditions or whether those closing conditions will be satisfied, including consent from certain significant landowners. If any of these conditions are not satisfied, including the failure to obtain certain consents, and in any event if the Chesapeake Transaction has not been consummated on or before November 24, 2023; provided that such date may be automatically extended for an additional 15 days to December 9, 2023, in the event certain approvals and consents have not been obtained by such date, it is possible that the Purchase Agreement may be terminated. Although the parties have agreed in the Purchase Agreement to use commercially reasonable efforts, subject to certain limitations, in regards to certain closing conditions, these and other conditions to the completion of the Chesapeake Transaction may fail to be satisfied.

If the Chesapeake Transaction is delayed, not consummated or consummated on terms different from those currently contemplated, the market price of our common stock may decline. Further, a failed transaction may result in negative publicity or a negative impression of us in the investment community and may affect our relationships with our business partners. Failure to complete the Chesapeake Transaction could cause us to be in breach of the Purchase Agreement, could result in litigation and other losses to us and a decline in the market price of our common stock.

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

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

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

47

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

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

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

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

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

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

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

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

None.

48

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 September 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).

49

Item 6. Exhibits.

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

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

50

SIGNATURES

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

		SILVERBOW RESOURCES, INC.   (Registrant)
Date:	November 2, 2023	By:	/s/ Christopher M. Abundis
			Christopher M. Abundis Executive Vice President, Chief Financial Officer and General Counsel
Date:	November 2, 2023	By:	/s/ W. Eric Schultz
			W. Eric Schultz Vice President of Accounting and Controller

51

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Sean C. Woolverton, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q for the period ended September 30, 2023, of SilverBow Resources, Inc. (the “registrant”);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting, to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 2, 2023	/s/ Sean C. Woolverton
		Sean C. Woolverton Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Christopher M. Abundis, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q for the period ended September 30, 2023, of SilverBow Resources, Inc. (the “registrant”);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting, to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 2, 2023	/s/ Christopher M. Abundis
		Christopher M. Abundis Executive Vice President, Chief Financial Officer and General Counsel

EX-32.1

Exhibit 32.1

Certification of the Chief Executive Officer and Chief Financial Officer

Pursuant to 18 U.S.C. Section 1350

In connection with the Quarterly Report on Form 10-Q for the period ended September 30, 2023 of SilverBow Resources, Inc. (the “Company”) as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Sean C. Woolverton, the Chief Executive Officer of the Company, and Christopher M. Abundis, the Executive Vice President, Chief Financial Officer and General Counsel of the Company, each certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 2, 2023	/s/ Sean C. Woolverton
		Sean C. Woolverton Chief Executive Officer
Date:	November 2, 2023	/s/ Christopher M. Abundis
		Christopher M. Abundis Executive Vice President, Chief Financial Officer and General Counsel

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Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2023	Oct. 27, 2023
Document and Entity Information [Abstract]
Document Type	10-Q
Document Period End Date	Sep. 30, 2023
Entity File Number	1-8754
Entity Registrant Name	SILVERBOW RESOURCES, INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	20-3940661
Entity Address, Address Line One	920 Memorial City Way
Entity Address, Address Line Two	Suite 850
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77024
City Area Code	281
Local Phone Number	874-2700
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	SBOW
Security Exchange Name	NYSE
Entity Filer Category	Accelerated Filer
Document Quarterly Report	true
Document Transition Report	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Central Index Key	0000351817
Current Fiscal Year End Date	--12-31
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	Q3
Entity Common Stock, Shares Outstanding		25,429,610

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Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Current Assets:
Cash and cash equivalents	$ 1,697	$ 792
Accounts receivable, net	80,202	89,714
Fair value of commodity derivatives	50,189	52,549
Other current assets	3,825	2,671
Total Current Assets	135,913	145,726
Property and Equipment:
Property and Equipment, full cost method	2,861,267	2,529,223
Less - Accumulated depreciation, depletion, and amortization	(1,151,141)	(1,004,044)
Net Furniture, Fixtures and other equipment	1,710,126	1,525,179
Capitalized Costs, unproved property balance	27,821	16,272
Right of Use Assets	10,085	12,077
Fair value of long-term commodity derivatives	14,180	24,172
Deposit and other fees for oil and gas property transaction	52,564	0
Other Long-Term Assets	7,581	9,208
Total Assets	1,930,449	1,716,362
Current Liabilities:
Accounts payable and accrued liabilities	74,731	60,200
Fair value of commodity derivatives	32,752	40,796
Accrued capital costs	56,424	56,465
Accrued interest	2,976	2,665
Current lease liability	5,507	8,553
Undistributed oil and gas revenues	22,462	27,160
Total Current Liabilities	194,852	195,839
Long-Term Debt	645,096	688,531
Non-current Lease Liability	4,604	3,775
Deferred Tax Liabilities	49,033	16,141
Asset Retirement Obligation	9,840	9,171
Fair value of long-term commodity derivatives	21,560	7,738
Other Long-Term Liabilities	922	3,588
Stockholders' Equity:
Preferred Stock, Value, Outstanding	0	0
Common stock, $0.01 par value	259	227
Additional paid-in capital	677,473	576,118
Treasury stock held, at cost	(10,616)	(7,534)
Retained earnings (Accumulated deficit)	337,426	222,768
Total Stockholders' Equity (Deficit)	1,004,542	791,579
Total Liabilities and Stockholders' Equity	$ 1,930,449	$ 1,716,362
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Authorized	10,000,000	10,000,000
Preferred Stock, Shares Outstanding	0	0
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	40,000,000	40,000,000
Common Stock, Shares, Issued	25,914,823	22,663,135
Common Stock, Shares, Outstanding	25,429,517	22,309,740
Treasury Stock, Shares	485,306	353,395

XML

Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares	Sep. 30, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred Stock, Shares Outstanding	0	0
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	40,000,000	40,000,000

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Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Income Statement [Abstract]
Oil and gas sales	$ 173,963	$ 242,181	$ 440,317	$ 554,442
Costs and Expenses [Abstract]
General and administrative, net	4,438	4,343	17,421	14,840
Depreciation, depletion, and amortization	53,186	41,501	147,037	89,096
Accretion of asset retirement obligation	254	166	718	366
Lease operating costs	22,678	17,701	62,417	37,095
Workovers	672	284	2,263	933
Transportation and gas processing	13,710	9,662	37,001	22,784
Severance and other taxes	10,407	12,581	28,563	30,183
Operating Expenses	105,345	86,238	295,420	195,297
Operating Income (Loss)	68,618	155,943	144,897	359,145
Net gain (loss) on commodity derivatives	(54,639)	4,832	57,604	(157,816)
Interest expense, net	(19,811)	(12,173)	(54,746)	(26,632)
Other Nonoperating Income (Expense)	112	5	117	57
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	(5,720)	148,607	147,872	174,754
Provision (Benefit) for Income Taxes	(949)	6,066	33,214	7,678
Net Income (Loss)	$ (4,771)	$ 142,541	$ 114,658	$ 167,076
Per Share Amounts-
Earnings Per Share, Basic	$ (0.21)	$ 6.39	$ 5.06	$ 8.85
Earnings Per Share, Diluted	$ (0.21)	$ 6.29	$ 5.02	$ 8.69
Weighted Average Shares Outstanding - Basic	22,985	22,308	22,677	18,885
Weighted Average Shares Outstanding - Diluted	22,985	22,669	22,852	19,237

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Condensed Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Treasury Stock	Retained Earnings (Accumulated Deficit)
Beginning Balance at Dec. 31, 2021	$ 292,532	$ 168	$ 413,017	$ (2,984)	$ (117,669)
Purchase of treasury shares	(2,462)	0	0	(2,462)	0
Treasury Stock, Value, Acquired Pursuant to Purchase Price Adjustment	(1,146)	0	0	(1,146)	0
Vesting of share-based compensation	0	3	(3)	0	0
Issuance pursuant to acquisition	12	0	12	0	0
Amortization of share-based compensation	1,101	0	1,101	0	0
Net Income (Loss)	(64,255)	0	0	0	(64,255)
Ending Balance at Mar. 31, 2022	$ 225,782	171	414,127	(6,592)	(181,924)
Purchase of treasury stock (shares)	96,012
Vesting of share-based compensation (shares)	318,390
Treasury Shares Pursuant to Purchase Price Adjustment (shares)	41,191
Issuance pursuant to acquisition (shares)	489
Beginning Balance at Dec. 31, 2021	$ 292,532	168	413,017	(2,984)	(117,669)
Net Income (Loss)	167,076
Ending Balance at Sep. 30, 2022	$ 616,985	227	574,885	(7,534)	49,407
Purchase of treasury stock (shares)	120,350
Treasury Shares Pursuant to Purchase Price Adjustment (shares)	41,375
Beginning Balance at Mar. 31, 2022	$ 225,782	171	414,127	(6,592)	(181,924)
Purchase of treasury shares	(503)	0	0	(503)	0
Stock options exercised	(39)	0	(39)	0	0
Vesting of share-based compensation	0	1	(1)	0	0
Issuance pursuant to acquisition	157,393	55	157,338	0	0
Amortization of share-based compensation	1,756	0	1,756	0	0
Net Income (Loss)	88,790	0	0	0	88,790
Ending Balance at Jun. 30, 2022	$ 473,257	227	573,259	(7,095)	(93,134)
Purchase of treasury stock (shares)	16,485
Options, Exercises in Period	4,497
Vesting of share-based compensation (shares)	57,355
Issuance pursuant to acquisition (shares)	5,448,472
Purchase of treasury shares	$ (432)	0	0	(432)	0
Stock options exercised	(387)	0	(387)	0	0
Treasury Stock, Value, Acquired Pursuant to Purchase Price Adjustment	(7)	0	0	(7)	0
Amortization of share-based compensation	1,239	0	1,239	0	0
Net Income (Loss)	142,541	0	0	0	142,541
Ending Balance at Sep. 30, 2022	$ 616,985	227	574,885	(7,534)	49,407
Purchase of treasury stock (shares)	7,853
Options, Exercises in Period	11,087
Treasury Shares Pursuant to Purchase Price Adjustment (shares)	184
Beginning Balance at Dec. 31, 2022	$ 791,579	227	576,118	(7,534)	222,768
Purchase of treasury shares	(2,945)	0	0	(2,945)	0
Vesting of share-based compensation	0	4	(4)	0	0
Amortization of share-based compensation	1,179	0	1,179	0	0
Net Income (Loss)	94,492	0	0	0	94,492
Ending Balance at Mar. 31, 2023	$ 884,305	231	577,293	(10,479)	317,260
Purchase of treasury stock (shares)	126,240
Vesting of share-based compensation (shares)	418,518
Beginning Balance at Dec. 31, 2022	$ 791,579	227	576,118	(7,534)	222,768
Net Income (Loss)	114,658
Ending Balance at Sep. 30, 2023	$ 1,004,542	259	677,473	(10,616)	337,426
Purchase of treasury stock (shares)	131,911
Beginning Balance at Mar. 31, 2023	$ 884,305	231	577,293	(10,479)	317,260
Purchase of treasury shares	(121)	0	0	(121)	0
Vesting of share-based compensation	0	0	0	0	0
Amortization of share-based compensation	1,524	0	1,524	0	0
Net Income (Loss)	24,937	0	0	0	24,937
Ending Balance at Jun. 30, 2023	$ 910,645	231	578,817	(10,600)	342,197
Purchase of treasury stock (shares)	5,310
Vesting of share-based compensation (shares)	21,134
Purchase of treasury shares	$ (16)	0	0	(16)	0
Vesting of share-based compensation	0	0	0	0	0
Amortization of share-based compensation	1,551	0	1,551	0	0
Net Income (Loss)	(4,771)	0	0	0	(4,771)
Ending Balance at Sep. 30, 2023	$ 1,004,542	259	677,473	(10,616)	337,426
Purchase of treasury stock (shares)	361
Vesting of share-based compensation (shares)	1,225
Issuance of common stock (shares)	2,810,811
Issuance of common stock	$ 97,133	$ 28	$ 97,105	$ 0	$ 0

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Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022	Dec. 31, 2021
Cash Flows from Operating Activities:
Net Income (Loss)	$ (4,771)	$ 142,541	$ 114,658	$ 167,076
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation, depletion, and amortization	53,186	41,501	147,037	89,096
Accretion of asset retirement obligation	254	166	718	366	$ 534
Deferred income taxes			32,892	7,496
Stock-based compensation expenses			4,043	3,901
Loss (gain) on derivatives			(57,604)	157,816
Cash Received (Paid) On Settlements of Derivative Contracts			70,670	(182,058)
Settlements of asset retirement obligations			(481)	(47)
Write off of Debt Issuance Cost			0	350
Other Noncash Income (Expense)			2,028	(6,425)
(Increase) decrease in accounts receivable and other current assets			9,129	(47,320)
Increase (decrease) in accounts payable and accrued liabilities			(5,320)	20,260
Increase (Decrease) in Income Taxes Payable			(321)	21
Increase (decrease) in accrued interest			311	1,688
Net Cash Provided by (Used in) Operating Activities			318,402	212,178
Cash Flows from Investing Activities:
Additions to property and equipment			(316,003)	(163,567)
Acquisition of oil and gas properties			(382)	(293,880)
Other Payments to Acquire Businesses			(51,163)	0
Proceeds from the sale of property and equipment			0	4,415	4,400
Payments on property sale obligations			0	(750)
Net Cash Provided by (Used in) Investing Activities			(367,548)	(453,782)
Cash Flows from Financing Activities:
Proceeds from bank borrowings			334,000	679,000
Payments of bank borrowings			(378,000)	(426,000)
Proceeds from Issuance of Common Stock			97,133	0
Net proceeds from stock options exercised			0	39
Purchase of treasury shares			(3,082)	(3,404)
Payments of Debt Issuance Costs			0	(7,228)
Net Cash Provided by (Used in) Financing Activities			50,051	242,407
Net increase (decrease) in Cash, Cash Equivalents and Restricted Cash			905	803
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 1,697	$ 1,924	1,697	1,924	$ 792	$ 1,121
Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest, net of amounts capitalized			52,170	22,701
Changes in capital accounts payable and capital accruals			13,363	60,595
Accrued other fees for oil and gas property transaction			(1,401)	0
Non-cash equity consideration for acquisitions			$ 0	$ (156,259)

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General Information

9 Months Ended

Sep. 30, 2023

Organization, Consolidation and Presentation of Financial Statements [Abstract]

General Information

(1)           General Information

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

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

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2023

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

(2)          Summary of Significant Accounting Policies

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

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

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

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

Through October 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 September 30, 2023:

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

Oil Basis Swaps (Argus Cushing (WTI) and Magellan East Houston)	Total Volumes (MMBtu)	Weighted-Average Price
2023 Contracts
4Q23	61,000	$	0.90
2025 Contracts
1Q25	90,000	$	1.75
2Q25	91,000	$	1.75
3Q25	92,000	$	1.75
4Q25	92,000	$	1.75
Calendar Monthly Roll Differential Swaps
2023 Contracts
4Q23	61,000	$	2.40
2025 Contracts
1Q25	90,000	$	0.50
2Q25	91,000	$	0.50
3Q25	92,000	$	0.50
4Q25	92,000	$	0.50

Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Price
Swap Contracts
2024 Contracts
1Q24	1,820,000	$	3.66
2Q24	2,430,000	$	3.31
3Q24	2,760,000	$	3.46
4Q24	2,760,000	$	3.75
2025 Contracts
1Q25	2,700,000	$	4.20
2Q25	2,730,000	$	3.75
3Q25	2,760,000	$	3.89
4Q25	1,540,000	$	4.11
2026 Contracts
1Q26	900,000	$	4.56
2Q26	910,000	$	3.53
3Q26	920,000	$	3.73
4Q26	920,000	$	4.19

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

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

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

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

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

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

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

•estimates of future costs to develop and produce reserves,

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

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

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

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

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

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

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

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

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

•estimates on future lease obligations.

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

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

Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended September 30, 2023 and 2022, such internal costs capitalized totaled $1.4 million and $1.1 million, respectively. For the nine months ended September 30, 2023 and 2022, such internal costs capitalized totaled $4.1 million and $3.3 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. There was no capitalized interest on our unproved properties for both the three months ended September 30, 2023 and 2022 and the nine months ended September 30, 2023 and 2022.

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

	September 30, 2023		December 31, 2022
Property and Equipment
Proved oil and gas properties	$	2,827,145	$	2,506,853
Unproved oil and gas properties	27,821		16,272
Furniture, fixtures and other equipment	6,301		6,098
Less – Accumulated depreciation, depletion, amortization & impairment	(1,151,141)		(1,004,044)
Property and Equipment, Net	$	1,710,126	$	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.

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

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

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

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

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

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

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 nine months ended September 30, 2023 and 2022 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $3.0 million and $2.8 million for the three months ended September 30, 2023 and 2022, respectively, and $8.6 million and $6.1 million for the nine months ended September 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 17% and 4% for the three months ended September 30, 2023 and 2022, respectively, and 22% and 4% for the nine months ended September 30, 2023 and 2022, respectively. The Company recorded an income tax benefit of $0.9 million and income tax provision of $33.2 million for the three and nine months ended September 30, 2023, respectively, and an income tax provision of $6.1 million and $7.7 million for the three and nine months ended September 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.

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

Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At September 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 September 30, 2023 and 2022 and the nine months ended September 30, 2023 and 2022 (in thousands):

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

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

	September 30, 2023		December 31, 2022
Trade accounts payable	$	30,708	$	23,660
Accrued operating expenses	11,266		10,572
Accrued compensation costs	3,267		4,814
Asset retirement obligations – current portion	1,578		1,284
Accrued non-income based taxes	13,303		4,849
Accrued corporate and legal fees	181		388
WTI contingency payouts - current portion	1,537		1,600
Payable for settled derivatives	3,549		6,026
Other payables	9,342		7,007
Total accounts payable and accrued liabilities	$	74,731	$	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.

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 nine months ended September 30, 2023, we purchased 131,911 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. For the nine months ended September 30, 2022, we purchased 120,350 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares and received 41,375 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, and ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, issued in December 2022. The guidance provides and clarifies optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The amendments within these ASUs were in effect beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2024. This guidance provides an optional practical expedient that allows qualifying modifications to be accounted for as a debt modification rather than be analyzed under existing guidance to determine if the modification should be accounted for as a debt extinguishment. The Company adopted this accounting pronouncement in conjunction with the execution of the Third Amendment to the Note Purchase Agreement in June 2023 and elected to apply this optional expedient. See Note 6 – Long-Term Debt for further discussion of the Company’s accounting for its existing debt and related issuance costs. The adoption of this accounting standard did not have a material impact on the Company's condensed consolidated financial statements and related disclosures.

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.

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Leases Leases (Notes)

9 Months Ended

Sep. 30, 2023

Leases [Abstract]

Lessee, Operating Leases

(3)       Leases

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

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

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

	As of September 30, 2023
2023 (Remaining)	$	2,667
2024	4,166
2025	2,427
2026	1,194
2027	61
Thereafter	475
Total undiscounted lease payments	10,990
Present value adjustment	(879)
Net operating lease liabilities	$	10,111

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Share-Based Compensation

9 Months Ended

Sep. 30, 2023

Share-Based Payment Arrangement [Abstract]

Share-Based Compensation

(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 $1.2 million for the three months ended September 30, 2023 and 2022, respectively, and $4.0 million and $3.9 million for the nine months ended September 30, 2023 and 2022, respectively. Capitalized share-based compensation was less than $0.1 million for both

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

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

    Stock Option Awards

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

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

Restricted Stock Units

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

As of September 30, 2023, we had $5.1 million unrecognized compensation expense related to our RSUs which is expected to be recognized over a weighted-average period of 2.0 years.

The following table provides information regarding RSU activity for the nine months ended September 30, 2023:

	RSUs	Wtd. Avg. Grant Price
RSUs outstanding, beginning of period	227,114	$	21.18
RSUs granted	195,791	$	23.75
RSUs forfeited	(1,424)	$	25.44
RSUs vested	(137,467)	$	17.78
RSUs outstanding, end of period	284,014	$	24.58

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 September 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 September 30, 2023.

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

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

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

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Earnings Per Share

9 Months Ended

Sep. 30, 2023

Earnings Per Share [Abstract]

Earnings Per Share

(5)          Earnings Per Share

Basic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three and nine months ended September 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 September 30, 2023					Three Months Ended September 30, 2022
	Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)		Shares	Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	(4,771)	22,985	$	(0.21)	$	142,541	22,308	$	6.39
Dilutive Securities:
Performance Based Stock Unit Awards			—					169
RSU Awards			—					137
Stock Option Awards			—					55
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	(4,771)	22,985	$	(0.21)	$	142,541	22,669	$	6.29

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

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

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

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

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

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Long-Term Debt

9 Months Ended

Sep. 30, 2023

Debt Disclosure [Abstract]

Long-Term Debt

(6)          Long-Term Debt

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

	September 30, 2023		December 31, 2022
Credit Facility Borrowings due 2026 (1)	$	498,000	$	542,000
Second Lien Notes due 2026	150,000		150,000
	648,000		692,000
Unamortized discount on Second Lien Notes due 2026	(738)		(882)
Unamortized debt issuance cost on Second Lien Notes due 2026	(2,166)		(2,587)
Long-Term Debt, net	$	645,096	$	688,531

(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our condensed consolidated balance sheet. As of September 30, 2023 and December 31, 2022, we had $7.0 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 $498.0 million and $542.0 million as of September 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 September 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 interest at 2.0% per annum above the rate and margin otherwise applicable thereto. As of September 30, 2023, the Company's weighted average interest rate on Credit Facility borrowings was 8.67%.

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 September 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 $14.6 million and $8.3 million for the three months ended September 30, 2023 and 2022, respectively, and $39.8 million and $15.9 million for the nine months ended September 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 September 30, 2023 and 2022, respectively, and $0.7 million and $0.9 million for the nine months ended September 30, 2023 and 2022, respectively.

    Senior Secured Second Lien Notes. On December 15, 2017, the Company entered into a Note Purchase Agreement for Senior Secured Second Lien Notes (as amended, the “Note Purchase Agreement,” and such second lien facility the “Second Lien”) 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 September 30, 2023, the Company's interest rate on Second Lien borrowings was 13.16%.

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 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 September 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 September 30, 2023, total net amounts recorded for the Second Lien were $147.1 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $5.2 million and $3.8 million for the three months ended September 30, 2023 and 2022, respectively, and $14.9 million and $10.7 million for the nine months ended September 30, 2023 and 2022, respectively.

Debt Issuance Costs. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings. During the nine months ended September 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 nine months ended September 30, 2023.

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Acquisitions and Dispositions Acquisitions and Dispostions

9 Months Ended

Sep. 30, 2023

Discontinued Operations and Disposal Groups [Abstract]

Acquisitions and Dispositions

(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 September 30, 2023 and 2022, the Company recorded losses of $0.9 million and gains of $0.7 million, respectively, and losses of $1.0 million and $0.8 million, respectively, for the nine months ended September 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.

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 nine months ended September 30, 2023, the Company recorded gains of $1.0 million related to valuation changes in the 2022 WTI Contingency Payout recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. Additionally, as part of our post-close settlement we settled the 2022 WTI Contingency during the second quarter of 2023. As such, we recorded a non-cash gain of $1.1 million during the nine months ended September 30, 2023, and we are no longer required to make a contingency payment related to the 2022 WTI Contingency Payout. We incurred approximately $6.8 million in transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.

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

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

August 2022 Acquisition

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

October 2022 Acquisition

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

2022 Non-strategic Dispositions

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

2023 Chesapeake Acquisition

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

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

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Price-Risk Management Price-Risk Management (Notes)

9 Months Ended

Sep. 30, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Price-Risk Management Activities

(8)          Price-Risk Management Activities

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

During the three months ended September 30, 2023 and 2022, the Company recorded losses of $53.7 million and losses of $1.3 million, respectively, on its commodity derivatives. During the nine months ended September 30, 2023 and 2022, the Company recorded gains of $56.5 million and losses of $162.5 million, respectively, on its commodity derivatives. During the three months ended September 30, 2023 and 2022, the Company recorded losses of $0.9 million and gains of $6.1 million, respectively, related to valuation changes on the 2021 WTI Contingency Payout and 2022 WTI Contingency Payout. During the nine months ended September 30, 2023 and 2022, the Company recorded gains of $1.1 million and gains of $4.7 million, respectively, related to valuation changes on the 2021 WTI Contingency Payout and 2022 WTI Contingency Payout. The Company collected cash payments of $70.7 million and made cash payments of $182.1 million for settled derivative contracts during the nine months ended September 30, 2023 and 2022, respectively.

At September 30, 2023 and December 31, 2022, there was $8.4 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 October 2023 and January 2023, respectively. At September 30, 2023 and December 31, 2022, we also had $3.5 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 October 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 September 30, 2023, there was $50.2 million and $14.2 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $32.8 million and $21.6 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 $10.1 million net fair value asset at September 30, 2023, and a $28.2 million net fair value asset at December 31, 2022. For further discussion related to the fair value of the Company's derivatives, refer to Note 9 of these Notes to Condensed Consolidated Financial Statements.

The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of September 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
4Q23	707,300	$	78.53
2024 Contracts
1Q24	728,000	$	77.67
2Q24	754,550	$	77.59
3Q24	779,620	$	76.48
4Q24	762,100	$	76.16
2025 Contracts
1Q25	666,000	$	71.60
2Q25	673,400	$	71.60
3Q25	680,800	$	71.60
4Q25	588,800	$	71.29
2026 Contracts
1Q26	315,000	$	69.40
2Q26	318,500	$	69.40
3Q26	322,000	$	69.40
4Q26	230,000	$	69.42
Collar Contracts
2023 Contracts
4Q23	302,242					$	65.89	$	74.54
2024 Contracts
1Q24	319,700					$	58.95	$	71.74
2Q24	215,000					$	61.08	$	73.57
3Q24	184,000					$	63.50	$	75.53
4Q24	184,000					$	63.00	$	75.35
2025 Contracts
1Q25	238,500					$	64.00	$	74.62
2Q25	227,500					$	60.80	$	72.22
2026 Contracts
1Q26	90,000					$	64.00	$	71.50
2Q26	91,000					$	64.00	$	71.50
3Q26	92,000					$	64.00	$	71.50
3-Way Collar Contracts
2023 Contracts
4Q23	8,970			$	43.08	$	53.38	$	63.35
2024 Contracts
1Q24	8,247			$	45.00	$	57.50	$	67.85
2Q24	7,757			$	45.00	$	57.50	$	67.85

Oil Basis Swaps (Argus Cushing (WTI) and Magellan East Houston)	Total Volumes (MMBtu)	Weighted-Average Price
2023 Contracts
4Q23	122,000	$	0.80
2024 Contracts
1Q24	364,000	$	1.47
2Q24	364,000	$	1.47
3Q24	368,000	$	1.47
4Q24	368,000	$	1.47
2025 Contracts
1Q25	270,000	$	1.75
2Q25	273,000	$	1.75
3Q25	276,000	$	1.75
4Q25	276,000	$	1.75
Calendar Monthly Roll Differential Swaps
2023 Contracts
4Q23	122,000	$	2.44
2024 Contracts
1Q24	364,000	$	0.69
2Q24	364,000	$	0.69
3Q24	368,000	$	0.69
4Q24	368,000	$	0.69
2025 Contracts
1Q25	270,000	$	0.40
2Q25	273,000	$	0.40
3Q25	276,000	$	0.40
4Q25	276,000	$	0.40

Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Price		Weighted-Average Collar Sub Floor Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
Swap Contracts
2023 Contracts
4Q23	5,727,000	$	4.20
2024 Contracts
1Q24	7,686,000	$	4.12
2Q24	12,350,000	$	3.67
3Q24	12,420,000	$	3.78
4Q24	12,420,000	$	4.12
2025 Contracts
1Q25	9,450,000	$	4.25
2Q25	9,555,000	$	3.71
3Q25	11,960,000	$	3.83
4Q25	8,740,000	$	4.17
2026 Contracts
1Q26	9,680,000	$	4.48
2Q26	9,555,000	$	3.56
3Q26	9,660,000	$	3.74
4Q26	9,200,000	$	4.13
Collar Contracts
2023 Contracts
4Q23	12,445,000					$	3.87	$	4.80
2024 Contracts
1Q24	9,661,000					$	3.94	$	5.83
2Q24	4,643,000					$	3.64	$	4.28
3Q24	3,878,000					$	3.77	$	4.76
4Q24	3,865,000					$	4.01	$	5.34
2025 Contracts
1Q25	5,130,000					$	4.00	$	5.32
2Q25	4,914,000					$	3.25	$	3.98
3Q25	920,000					$	3.50	$	3.99
4Q25	920,000					$	3.75	$	4.65
3-Way Collar Contracts
2023 Contracts
4Q23	219,200			$	2.00	$	2.50	$	2.94
2024 Contracts
1Q24	198,000			$	2.00	$	2.50	$	3.37
2Q24	188,000			$	2.00	$	2.50	$	3.37

Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes (MMBtu)	Weighted-Average Price
2023 Contracts
4Q23	13,800,000	$	(0.23)
2024 Contracts
1Q24	15,470,000	$	(0.02)
2Q24	15,470,000	$	(0.29)
3Q24	15,640,000	$	(0.26)
4Q24	15,640,000	$	(0.28)
2025 Contracts
1Q25	5,400,000	$	(0.09)
2Q25	5,460,000	$	(0.26)
3Q25	5,520,000	$	(0.23)
4Q25	5,520,000	$	(0.25)

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

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Fair Value Measurements

9 Months Ended

Sep. 30, 2023

Fair Value Disclosures [Abstract]

Fair Value Measurements

(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 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.

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

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

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

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Asset Retirement Obligations Asset Retirement Obligations (Notes)

9 Months Ended

Sep. 30, 2023

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

(10)           Asset Retirement Obligations

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

obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets.

The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2022 and the nine months ended September 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	718
Liabilities incurred for new wells, acquired wells and facilities construction	313
Reductions due to plugged wells and facilities	(603)
Revisions in estimates	534
Asset Retirement Obligations as of September 30, 2023	$	11,418

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

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Commitments and Contingencies Commitments and Contingencies

9 Months Ended

Sep. 30, 2023

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

(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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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2023

Accounting Policies [Abstract]

Principles of Consolidation

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.

Use of Estimates

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,

•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

Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended September 30, 2023 and 2022, such internal costs capitalized totaled $1.4 million and $1.1 million, respectively. For the nine months ended September 30, 2023 and 2022, such internal costs capitalized totaled $4.1 million and $3.3 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. There was no capitalized interest on our unproved properties for both the three months ended September 30, 2023 and 2022 and the nine months ended September 30, 2023 and 2022.

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

	September 30, 2023		December 31, 2022
Property and Equipment
Proved oil and gas properties	$	2,827,145	$	2,506,853
Unproved oil and gas properties	27,821		16,272
Furniture, fixtures and other equipment	6,301		6,098
Less – Accumulated depreciation, depletion, amortization & impairment	(1,151,141)		(1,004,044)
Property and Equipment, Net	$	1,710,126	$	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.

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

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.

Accounts Receivable, Net

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

Supervision Fees

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.

Income Taxes

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 17% and 4% for the three months ended September 30, 2023 and 2022, respectively, and 22% and 4% for the nine months ended September 30, 2023 and 2022, respectively. The Company recorded an income tax benefit of $0.9 million and income tax provision of $33.2 million for the three and nine months ended September 30, 2023, respectively, and an income tax provision of $6.1 million and $7.7 million for the three and nine months ended September 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.

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

Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At September 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

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.

Accounts Payable and Accrued Liabilities

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

	September 30, 2023		December 31, 2022
Trade accounts payable	$	30,708	$	23,660
Accrued operating expenses	11,266		10,572
Accrued compensation costs	3,267		4,814
Asset retirement obligations – current portion	1,578		1,284
Accrued non-income based taxes	13,303		4,849
Accrued corporate and legal fees	181		388
WTI contingency payouts - current portion	1,537		1,600
Payable for settled derivatives	3,549		6,026
Other payables	9,342		7,007
Total accounts payable and accrued liabilities	$	74,731	$	60,200

Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy

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

Treasury Stock

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.

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Leases Leases (Policies)

9 Months Ended

Sep. 30, 2023

Leases [Abstract]

Lessee, Leases [Policy Text Block]

Leases

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

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

9 Months Ended

Sep. 30, 2023

Share-Based Payment Arrangement [Abstract]

Share-based Compensation, Option and Incentive Plans Policy

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.

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Earnings Per Share Earnings Per Share (Policies)	9 Months Ended
	Sep. 30, 2023
Earnings Per Share [Abstract]
Earnings Per Share, Policy	Earnings Per ShareBasic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three and nine months ended September 30, 2023 and 2022 are discussed below.

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Long-Term Debt Long-Term Debt (Policies)	9 Months Ended
	Sep. 30, 2023
Debt Disclosure [Abstract]
Debt Issuance Costs, Policy	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.

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Price-Risk Management Price-Risk Management (Policies)	9 Months Ended
	Sep. 30, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Price-Risk Management Activities, Policy	Price-Risk Management ActivitiesDerivatives 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.

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Fair Value Measurements Fair Value Disclosures (Policies)

9 Months Ended

Sep. 30, 2023

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments, Policy

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 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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Asset Retirement Obligations Asset Retirement Obligations (Policies)	9 Months Ended
	Sep. 30, 2023
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations, Policy	Asset Retirement ObligationsLiabilities 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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Commitments and Contingencies Commitments and Contingencies (Policies)	9 Months Ended
	Sep. 30, 2023
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies, Policy	Commitments and Contingencies    In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as an operator of oil and natural gas wells. In our management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.

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Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2023

Accounting Policies [Abstract]

Schedule of Subsequent Events

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

Through October 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 September 30, 2023:

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

Oil Basis Swaps (Argus Cushing (WTI) and Magellan East Houston)	Total Volumes (MMBtu)	Weighted-Average Price
2023 Contracts
4Q23	61,000	$	0.90
2025 Contracts
1Q25	90,000	$	1.75
2Q25	91,000	$	1.75
3Q25	92,000	$	1.75
4Q25	92,000	$	1.75
Calendar Monthly Roll Differential Swaps
2023 Contracts
4Q23	61,000	$	2.40
2025 Contracts
1Q25	90,000	$	0.50
2Q25	91,000	$	0.50
3Q25	92,000	$	0.50
4Q25	92,000	$	0.50

Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Price
Swap Contracts
2024 Contracts
1Q24	1,820,000	$	3.66
2Q24	2,430,000	$	3.31
3Q24	2,760,000	$	3.46
4Q24	2,760,000	$	3.75
2025 Contracts
1Q25	2,700,000	$	4.20
2Q25	2,730,000	$	3.75
3Q25	2,760,000	$	3.89
4Q25	1,540,000	$	4.11
2026 Contracts
1Q26	900,000	$	4.56
2Q26	910,000	$	3.53
3Q26	920,000	$	3.73
4Q26	920,000	$	4.19

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

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

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

Property and Equipment

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

	September 30, 2023		December 31, 2022
Property and Equipment
Proved oil and gas properties	$	2,827,145	$	2,506,853
Unproved oil and gas properties	27,821		16,272
Furniture, fixtures and other equipment	6,301		6,098
Less – Accumulated depreciation, depletion, amortization & impairment	(1,151,141)		(1,004,044)
Property and Equipment, Net	$	1,710,126	$	1,525,179

Disaggregation of Revenue

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

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

Accounts Payable and Accrued Liabilities

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

	September 30, 2023		December 31, 2022
Trade accounts payable	$	30,708	$	23,660
Accrued operating expenses	11,266		10,572
Accrued compensation costs	3,267		4,814
Asset retirement obligations – current portion	1,578		1,284
Accrued non-income based taxes	13,303		4,849
Accrued corporate and legal fees	181		388
WTI contingency payouts - current portion	1,537		1,600
Payable for settled derivatives	3,549		6,026
Other payables	9,342		7,007
Total accounts payable and accrued liabilities	$	74,731	$	60,200

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Leases Leases (Tables)

9 Months Ended

Sep. 30, 2023

Leases [Abstract]

Lessee, Operating Lease, Liability, Maturity [Table Text Block]

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

	As of September 30, 2023
2023 (Remaining)	$	2,667
2024	4,166
2025	2,427
2026	1,194
2027	61
Thereafter	475
Total undiscounted lease payments	10,990
Present value adjustment	(879)
Net operating lease liabilities	$	10,111

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Share-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2023

Share-Based Payment Arrangement [Abstract]

Stock option activity

The following table provides information regarding stock option award activity for the nine months ended September 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

Restricted stock activity

The following table provides information regarding RSU activity for the nine months ended September 30, 2023:

	RSUs	Wtd. Avg. Grant Price
RSUs outstanding, beginning of period	227,114	$	21.18
RSUs granted	195,791	$	23.75
RSUs forfeited	(1,424)	$	25.44
RSUs vested	(137,467)	$	17.78
RSUs outstanding, end of period	284,014	$	24.58

Performance-Based Stock Units Activity

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

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

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2023

Earnings Per Share [Abstract]

Reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS

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

	Three Months Ended September 30, 2023					Three Months Ended September 30, 2022
	Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)		Shares	Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	(4,771)	22,985	$	(0.21)	$	142,541	22,308	$	6.39
Dilutive Securities:
Performance Based Stock Unit Awards			—					169
RSU Awards			—					137
Stock Option Awards			—					55
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	(4,771)	22,985	$	(0.21)	$	142,541	22,669	$	6.29

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

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Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2023

Debt Disclosure [Abstract]

Schedule of Long-term Debt Instruments

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

	September 30, 2023		December 31, 2022
Credit Facility Borrowings due 2026 (1)	$	498,000	$	542,000
Second Lien Notes due 2026	150,000		150,000
	648,000		692,000
Unamortized discount on Second Lien Notes due 2026	(738)		(882)
Unamortized debt issuance cost on Second Lien Notes due 2026	(2,166)		(2,587)
Long-Term Debt, net	$	645,096	$	688,531

(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our condensed consolidated balance sheet. As of September 30, 2023 and December 31, 2022, we had $7.0 million and $8.7 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.

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Business Combinations and Asset Acquisitions (Tables)

Jun. 30, 2022

May 10, 2022

Business Combination and Asset Acquisition [Abstract]

Schedule of Recognized Identified 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

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

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Price-Risk Management Price-Risk Management (Tables)

9 Months Ended

Sep. 30, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments [Table Text Block]

The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of September 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
4Q23	707,300	$	78.53
2024 Contracts
1Q24	728,000	$	77.67
2Q24	754,550	$	77.59
3Q24	779,620	$	76.48
4Q24	762,100	$	76.16
2025 Contracts
1Q25	666,000	$	71.60
2Q25	673,400	$	71.60
3Q25	680,800	$	71.60
4Q25	588,800	$	71.29
2026 Contracts
1Q26	315,000	$	69.40
2Q26	318,500	$	69.40
3Q26	322,000	$	69.40
4Q26	230,000	$	69.42
Collar Contracts
2023 Contracts
4Q23	302,242					$	65.89	$	74.54
2024 Contracts
1Q24	319,700					$	58.95	$	71.74
2Q24	215,000					$	61.08	$	73.57
3Q24	184,000					$	63.50	$	75.53
4Q24	184,000					$	63.00	$	75.35
2025 Contracts
1Q25	238,500					$	64.00	$	74.62
2Q25	227,500					$	60.80	$	72.22
2026 Contracts
1Q26	90,000					$	64.00	$	71.50
2Q26	91,000					$	64.00	$	71.50
3Q26	92,000					$	64.00	$	71.50
3-Way Collar Contracts
2023 Contracts
4Q23	8,970			$	43.08	$	53.38	$	63.35
2024 Contracts
1Q24	8,247			$	45.00	$	57.50	$	67.85
2Q24	7,757			$	45.00	$	57.50	$	67.85

Oil Basis Swaps (Argus Cushing (WTI) and Magellan East Houston)	Total Volumes (MMBtu)	Weighted-Average Price
2023 Contracts
4Q23	122,000	$	0.80
2024 Contracts
1Q24	364,000	$	1.47
2Q24	364,000	$	1.47
3Q24	368,000	$	1.47
4Q24	368,000	$	1.47
2025 Contracts
1Q25	270,000	$	1.75
2Q25	273,000	$	1.75
3Q25	276,000	$	1.75
4Q25	276,000	$	1.75
Calendar Monthly Roll Differential Swaps
2023 Contracts
4Q23	122,000	$	2.44
2024 Contracts
1Q24	364,000	$	0.69
2Q24	364,000	$	0.69
3Q24	368,000	$	0.69
4Q24	368,000	$	0.69
2025 Contracts
1Q25	270,000	$	0.40
2Q25	273,000	$	0.40
3Q25	276,000	$	0.40
4Q25	276,000	$	0.40

Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted-Average Price		Weighted-Average Collar Sub Floor Price		Weighted-Average Collar Floor Price		Weighted-Average Collar Call Price
Swap Contracts
2023 Contracts
4Q23	5,727,000	$	4.20
2024 Contracts
1Q24	7,686,000	$	4.12
2Q24	12,350,000	$	3.67
3Q24	12,420,000	$	3.78
4Q24	12,420,000	$	4.12
2025 Contracts
1Q25	9,450,000	$	4.25
2Q25	9,555,000	$	3.71
3Q25	11,960,000	$	3.83
4Q25	8,740,000	$	4.17
2026 Contracts
1Q26	9,680,000	$	4.48
2Q26	9,555,000	$	3.56
3Q26	9,660,000	$	3.74
4Q26	9,200,000	$	4.13
Collar Contracts
2023 Contracts
4Q23	12,445,000					$	3.87	$	4.80
2024 Contracts
1Q24	9,661,000					$	3.94	$	5.83
2Q24	4,643,000					$	3.64	$	4.28
3Q24	3,878,000					$	3.77	$	4.76
4Q24	3,865,000					$	4.01	$	5.34
2025 Contracts
1Q25	5,130,000					$	4.00	$	5.32
2Q25	4,914,000					$	3.25	$	3.98
3Q25	920,000					$	3.50	$	3.99
4Q25	920,000					$	3.75	$	4.65
3-Way Collar Contracts
2023 Contracts
4Q23	219,200			$	2.00	$	2.50	$	2.94
2024 Contracts
1Q24	198,000			$	2.00	$	2.50	$	3.37
2Q24	188,000			$	2.00	$	2.50	$	3.37

Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements)	Total Volumes (MMBtu)	Weighted-Average Price
2023 Contracts
4Q23	13,800,000	$	(0.23)
2024 Contracts
1Q24	15,470,000	$	(0.02)
2Q24	15,470,000	$	(0.29)
3Q24	15,640,000	$	(0.26)
4Q24	15,640,000	$	(0.28)
2025 Contracts
1Q25	5,400,000	$	(0.09)
2Q25	5,460,000	$	(0.26)
3Q25	5,520,000	$	(0.23)
4Q25	5,520,000	$	(0.25)

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

XML

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2023

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

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

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

XML

Asset Retirement Obligations Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2023

Asset Retirement Obligation Disclosure [Abstract]

Roll-forward of our asset retirement obligations

The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2022 and the nine months ended September 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	718
Liabilities incurred for new wells, acquired wells and facilities construction	313
Reductions due to plugged wells and facilities	(603)
Revisions in estimates	534
Asset Retirement Obligations as of September 30, 2023	$	11,418

XML

Summary of Significant Accounting Policies (Details) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023 USD ($) bbl MMBTU $ / Boe $ / MMBTU	Sep. 30, 2022 USD ($)	Sep. 30, 2023 USD ($) bbl MMBTU $ / Boe $ / MMBTU	Sep. 30, 2022 USD ($)	Oct. 31, 2023 bbl MMBTU $ / MMBTU $ / Boe	Dec. 31, 2022 USD ($)
Property and Equipment
Proved oil and gas properties | $	$ 2,827,145		$ 2,827,145			$ 2,506,853
Unproved oil and gas properties | $	27,821		27,821			16,272
Furniture, fixtures, and other equipment | $	6,301		6,301			6,098
Less - Accumulated depreciation, depletion, and amortization | $	(1,151,141)		(1,151,141)			(1,004,044)
Net Furniture, Fixtures and other equipment | $	1,710,126		1,710,126			1,525,179
Disaggregation of Revenue [Line Items]
Oil and gas sales | $	173,963	$ 242,181	440,317	$ 554,442
Accounts Payable and Accrued Liabilities
Trade accounts payable | $	30,708		30,708			23,660
Accrued operating expenses | $	11,266		11,266			10,572
Accrued compensation costs | $	3,267		3,267			4,814
Asset retirement obligation - current portion | $	1,578		1,578			1,284
Accrued non-income based taxes | $	13,303		13,303			4,849
Accrued corporate and legal fees | $	181		181			388
WTI contingency payouts - current portion | $	1,537		1,537			1,600
Payables for Settled Derivatives | $	3,549		3,549			6,026
Other payables | $	9,342		9,342			7,007
Total Accounts payable and accrued liabilities | $	74,731		74,731			$ 60,200
Oil sales [Member]
Disaggregation of Revenue [Line Items]
Oil and gas sales | $	112,456	71,811	267,263	155,566
Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Oil and gas sales | $	46,075	150,958	132,802	351,626
NGL sales [Member]
Disaggregation of Revenue [Line Items]
Oil and gas sales | $	$ 15,432	$ 19,412	$ 40,252	$ 47,250
Swap [Member] | Fourth Quarter 2023 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	707,300		707,300
Derivative, Swap Type, Fixed Price | $ / Boe	78.53		78.53
Swap [Member] | Fourth Quarter 2023 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	5,727,000		5,727,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	4.20		4.20
Swap [Member] | Fourth Quarter 2023 | NGL Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	345,000		345,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	32.87		32.87
Swap [Member] | First Quarter 2024 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	728,000		728,000
Derivative, Swap Type, Fixed Price | $ / Boe	77.67		77.67
Swap [Member] | First Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					91,000
Derivative, Swap Type, Fixed Price | $ / Boe					83.40
Swap [Member] | First Quarter 2024 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,686,000		7,686,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	4.12		4.12
Swap [Member] | First Quarter 2024 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					1,820,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					3.66
Swap [Member] | First Quarter 2024 | NGL Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	400,400		400,400
Derivative, Swap Type, Fixed Price | $ / MMBTU	26.30		26.30
Swap [Member] | First Quarter 2024 | NGL Derivative | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					91,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					24.25
Swap [Member] | Second Quarter 2024 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	754,550		754,550
Derivative, Swap Type, Fixed Price | $ / Boe	77.59		77.59
Swap [Member] | Second Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					91,000
Derivative, Swap Type, Fixed Price | $ / Boe					81.31
Swap [Member] | Second Quarter 2024 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,350,000		12,350,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	3.67		3.67
Swap [Member] | Second Quarter 2024 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					2,430,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					3.31
Swap [Member] | Second Quarter 2024 | NGL Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	400,400		400,400
Derivative, Swap Type, Fixed Price | $ / MMBTU	26.30		26.30
Swap [Member] | Second Quarter 2024 | NGL Derivative | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					91,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					24.25
Swap [Member] | Third Quarter 2024 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	779,620		779,620
Derivative, Swap Type, Fixed Price | $ / Boe	76.48		76.48
Swap [Member] | Third Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					92,000
Derivative, Swap Type, Fixed Price | $ / Boe					79.63
Swap [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,420,000		12,420,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	3.78		3.78
Swap [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					2,760,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					3.46
Swap [Member] | Third Quarter 2024 | NGL Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	404,800		404,800
Derivative, Swap Type, Fixed Price | $ / MMBTU	26.30		26.30
Swap [Member] | Third Quarter 2024 | NGL Derivative | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					92,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					24.25
Swap [Member] | Fourth Quarter 2024 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	762,100		762,100
Derivative, Swap Type, Fixed Price | $ / Boe	76.16		76.16
Swap [Member] | Fourth Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					92,000
Derivative, Swap Type, Fixed Price | $ / Boe					78.21
Swap [Member] | Fourth Quarter 2024 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,420,000		12,420,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	4.12		4.12
Swap [Member] | Fourth Quarter 2024 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					2,760,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					3.75
Swap [Member] | Fourth Quarter 2024 | NGL Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	404,800		404,800
Derivative, Swap Type, Fixed Price | $ / MMBTU	26.30		26.30
Swap [Member] | Fourth Quarter 2024 | NGL Derivative | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					92,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					24.25
Swap [Member] | First Quarter 2025 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	666,000		666,000
Derivative, Swap Type, Fixed Price | $ / Boe	71.60		71.60
Swap [Member] | First Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					90,000
Derivative, Swap Type, Fixed Price | $ / Boe					76.52
Swap [Member] | First Quarter 2025 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	9,450,000		9,450,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	4.25		4.25
Swap [Member] | First Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					2,700,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					4.20
Swap [Member] | First Quarter 2025 | NGL Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	270,000		270,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	24.17		24.17
Swap [Member] | Second Quarter 2025 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	673,400		673,400
Derivative, Swap Type, Fixed Price | $ / Boe	71.60		71.60
Swap [Member] | Second Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					91,000
Derivative, Swap Type, Fixed Price | $ / Boe					75.38
Swap [Member] | Second Quarter 2025 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	9,555,000		9,555,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	3.71		3.71
Swap [Member] | Second Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					2,730,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					3.75
Swap [Member] | Second Quarter 2025 | NGL Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	273,000		273,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	24.17		24.17
Swap [Member] | Third Quarter 2025 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	680,800		680,800
Derivative, Swap Type, Fixed Price | $ / Boe	71.60		71.60
Swap [Member] | Third Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					92,000
Derivative, Swap Type, Fixed Price | $ / Boe					74.56
Swap [Member] | Third Quarter 2025 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	11,960,000		11,960,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	3.83		3.83
Swap [Member] | Third Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					2,760,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					3.89
Swap [Member] | Third Quarter 2025 | NGL Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	276,000		276,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	24.17		24.17
Swap [Member] | Fourth Quarter 2025 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	588,800		588,800
Derivative, Swap Type, Fixed Price | $ / Boe	71.29		71.29
Swap [Member] | Fourth Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					92,000
Derivative, Swap Type, Fixed Price | $ / Boe					73.58
Swap [Member] | Fourth Quarter 2025 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	8,740,000		8,740,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	4.17		4.17
Swap [Member] | Fourth Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					1,540,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					4.11
Swap [Member] | Fourth Quarter 2025 | NGL Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	276,000		276,000
Swap [Member] | First Quarter 2026 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	315,000		315,000
Derivative, Swap Type, Fixed Price | $ / Boe	69.40		69.40
Swap [Member] | First Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					157,500
Derivative, Swap Type, Fixed Price | $ / Boe					68.01
Swap [Member] | First Quarter 2026 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	9,680,000		9,680,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	4.48		4.48
Swap [Member] | First Quarter 2026 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					900,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					4.56
Swap [Member] | Second Quarter 2026 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	318,500		318,500
Derivative, Swap Type, Fixed Price | $ / Boe	69.40		69.40
Swap [Member] | Second Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					136,500
Derivative, Swap Type, Fixed Price | $ / Boe					67.98
Swap [Member] | Second Quarter 2026 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	9,555,000		9,555,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	3.56		3.56
Swap [Member] | Second Quarter 2026 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					910,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					3.53
Swap [Member] | Third Quarter 2026 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	322,000		322,000
Derivative, Swap Type, Fixed Price | $ / Boe	69.40		69.40
Swap [Member] | Third Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					110,400
Derivative, Swap Type, Fixed Price | $ / Boe					67.94
Swap [Member] | Third Quarter 2026 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	9,660,000		9,660,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	3.74		3.74
Swap [Member] | Third Quarter 2026 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					920,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					3.73
Swap [Member] | Fourth Quarter 2026 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	230,000		230,000
Derivative, Swap Type, Fixed Price | $ / Boe	69.42		69.42
Swap [Member] | Fourth Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					156,150
Derivative, Swap Type, Fixed Price | $ / Boe					68.60
Swap [Member] | Fourth Quarter 2026 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	9,200,000		9,200,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	4.13		4.13
Swap [Member] | Fourth Quarter 2026 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					920,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					4.19
Basis Swap [Member] | Fourth Quarter 2023 | Natural Gas Basis Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	13,800,000		13,800,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	(0.23)		(0.23)
Basis Swap [Member] | Fourth Quarter 2023 | Oil Basis Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	122,000		122,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.80		0.80
Basis Swap [Member] | Fourth Quarter 2023 | Oil Basis Derivative | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					61,000
Derivative, Swap Type, Fixed Price | $ / Boe					0.90
Basis Swap [Member] | Fourth Quarter 2023 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	122,000		122,000
Derivative, Swap Type, Fixed Price | $ / Boe	2.44		2.44
Basis Swap [Member] | Fourth Quarter 2023 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					61,000
Derivative, Swap Type, Fixed Price | $ / Boe					2.40
Basis Swap [Member] | First Quarter 2024 | Natural Gas Basis Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	15,470,000		15,470,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	(0.02)		(0.02)
Basis Swap [Member] | First Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					910,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					(0.21)
Basis Swap [Member] | First Quarter 2024 | Oil Basis Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	364,000		364,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.47		1.47
Basis Swap [Member] | First Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	364,000		364,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.69		0.69
Basis Swap [Member] | Second Quarter 2024 | Natural Gas Basis Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	15,470,000		15,470,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	(0.29)		(0.29)
Basis Swap [Member] | Second Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					910,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					(0.21)
Basis Swap [Member] | Second Quarter 2024 | Oil Basis Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	364,000		364,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.47		1.47
Basis Swap [Member] | Second Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	364,000		364,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.69		0.69
Basis Swap [Member] | Third Quarter 2024 | Natural Gas Basis Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	15,640,000		15,640,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	(0.26)		(0.26)
Basis Swap [Member] | Third Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					920,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					(0.21)
Basis Swap [Member] | Third Quarter 2024 | Oil Basis Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	368,000		368,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.47		1.47
Basis Swap [Member] | Third Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	368,000		368,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.69		0.69
Basis Swap [Member] | Fourth Quarter 2024 | Natural Gas Basis Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	15,640,000		15,640,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	(0.28)		(0.28)
Basis Swap [Member] | Fourth Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					920,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					(0.21)
Basis Swap [Member] | Fourth Quarter 2024 | Oil Basis Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	368,000		368,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.47		1.47
Basis Swap [Member] | Fourth Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	368,000		368,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.69		0.69
Basis Swap [Member] | First Quarter 2025 | Natural Gas Basis Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	5,400,000		5,400,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	(0.09)		(0.09)
Basis Swap [Member] | First Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					900,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					(0.23)
Basis Swap [Member] | First Quarter 2025 | Oil Basis Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	270,000		270,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75		1.75
Basis Swap [Member] | First Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					90,000
Derivative, Swap Type, Fixed Price | $ / Boe					1.75
Basis Swap [Member] | First Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	270,000		270,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.40		0.40
Basis Swap [Member] | First Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					90,000
Derivative, Swap Type, Fixed Price | $ / Boe					0.50
Basis Swap [Member] | Second Quarter 2025 | Natural Gas Basis Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	5,460,000		5,460,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	(0.26)		(0.26)
Basis Swap [Member] | Second Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					910,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					(0.23)
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	273,000		273,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75		1.75
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					91,000
Derivative, Swap Type, Fixed Price | $ / Boe					1.75
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	273,000		273,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.40		0.40
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					91,000
Derivative, Swap Type, Fixed Price | $ / Boe					0.50
Basis Swap [Member] | Third Quarter 2025 | Natural Gas Basis Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	5,520,000		5,520,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	(0.23)		(0.23)
Basis Swap [Member] | Third Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					920,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					(0.23)
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	276,000		276,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75		1.75
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					92,000
Derivative, Swap Type, Fixed Price | $ / Boe					1.75
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	276,000		276,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.40		0.40
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					92,000
Derivative, Swap Type, Fixed Price | $ / Boe					0.50
Basis Swap [Member] | Fourth Quarter 2025 | Natural Gas Basis Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	5,520,000		5,520,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	(0.25)		(0.25)
Basis Swap [Member] | Fourth Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					920,000
Derivative, Swap Type, Fixed Price | $ / MMBTU					(0.23)
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	276,000		276,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75		1.75
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					92,000
Derivative, Swap Type, Fixed Price | $ / Boe					1.75
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes	276,000		276,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.40		0.40
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes					92,000
Derivative, Swap Type, Fixed Price | $ / Boe					0.50

XML

Summary of Significant Accounting Policies (Details Textual) $ in Thousands	3 Months Ended						9 Months Ended
	Sep. 30, 2023 USD ($) MMBTU bbl $ / Boe $ / MMBTU shares	Jun. 30, 2023 shares	Mar. 31, 2023 shares	Sep. 30, 2022 USD ($) shares	Jun. 30, 2022 shares	Mar. 31, 2022 shares	Sep. 30, 2023 USD ($) MMBTU bbl $ / Boe $ / MMBTU shares	Sep. 30, 2022 USD ($) shares	Oct. 31, 2023 bbl MMBTU $ / MMBTU $ / Boe	Dec. 31, 2022 USD ($)	Sep. 20, 2022	Dec. 31, 2021 USD ($)
Summary of Significant Accounting Policies
Capitalized Costs Oil and Gas Producing Activities | $	$ 1,400			$ 1,100			$ 4,100	$ 3,300
Proved oil and gas properties | $	2,827,145						2,827,145			$ 2,506,853
Unproved oil and gas properties | $	27,821						27,821			16,272
Furniture, fixtures, and other equipment | $	6,301						6,301			6,098
Less - Accumulated depreciation, depletion, and amortization | $	(1,151,141)						(1,151,141)			(1,004,044)
Net Furniture, Fixtures and other equipment | $	$ 1,710,126						1,710,126			1,525,179
Discount rate for estimated future net revenues from proved properties	10.00%
Write-down of oil and gas properties | $	$ 0			0			0	0
Allowance for doubtful accounts receivable, current | $	100						100			100		$ 100
Accounts receivable, gross | $	60,400						60,400			70,900		45,300
Accounts receivable related to joint interest owners | $	1,900						1,900			5,600		1,900
Severance tax receivable | $	9,100						9,100			4,300		1,000
Other receivables | $	8,800						$ 8,800			8,900		$ 1,500
Percentage of working interest in wells							100.00%
Total amount of supervision fees charged to wells | $	$ 3,000			$ 2,800			$ 8,600	$ 6,100
Effective Income Tax Rate Reconciliation, Percent	17.00%			4.00%			22.00%	4.00%
Provision (Benefit) for Income Taxes | $	$ (949)			$ 6,066			$ 33,214	$ 7,678
Oil and gas sales | $	173,963			$ 242,181			440,317	$ 554,442
Trade accounts payable | $	30,708						30,708			23,660
Accrued operating expenses | $	11,266						11,266			10,572
Accrued payroll costs | $	3,267						3,267			4,814
Asset retirement obligation - current portion | $	1,578						1,578			1,284
Accrued non-income based taxes | $	13,303						13,303			4,849
Accrued corporate and legal fees | $	181						181			388
WTI contingency payouts - current portion | $	1,537						1,537			1,600
Payables for Settled Derivatives | $	3,549						3,549			6,026
Other payables | $	9,342						9,342			7,007
Accounts payable and accrued liabilities | $	$ 74,731						$ 74,731			$ 60,200
Purchase of treasury stock (shares) | shares	361	5,310	126,240	7,853	16,485	96,012	131,911	120,350
Treasury Shares Pursuant to Purchase Price Adjustment (shares) | shares				184		41,191		41,375
Stockholders Rights Agreement, Percentage of Common Stock Threshold											0.15
Oil sales [Member]
Summary of Significant Accounting Policies
Oil and gas sales | $	$ 112,456			$ 71,811			$ 267,263	$ 155,566
Natural gas sales [Member]
Summary of Significant Accounting Policies
Oil and gas sales | $	46,075			150,958			132,802	351,626
NGL sales [Member]
Summary of Significant Accounting Policies
Oil and gas sales | $	$ 15,432			$ 19,412			$ 40,252	$ 47,250
Collar Contracts [Member] | Fourth Quarter 2023 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	302,242						302,242
Collar Contracts [Member] | Fourth Quarter 2023 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	12,445,000						12,445,000
Collar Contracts [Member] | First Quarter 2024 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	319,700						319,700
Collar Contracts [Member] | First Quarter 2024 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	9,661,000						9,661,000
Collar Contracts [Member] | Second Quarter 2024 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	215,000						215,000
Collar Contracts [Member] | Second Quarter 2024 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	4,643,000						4,643,000
Collar Contracts [Member] | Third Quarter 2024 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	184,000						184,000
Collar Contracts [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	3,878,000						3,878,000
Collar Contracts [Member] | Fourth Quarter 2024 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	184,000						184,000
Collar Contracts [Member] | Fourth Quarter 2024 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	3,865,000						3,865,000
Collar Contracts [Member] | First Quarter 2025 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	238,500						238,500
Collar Contracts [Member] | First Quarter 2025 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	5,130,000						5,130,000
Collar Contracts [Member] | Second Quarter 2025 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	227,500						227,500
Collar Contracts [Member] | Second Quarter 2025 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	4,914,000						4,914,000
Collar Contracts [Member] | Third Quarter 2025 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	920,000						920,000
Collar Contracts [Member] | Fourth Quarter 2025 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	920,000						920,000
Collar Contracts [Member] | First Quarter 2026 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	90,000						90,000
Collar Contracts [Member] | Second Quarter 2026 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	91,000						91,000
Collar Contracts [Member] | Third Quarter 2026 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	92,000						92,000
Swap [Member] | Fourth Quarter 2023 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	707,300						707,300
Derivative, Swap Type, Fixed Price | $ / Boe	78.53						78.53
Swap [Member] | Fourth Quarter 2023 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	5,727,000						5,727,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	4.20						4.20
Swap [Member] | Fourth Quarter 2023 | NGL Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	345,000						345,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	32.87						32.87
Swap [Member] | First Quarter 2024 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	728,000						728,000
Derivative, Swap Type, Fixed Price | $ / Boe	77.67						77.67
Swap [Member] | First Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									91,000
Derivative, Swap Type, Fixed Price | $ / Boe									83.40
Swap [Member] | First Quarter 2024 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	7,686,000						7,686,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	4.12						4.12
Swap [Member] | First Quarter 2024 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									1,820,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									3.66
Swap [Member] | First Quarter 2024 | NGL Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	400,400						400,400
Derivative, Swap Type, Fixed Price | $ / MMBTU	26.30						26.30
Swap [Member] | First Quarter 2024 | NGL Derivative | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									91,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									24.25
Swap [Member] | Second Quarter 2024 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	754,550						754,550
Derivative, Swap Type, Fixed Price | $ / Boe	77.59						77.59
Swap [Member] | Second Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									91,000
Derivative, Swap Type, Fixed Price | $ / Boe									81.31
Swap [Member] | Second Quarter 2024 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	12,350,000						12,350,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	3.67						3.67
Swap [Member] | Second Quarter 2024 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									2,430,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									3.31
Swap [Member] | Second Quarter 2024 | NGL Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	400,400						400,400
Derivative, Swap Type, Fixed Price | $ / MMBTU	26.30						26.30
Swap [Member] | Second Quarter 2024 | NGL Derivative | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									91,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									24.25
Swap [Member] | Third Quarter 2024 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	779,620						779,620
Derivative, Swap Type, Fixed Price | $ / Boe	76.48						76.48
Swap [Member] | Third Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									92,000
Derivative, Swap Type, Fixed Price | $ / Boe									79.63
Swap [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	12,420,000						12,420,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	3.78						3.78
Swap [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									2,760,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									3.46
Swap [Member] | Third Quarter 2024 | NGL Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	404,800						404,800
Derivative, Swap Type, Fixed Price | $ / MMBTU	26.30						26.30
Swap [Member] | Third Quarter 2024 | NGL Derivative | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									92,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									24.25
Swap [Member] | Fourth Quarter 2024 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	762,100						762,100
Derivative, Swap Type, Fixed Price | $ / Boe	76.16						76.16
Swap [Member] | Fourth Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									92,000
Derivative, Swap Type, Fixed Price | $ / Boe									78.21
Swap [Member] | Fourth Quarter 2024 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	12,420,000						12,420,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	4.12						4.12
Swap [Member] | Fourth Quarter 2024 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									2,760,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									3.75
Swap [Member] | Fourth Quarter 2024 | NGL Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	404,800						404,800
Derivative, Swap Type, Fixed Price | $ / MMBTU	26.30						26.30
Swap [Member] | Fourth Quarter 2024 | NGL Derivative | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									92,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									24.25
Swap [Member] | First Quarter 2025 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	666,000						666,000
Derivative, Swap Type, Fixed Price | $ / Boe	71.60						71.60
Swap [Member] | First Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									90,000
Derivative, Swap Type, Fixed Price | $ / Boe									76.52
Swap [Member] | First Quarter 2025 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	9,450,000						9,450,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	4.25						4.25
Swap [Member] | First Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									2,700,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									4.20
Swap [Member] | First Quarter 2025 | NGL Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	270,000						270,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	24.17						24.17
Swap [Member] | Second Quarter 2025 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	673,400						673,400
Derivative, Swap Type, Fixed Price | $ / Boe	71.60						71.60
Swap [Member] | Second Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									91,000
Derivative, Swap Type, Fixed Price | $ / Boe									75.38
Swap [Member] | Second Quarter 2025 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	9,555,000						9,555,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	3.71						3.71
Swap [Member] | Second Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									2,730,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									3.75
Swap [Member] | Second Quarter 2025 | NGL Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	273,000						273,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	24.17						24.17
Swap [Member] | Third Quarter 2025 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	680,800						680,800
Derivative, Swap Type, Fixed Price | $ / Boe	71.60						71.60
Swap [Member] | Third Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									92,000
Derivative, Swap Type, Fixed Price | $ / Boe									74.56
Swap [Member] | Third Quarter 2025 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	11,960,000						11,960,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	3.83						3.83
Swap [Member] | Third Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									2,760,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									3.89
Swap [Member] | Third Quarter 2025 | NGL Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	276,000						276,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	24.17						24.17
Swap [Member] | Fourth Quarter 2025 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	588,800						588,800
Derivative, Swap Type, Fixed Price | $ / Boe	71.29						71.29
Swap [Member] | Fourth Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									92,000
Derivative, Swap Type, Fixed Price | $ / Boe									73.58
Swap [Member] | Fourth Quarter 2025 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	8,740,000						8,740,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	4.17						4.17
Swap [Member] | Fourth Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									1,540,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									4.11
Swap [Member] | Fourth Quarter 2025 | NGL Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	276,000						276,000
Swap [Member] | First Quarter 2026 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	315,000						315,000
Derivative, Swap Type, Fixed Price | $ / Boe	69.40						69.40
Swap [Member] | First Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									157,500
Derivative, Swap Type, Fixed Price | $ / Boe									68.01
Swap [Member] | First Quarter 2026 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	9,680,000						9,680,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	4.48						4.48
Swap [Member] | First Quarter 2026 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									900,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									4.56
Swap [Member] | Second Quarter 2026 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	318,500						318,500
Derivative, Swap Type, Fixed Price | $ / Boe	69.40						69.40
Swap [Member] | Second Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									136,500
Derivative, Swap Type, Fixed Price | $ / Boe									67.98
Swap [Member] | Second Quarter 2026 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	9,555,000						9,555,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	3.56						3.56
Swap [Member] | Second Quarter 2026 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									910,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									3.53
Swap [Member] | Third Quarter 2026 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	322,000						322,000
Derivative, Swap Type, Fixed Price | $ / Boe	69.40						69.40
Swap [Member] | Third Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									110,400
Derivative, Swap Type, Fixed Price | $ / Boe									67.94
Swap [Member] | Third Quarter 2026 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	9,660,000						9,660,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	3.74						3.74
Swap [Member] | Third Quarter 2026 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									920,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									3.73
Swap [Member] | Fourth Quarter 2026 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	230,000						230,000
Derivative, Swap Type, Fixed Price | $ / Boe	69.42						69.42
Swap [Member] | Fourth Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									156,150
Derivative, Swap Type, Fixed Price | $ / Boe									68.60
Swap [Member] | Fourth Quarter 2026 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	9,200,000						9,200,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	4.13						4.13
Swap [Member] | Fourth Quarter 2026 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									920,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									4.19
Basis Swap [Member] | Fourth Quarter 2023 | Natural Gas Basis Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	13,800,000						13,800,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	(0.23)						(0.23)
Basis Swap [Member] | Fourth Quarter 2023 | Oil Basis Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	122,000						122,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.80						0.80
Basis Swap [Member] | Fourth Quarter 2023 | Oil Basis Derivative | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									61,000
Derivative, Swap Type, Fixed Price | $ / Boe									0.90
Basis Swap [Member] | Fourth Quarter 2023 | Oil Basis Calendar Monthly Roll Differential Swap
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	122,000						122,000
Derivative, Swap Type, Fixed Price | $ / Boe	2.44						2.44
Basis Swap [Member] | Fourth Quarter 2023 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									61,000
Derivative, Swap Type, Fixed Price | $ / Boe									2.40
Basis Swap [Member] | First Quarter 2024 | Natural Gas Basis Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	15,470,000						15,470,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	(0.02)						(0.02)
Basis Swap [Member] | First Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									910,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									(0.21)
Basis Swap [Member] | First Quarter 2024 | Oil Basis Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	364,000						364,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.47						1.47
Basis Swap [Member] | First Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	364,000						364,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.69						0.69
Basis Swap [Member] | Second Quarter 2024 | Natural Gas Basis Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	15,470,000						15,470,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	(0.29)						(0.29)
Basis Swap [Member] | Second Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									910,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									(0.21)
Basis Swap [Member] | Second Quarter 2024 | Oil Basis Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	364,000						364,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.47						1.47
Basis Swap [Member] | Second Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	364,000						364,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.69						0.69
Basis Swap [Member] | Third Quarter 2024 | Natural Gas Basis Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	15,640,000						15,640,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	(0.26)						(0.26)
Basis Swap [Member] | Third Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									920,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									(0.21)
Basis Swap [Member] | Third Quarter 2024 | Oil Basis Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	368,000						368,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.47						1.47
Basis Swap [Member] | Third Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	368,000						368,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.69						0.69
Basis Swap [Member] | Fourth Quarter 2024 | Natural Gas Basis Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	15,640,000						15,640,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	(0.28)						(0.28)
Basis Swap [Member] | Fourth Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									920,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									(0.21)
Basis Swap [Member] | Fourth Quarter 2024 | Oil Basis Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	368,000						368,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.47						1.47
Basis Swap [Member] | Fourth Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	368,000						368,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.69						0.69
Basis Swap [Member] | First Quarter 2025 | Natural Gas Basis Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	5,400,000						5,400,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	(0.09)						(0.09)
Basis Swap [Member] | First Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									900,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									(0.23)
Basis Swap [Member] | First Quarter 2025 | Oil Basis Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	270,000						270,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75						1.75
Basis Swap [Member] | First Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									90,000
Derivative, Swap Type, Fixed Price | $ / Boe									1.75
Basis Swap [Member] | First Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	270,000						270,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.40						0.40
Basis Swap [Member] | First Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									90,000
Derivative, Swap Type, Fixed Price | $ / Boe									0.50
Basis Swap [Member] | Second Quarter 2025 | Natural Gas Basis Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	5,460,000						5,460,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	(0.26)						(0.26)
Basis Swap [Member] | Second Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									910,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									(0.23)
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	273,000						273,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75						1.75
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									91,000
Derivative, Swap Type, Fixed Price | $ / Boe									1.75
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	273,000						273,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.40						0.40
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									91,000
Derivative, Swap Type, Fixed Price | $ / Boe									0.50
Basis Swap [Member] | Third Quarter 2025 | Natural Gas Basis Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	5,520,000						5,520,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	(0.23)						(0.23)
Basis Swap [Member] | Third Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									920,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									(0.23)
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	276,000						276,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75						1.75
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									92,000
Derivative, Swap Type, Fixed Price | $ / Boe									1.75
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	276,000						276,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.40						0.40
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									92,000
Derivative, Swap Type, Fixed Price | $ / Boe									0.50
Basis Swap [Member] | Fourth Quarter 2025 | Natural Gas Basis Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	5,520,000						5,520,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	(0.25)						(0.25)
Basis Swap [Member] | Fourth Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU									920,000
Derivative, Swap Type, Fixed Price | $ / MMBTU									(0.23)
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	276,000						276,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75						1.75
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									92,000
Derivative, Swap Type, Fixed Price | $ / Boe									1.75
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes	276,000						276,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.40						0.40
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes									92,000
Derivative, Swap Type, Fixed Price | $ / Boe									0.50
Minimum [Member]
Summary of Significant Accounting Policies
Estimated useful lives of property	2 years						2 years
Maximum [Member]
Summary of Significant Accounting Policies
Estimated useful lives of property	20 years						20 years

XML

Leases Leases (Details) $ in Thousands	Sep. 30, 2023 USD ($)
Leases [Abstract]
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year	$ 2,667
Lessee, Operating Lease, Liability, Payments, Due Year Two	4,166
Lessee, Operating Lease, Liability, Payments, Due Year Three	2,427
Lessee, Operating Lease, Liability, Payments, Due Year Four	1,194
Lessee, Operating Lease, Liability, Payments, Due Year Five	61
Lessee, Operating Lease, Liability, Payments, Due after Year Five	475
Lessee, Operating Lease, Liability, Payments, Due	10,990
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(879)
Operating Lease, Liability	$ 10,111

XML

Share-Based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Thousands							3 Months Ended			9 Months Ended
	Sep. 30, 2023	Feb. 23, 2023	Feb. 22, 2023	Feb. 23, 2022	Feb. 24, 2021	May 21, 2019	Sep. 30, 2023	Sep. 30, 2022	Jun. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Share-based Compensation (Details Textual)
Share-based Payment Arrangement, Noncash Expense										$ 4,043	$ 3,901
Share-based compensation (capitalized)							$ 100	$ 100		200	200
Stock Option Activity
Options, Exercises in Period								(11,087)	(4,497)
General and Administrative Expense [Member]
Share-based Compensation (Details Textual)
Share-based Payment Arrangement, Noncash Expense							1,500	$ 1,200		4,000	$ 3,900
Share-based Payment Arrangement, Option [Member]
Share-based Compensation (Details Textual)
Stock option award unrecognized compensation	$ 0						0			0
Stock option award outstanding aggregate intrinsic value	$ 1,800						$ 1,800			1,800
Remaining contract life of outstanding stock options.	3 years 7 months 6 days
Remaining contract life of exercisable stock option	3 years 7 months 6 days
Stock option award exercisable aggregate intrinsic value										$ 1,800
Stock Option Activity
Options outstanding, beginning of period, shares	196,162						196,162			196,162		196,162
Options outstanding, beginning of period, weighted average price	$ 26.46						$ 26.46			$ 26.46		$ 26.46
Options, Grants in Period										0
Options, Grants in Period, Weighted Average Grant Date Fair Value										$ 0
Options, Exercises in Period										0
Options, Exercises in Period, Weighted Average Exercise Price										$ 0
Options exercisable, end of period, shares	196,162						196,162			196,162
Options exercisable, end of period, weighted average price	$ 26.46						$ 26.46			$ 26.46
Restricted Stock Units (RSUs) [Member]
Share-based Compensation (Details Textual)
Stock option award unrecognized compensation	$ 5,100						$ 5,100			$ 5,100
Unrecognized compensation expense weighted-average period										2 years
Restricted stock activity
Restricted shares outstanding, beginning of period, shares										227,114
Restricted shares outstanding, beginning of period, weighted average price										$ 21.18
Restricted shares granted, shares										195,791
Restricted shares granted, weighted average price										$ 23.75
Restricted shares forfeited										(1,424)
Restricted shares forfeited, weighted average price										$ 25.44
Restricted shares vested, shares										(137,467)
Restricted shares vested, weighted average price										$ 17.78
Restricted shares outstanding, end of period, shares	284,014						284,014			284,014
Restricted shares outstanding, end of period, weighted average price	$ 24.58						$ 24.58			$ 24.58
Performance Shares [Member]
Share-based Compensation (Details Textual)
Stock option award unrecognized compensation	$ 4,900						$ 4,900			$ 4,900
Unrecognized compensation expense weighted-average period	1 year 10 months 24 days
Share-based Compensation, Expected Term		3 years		3 years	2 years	3 years
Restricted stock activity
Restricted shares outstanding, beginning of period, shares										283,500
Restricted shares outstanding, beginning of period, weighted average price										$ 23.18
Restricted shares granted, shares		120,749		122,111	161,389	99,500
Restricted shares granted, weighted average price		$ 31.18		$ 36.47	$ 13.13	$ 18.86
Performance based stock units, incremental shares vested				142,021
Performance based stock units, incremental shares vested, Weighted Average Grant Date Fair Value				$ 13.13
Restricted shares vested, shares			(303,410)	(97,812)						(303,410)
Restricted shares vested, weighted average price										$ 13.13
Restricted shares outstanding, end of period, shares	242,860						242,860			242,860
Restricted shares outstanding, end of period, weighted average price	$ 33.84						$ 33.84			$ 33.84
Percent of payout for performance based stock units	100.00%	136.28%		150.93%	157.60%	112.90%	100.00%			100.00%
Approved payout for performance based stock units			188.00%	117.00%
Minimum [Member] | Share-based Payment Arrangement, Option [Member]
Share-based Compensation (Details Textual)
Stock option award vesting period										1 year
Minimum [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation (Details Textual)
Stock option award vesting period										1 year
Minimum [Member] | Performance Shares [Member]
Restricted stock activity
Percent of payout for performance based stock units		0.00%		0.00%	0.00%	0.00%
Maximum [Member] | Share-based Payment Arrangement, Option [Member]
Share-based Compensation (Details Textual)
Stock option award vesting period										5 years
Maximum [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation (Details Textual)
Stock option award vesting period										5 years
Maximum [Member] | Performance Shares [Member]
Restricted stock activity
Percent of payout for performance based stock units		200.00%		200.00%	200.00%	200.00%

XML

Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended						9 Months Ended
	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Sep. 30, 2023	Sep. 30, 2022
Basic EPS:
Net Income (Loss)	$ (4,771)	$ 24,937	$ 94,492	$ 142,541	$ 88,790	$ (64,255)	$ 114,658	$ 167,076
Income, share amounts	22,985,000			22,308,000			22,677,000	18,885,000
Earnings Per Share, Basic	$ (0.21)			$ 6.39			$ 5.06	$ 8.85
Diluted EPS:
Net Income (Loss) Available to Common Stockholders, Diluted	$ (4,771)			$ 142,541			$ 114,658	$ 167,076
Weighted Average Shares Outstanding - Diluted	22,985,000			22,669,000			22,852,000	19,237,000
Earnings Per Share, Diluted	$ (0.21)			$ 6.29			$ 5.02	$ 8.69
Issuance of common stock (shares)	2,810,811
Proceeds from Issuance of Common Stock							$ 97,133	$ 0
Share-based Payment Arrangement, Option [Member]
Dilutive Securities:
Dilutive Securities	0			55,000			17,000	40,000
Diluted EPS:
Antidilutive shares excluded from EPS, shares	200,000			0			100,000	100,000
Restricted Stock Units (RSUs) [Member]
Dilutive Securities:
Dilutive Securities	0			137,000			91,000	171,000
Diluted EPS:
Antidilutive shares excluded from EPS, shares	200,000			100,000			100,000	100,000
Performance Shares [Member]
Dilutive Securities:
Dilutive Securities	0			169,000			67,000	141,000
Diluted EPS:
Antidilutive shares excluded from EPS, shares	100,000			0			0	0

XML

Long-Term Debt (Details) $ in Thousands					3 Months Ended		9 Months Ended
	Jun. 14, 2023	Mar. 20, 2023 USD ($)	Nov. 29, 2021 USD ($)	Nov. 12, 2021 USD ($)	Sep. 30, 2023 USD ($)	Sep. 30, 2022 USD ($)	Sep. 30, 2023 USD ($)	Sep. 30, 2022 USD ($)	Dec. 31, 2022 USD ($)	Dec. 15, 2017 USD ($)
Bank Borrowings
Long-term Debt, excluding current maturities					$ 645,096		$ 645,096		$ 688,531
Payments of Debt Issuance Costs							0	$ 7,228
Second Lien [Abstract]
Long-term debt, gross					$ 648,000		648,000		692,000
Discount Rate for Estimated Future Net Revenues from Proved Properties					10.00%
Gross interest expense including amortization of debt issuance costs					$ 19,811	$ 12,173	54,746	26,632
New Credit Facility [Member]
Bank Borrowings
Debt Issuance Costs, Net					7,000		7,000		8,700
Second Lien Notes [Member]
Bank Borrowings
Debt Issuance Costs, Net					2,166		2,166		2,587
Long-term Debt, excluding current maturities					150,000		150,000		150,000	$ 198,000
Second Lien [Abstract]
Long-term debt, gross				$ 150,000						200,000
Debt Instrument, Unamortized Discount					$ (738)		$ (738)		(882)	$ (2,000)
Repayments of Long-Term Debt			$ 50,000
Debt Instrument, Interest Rate, Stated Percentage					13.16%		13.16%
Second Lien, Required Security Interest on Proved Reserves				90.00%
Second Lien, Required Security Interest on Oil and Gas Properties				90.00%
Discount Rate for Estimated Future Net Revenues for Proved Properties at 9%				9.00%
Second Lien, Asset Coverage Ratio, Minimum				1.25
Second Lien, Debt to EBITDA Ratio, after March 31, 2022				3.25
Long-term debt, net					$ 147,100		$ 147,100
Gross interest expense including amortization of debt issuance costs					5,200	3,800	14,900	10,700
Second Lien Notes [Member] | Alternative Base Interest Rate [Member]
Second Lien [Abstract]
Debt Instrument, Minimum Margin on SOFR	1.00%
Debt Instrument, Basis Spread on Variable Rate	6.50%
Second Lien Notes [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate
Second Lien [Abstract]
Debt Instrument, Minimum Margin on SOFR	0.25%
Debt Instrument, Basis Spread on Variable Rate	7.50%
Second Lien Notes [Member] | Fed Funds Effective Rate Overnight Index Swap Rate
Second Lien [Abstract]
Debt Instrument, Basis Spread on Variable Rate	0.50%
Line of Credit [Member] | New Credit Facility [Member]
Bank Borrowings
Long-term Debt, excluding current maturities					498,000		498,000		542,000
Line of Credit Facility, Maximum Borrowing Capacity		$ 2,000,000
Line of Credit Facility, Current Borrowing Capacity		775,000
Line of Credit, Letters of Credit Issuable		$ 25,000
Letters of Credit Outstanding, Amount					$ 0		$ 0		$ 0
Commitment fee basis points for the credit facility		0.50%
Line of Credit, Additional Interest Due to Payment Default		2.00%
Debt, Weighted Average Interest Rate					8.67%		8.67%
Line of Credit, Required Security Interest on Oil and Gas Properties		85.00%
Line of Credit, Covenant, Debt to EBITDA Ratio		3.00
Line of Credit, Covenant, Current Ratio, Minimum		1.00
Line of Credit Facility, Commitment Fee Amount					$ 200	300	$ 700	900
Payments of Debt Issuance Costs							0	7,200
Second Lien [Abstract]
Gross interest expense including amortization of debt issuance costs					$ 14,600	$ 8,300	$ 39,800	$ 15,900
Line of Credit [Member] | New Credit Facility [Member] | Minimum [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate
Bank Borrowings
Debt instrument escalating basis spread on base rate		0.0175
Debt Instrument Escalating Rates for Eurodollar Rate Loans		0.0275
Line of Credit [Member] | New Credit Facility [Member] | Maximum [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate
Bank Borrowings
Debt instrument escalating basis spread on base rate		0.0275
Debt Instrument Escalating Rates for Eurodollar Rate Loans		0.0375

XML

Acquisitions and Dispositions Acquisitions and Dispositions (Details) $ in Thousands							3 Months Ended				9 Months Ended		12 Months Ended
	Aug. 11, 2023 USD ($)	Oct. 31, 2022 USD ($)	Aug. 15, 2022 USD ($)	Jun. 30, 2022 USD ($) shares	May 10, 2022 USD ($) shares	Nov. 19, 2021 USD ($) shares	Sep. 30, 2023 USD ($)	Sep. 30, 2022 USD ($)	Jun. 30, 2022 USD ($) shares	Mar. 31, 2022 shares	Sep. 30, 2023 USD ($)	Sep. 30, 2022 USD ($)	Dec. 31, 2022 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stock Issued During Period, Shares, Acquisitions | shares									5,448,472	489
Other current assets							$ 3,825				$ 3,825		$ 2,671
Right of Use Assets							10,085				10,085		12,077
Derivative, Fair Value, Net							10,100				10,100		28,200
Non-current Lease Liability							4,604				4,604		3,775
Asset Retirement Obligations, Noncurrent							9,840				9,840		9,171
WTI Contingency Payout Fair Value						$ 1,900
Proceeds from the sale of property and equipment											0	$ 4,415	4,400
Gain (Loss) on WTI Contingency Payout							(900)	$ 6,100			1,100	4,700
Teal Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acquisition of oil and gas properties						37,600
Asset Acquisition, Consideration Transferred						77,400
Asset Acquisition, Consideration Transferred, Equity Interest Issued and Issuable						37,900
WTI Annual Earn Out Payment						$ 1,600
WTI Annual Earn Out, Average Monthly Settlement Price						70
2021 WTI Contingency Payable													1,600
Gain (Loss) on WTI Contingency Payout							$ 900	$ 700			1,000	$ 800
Teal Acquisition | Asset Acquisition, Shares Issuable
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stock Issued During Period, Shares, Acquisitions | shares						1,351,961
SandPoint Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acquisition of oil and gas properties					$ 27,709
Asset Acquisition, Consideration Transferred					67,476
Asset Acquisition, Consideration Transferred, Equity Interest Issued and Issuable					$ 39,767
Asset Acquisition, Transaction Costs													466
Asset Acquisition, Total Cost of Transaction													67,942
Allocation of Total Cost, Oil and gas properties													84,810
Allocation of Total cost, Total assets													84,810
Accounts Payable and Accrued Liabilities, Current													199
Derivative, Fair Value, Net													16,511
Asset Retirement Obligations, Noncurrent													158
Allocation of Total Cost, Total Liabilities													16,868
SandPoint Acquisition | Asset Acquisition, Shares Issuable
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stock Issued During Period, Shares, Acquisitions | shares					1,300,000
Sundance Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acquisition of oil and gas properties				$ 220,866
Asset Acquisition, Consideration Transferred				344,939
Asset Acquisition, Consideration Transferred, Equity Interest Issued and Issuable				117,651
Asset Acquisition, Transaction Costs				6,766					$ 6,766				6,800
Asset Acquisition, Total Cost of Transaction				351,705
Other current assets				4,202					4,202
Allocation of Total Cost, Oil and gas properties				397,401
Right of Use Assets				890					890
Allocation of Total cost, Total assets				402,493
Accounts Payable and Accrued Liabilities, Current				13,687					13,687
Derivative, Fair Value, Net				33,767					33,767
Non-current Lease Liability				890					890
Asset Retirement Obligations, Noncurrent				2,444					2,444
Allocation of Total Cost, Total Liabilities				50,788
2022 WTI Contingency Payout Fair Value				7,422					7,422
WTI Annual Earn Out Payment				7,500					7,500
Account Receivable for purchase price adjustments				$ (1,000)					$ (1,000)
WTI Annual Earn Out, Average Monthly Settlement 2022				95					95
2023 WTI Annual Earn Out Payment													$ 7,500
WTI Annual Earn Out, Average Monthly Settlement Price 2023				85					85
2024 WTI Annual Earn Out Payment				$ 7,500					$ 7,500
Gain (Loss) on WTI Contingency Payout											1,000
Non-Cash Gain on WTI Contingency											$ 1,100
Sundance Acquisition | Asset Acquisition, Shares Issuable
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stock Issued During Period, Shares, Acquisitions | shares				4,148,472
Arkoma Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset Acquisition, Consideration Transferred			$ 31,200
Dewitt and Gonzalez Counties Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset Acquisition, Consideration Transferred		$ 80,100
Chesapeake South Texas Rich Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
WTI Annual Earn Out Payment	$ 50,000
Asset Acquisition, Price of Acquisition, Expected	700,000
Asset Acquisition, Cash Price to be Paid for Acquisition	650,000
Asset Acquisition, Deferred Cash Payment	50,000
Asset Acquisition, Cash Deposit in Escrow	$ 50,000

XML

Price-Risk Management Price-Risk Management (Details) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023 USD ($) MMBTU bbl $ / MMBTU $ / Boe	Sep. 30, 2022 USD ($)	Sep. 30, 2023 USD ($) MMBTU bbl $ / MMBTU $ / Boe	Sep. 30, 2022 USD ($)	Dec. 31, 2022 USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Price Risk Derivatives, Net | $	$ (53,700)	$ (1,300)	$ 56,500	$ (162,500)
Gain (Loss) on WTI Contingency Payout | $	(900)	$ 6,100	1,100	4,700
Cash Received (Paid) On Settlements of Derivative Contracts | $			70,670	$ (182,058)
Receivables for Settled Derivatives | $	8,400		8,400		$ 6,900
Payables for Settled Derivatives | $	3,549		3,549		6,026
Derivative, Fair Value, Net | $	10,100		10,100		28,200
Other Current Assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	50,200		50,200		52,500
Other Noncurrent Assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	14,200		14,200		24,200
Other Current Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	32,800		32,800		40,800
Other Noncurrent Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	$ 21,600		$ 21,600		$ 7,700
Swap [Member] | Oil Derivative Swaps | Fourth Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	707,300		707,300
Derivative, Swap Type, Fixed Price | $ / Boe	78.53		78.53
Swap [Member] | Oil Derivative Swaps | First Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	728,000		728,000
Derivative, Swap Type, Fixed Price | $ / Boe	77.67		77.67
Swap [Member] | Oil Derivative Swaps | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	754,550		754,550
Derivative, Swap Type, Fixed Price | $ / Boe	77.59		77.59
Swap [Member] | Oil Derivative Swaps | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	779,620		779,620
Derivative, Swap Type, Fixed Price | $ / Boe	76.48		76.48
Swap [Member] | Oil Derivative Swaps | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	762,100		762,100
Derivative, Swap Type, Fixed Price | $ / Boe	76.16		76.16
Swap [Member] | Oil Derivative Swaps | First Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	666,000		666,000
Derivative, Swap Type, Fixed Price | $ / Boe	71.60		71.60
Swap [Member] | Oil Derivative Swaps | Second Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	673,400		673,400
Derivative, Swap Type, Fixed Price | $ / Boe	71.60		71.60
Swap [Member] | Oil Derivative Swaps | Third Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	680,800		680,800
Derivative, Swap Type, Fixed Price | $ / Boe	71.60		71.60
Swap [Member] | Oil Derivative Swaps | Fourth Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	588,800		588,800
Derivative, Swap Type, Fixed Price | $ / Boe	71.29		71.29
Swap [Member] | Oil Derivative Swaps | First Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	315,000		315,000
Derivative, Swap Type, Fixed Price | $ / Boe	69.40		69.40
Swap [Member] | Oil Derivative Swaps | Second Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	318,500		318,500
Derivative, Swap Type, Fixed Price | $ / Boe	69.40		69.40
Swap [Member] | Oil Derivative Swaps | Third Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	322,000		322,000
Derivative, Swap Type, Fixed Price | $ / Boe	69.40		69.40
Swap [Member] | Oil Derivative Swaps | Fourth Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	230,000		230,000
Derivative, Swap Type, Fixed Price | $ / Boe	69.42		69.42
Swap [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	5,727,000		5,727,000
Derivative, Swap Type, Fixed Price	4.20		4.20
Swap [Member] | Natural Gas Derivative Swaps | First Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,686,000		7,686,000
Derivative, Swap Type, Fixed Price	4.12		4.12
Swap [Member] | Natural Gas Derivative Swaps | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,350,000		12,350,000
Derivative, Swap Type, Fixed Price	3.67		3.67
Swap [Member] | Natural Gas Derivative Swaps | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,420,000		12,420,000
Derivative, Swap Type, Fixed Price	3.78		3.78
Swap [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,420,000		12,420,000
Derivative, Swap Type, Fixed Price	4.12		4.12
Swap [Member] | Natural Gas Derivative Swaps | First Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	9,450,000		9,450,000
Derivative, Swap Type, Fixed Price	4.25		4.25
Swap [Member] | Natural Gas Derivative Swaps | Second Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	9,555,000		9,555,000
Derivative, Swap Type, Fixed Price	3.71		3.71
Swap [Member] | Natural Gas Derivative Swaps | Third Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	11,960,000		11,960,000
Derivative, Swap Type, Fixed Price	3.83		3.83
Swap [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	8,740,000		8,740,000
Derivative, Swap Type, Fixed Price	4.17		4.17
Swap [Member] | Natural Gas Derivative Swaps | First Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	9,680,000		9,680,000
Derivative, Swap Type, Fixed Price	4.48		4.48
Swap [Member] | Natural Gas Derivative Swaps | Second Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	9,555,000		9,555,000
Derivative, Swap Type, Fixed Price	3.56		3.56
Swap [Member] | Natural Gas Derivative Swaps | Third Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	9,660,000		9,660,000
Derivative, Swap Type, Fixed Price	3.74		3.74
Swap [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	9,200,000		9,200,000
Derivative, Swap Type, Fixed Price	4.13		4.13
Swap [Member] | NGL Derivative | Fourth Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	345,000		345,000
Derivative, Swap Type, Fixed Price	32.87		32.87
Swap [Member] | NGL Derivative | First Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	400,400		400,400
Derivative, Swap Type, Fixed Price	26.30		26.30
Swap [Member] | NGL Derivative | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	400,400		400,400
Derivative, Swap Type, Fixed Price	26.30		26.30
Swap [Member] | NGL Derivative | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	404,800		404,800
Derivative, Swap Type, Fixed Price	26.30		26.30
Swap [Member] | NGL Derivative | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	404,800		404,800
Derivative, Swap Type, Fixed Price	26.30		26.30
Swap [Member] | NGL Derivative | First Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	270,000		270,000
Derivative, Swap Type, Fixed Price	24.17		24.17
Swap [Member] | NGL Derivative | Second Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	273,000		273,000
Derivative, Swap Type, Fixed Price	24.17		24.17
Swap [Member] | NGL Derivative | Third Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	276,000		276,000
Derivative, Swap Type, Fixed Price	24.17		24.17
Swap [Member] | NGL Derivative | Fourth Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	276,000		276,000
Collar Contracts [Member] | Oil Derivative Swaps | Fourth Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	302,242		302,242
Derivative, Average Floor Price	65.89		65.89
Derivative, Average Cap Price	74.54		74.54
Collar Contracts [Member] | Oil Derivative Swaps | First Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	319,700		319,700
Derivative, Average Floor Price	58.95		58.95
Derivative, Average Cap Price	71.74		71.74
Collar Contracts [Member] | Oil Derivative Swaps | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	215,000		215,000
Derivative, Average Floor Price	61.08		61.08
Derivative, Average Cap Price	73.57		73.57
Collar Contracts [Member] | Oil Derivative Swaps | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	184,000		184,000
Derivative, Average Floor Price	63.50		63.50
Derivative, Average Cap Price	75.53		75.53
Collar Contracts [Member] | Oil Derivative Swaps | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	184,000		184,000
Derivative, Average Floor Price	63.00		63.00
Derivative, Average Cap Price	75.35		75.35
Collar Contracts [Member] | Oil Derivative Swaps | First Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	238,500		238,500
Derivative, Average Floor Price	64.00		64.00
Derivative, Average Cap Price	74.62		74.62
Collar Contracts [Member] | Oil Derivative Swaps | Second Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	227,500		227,500
Derivative, Average Floor Price	60.80		60.80
Derivative, Average Cap Price	72.22		72.22
Collar Contracts [Member] | Oil Derivative Swaps | First Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	90,000		90,000
Derivative, Average Floor Price	64.00		64.00
Derivative, Average Cap Price	71.50		71.50
Collar Contracts [Member] | Oil Derivative Swaps | Second Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	91,000		91,000
Derivative, Average Floor Price	64.00		64.00
Derivative, Average Cap Price	71.50		71.50
Collar Contracts [Member] | Oil Derivative Swaps | Third Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	92,000		92,000
Derivative, Average Floor Price	64.00		64.00
Derivative, Average Cap Price	71.50		71.50
Collar Contracts [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,445,000		12,445,000
Derivative, Average Floor Price	3.87		3.87
Derivative, Average Cap Price	4.80		4.80
Collar Contracts [Member] | Natural Gas Derivative Swaps | First Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	9,661,000		9,661,000
Derivative, Average Floor Price	3.94		3.94
Derivative, Average Cap Price	5.83		5.83
Collar Contracts [Member] | Natural Gas Derivative Swaps | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	4,643,000		4,643,000
Derivative, Average Floor Price	3.64		3.64
Derivative, Average Cap Price	4.28		4.28
Collar Contracts [Member] | Natural Gas Derivative Swaps | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	3,878,000		3,878,000
Derivative, Average Floor Price	3.77		3.77
Derivative, Average Cap Price	4.76		4.76
Collar Contracts [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	3,865,000		3,865,000
Derivative, Average Floor Price	4.01		4.01
Derivative, Average Cap Price	5.34		5.34
Collar Contracts [Member] | Natural Gas Derivative Swaps | First Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	5,130,000		5,130,000
Derivative, Average Floor Price	4.00		4.00
Derivative, Average Cap Price	5.32		5.32
Collar Contracts [Member] | Natural Gas Derivative Swaps | Second Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	4,914,000		4,914,000
Derivative, Average Floor Price	3.25		3.25
Derivative, Average Cap Price	3.98		3.98
Collar Contracts [Member] | Natural Gas Derivative Swaps | Third Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	920,000		920,000
Derivative, Average Floor Price	3.50		3.50
Derivative, Average Cap Price	3.99		3.99
Collar Contracts [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	920,000		920,000
Derivative, Average Floor Price	3.75		3.75
Derivative, Average Cap Price	4.65		4.65
3-Way Collar | Oil Derivative Swaps | Fourth Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	8,970		8,970
Derivative, Average Sub Floor Price	43.08		43.08
Derivative, Average Floor Price	53.38		53.38
Derivative, Average Cap Price	63.35		63.35
3-Way Collar | Oil Derivative Swaps | First Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	8,247		8,247
Derivative, Average Sub Floor Price	45.00		45.00
Derivative, Average Floor Price	57.50		57.50
Derivative, Average Cap Price	67.85		67.85
3-Way Collar | Oil Derivative Swaps | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,757		7,757
Derivative, Average Sub Floor Price	45.00		45.00
Derivative, Average Floor Price	57.50		57.50
Derivative, Average Cap Price	67.85		67.85
3-Way Collar | Natural Gas Derivative Swaps | Fourth Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	219,200		219,200
Derivative, Average Sub Floor Price	2.00		2.00
Derivative, Average Floor Price	2.50		2.50
Derivative, Average Cap Price	2.94		2.94
3-Way Collar | Natural Gas Derivative Swaps | First Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	198,000		198,000
Derivative, Average Sub Floor Price	2.00		2.00
Derivative, Average Floor Price	2.50		2.50
Derivative, Average Cap Price	3.37		3.37
3-Way Collar | Natural Gas Derivative Swaps | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	188,000		188,000
Derivative, Average Sub Floor Price	2.00		2.00
Derivative, Average Floor Price	2.50		2.50
Derivative, Average Cap Price	3.37		3.37
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	13,800,000		13,800,000
Derivative, Swap Type, Fixed Price	(0.23)		(0.23)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | First Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	15,470,000		15,470,000
Derivative, Swap Type, Fixed Price	(0.02)		(0.02)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	15,470,000		15,470,000
Derivative, Swap Type, Fixed Price	(0.29)		(0.29)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	15,640,000		15,640,000
Derivative, Swap Type, Fixed Price	(0.26)		(0.26)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	15,640,000		15,640,000
Derivative, Swap Type, Fixed Price	(0.28)		(0.28)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | First Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	5,400,000		5,400,000
Derivative, Swap Type, Fixed Price	(0.09)		(0.09)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Second Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	5,460,000		5,460,000
Derivative, Swap Type, Fixed Price	(0.26)		(0.26)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Third Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	5,520,000		5,520,000
Derivative, Swap Type, Fixed Price	(0.23)		(0.23)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	5,520,000		5,520,000
Derivative, Swap Type, Fixed Price	(0.25)		(0.25)
Basis Swap [Member] | Oil Basis Derivative | Fourth Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	122,000		122,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.80		0.80
Basis Swap [Member] | Oil Basis Derivative | First Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	364,000		364,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.47		1.47
Basis Swap [Member] | Oil Basis Derivative | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	364,000		364,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.47		1.47
Basis Swap [Member] | Oil Basis Derivative | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000		368,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.47		1.47
Basis Swap [Member] | Oil Basis Derivative | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000		368,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.47		1.47
Basis Swap [Member] | Oil Basis Derivative | First Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	270,000		270,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75		1.75
Basis Swap [Member] | Oil Basis Derivative | Second Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	273,000		273,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75		1.75
Basis Swap [Member] | Oil Basis Derivative | Third Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	276,000		276,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75		1.75
Basis Swap [Member] | Oil Basis Derivative | Fourth Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	276,000		276,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75		1.75
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Fourth Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	122,000		122,000
Derivative, Swap Type, Fixed Price | $ / Boe	2.44		2.44
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | First Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	364,000		364,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.69		0.69
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	364,000		364,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.69		0.69
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000		368,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.69		0.69
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000		368,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.69		0.69
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | First Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	270,000		270,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.40		0.40
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Second Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	273,000		273,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.40		0.40
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Third Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	276,000		276,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.40		0.40
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Fourth Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	276,000		276,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.40		0.40

XML

Fair Value Measurements (Details) - Fair Value, Recurring [Member] - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 53,032	$ 25,960
Derivative Liability	5,346	28,579
Natural Gas Basis Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	5,395	26,023
Derivative Liability	5,415	409
Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	418	14,604
Derivative Liability	41,908	19,442
2022 WTI Contingency Payout Fair Value		2,135
2021 WTI Contingency Payout	2,459	1,453
Oil Basis Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	254
Derivative Liability	858
NGL Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	5,270	10,134
Derivative Liability	785	104
Fair Value, Inputs, Level 1 [Member] | Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Natural Gas Basis Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
2022 WTI Contingency Payout Fair Value		0
2021 WTI Contingency Payout	0	0
Fair Value, Inputs, Level 1 [Member] | Oil Basis Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0
Derivative Liability	0
Fair Value, Inputs, Level 1 [Member] | NGL Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 2 [Member] | Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	53,032	25,960
Derivative Liability	5,346	28,579
Fair Value, Inputs, Level 2 [Member] | Natural Gas Basis Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	5,395	26,023
Derivative Liability	5,415	409
Fair Value, Inputs, Level 2 [Member] | Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	418	14,604
Derivative Liability	41,908	19,442
2022 WTI Contingency Payout Fair Value		2,135
2021 WTI Contingency Payout	2,459	1,453
Fair Value, Inputs, Level 2 [Member] | Oil Basis Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	254
Derivative Liability	858
Fair Value, Inputs, Level 2 [Member] | NGL Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	5,270	10,134
Derivative Liability	785	104
Fair Value, Inputs, Level 3 [Member] | Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Natural Gas Basis Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
2022 WTI Contingency Payout Fair Value		0
2021 WTI Contingency Payout	0	0
Fair Value, Inputs, Level 3 [Member] | Oil Basis Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0
Derivative Liability	0
Fair Value, Inputs, Level 3 [Member] | NGL Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	$ 0	$ 0

XML

Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	$ 11,418		$ 11,418		$ 10,456	$ 6,050
Accretion expense	254	$ 166	718	$ 366	534
Liabilities incurred for new wells and facilities construction			313		3,032
Reduction due to sold wells and facilities					(57)
Reductions due to plugged wells and facilities			(603)		(22)
Revisions in estimates			534		919
Asset retirement obligation - current portion	$ 1,578		$ 1,578		$ 1,284

XML

Commitments and Contingencies (Details)	3 Months Ended
	Jun. 30, 2023 MMBTU
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production	116,000