Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2023 | Jul. 28, 2023 | |
Document and Entity Information [Abstract] | ||
Document Type | 10-Q | |
Document Period End Date | Jun. 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 $0.01 per share | |
Trading Symbol | SBOW | |
Security Exchange Name | NYSE | |
Entity Filer Category | Accelerated Filer | |
Document Quarterly Report | true | |
Document Transition Report | false | |
Entity Emerging Growth Company | false | |
Entity Small Business | false | |
Entity Shell Company | false | |
Entity Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Central Index Key | 0000351817 | |
Current Fiscal Year End Date | --12-31 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2023 | |
Document Fiscal Period Focus | Q2 | |
Entity Common Stock, Shares Outstanding | 22,617,842 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets - USD ($) $ in Thousands | Jun. 30, 2023 | Dec. 31, 2022 |
Current Assets: | ||
Cash and cash equivalents | $ 1,102 | $ 792 |
Accounts receivable, net | 64,587 | 89,714 |
Fair value of commodity derivatives | 72,590 | 52,549 |
Other current assets | 3,935 | 2,671 |
Total Current Assets | 142,214 | 145,726 |
Property and Equipment: | ||
Property and Equipment, full cost method | 2,756,694 | 2,529,223 |
Less - Accumulated depreciation, depletion, and amortization | (1,097,935) | (1,004,044) |
Net Furniture, Fixtures and other equipment | 1,658,759 | 1,525,179 |
Capitalized Costs, unproved property balance | 26,344 | 16,272 |
Right of Use Assets | 9,435 | 12,077 |
Fair value of long-term commodity derivatives | 21,903 | 24,172 |
Other Long-Term Assets | 8,159 | 9,208 |
Total Assets | 1,840,470 | 1,716,362 |
Current Liabilities: | ||
Accounts payable and accrued liabilities | 60,143 | 60,200 |
Fair value of commodity derivatives | 9,711 | 40,796 |
Accrued capital costs | 44,047 | 56,465 |
Accrued interest | 2,755 | 2,665 |
Current lease liability | 5,966 | 8,553 |
Undistributed oil and gas revenues | 18,463 | 27,160 |
Total Current Liabilities | 141,085 | 195,839 |
Long-Term Debt | 722,904 | 688,531 |
Non-current Lease Liability | 3,571 | 3,775 |
Deferred Tax Liabilities | 50,073 | 16,141 |
Asset Retirement Obligation | 9,619 | 9,171 |
Fair value of long-term commodity derivatives | 2,032 | 7,738 |
Other Long-Term Liabilities | 541 | 3,588 |
Stockholders' Equity: | ||
Preferred Stock, Value, Outstanding | 0 | 0 |
Common stock, $0.01 par value | 231 | 227 |
Additional paid-in capital | 578,817 | 576,118 |
Treasury stock held, at cost | (10,600) | (7,534) |
Retained earnings (Accumulated deficit) | 342,197 | 222,768 |
Total Stockholders' Equity (Deficit) | 910,645 | 791,579 |
Total Liabilities and Stockholders' Equity | $ 1,840,470 | $ 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 | 23,102,787 | 22,663,135 |
Common Stock, Shares, Outstanding | 22,617,842 | 22,309,740 |
Treasury Stock, Shares | 484,945 | 353,395 |
Condensed Consolidated Balanc_2
Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares | Jun. 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 |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | |
Income Statement [Abstract] | ||||
Oil and gas sales | $ 126,400 | $ 182,605 | $ 266,354 | $ 312,261 |
Costs and Expenses [Abstract] | ||||
General and administrative, net | 5,318 | 5,710 | 12,982 | 10,497 |
Depreciation, depletion, and amortization | 49,853 | 26,441 | 93,850 | 47,595 |
Accretion of asset retirement obligation | 240 | 101 | 464 | 200 |
Lease operating costs | 19,180 | 10,270 | 39,740 | 19,395 |
Workovers | 811 | 2 | 1,590 | 649 |
Transportation and gas processing | 11,771 | 6,769 | 23,292 | 13,121 |
Severance and other taxes | 8,771 | 9,838 | 18,156 | 17,602 |
Operating Expenses | 95,944 | 59,131 | 190,074 | 109,059 |
Operating Income (Loss) | 30,456 | 123,474 | 76,280 | 203,202 |
Net gain (loss) on commodity derivatives | 19,993 | (22,406) | 112,243 | (162,648) |
Interest expense, net | (18,190) | (7,902) | (34,935) | (14,459) |
Other Nonoperating Income (Expense) | 29 | (10) | 4 | 52 |
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest | 32,288 | 93,156 | 153,592 | 26,147 |
Provision (Benefit) for Income Taxes | 7,351 | 4,366 | 34,163 | 1,612 |
Net Income (Loss) | $ 24,937 | $ 88,790 | $ 119,429 | $ 24,535 |
Per Share Amounts- | ||||
Earnings Per Share, Basic | $ 1.10 | $ 5.05 | $ 5.30 | $ 1.43 |
Earnings Per Share, Diluted | $ 1.10 | $ 4.95 | $ 5.27 | $ 1.40 |
Weighted Average Shares Outstanding - Basic | 22,615 | 17,581 | 22,527 | 17,146 |
Weighted Average Shares Outstanding - Diluted | 22,674 | 17,938 | 22,654 | 17,506 |
Condensed Consolidated Statem_2
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) | 24,535 | ||||
Ending Balance at Jun. 30, 2022 | $ 473,257 | 227 | 573,259 | (7,095) | (93,134) |
Purchase of treasury stock (shares) | 112,497 | ||||
Treasury Shares Pursuant to Purchase Price Adjustment (shares) | 41,191 | ||||
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 | ||||
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) | 119,429 | ||||
Ending Balance at Jun. 30, 2023 | $ 910,645 | 231 | 578,817 | (10,600) | 342,197 |
Purchase of treasury stock (shares) | 131,550 | ||||
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 |
Condensed Consolidated Statem_3
Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | |
Cash Flows from Operating Activities: | ||||||
Net Income (Loss) | $ 24,937 | $ 88,790 | $ 119,429 | $ 24,535 | ||
Adjustments to reconcile net income to net cash provided by operating activities - | ||||||
Depreciation, depletion, and amortization | 49,853 | 26,441 | 93,850 | 47,595 | ||
Accretion of asset retirement obligation | 240 | 101 | 464 | 200 | $ 534 | |
Deferred income taxes | 33,932 | 1,205 | ||||
Stock-based compensation expenses | 2,575 | 2,714 | ||||
Loss (gain) on derivatives | (112,243) | 162,648 | ||||
Cash settlements on derivatives | 47,481 | (90,603) | ||||
Settlements of asset retirement obligations | (411) | (54) | ||||
Write off of Debt Issuance Cost | 0 | 350 | ||||
Other Noncash Income (Expense) | 1,312 | 1,668 | ||||
(Increase) decrease in accounts receivable and other current assets | 26,297 | (34,422) | ||||
Increase (decrease) in accounts payable and accrued liabilities | (21,916) | (1,254) | ||||
Increase (Decrease) in Income Taxes Payable | 229 | 304 | ||||
Increase (decrease) in accrued interest | 89 | 723 | ||||
Net Cash Provided by (Used in) Operating Activities | 191,088 | 115,609 | ||||
Cash Flows from Investing Activities: | ||||||
Additions to property and equipment | (221,464) | (93,746) | ||||
Acquisition of oil and gas properties | (248) | (272,225) | ||||
Proceeds from the sale of property and equipment | 0 | 2,532 | 4,300 | |||
Payments on property sale obligations | 0 | (750) | ||||
Net Cash Provided by (Used in) Investing Activities | (221,712) | (364,189) | ||||
Cash Flows from Financing Activities: | ||||||
Proceeds from bank borrowings | 210,000 | 482,000 | ||||
Payments of bank borrowings | (176,000) | (215,000) | ||||
Net proceeds from stock options exercised | 0 | 39 | ||||
Purchase of treasury shares | (3,066) | (2,965) | ||||
Payments of Debt Issuance Costs | 0 | (7,207) | ||||
Net Cash Provided by (Used in) Financing Activities | 30,934 | 256,867 | ||||
Net increase (decrease) in Cash, Cash Equivalents and Restricted Cash | 310 | 8,287 | ||||
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | $ 1,102 | $ 9,408 | 1,102 | 9,408 | $ 792 | $ 1,121 |
Supplemental Disclosures of Cash Flows Information: | ||||||
Cash paid during period for interest, net of amounts capitalized | 33,340 | 12,228 | ||||
Changes in capital accounts payable and capital accruals | 3,485 | 20,882 | ||||
Non-cash equity consideration for acquisitions | $ 0 | $ (156,259) |
General Information
General Information | 6 Months Ended |
Jun. 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, the Company possesses a significant understanding of the reservoirs in the region. We leverage this competitive understanding to assemble high quality drilling inventory while continuously enhancing our operations to maximize returns on capital invested. The condensed consolidated financial statements included herein are unaudited and certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2022. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 6 Months Ended |
Jun. 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. Subsequent Events . We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements. Through July 31, 2023, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after June 30, 2023: Oil Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2024 Contracts 1Q24 273,000 $ 75.11 2Q24 273,000 $ 75.11 3Q24 276,000 $ 75.11 4Q24 276,000 $ 75.11 2025 Contracts 1Q25 270,000 $ 70.60 2Q25 273,000 $ 70.60 3Q25 276,000 $ 70.60 4Q25 276,000 $ 70.60 Collar Contracts 2023 Contracts 4Q23 92,000 $ 70.00 $ 80.40 2024 Contracts 1Q24 91,000 $ 65.00 $ 79.10 2Q24 91,000 $ 65.00 $ 79.10 3Q24 92,000 $ 65.00 $ 79.10 4Q24 92,000 $ 65.00 $ 79.10 2025 Contracts 2Q25 136,500 $ 61.33 $ 73.97 2026 Contracts 1Q26 90,000 $ 64.00 $ 71.50 2Q26 91,000 $ 64.00 $ 71.50 3Q26 92,000 $ 64.00 $ 71.50 Natural Gas Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2025 Contracts 3Q25 920,000 $ 3.75 4Q25 920,000 $ 4.16 Collar Contracts 2024 Contracts 1Q24 1,820,000 $ 3.25 $ 4.29 2Q24 1,820,000 $ 3.00 $ 3.31 3Q24 920,000 $ 3.00 $ 3.65 4Q24 920,000 $ 3.25 $ 4.40 2025 Contracts 2Q25 4,004,000 $ 3.25 $ 3.97 3Q25 920,000 $ 3.25 $ 3.99 4Q25 920,000 $ 3.75 $ 4.65 Natural Gas Basis Derivative Swaps Total Volumes Weighted-Average Price 2024 Contracts 1Q24 910,000 $ 0.075 2Q24 910,000 $ (0.261) 3Q24 920,000 $ (0.234) 4Q24 920,000 $ (0.276) 2025 Contracts 1Q25 900,000 $ 0.023 2Q25 910,000 $ (0.315) 3Q25 920,000 $ (0.240) 4Q25 920,000 $ (0.274) There were no other material subsequent events requiring additional disclosure in these condensed consolidated financial statements. Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include: • the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom, and the Ceiling Test impairment calculation, • estimates related to the collectability of accounts receivable and the creditworthiness of our customers, • estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf, • estimates of future costs to develop and produce reserves, • accruals related to oil and gas sales, capital expenditures and lease operating expenses (“LOE”), • estimates in the calculation of share-based compensation expense, • estimates of our ownership in properties prior to final division of interest determination, • the estimated future cost and timing of asset retirement obligations, • estimates made in our income tax calculations, including the valuation of our deferred tax assets, • estimates in the calculation of the fair value of commodity derivative assets and liabilities, • estimates in the assessment of current litigation claims against the Company, • estimates used in the assessment of business combinations and asset purchases, • estimates in amounts due with respect to open state regulatory audits, and • estimates on future lease obligations. While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, reallocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known. We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated. Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For both the three months ended June 30, 2023 and 2022, such internal costs capitalized totaled $1.2 million. For the six months ended June 30, 2023 and 2022, such internal costs capitalized totaled $2.6 million and $2.2 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. There was no capitalized interest on our unproved properties for both the three months ended June 30, 2023 and 2022 and the six months ended June 30, 2023 and 2022. The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): June 30, 2023 December 31, 2022 Property and Equipment Proved oil and gas properties $ 2,724,110 $ 2,506,853 Unproved oil and gas properties 26,344 16,272 Furniture, fixtures and other equipment 6,240 6,098 Less – Accumulated depreciation, depletion, amortization & impairment (1,097,935) (1,004,044) Property and Equipment, Net $ 1,658,759 $ 1,525,179 No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred. We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and natural gas properties, including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties, by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved oil and gas properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved oil and gas properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, economic conditions, capital availability and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized. Full-Cost Ceiling Test . At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10% and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”). The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. There was no ceiling test write-down for either of the three months ended June 30, 2023 and 2022 or the six months ended June 30, 2023 and 2022. If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur again in the future. We cannot control and cannot predict what future prices for oil and natural gas will be; therefore, we cannot estimate the amount of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices. However, it is reasonably possible that we will record additional Ceiling Test write-downs in future periods. Accounts Receivable, Net. We assess the collectability of accounts receivable based on a broad range of reasonable and forward-looking information including historical losses, current economic conditions, future forecasts and contractual terms. The Company's credit losses based on these assessments are considered immaterial. At both June 30, 2023 and December 31, 2022, we had an allowance of less than $0.1 million. The allowance has been deducted from the total “Accounts receivable, net” balance on the accompanying condensed consolidated balance sheets. At June 30, 2023, our “Accounts receivable, net” balance included $45.2 million for oil and gas sales, $1.4 million due from joint interest owners, $7.6 million for severance tax credit receivables and $10.4 million for other receivables. At December 31, 2022, our “Accounts receivable, net” balance included $70.9 million for oil and gas sales, $5.6 million due from joint interest owners, $4.3 million for severance tax credit receivables and $8.9 million for other receivables. Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the six months ended June 30, 2023 and 2022 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $2.9 million and $1.7 million for the three months ended June 30, 2023 and 2022, respectively, and $5.5 million and $3.4 million for the six months ended June 30, 2023 and 2022, respectively. Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. The Company's effective tax rate was approximately 22% and 4% for the three months ended June 30, 2023 and 2022, respectively, and 22% and 6% for the six months ended June 30, 2023 and 2022, respectively. The Company recorded an income tax provision of $7.4 million and $34.2 million for the three and six months ended June 30, 2023, respectively, and an income tax provision of $4.4 million and $1.6 million for the three and six months ended June 30, 2022, respectively. The tax impact for both periods was a product of the overall forecasted annual effective tax rate applied to the year to date income. Section 382 of the Internal Revenue Code (“Section 382”) imposes limitations on a corporation’s ability to utilize its net operating losses (“NOLs”) if it experiences an ownership change. Generally, an “ownership change” occurs if one or more shareholders, each of whom is deemed to own five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50 percent over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382. We believe we had an ownership change in August 2022 and, therefore, are subject to an annual limitation on the usage of our NOLs generated prior to the ownership change. However, we do not expect to have any of our NOLs expire before becoming available to be utilized by the Company. Management will continue to monitor the potential impact of Section 382 with respect to our NOLs. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At June 30, 2023 and December 31, 2022, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. Revenue Recognition . Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. Natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers. The following table provides information regarding our oil and gas sales, by product, reported on the Condensed Consolidated Statements of Operations for the three months ended June 30, 2023 and 2022 and the six months ended June 30, 2023 and 2022 (in thousands): Three Months Ended June 30, 2023 Three Months Ended June 30, 2022 Six Months Ended June 30, 2023 Six Months Ended June 30, 2022 Oil, natural gas and NGLs sales: Oil $ 80,151 $ 44,014 $ 154,807 $ 83,755 Natural gas 33,805 123,296 86,727 200,668 NGLs 12,443 15,295 24,820 27,838 Total $ 126,400 $ 182,605 $ 266,354 $ 312,261 Accounts Payable and Accrued Liabilities . The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): June 30, 2023 December 31, 2022 Trade accounts payable $ 32,210 $ 23,660 Accrued operating expenses 10,565 10,572 Accrued compensation costs 2,328 4,814 Asset retirement obligations – current portion 1,551 1,284 Accrued non-income based taxes 8,957 4,849 Accrued corporate and legal fees 260 388 WTI contingency payouts - current portion 975 1,600 Payable for settled derivatives 1,016 6,026 Other payables 2,281 7,007 Total accounts payable and accrued liabilities $ 60,143 $ 60,200 Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted. The Company maintains cash and cash equivalent balances with major financial institutions, which at times exceed federally insured limits. The Company monitors the financial condition of the financial institutions and has experienced no losses associated with these accounts. Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock, held at cost” on the accompanying condensed consolidated balance sheets. For the six months ended June 30, 2023, we purchased 131,550 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. For the six months ended June 30, 2022, we purchased 112,497 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares and received 41,191 shares in conjunction with our post-closing settlement for a previously disclosed acquisition. New Accounting Pronouncements . In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Credit Losses - Measurement of Credit Losses on Financial Instruments. The standard changes how entities will measure credit losses for most financial assets, including accounts and notes receivables. The new standard replaces the existing incurred loss impairment methodology with a methodology that requires consideration of a broader range of reasonable and supportable forward-looking information to estimate all expected credit losses. The updated guidance is effective for the Company for annual and quarterly reporting periods beginning after December 15, 2022, and the Company adopted the guidance on January 1, 2023. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements or disclosures. In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021. The guidance provides and clarifies optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The amendments within these ASUs were in effect beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2024. As of June 30, 2023, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. In August 2020, the FASB issued ASU No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The guidance simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. Additionally, the amendment requires the application of the if-converted method to calculate the impact of convertible instruments on diluted earnings per share (EPS). The guidance is effective for the Company for fiscal years beginning after December 15, 2022, and the Company adopted the guidance on January 1, 2023. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements or disclosures. |
Leases Leases (Notes)
Leases Leases (Notes) | 6 Months Ended |
Jun. 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 Consolidated Balance Sheets. We have elected to not account for lease and non-lease components separately. The Company has contractual agreements for its corporate office lease, vehicle fleet, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of June 30, 2023, all of the Company’s leases were operating leases. The initial asset and liability balances are recorded at the present value of the payment obligations over the lease term. If lease terms include options to extend the lease and it is reasonably certain that the Company will exercise that option, the lease term used for capitalization includes the expected renewal periods. Most leases do not provide an implicit interest rate. Unless the lease contract contains an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease inception to compute the fair value of the lease payments. The ROU asset balance and current and non-current lease liabilities are reported separately on the accompanying Condensed Consolidated Balance Sheets. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. The Company recognizes lease expense on a straight-line basis over the lease term. As of June 30, 2023, the Company's future cash payment obligation for its operating lease liabilities are as follows (in thousands): As of June 30, 2023 2023 (Remaining) $ 4,730 2024 2,607 2025 1,422 2026 955 2027 61 Thereafter 472 Total undiscounted lease payments 10,247 Present value adjustment (710) Net operating lease liabilities $ 9,537 |
Share-Based Compensation
Share-Based Compensation | 6 Months Ended |
Jun. 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 $1.7 million for the three months ended June 30, 2023 and 2022, respectively, and $2.6 million and $2.7 million for the six months ended June 30, 2023 and 2022, respectively. Capitalized share-based compensation was less than $0.1 million for both the three months ended June 30, 2023 and 2022, and $0.1 million for both the six months ended June 30, 2023 and 2022. We view stock option awards and RSUs with graded vesting as single awards with an expected life equal to the average expected life of component awards, and we amortize the awards on a straight-line basis over the life of the awards. The Company accounts for forfeitures in compensation cost when they occur. Stock Option Awards The compensation cost related to stock option awards is based on the grant date fair value and is typically expensed over the vesting period (generally one five At June 30, 2023, we had no unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the six months ended June 30, 2023: Shares Wtd. Avg. Exer. Price Options outstanding, beginning of period 196,162 $ 26.46 Options granted — $ — Options exercised — $ — Options outstanding, end of period 196,162 $ 26.46 Options exercisable, end of period 196,162 $ 26.46 Our outstanding stock option awards had $0.5 million measurable aggregate intrinsic value at June 30, 2023. At June 30, 2023, the weighted-average remaining contract life of stock option awards outstanding was 3.9 years and exercisable was 3.9 years. The total intrinsic value of stock option awards exercisable was $0.5 million as of June 30, 2023. 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 As of June 30, 2023, we had $5.8 million unrecognized compensation expense related to our RSUs which is expected to be recognized over a weighted-average period of 2.2 years. The following table provides information regarding RSU activity for the six months ended June 30, 2023: RSUs Wtd. Avg. Grant Price RSUs outstanding, beginning of period 227,114 $ 21.18 RSUs granted 192,014 $ 23.66 RSUs forfeited (1,424) $ 25.44 RSUs vested (136,242) $ 17.55 RSUs outstanding, end of period 281,462 $ 24.61 Performance-Based Stock Units On May 21, 2019, the Company granted 99,500 PSUs for which the number of shares earned was based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2019 to December 31, 2021. The awards contained market conditions which allowed a payout ranging between 0% payout and 200% of the target payout. The fair value as of the grant date was $18.86 per unit or 112.9% of stock price. The awards had a cliff-vesting period of three 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 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 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 As of June 30, 2023, we had $5.6 million unrecognized compensation expense related to our PSUs based on the assumption of 100% target payout. The remaining weighted-average performance period is 2.1 years. The following table provides information regarding performance-based stock unit activity for the six months ended June 30, 2023: PSUs Wtd. Avg. Grant Price Performance based stock units outstanding, beginning of period 283,500 $ 23.18 Performance based stock units granted 120,749 $ 31.18 Performance based stock units incremental shares granted 142,021 $ 13.13 Performance based stock units vested (303,410) $ 13.13 Performance based stock units outstanding, end of period 242,860 $ 33.84 |
Earnings Per Share
Earnings Per Share | 6 Months Ended |
Jun. 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 six months ended June 30, 2023 and 2022 are discussed below. The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts): Three Months Ended June 30, 2023 Three Months Ended June 30, 2022 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 24,937 22,615 $ 1.10 $ 88,790 17,581 $ 5.05 Dilutive Securities: Performance Based Stock Unit Awards 19 171 RSU Awards 33 128 Stock Option Awards 7 58 Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 24,937 22,674 $ 1.10 $ 88,790 17,938 $ 4.95 Six Months Ended June 30, 2023 Six Months Ended June 30, 2022 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 119,429 22,527 $ 5.30 $ 24,535 17,146 $ 1.43 Dilutive Securities: Performance Based Stock Unit Awards 58 142 RSU Awards 62 188 Stock Option Awards 7 30 Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 119,429 22,654 $ 5.27 $ 24,535 17,506 $ 1.40 There were 0.1 million stock options to purchase shares which were not included in the computation of Diluted EPS for the three months ended June 30, 2023 because they were antidilutive, while there were no antidilutive stock options for the three months ended June 30, 2022. Additionally, there were 0.1 million and less than 0.1 million stock options to purchase shares which were not included in the computation of Diluted EPS for the six months ended June 30, 2023 and 2022, respectively, because they were antidilutive. There were less than 0.1 million shares of RSUs that were not included in the computation of Diluted EPS for the three months ended June 30, 2023 and 2022 because they were antidilutive while less than 0.1 million shares of RSUs were not included in the computation of Diluted EPS for the six months ended June 30, 2023 and 2022 because they were antidilutive. There were 0.1 million shares of PSUs excluded from Diluted EPS for the three months ended June 30, 2023 because they were antidilutive while there were no antidilutive shares of PSUs that could be converted to common shares for the three months ended June 30, 2022. Additionally, there were 0.1 million shares of PSUs that could be converted to common shares which were not included in the computation of Diluted EPS for the six months ended June 30, 2023 because they were antidilutive while there were no antidilutive shares of PSUs that could be converted to common shares for the six months ended June 30, 2022. |
Long-Term Debt
Long-Term Debt | 6 Months Ended |
Jun. 30, 2023 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | (6) Long-Term Debt The Company's long-term debt consisted of the following (in thousands): June 30, 2023 December 31, 2022 Credit Facility Borrowings due 2026 (1) $ 576,000 $ 542,000 Second Lien Notes due 2026 150,000 150,000 726,000 692,000 Unamortized discount on Second Lien Notes due 2026 (787) (882) Unamortized debt issuance cost on Second Lien Notes due 2026 (2,309) (2,587) Long-Term Debt, net $ 722,904 $ 688,531 (1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “ Other Long-Term Assets ” in our consolidated balance sheet. As of June 30, 2023 and December 31, 2022, we had $7.6 million and $8.7 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings. Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $576.0 million and $542.0 million as of June 30, 2023 and December 31, 2022, respectively. The Company is a party to a First Amended and Restated Senior Secured Revolving Credit Agreement with JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended (such agreement, the “Credit Agreement” and the borrowing facility provided thereby, the “Credit Facility”). The Credit Facility matures October 19, 2026 (or to the extent earlier, the date that is 91 days prior to the scheduled maturity of the Company's Second Lien notes), and provides for a maximum credit amount of $2.0 billion, subject to the current borrowing base of $775.0 million. The borrowing base is regularly redetermined in or about May and November of each calendar year and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders, in their discretion, in accordance with their oil and gas lending criteria at the time of the relevant redetermination. In conjunction with its regularly scheduled semi-annual redeterminations, the Company reaffirmed the borrowing base and elected commitment amount under the Credit Facility at $775.0 million, effective November 22, 2022, and again on March 20, 2023. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to $25.0 million, which reduces the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit. There were no outstanding letters of credit as of June 30, 2023, and no outstanding letters of credit as of December 31, 2022. Maintaining or increasing our borrowing base under our Credit Facility is dependent on many factors, including commodity prices, our hedge positions , changes in our lenders' lending criteria and our ability to raise capital to drill wells to replace produced reserves. Interest under the Credit Facility accrues at the Company’s option either at an Alternate Base Rate plus the applicable margin (“ABR Loans”), the Adjusted Term Secured Overnight Financing Rate (“SOFR”) plus the applicable margin (“Term Benchmark Loans”) or Adjusted Daily Simple SOFR plus the applicable margin (“RFR Loans”). The applicable margin ranges from 1.75% to 2.75% based on borrowing base utilization for ABR Loans and 2.75% to 3.75% based on borrowing base utilization for Term Benchmark Loans and RFR Loans. The Alternate Base Rate and SOFR are defined, and the applicable margins are set forth, in the Credit Agreement. Undrawn amounts under the Credit Facility are subject to a 0.5% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. As of June 30, 2023, the Company's weighted average interest rate on Credit Facility borrowings was 8.48%. The obligations under the Credit Agreement are secured, subject to certain exceptions, by a first priority lien on substantially all assets of the Company and its subsidiary, including a first priority lien on properties attributed with at least 85% of estimated proved reserves of the Company and its subsidiary. The Credit Agreement contains the following financial covenants: • a ratio of total debt to earnings before interest, tax, depreciation and amortization (“EBITDA”), as defined in the Credit Agreement, for the most recently completed four fiscal quarters, not to exceed 3.00 to 1.00 as of the last day of each fiscal quarter; and • a current ratio, as defined in the Credit Agreement, which includes in the numerator available borrowings undrawn under the borrowing base, of not less than 1.00 to 1.00 as of the last day of each fiscal quarter. As of June 30, 2023, the Company was in compliance with all financial covenants under the Credit Agreement. Additionally, the Credit Agreement contains certain representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable. Total interest expense on the Credit Facility, which includes commitment fees and amortization of debt issuance costs, was $13.2 million and $4.4 million for the three months ended June 30, 2023 and 2022, respectively, and $25.2 million and $7.6 million for the six months ended June 30, 2023 and 2022, respectively. The amount of commitment fee amortization included in interest expense, net was $0.2 million and $0.3 million for the three months ended June 30, 2023 and 2022, respectively, and $0.5 million and $0.6 million for the six months ended June 30, 2023 and 2022, respectively. Senior Secured Second Lien Notes . On December 15, 2017, the Company entered into a Note Purchase Agreement for Senior Secured Second Lien Notes (as amended, the “Note Purchase Agreement,” and such second lien facility the “Second Lien”) among the Company as issuer, U.S. Bank National Association as agent and collateral agent, and certain holders that are a party thereto, and issued notes in an initial principal amount of $200.0 million, with a $2.0 million discount, for net proceeds of $198.0 million. Effective November 12, 2021, the Company entered into the Second Amendment to the Note Purchase Agreement, which extended the maturity date from December 15, 2024 to December 15, 2026 subject to paying down the principal amount of the Second Lien from $200.0 million to $150.0 million. The Company made the $50.0 million redemption of the Second Lien notes on November 29, 2021. On June 14, 2023, the Company entered into the Third Amendment to the Note Purchase Agreement to effectuate the replacement of LIBOR with an adjusted term secured overnight financing rate plus a margin of 0.25% (“Term SOFR”). After the Third Amendment, interest under the Second Lien is payable quarterly and accrues, based on the Company's election at the time of the borrowing, either at Term SOFR plus a margin of 7.5% (“Second Lien Term SOFR Loans”) or at an Alternate Base Rate which is based on the greater of (i) the prime rate; (ii) the greater of the federal funds effective rate or overnight bank funding rate, plus 0.5%; or (iii) Term SOFR plus 1% (“Second Lien ABR Loans”) plus a margin of 6.5%. Additionally, to the extent the Company were to default on the Second Lien, this would potentially trigger a cross-default under our Credit Facility. As of June 30, 2023, the Company's interest rate on Second Lien borrowings was 12.75%. The Company has the right, to the extent permitted under the Credit Facility and subject to the terms and conditions of the Second Lien, to optionally prepay the notes at no premium. Additionally, the Second Lien contains customary mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and incurrences of certain debt, subject to, in certain circumstances, reinvestment periods. Management believes the probability of mandatory prepayment due to default is remote. The obligations under the Second Lien are secured, subject to certain exceptions and other permitted liens (including the liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit Facility, and mortgage lien on substantially all assets of the Company and its subsidiary, including a mortgage lien on oil and gas properties attributed with at least 90% of estimated PV-9 (defined below), of proved reserves of the Company and its subsidiary and 90% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions by the administrative agent of the Credit Facility. PV-9 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 9%. The Second Lien contains an Asset Coverage Ratio, which is only tested (i) as a condition to issuance of additional notes and (ii) in connection with certain asset sales in order to determine whether the proceeds of such asset sale must be applied as a prepayment of the notes and includes in the numerator of the PV-10 (defined below), based on forward strip pricing, plus the swap mark-to-market value of the commodity derivative contracts of the Company and its restricted subsidiary and in the denominator the total net indebtedness of the Company and its restricted subsidiary, of not less than 1.25 to 1.0 as of each date of determination (the “Asset Coverage Ratio”). PV-10 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%. The Second Lien also contains a financial covenant measuring the ratio of total net debt-to-EBITDA, as defined in the Note Purchase Agreement, for the most recently completed four fiscal quarters, not to exceed 3.25 to 1.0 as of the last day of each fiscal quarter. As of June 30, 2023, the Company was in compliance with all financial covenants under the Second Lien. The Second Lien contains certain customary representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Second Lien contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Second Lien to be immediately due and payable. As of June 30, 2023, total net amounts recorded for the Second Lien were $146.9 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $5.0 million and $3.5 million for the three months ended June 30, 2023 and 2022, respectively, and $9.8 million and $6.9 million for the six months ended June 30, 2023 and 2022, respectively. Debt Issuance Costs . Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings. During the six months ended June 30, 2022, the Company capitalized $7.2 million for debt issuance costs incurred in connection with the amendments to our Credit Facility. There were no capitalized costs incurred during the six months ended June 30, 2023. |
Acquisitions and Dispositions A
Acquisitions and Dispositions Acquisitions and Dispostions | 6 Months Ended |
Jun. 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 June 30, 2023 and 2022, the Company recorded losses of less than $0.1 million and $0.2 million, respectively, and losses of $0.1 million and $1.5 million, respectively, for the six months ended June 30, 2023 and 2022 related to the 2021 WTI Contingency Payout which are recorded in “Gain (loss) on commodity derivatives, net” on the consolidated statements of operations. We also recorded $1.6 million in earn-out consideration payable to the seller related to the 2022 calendar year in “Accounts payable and accrued liabilities” on the condensed consolidated balance sheet as of December 31, 2022. For further discussion of the fair value related to the Company's contingent consideration, refer to Note 9 of these Notes to Consolidated Financial Statements. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. May 2022 Acquisition On May 10, 2022, the Company closed the acquisition of certain oil and gas assets located in La Salle and McMullen Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date, from SandPoint Operating, LLC, a subsidiary of SandPoint Resources, LLC (collectively, “SandPoint”). After consideration of closing adjustments, total aggregate consideration was approximately $67.5 million, consisting of $27.7 million in cash and 1,300,000 shares of our common stock valued at approximately $39.8 million based on the Company's share price on the closing date. We incurred approximately $0.5 million in transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. The following table represents the allocation of the total cost of the acquisition to the assets acquired and liabilities assumed (in thousands): Total Cost Cash consideration $ 27,709 Equity consideration 39,767 Total Consideration 67,476 Transaction costs 466 Total Cost of Transaction $ 67,942 Allocation of Total Cost Assets Oil and gas properties $ 84,810 Total assets 84,810 Liabilities Accounts payable and accrued liabilities 199 Fair value of commodity derivatives 16,511 Asset retirement obligations 158 Total Liabilities $ 16,868 Net Assets Acquired $ 67,942 June 2022 Acquisition On June 30, 2022, the Company closed the acquisition of certain oil and gas assets located in Atascosa, La Salle, Live Oak and McMullen Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date, from Sundance Energy, Inc., and its affiliated entities Armadillo E&P, Inc. and SEA Eagle Ford, LLC (collectively, “Sundance”). After consideration of closing adjustments, total aggregate consideration was approximately $344.9 million, consisting of $220.9 million in cash, 4,148,472 shares of our common stock valued at approximately $117.7 million based on the Company's share price on the closing date, accrued purchase price adjustments receivable of $1.0 million and contingent consideration with an estimated fair value of $7.4 million. The contingent consideration consists of up to two earn-out payments of $7.5 million each, contingent upon the average monthly settlement price of NYMEX West Texas Intermediate crude oil exceeding $95 per barrel for the period from April 13, 2022 through December 31, 2022 which would trigger a payment of $7.5 million in 2023 and $85 per barrel for 2023 which would trigger a payment of $7.5 million in 2024 (the “2022 WTI Contingency Payout”). The contingent payout for the period of April 13, 2022 through December 31, 2022 did not materialize. During the six months ended June 30, 2023, the Company recorded gains of $1.0 million related to valuation changes in the 2022 WTI Contingency Payout recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. Additionally, as part of our post-close settlement we settled the 2022 WTI Contingency during the second quarter of 2023. As such, we recorded a non-cash gain of $1.1 million during the six months ended June 30, 2023, and we are no longer required to make a contingency payment related to the 2022 WTI Contingency Payout. We incurred approximately $6.8 million in transaction costs during the year ended December 31, 2022 related to the acquisition. 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 $4.3 million. The transactions are subject to further customary post-closing adjustments. There was no gain or loss recognized in connection with the dispositions. |
Price-Risk Management Price-Ris
Price-Risk Management Price-Risk Management (Notes) | 6 Months Ended |
Jun. 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 June 30, 2023 and 2022, the Company recorded gains of $18.9 million and losses of $22.2 million, respectively, on its commodity derivatives. During the six months ended June 30, 2023 and 2022, the Company recorded gains of $110.2 million and losses of $161.2 million, respectively, on its commodity derivatives. During the three months ended June 30, 2023 and 2022, the Company recorded losses of less than $0.1 million and losses of $0.2 million, respectively, related to valuation changes on the 2021 WTI Contingency Payout and 2022 WTI Contingency Payout. During the six months ended June 30, 2023 and 2022, the Company recorded gains of $0.9 million and losses of $1.5 million, respectively, related to valuation changes on the 2021 WTI Contingency Payout and 2022 WTI Contingency Payout. The Company collected cash payments of $47.5 million and made cash payments of $90.6 million for settled derivative contracts during the six months ended June 30, 2023 and 2022, respectively. At June 30, 2023 and December 31, 2022, there was $10.0 million and $6.9 million, respectively, in receivables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts receivable, net” and were subsequently collected in July 2023 and January 2023, respectively. At June 30, 2023 and December 31, 2022, we also had $1.0 million and $6.0 million, respectively, in payables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts payable and accrued liabilities” and were subsequently paid in July 2023 and January 2023, respectively. The fair values of our swap contracts are computed using observable market data whereas our collar contracts are valued using a Black-Scholes pricing model. At June 30, 2023, there was $72.6 million and $21.9 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $9.7 million and $2.0 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2022, there was $52.5 million and $24.2 million in current and long-term unsettled derivative assets, respectively, and $40.8 million and $7.7 million in current and long-term unsettled derivative liabilities, respectively. The Company uses an International Swap and Derivatives Association master agreement for our derivative contracts. This is an industry-standardized contract containing the general conditions of our derivative transactions including provisions relating to netting derivative settlement payments under certain circumstances (such as default). For reporting purposes, the Company has elected to not offset the asset and liability fair value amounts of its derivatives on the accompanying condensed consolidated balance sheet. Under the right of set-off, there was a $82.8 million net fair value asset at June 30, 2023, and a $28.2 million net fair value asset at December 31, 2022. For further discussion related to the fair value of the Company's derivatives, refer to Note 9 of these Notes to Condensed Consolidated Financial Statements. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of June 30, 2023: Oil Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Sub Floor Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2023 Contracts 3Q23 533,980 $ 77.36 4Q23 569,300 $ 78.26 2024 Contracts 1Q24 227,500 $ 80.78 2Q24 254,050 $ 80.24 3Q24 273,620 $ 76.89 4Q24 256,100 $ 75.98 Collar Contracts 2023 Contracts 3Q23 210,847 $ 64.55 $ 72.82 4Q23 210,242 $ 64.09 $ 71.97 2024 Contracts 1Q24 228,700 $ 56.54 $ 68.82 2Q24 124,000 $ 58.21 $ 69.51 3Q24 92,000 $ 62.00 $ 71.95 4Q24 92,000 $ 61.00 $ 71.60 2025 Contracts 1Q25 238,500 $ 64.00 $ 74.62 2Q25 91,000 $ 60.00 $ 69.60 3-Way Collar Contracts 2023 Contracts 3Q23 9,570 $ 43.08 $ 53.41 $ 63.33 4Q23 8,970 $ 43.08 $ 53.38 $ 63.35 2024 Contracts 1Q24 8,247 $ 45.00 $ 57.50 $ 67.85 2Q24 7,757 $ 45.00 $ 57.50 $ 67.85 Natural Gas Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Sub Floor Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2023 Contracts 3Q23 4,816,000 $ 4.57 4Q23 3,887,000 $ 4.71 2024 Contracts 1Q24 2,711,000 $ 5.15 2Q24 7,800,000 $ 3.95 3Q24 7,820,000 $ 4.03 4Q24 7,820,000 $ 4.35 2025 Contracts 1Q25 900,000 $ 5.01 2Q25 910,000 $ 4.12 3Q25 920,000 $ 4.27 4Q25 920,000 $ 4.70 Collar Contracts 2023 Contracts 3Q23 11,896,400 $ 3.43 $ 4.23 4Q23 12,445,000 $ 3.87 $ 4.80 2024 Contracts 1Q24 7,841,000 $ 4.10 $ 6.19 2Q24 2,823,000 $ 4.05 $ 4.91 3Q24 2,958,000 $ 4.00 $ 5.10 4Q24 2,945,000 $ 4.24 $ 5.63 2025 Contracts 1Q25 5,130,000 $ 4.00 $ 5.32 2Q25 910,000 $ 3.25 $ 4.03 3-Way Collar Contracts 2023 Contracts 3Q23 233,100 $ 2.00 $ 2.50 $ 2.95 4Q23 219,200 $ 2.00 $ 2.50 $ 2.94 2024 Contracts 1Q24 198,000 $ 2.00 $ 2.50 $ 3.37 2Q24 188,000 $ 2.00 $ 2.50 $ 3.37 Natural Gas Basis Derivative Swaps Total Volumes Weighted-Average Price 2023 Contracts 3Q23 14,720,000 $ (0.21) 4Q23 13,800,000 $ (0.23) 2024 Contracts 1Q24 11,830,000 $ 0.01 2Q24 11,830,000 $ (0.32) 3Q24 11,960,000 $ (0.27) 4Q24 11,960,000 $ (0.31) 2025 Contracts 1Q25 1,800,000 $ 0.04 2Q25 1,820,000 $ (0.29) 3Q25 1,840,000 $ (0.24) 4Q25 1,840,000 $ (0.29) NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2023 Contracts 3Q23 345,000 $ 32.87 4Q23 345,000 $ 32.87 2024 Contracts 1Q24 127,400 $ 29.39 2Q24 127,400 $ 29.39 3Q24 128,800 $ 29.39 4Q24 128,800 $ 29.39 |
Fair Value Measurements
Fair Value Measurements | 6 Months Ended |
Jun. 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. T he following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of June 30, 2023 and December 31, 2022, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these Notes to Condensed Consolidated Financial Statements. Fair Value Measurements at (in thousands) Total Quoted Prices in Significant Other Significant June 30, 2023 Assets Natural Gas Derivatives $ 59,049 $ — $ 59,049 $ — Natural Gas Basis Derivatives 2,486 — 2,486 — Oil Derivatives 21,229 — 21,229 — NGL Derivatives 11,729 — 11,729 — Liabilities Natural Gas Derivatives 1,076 — 1,076 — Natural Gas Basis Derivatives 4,354 — 4,354 — Oil Derivatives 6,313 — 6,313 — 2021 WTI Contingency Payout 1,515 — 1,515 — December 31, 2022 Assets Natural Gas Derivatives $ 25,960 $ — $ 25,960 $ — Natural Gas Basis Derivatives 26,023 — 26,023 — Oil Derivatives 14,604 — 14,604 — NGL Derivatives 10,134 — 10,134 — Liabilities Natural Gas Derivatives 28,579 — 28,579 — Natural Gas Basis Derivatives 409 — 409 — Oil Derivatives 19,442 — 19,442 — NGL Derivatives 104 — 104 — 2022 WTI Contingency Payout 2,135 — 2,135 — 2021 WTI Contingency Payout 1,453 — 1,453 — Our current and long-term unsettled derivative assets and liabilities in the table above are measured at gross fair value and are shown on the accompanying condensed consolidated balance sheets in “Fair value of commodity derivatives” and “Fair Value of Long-Term Commodity Derivatives,” respectively. |
Asset Retirement Obligations As
Asset Retirement Obligations Asset Retirement Obligations (Notes) | 6 Months Ended |
Jun. 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 six months ended June 30, 2023 (in thousands): Asset Retirement Obligations as of December 31, 2021 $ 6,050 Accretion expense 534 Liabilities incurred for new wells, acquired wells and facilities construction 3,032 Reductions due to sold wells and facilities (57) Reductions due to plugged wells and facilities (22) Revisions in estimates 919 Asset Retirement Obligations as of December 31, 2022 $ 10,456 Accretion expense 464 Liabilities incurred for new wells, acquired wells and facilities construction 280 Reductions due to plugged wells and facilities (412) Revisions in estimates 382 Asset Retirement Obligations as of June 30, 2023 $ 11,170 At June 30, 2023 and December 31, 2022, approximately $1.6 million and $1.3 million of our asset retirement obligations, respectively, were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets. |
Commitments and Contingencies C
Commitments and Contingencies Commitments and Contingencies | 6 Months Ended |
Jun. 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. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 6 Months Ended |
Jun. 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 both the three months ended June 30, 2023 and 2022, such internal costs capitalized totaled $1.2 million. For the six months ended June 30, 2023 and 2022, such internal costs capitalized totaled $2.6 million and $2.2 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. There was no capitalized interest on our unproved properties for both the three months ended June 30, 2023 and 2022 and the six months ended June 30, 2023 and 2022. The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): June 30, 2023 December 31, 2022 Property and Equipment Proved oil and gas properties $ 2,724,110 $ 2,506,853 Unproved oil and gas properties 26,344 16,272 Furniture, fixtures and other equipment 6,240 6,098 Less – Accumulated depreciation, depletion, amortization & impairment (1,097,935) (1,004,044) Property and Equipment, Net $ 1,658,759 $ 1,525,179 No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred. We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and natural gas properties, including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties, by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two |
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”). |
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 both June 30, 2023 and December 31, 2022, we had an allowance of less than $0.1 million. The allowance has been deducted from the total “Accounts receivable, net” balance on the accompanying condensed consolidated balance sheets. |
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 22% and 4% for the three months ended June 30, 2023 and 2022, respectively, and 22% and 6% for the six months ended June 30, 2023 and 2022, respectively. The Company recorded an income tax provision of $7.4 million and $34.2 million for the three and six months ended June 30, 2023, respectively, and an income tax provision of $4.4 million and $1.6 million for the three and six months ended June 30, 2022, respectively. The tax impact for both periods was a product of the overall forecasted annual effective tax rate applied to the year to date income. Section 382 of the Internal Revenue Code (“Section 382”) imposes limitations on a corporation’s ability to utilize its net operating losses (“NOLs”) if it experiences an ownership change. Generally, an “ownership change” occurs if one or more shareholders, each of whom is deemed to own five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50 percent over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382. We believe we had an ownership change in August 2022 and, therefore, are subject to an annual limitation on the usage of our NOLs generated prior to the ownership change. However, we do not expect to have any of our NOLs expire before becoming available to be utilized by the Company. Management will continue to monitor the potential impact of Section 382 with respect to our NOLs. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At June 30, 2023 and December 31, 2022, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. |
Revenue Recognition | 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): June 30, 2023 December 31, 2022 Trade accounts payable $ 32,210 $ 23,660 Accrued operating expenses 10,565 10,572 Accrued compensation costs 2,328 4,814 Asset retirement obligations – current portion 1,551 1,284 Accrued non-income based taxes 8,957 4,849 Accrued corporate and legal fees 260 388 WTI contingency payouts - current portion 975 1,600 Payable for settled derivatives 1,016 6,026 Other payables 2,281 7,007 Total accounts payable and accrued liabilities $ 60,143 $ 60,200 |
Cash and Cash Equivalents, 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. |
Leases Leases (Policies)
Leases Leases (Policies) | 6 Months Ended |
Jun. 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 Consolidated Balance Sheets. We have elected to not account for lease and non-lease components separately. The Company has contractual agreements for its corporate office lease, vehicle fleet, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of June 30, 2023, all of the Company’s leases were operating leases. The initial asset and liability balances are recorded at the present value of the payment obligations over the lease term. If lease terms include options to extend the lease and it is reasonably certain that the Company will exercise that option, the lease term used for capitalization includes the expected renewal periods. Most leases do not provide an implicit interest rate. Unless the lease contract contains an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease inception to compute the fair value of the lease payments. The ROU asset balance and current and non-current lease liabilities are reported separately on the accompanying Condensed Consolidated Balance Sheets. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. The Company recognizes lease expense on a straight-line basis over the lease term. |
Share-Based Compensation Share-
Share-Based Compensation Share-Based Compensation (Policies) | 6 Months Ended |
Jun. 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. |
Earnings Per Share Earnings Per
Earnings Per Share Earnings Per Share (Policies) | 6 Months Ended |
Jun. 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 six months ended June 30, 2023 and 2022 are discussed below. |
Long-Term Debt Long-Term Debt (
Long-Term Debt Long-Term Debt (Policies) | 6 Months Ended |
Jun. 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. |
Price-Risk Management Price-R_2
Price-Risk Management Price-Risk Management (Policies) | 6 Months Ended |
Jun. 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. |
Fair Value Measurements Fair Va
Fair Value Measurements Fair Value Disclosures (Policies) | 6 Months Ended |
Jun. 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. |
Asset Retirement Obligations _2
Asset Retirement Obligations Asset Retirement Obligations (Policies) | 6 Months Ended |
Jun. 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. |
Commitments and Contingencies_2
Commitments and Contingencies Commitments and Contingencies (Policies) | 6 Months Ended |
Jun. 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. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 6 Months Ended |
Jun. 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 July 31, 2023, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after June 30, 2023: Oil Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2024 Contracts 1Q24 273,000 $ 75.11 2Q24 273,000 $ 75.11 3Q24 276,000 $ 75.11 4Q24 276,000 $ 75.11 2025 Contracts 1Q25 270,000 $ 70.60 2Q25 273,000 $ 70.60 3Q25 276,000 $ 70.60 4Q25 276,000 $ 70.60 Collar Contracts 2023 Contracts 4Q23 92,000 $ 70.00 $ 80.40 2024 Contracts 1Q24 91,000 $ 65.00 $ 79.10 2Q24 91,000 $ 65.00 $ 79.10 3Q24 92,000 $ 65.00 $ 79.10 4Q24 92,000 $ 65.00 $ 79.10 2025 Contracts 2Q25 136,500 $ 61.33 $ 73.97 2026 Contracts 1Q26 90,000 $ 64.00 $ 71.50 2Q26 91,000 $ 64.00 $ 71.50 3Q26 92,000 $ 64.00 $ 71.50 Natural Gas Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2025 Contracts 3Q25 920,000 $ 3.75 4Q25 920,000 $ 4.16 Collar Contracts 2024 Contracts 1Q24 1,820,000 $ 3.25 $ 4.29 2Q24 1,820,000 $ 3.00 $ 3.31 3Q24 920,000 $ 3.00 $ 3.65 4Q24 920,000 $ 3.25 $ 4.40 2025 Contracts 2Q25 4,004,000 $ 3.25 $ 3.97 3Q25 920,000 $ 3.25 $ 3.99 4Q25 920,000 $ 3.75 $ 4.65 Natural Gas Basis Derivative Swaps Total Volumes Weighted-Average Price 2024 Contracts 1Q24 910,000 $ 0.075 2Q24 910,000 $ (0.261) 3Q24 920,000 $ (0.234) 4Q24 920,000 $ (0.276) 2025 Contracts 1Q25 900,000 $ 0.023 2Q25 910,000 $ (0.315) 3Q25 920,000 $ (0.240) 4Q25 920,000 $ (0.274) There were no other material subsequent events requiring additional disclosure in these condensed consolidated financial statements. |
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): June 30, 2023 December 31, 2022 Property and Equipment Proved oil and gas properties $ 2,724,110 $ 2,506,853 Unproved oil and gas properties 26,344 16,272 Furniture, fixtures and other equipment 6,240 6,098 Less – Accumulated depreciation, depletion, amortization & impairment (1,097,935) (1,004,044) Property and Equipment, Net $ 1,658,759 $ 1,525,179 |
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 June 30, 2023 and 2022 and the six months ended June 30, 2023 and 2022 (in thousands): Three Months Ended June 30, 2023 Three Months Ended June 30, 2022 Six Months Ended June 30, 2023 Six Months Ended June 30, 2022 Oil, natural gas and NGLs sales: Oil $ 80,151 $ 44,014 $ 154,807 $ 83,755 Natural gas 33,805 123,296 86,727 200,668 NGLs 12,443 15,295 24,820 27,838 Total $ 126,400 $ 182,605 $ 266,354 $ 312,261 |
Accounts Payable and Accrued Liabilities | The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): June 30, 2023 December 31, 2022 Trade accounts payable $ 32,210 $ 23,660 Accrued operating expenses 10,565 10,572 Accrued compensation costs 2,328 4,814 Asset retirement obligations – current portion 1,551 1,284 Accrued non-income based taxes 8,957 4,849 Accrued corporate and legal fees 260 388 WTI contingency payouts - current portion 975 1,600 Payable for settled derivatives 1,016 6,026 Other payables 2,281 7,007 Total accounts payable and accrued liabilities $ 60,143 $ 60,200 |
Leases Leases (Tables)
Leases Leases (Tables) | 6 Months Ended |
Jun. 30, 2023 | |
Leases [Abstract] | |
Lessee, Operating Lease, Liability, Maturity [Table Text Block] | As of June 30, 2023, the Company's future cash payment obligation for its operating lease liabilities are as follows (in thousands): As of June 30, 2023 2023 (Remaining) $ 4,730 2024 2,607 2025 1,422 2026 955 2027 61 Thereafter 472 Total undiscounted lease payments 10,247 Present value adjustment (710) Net operating lease liabilities $ 9,537 |
Share-Based Compensation (Table
Share-Based Compensation (Tables) | 6 Months Ended |
Jun. 30, 2023 | |
Share-Based Payment Arrangement [Abstract] | |
Stock option activity | The following table provides information regarding stock option award activity for the six months ended June 30, 2023: Shares Wtd. Avg. Exer. Price Options outstanding, beginning of period 196,162 $ 26.46 Options granted — $ — Options exercised — $ — Options outstanding, end of period 196,162 $ 26.46 Options exercisable, end of period 196,162 $ 26.46 |
Restricted stock activity | The following table provides information regarding RSU activity for the six months ended June 30, 2023: RSUs Wtd. Avg. Grant Price RSUs outstanding, beginning of period 227,114 $ 21.18 RSUs granted 192,014 $ 23.66 RSUs forfeited (1,424) $ 25.44 RSUs vested (136,242) $ 17.55 RSUs outstanding, end of period 281,462 $ 24.61 |
Performance-Based Stock Units Activity | The following table provides information regarding performance-based stock unit activity for the six months ended June 30, 2023: PSUs Wtd. Avg. Grant Price Performance based stock units outstanding, beginning of period 283,500 $ 23.18 Performance based stock units granted 120,749 $ 31.18 Performance based stock units incremental shares granted 142,021 $ 13.13 Performance based stock units vested (303,410) $ 13.13 Performance based stock units outstanding, end of period 242,860 $ 33.84 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 6 Months Ended |
Jun. 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 June 30, 2023 Three Months Ended June 30, 2022 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 24,937 22,615 $ 1.10 $ 88,790 17,581 $ 5.05 Dilutive Securities: Performance Based Stock Unit Awards 19 171 RSU Awards 33 128 Stock Option Awards 7 58 Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 24,937 22,674 $ 1.10 $ 88,790 17,938 $ 4.95 Six Months Ended June 30, 2023 Six Months Ended June 30, 2022 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 119,429 22,527 $ 5.30 $ 24,535 17,146 $ 1.43 Dilutive Securities: Performance Based Stock Unit Awards 58 142 RSU Awards 62 188 Stock Option Awards 7 30 Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 119,429 22,654 $ 5.27 $ 24,535 17,506 $ 1.40 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 6 Months Ended |
Jun. 30, 2023 | |
Debt Disclosure [Abstract] | |
Schedule of Long-term Debt Instruments | The Company's long-term debt consisted of the following (in thousands): June 30, 2023 December 31, 2022 Credit Facility Borrowings due 2026 (1) $ 576,000 $ 542,000 Second Lien Notes due 2026 150,000 150,000 726,000 692,000 Unamortized discount on Second Lien Notes due 2026 (787) (882) Unamortized debt issuance cost on Second Lien Notes due 2026 (2,309) (2,587) Long-Term Debt, net $ 722,904 $ 688,531 (1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “ Other Long-Term Assets ” in our consolidated balance sheet. As of June 30, 2023 and December 31, 2022, we had $7.6 million and $8.7 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings. |
Business Combinations and Asset
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 |
Price-Risk Management Price-R_3
Price-Risk Management Price-Risk Management (Tables) | 6 Months Ended |
Jun. 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 June 30, 2023: Oil Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Sub Floor Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2023 Contracts 3Q23 533,980 $ 77.36 4Q23 569,300 $ 78.26 2024 Contracts 1Q24 227,500 $ 80.78 2Q24 254,050 $ 80.24 3Q24 273,620 $ 76.89 4Q24 256,100 $ 75.98 Collar Contracts 2023 Contracts 3Q23 210,847 $ 64.55 $ 72.82 4Q23 210,242 $ 64.09 $ 71.97 2024 Contracts 1Q24 228,700 $ 56.54 $ 68.82 2Q24 124,000 $ 58.21 $ 69.51 3Q24 92,000 $ 62.00 $ 71.95 4Q24 92,000 $ 61.00 $ 71.60 2025 Contracts 1Q25 238,500 $ 64.00 $ 74.62 2Q25 91,000 $ 60.00 $ 69.60 3-Way Collar Contracts 2023 Contracts 3Q23 9,570 $ 43.08 $ 53.41 $ 63.33 4Q23 8,970 $ 43.08 $ 53.38 $ 63.35 2024 Contracts 1Q24 8,247 $ 45.00 $ 57.50 $ 67.85 2Q24 7,757 $ 45.00 $ 57.50 $ 67.85 Natural Gas Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Sub Floor Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2023 Contracts 3Q23 4,816,000 $ 4.57 4Q23 3,887,000 $ 4.71 2024 Contracts 1Q24 2,711,000 $ 5.15 2Q24 7,800,000 $ 3.95 3Q24 7,820,000 $ 4.03 4Q24 7,820,000 $ 4.35 2025 Contracts 1Q25 900,000 $ 5.01 2Q25 910,000 $ 4.12 3Q25 920,000 $ 4.27 4Q25 920,000 $ 4.70 Collar Contracts 2023 Contracts 3Q23 11,896,400 $ 3.43 $ 4.23 4Q23 12,445,000 $ 3.87 $ 4.80 2024 Contracts 1Q24 7,841,000 $ 4.10 $ 6.19 2Q24 2,823,000 $ 4.05 $ 4.91 3Q24 2,958,000 $ 4.00 $ 5.10 4Q24 2,945,000 $ 4.24 $ 5.63 2025 Contracts 1Q25 5,130,000 $ 4.00 $ 5.32 2Q25 910,000 $ 3.25 $ 4.03 3-Way Collar Contracts 2023 Contracts 3Q23 233,100 $ 2.00 $ 2.50 $ 2.95 4Q23 219,200 $ 2.00 $ 2.50 $ 2.94 2024 Contracts 1Q24 198,000 $ 2.00 $ 2.50 $ 3.37 2Q24 188,000 $ 2.00 $ 2.50 $ 3.37 Natural Gas Basis Derivative Swaps Total Volumes Weighted-Average Price 2023 Contracts 3Q23 14,720,000 $ (0.21) 4Q23 13,800,000 $ (0.23) 2024 Contracts 1Q24 11,830,000 $ 0.01 2Q24 11,830,000 $ (0.32) 3Q24 11,960,000 $ (0.27) 4Q24 11,960,000 $ (0.31) 2025 Contracts 1Q25 1,800,000 $ 0.04 2Q25 1,820,000 $ (0.29) 3Q25 1,840,000 $ (0.24) 4Q25 1,840,000 $ (0.29) NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2023 Contracts 3Q23 345,000 $ 32.87 4Q23 345,000 $ 32.87 2024 Contracts 1Q24 127,400 $ 29.39 2Q24 127,400 $ 29.39 3Q24 128,800 $ 29.39 4Q24 128,800 $ 29.39 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 6 Months Ended |
Jun. 30, 2023 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | T he following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of June 30, 2023 and December 31, 2022, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these Notes to Condensed Consolidated Financial Statements. Fair Value Measurements at (in thousands) Total Quoted Prices in Significant Other Significant June 30, 2023 Assets Natural Gas Derivatives $ 59,049 $ — $ 59,049 $ — Natural Gas Basis Derivatives 2,486 — 2,486 — Oil Derivatives 21,229 — 21,229 — NGL Derivatives 11,729 — 11,729 — Liabilities Natural Gas Derivatives 1,076 — 1,076 — Natural Gas Basis Derivatives 4,354 — 4,354 — Oil Derivatives 6,313 — 6,313 — 2021 WTI Contingency Payout 1,515 — 1,515 — December 31, 2022 Assets Natural Gas Derivatives $ 25,960 $ — $ 25,960 $ — Natural Gas Basis Derivatives 26,023 — 26,023 — Oil Derivatives 14,604 — 14,604 — NGL Derivatives 10,134 — 10,134 — Liabilities Natural Gas Derivatives 28,579 — 28,579 — Natural Gas Basis Derivatives 409 — 409 — Oil Derivatives 19,442 — 19,442 — NGL Derivatives 104 — 104 — 2022 WTI Contingency Payout 2,135 — 2,135 — 2021 WTI Contingency Payout 1,453 — 1,453 — |
Asset Retirement Obligations _3
Asset Retirement Obligations Asset Retirement Obligations (Tables) | 6 Months Ended |
Jun. 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 six months ended June 30, 2023 (in thousands): Asset Retirement Obligations as of December 31, 2021 $ 6,050 Accretion expense 534 Liabilities incurred for new wells, acquired wells and facilities construction 3,032 Reductions due to sold wells and facilities (57) Reductions due to plugged wells and facilities (22) Revisions in estimates 919 Asset Retirement Obligations as of December 31, 2022 $ 10,456 Accretion expense 464 Liabilities incurred for new wells, acquired wells and facilities construction 280 Reductions due to plugged wells and facilities (412) Revisions in estimates 382 Asset Retirement Obligations as of June 30, 2023 $ 11,170 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies (Details) $ in Thousands | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2023 USD ($) MMBTU bbl $ / MMBTU $ / Boe | Jun. 30, 2022 USD ($) | Jun. 30, 2023 USD ($) MMBTU bbl $ / MMBTU $ / Boe | Jun. 30, 2022 USD ($) | Jul. 31, 2023 bbl MMBTU $ / MMBTU $ / Boe | Dec. 31, 2022 USD ($) | |
Property and Equipment | ||||||
Proved oil and gas properties | $ | $ 2,724,110 | $ 2,724,110 | $ 2,506,853 | |||
Unproved oil and gas properties | $ | 26,344 | 26,344 | 16,272 | |||
Furniture, fixtures, and other equipment | $ | 6,240 | 6,240 | 6,098 | |||
Less - Accumulated depreciation, depletion, and amortization | $ | (1,097,935) | (1,097,935) | (1,004,044) | |||
Net Furniture, Fixtures and other equipment | $ | 1,658,759 | 1,658,759 | 1,525,179 | |||
Disaggregation of Revenue [Line Items] | ||||||
Oil and gas sales | $ | 126,400 | $ 182,605 | 266,354 | $ 312,261 | ||
Accounts Payable and Accrued Liabilities | ||||||
Trade accounts payable | $ | 32,210 | 32,210 | 23,660 | |||
Accrued operating expenses | $ | 10,565 | 10,565 | 10,572 | |||
Accrued compensation costs | $ | 2,328 | 2,328 | 4,814 | |||
Asset retirement obligation - current portion | $ | 1,551 | 1,551 | 1,284 | |||
Accrued non-income based taxes | $ | 8,957 | 8,957 | 4,849 | |||
Accrued corporate and legal fees | $ | 260 | 260 | 388 | |||
WTI contingency payouts - current portion | $ | 975 | 975 | 1,600 | |||
Payables for Settled Derivatives | $ | 1,016 | 1,016 | 6,026 | |||
Other payables | $ | 2,281 | 2,281 | 7,007 | |||
Total Accounts payable and accrued liabilities | $ | 60,143 | 60,143 | $ 60,200 | |||
Oil sales [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Oil and gas sales | $ | 80,151 | 44,014 | 154,807 | 83,755 | ||
Natural gas sales [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Oil and gas sales | $ | 33,805 | 123,296 | 86,727 | 200,668 | ||
NGL sales [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Oil and gas sales | $ | $ 12,443 | $ 15,295 | $ 24,820 | $ 27,838 | ||
Swap [Member] | Fourth Quarter 2023 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 569,300 | 569,300 | ||||
Derivative, Swap Type, Fixed Price | $ / Boe | 78.26 | 78.26 | ||||
Swap [Member] | Fourth Quarter 2023 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 3,887,000 | 3,887,000 | ||||
Derivative, Swap Type, Fixed Price | 4.71 | 4.71 | ||||
Swap [Member] | First Quarter 2024 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 227,500 | 227,500 | ||||
Derivative, Swap Type, Fixed Price | $ / Boe | 80.78 | 80.78 | ||||
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 | bbl | 273,000 | |||||
Derivative, Swap Type, Fixed Price | $ / Boe | 75.11 | |||||
Swap [Member] | First Quarter 2024 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 2,711,000 | 2,711,000 | ||||
Derivative, Swap Type, Fixed Price | 5.15 | 5.15 | ||||
Swap [Member] | Second Quarter 2024 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 254,050 | 254,050 | ||||
Derivative, Swap Type, Fixed Price | $ / Boe | 80.24 | 80.24 | ||||
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 | bbl | 273,000 | |||||
Derivative, Swap Type, Fixed Price | $ / Boe | 75.11 | |||||
Swap [Member] | Second Quarter 2024 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 7,800,000 | 7,800,000 | ||||
Derivative, Swap Type, Fixed Price | 3.95 | 3.95 | ||||
Swap [Member] | Third Quarter 2024 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 273,620 | 273,620 | ||||
Derivative, Swap Type, Fixed Price | $ / Boe | 76.89 | 76.89 | ||||
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 | bbl | 276,000 | |||||
Derivative, Swap Type, Fixed Price | $ / Boe | 75.11 | |||||
Swap [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 7,820,000 | 7,820,000 | ||||
Derivative, Swap Type, Fixed Price | 4.03 | 4.03 | ||||
Swap [Member] | Fourth Quarter 2024 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 256,100 | 256,100 | ||||
Derivative, Swap Type, Fixed Price | $ / Boe | 75.98 | 75.98 | ||||
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 | bbl | 276,000 | |||||
Derivative, Swap Type, Fixed Price | $ / Boe | 75.11 | |||||
Swap [Member] | Fourth Quarter 2024 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 7,820,000 | 7,820,000 | ||||
Derivative, Swap Type, Fixed Price | 4.35 | 4.35 | ||||
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 | bbl | 270,000 | |||||
Derivative, Swap Type, Fixed Price | $ / Boe | 70.60 | |||||
Swap [Member] | First Quarter 2025 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 900,000 | 900,000 | ||||
Derivative, Swap Type, Fixed Price | 5.01 | 5.01 | ||||
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 | bbl | 273,000 | |||||
Derivative, Swap Type, Fixed Price | $ / Boe | 70.60 | |||||
Swap [Member] | Second Quarter 2025 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 910,000 | 910,000 | ||||
Derivative, Swap Type, Fixed Price | 4.12 | 4.12 | ||||
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 | bbl | 276,000 | |||||
Derivative, Swap Type, Fixed Price | $ / Boe | 70.60 | |||||
Swap [Member] | Third Quarter 2025 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 920,000 | 920,000 | ||||
Derivative, Swap Type, Fixed Price | 4.27 | 4.27 | ||||
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 | 920,000 | |||||
Derivative, Swap Type, Fixed Price | 3.75 | |||||
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 | bbl | 276,000 | |||||
Derivative, Swap Type, Fixed Price | $ / Boe | 70.60 | |||||
Swap [Member] | Fourth Quarter 2025 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 920,000 | 920,000 | ||||
Derivative, Swap Type, Fixed Price | 4.70 | 4.70 | ||||
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 | 920,000 | |||||
Derivative, Swap Type, Fixed Price | 4.16 | |||||
Collar Contracts [Member] | Fourth Quarter 2023 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 210,242 | 210,242 | ||||
Derivative, Average Floor Price | 64.09 | 64.09 | ||||
Derivative, Average Cap Price | 71.97 | 71.97 | ||||
Collar Contracts [Member] | Fourth Quarter 2023 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 92,000 | |||||
Derivative, Average Floor Price | 70 | |||||
Derivative, Average Cap Price | 80.40 | |||||
Collar Contracts [Member] | Fourth Quarter 2023 | Natural Gas Derivative Swaps | ||||||
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] | First Quarter 2024 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 228,700 | 228,700 | ||||
Derivative, Average Floor Price | 56.54 | 56.54 | ||||
Derivative, Average Cap Price | 68.82 | 68.82 | ||||
Collar Contracts [Member] | First Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 91,000 | |||||
Derivative, Average Floor Price | 65 | |||||
Derivative, Average Cap Price | 79.10 | |||||
Collar Contracts [Member] | First Quarter 2024 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 7,841,000 | 7,841,000 | ||||
Derivative, Average Floor Price | 4.10 | 4.10 | ||||
Derivative, Average Cap Price | 6.19 | 6.19 | ||||
Collar Contracts [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, Average Floor Price | 3.25 | |||||
Derivative, Average Cap Price | 4.29 | |||||
Collar Contracts [Member] | Second Quarter 2024 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 124,000 | 124,000 | ||||
Derivative, Average Floor Price | 58.21 | 58.21 | ||||
Derivative, Average Cap Price | 69.51 | 69.51 | ||||
Collar Contracts [Member] | Second Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 91,000 | |||||
Derivative, Average Floor Price | 65 | |||||
Derivative, Average Cap Price | 79.10 | |||||
Collar Contracts [Member] | Second Quarter 2024 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 2,823,000 | 2,823,000 | ||||
Derivative, Average Floor Price | 4.05 | 4.05 | ||||
Derivative, Average Cap Price | 4.91 | 4.91 | ||||
Collar Contracts [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 | 1,820,000 | |||||
Derivative, Average Floor Price | 3 | |||||
Derivative, Average Cap Price | 3.31 | |||||
Collar Contracts [Member] | Third Quarter 2024 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 92,000 | 92,000 | ||||
Derivative, Average Floor Price | 62 | 62 | ||||
Derivative, Average Cap Price | 71.95 | 71.95 | ||||
Collar Contracts [Member] | Third Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 92,000 | |||||
Derivative, Average Floor Price | 65 | |||||
Derivative, Average Cap Price | 79.10 | |||||
Collar Contracts [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 2,958,000 | 2,958,000 | ||||
Derivative, Average Floor Price | 4 | 4 | ||||
Derivative, Average Cap Price | 5.10 | 5.10 | ||||
Collar Contracts [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 | 920,000 | |||||
Derivative, Average Floor Price | 3 | |||||
Derivative, Average Cap Price | 3.65 | |||||
Collar Contracts [Member] | Fourth Quarter 2024 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 92,000 | 92,000 | ||||
Derivative, Average Floor Price | 61 | 61 | ||||
Derivative, Average Cap Price | 71.60 | 71.60 | ||||
Collar Contracts [Member] | Fourth Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 92,000 | |||||
Derivative, Average Floor Price | 65 | |||||
Derivative, Average Cap Price | 79.10 | |||||
Collar Contracts [Member] | Fourth Quarter 2024 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 2,945,000 | 2,945,000 | ||||
Derivative, Average Floor Price | 4.24 | 4.24 | ||||
Derivative, Average Cap Price | 5.63 | 5.63 | ||||
Collar Contracts [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 | 920,000 | |||||
Derivative, Average Floor Price | 3.25 | |||||
Derivative, Average Cap Price | 4.40 | |||||
Collar Contracts [Member] | First Quarter 2025 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 238,500 | 238,500 | ||||
Derivative, Average Floor Price | 64 | 64 | ||||
Derivative, Average Cap Price | 74.62 | 74.62 | ||||
Collar Contracts [Member] | First Quarter 2025 | Natural Gas Derivative Swaps | ||||||
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 | 4 | ||||
Derivative, Average Cap Price | 5.32 | 5.32 | ||||
Collar Contracts [Member] | Second Quarter 2025 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 91,000 | 91,000 | ||||
Derivative, Average Floor Price | 60 | 60 | ||||
Derivative, Average Cap Price | 69.60 | 69.60 | ||||
Collar Contracts [Member] | Second Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 136,500 | |||||
Derivative, Average Floor Price | 61.33 | |||||
Derivative, Average Cap Price | 73.97 | |||||
Collar Contracts [Member] | Second Quarter 2025 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 910,000 | 910,000 | ||||
Derivative, Average Floor Price | 3.25 | 3.25 | ||||
Derivative, Average Cap Price | 4.03 | 4.03 | ||||
Collar Contracts [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 | 4,004,000 | |||||
Derivative, Average Floor Price | 3.25 | |||||
Derivative, Average Cap Price | 3.97 | |||||
Collar Contracts [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 | 920,000 | |||||
Derivative, Average Floor Price | 3.25 | |||||
Derivative, Average Cap Price | 3.99 | |||||
Collar Contracts [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 | 920,000 | |||||
Derivative, Average Floor Price | 3.75 | |||||
Derivative, Average Cap Price | 4.65 | |||||
Collar Contracts [Member] | First Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 90,000 | |||||
Derivative, Average Floor Price | 64 | |||||
Derivative, Average Cap Price | 71.50 | |||||
Collar Contracts [Member] | Second Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 91,000 | |||||
Derivative, Average Floor Price | 64 | |||||
Derivative, Average Cap Price | 71.50 | |||||
Collar Contracts [Member] | Third Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 92,000 | |||||
Derivative, Average Floor Price | 64 | |||||
Derivative, Average Cap Price | 71.50 | |||||
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 | (0.23) | (0.23) | ||||
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 | 11,830,000 | 11,830,000 | ||||
Derivative, Swap Type, Fixed Price | 0.01 | 0.01 | ||||
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 | 0.075 | |||||
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 | 11,830,000 | 11,830,000 | ||||
Derivative, Swap Type, Fixed Price | (0.32) | (0.32) | ||||
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 | (0.261) | |||||
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 | 11,960,000 | 11,960,000 | ||||
Derivative, Swap Type, Fixed Price | (0.27) | (0.27) | ||||
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 | (0.234) | |||||
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 | 11,960,000 | 11,960,000 | ||||
Derivative, Swap Type, Fixed Price | (0.31) | (0.31) | ||||
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 | (0.276) | |||||
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 | 1,800,000 | 1,800,000 | ||||
Derivative, Swap Type, Fixed Price | 0.04 | 0.04 | ||||
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 | 0.023 | |||||
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 | 1,820,000 | 1,820,000 | ||||
Derivative, Swap Type, Fixed Price | (0.29) | (0.29) | ||||
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 | (0.315) | |||||
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 | 1,840,000 | 1,840,000 | ||||
Derivative, Swap Type, Fixed Price | (0.24) | (0.24) | ||||
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 | (0.240) | |||||
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 | 1,840,000 | 1,840,000 | ||||
Derivative, Swap Type, Fixed Price | (0.29) | (0.29) | ||||
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 | (0.274) |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies (Details Textual) $ in Thousands | 3 Months Ended | 6 Months Ended | ||||||
Jun. 30, 2023 USD ($) MMBTU bbl $ / MMBTU $ / Boe shares | Mar. 31, 2023 shares | Jun. 30, 2022 USD ($) shares | Mar. 31, 2022 shares | Jun. 30, 2023 USD ($) MMBTU bbl $ / MMBTU $ / Boe shares | Jun. 30, 2022 USD ($) shares | Jul. 31, 2023 bbl MMBTU $ / MMBTU $ / Boe | Dec. 31, 2022 USD ($) | |
Summary of Significant Accounting Policies | ||||||||
Capitalized Costs Oil and Gas Producing Activities | $ | $ 1,200 | $ 1,200 | $ 2,600 | $ 2,200 | ||||
Proved oil and gas properties | $ | 2,724,110 | 2,724,110 | $ 2,506,853 | |||||
Unproved oil and gas properties | $ | 26,344 | 26,344 | 16,272 | |||||
Furniture, fixtures, and other equipment | $ | 6,240 | 6,240 | 6,098 | |||||
Less - Accumulated depreciation, depletion, and amortization | $ | (1,097,935) | (1,097,935) | (1,004,044) | |||||
Net Furniture, Fixtures and other equipment | $ | $ 1,658,759 | 1,658,759 | 1,525,179 | |||||
Discount rate for estimated future net revenues from proved properties | 10% | |||||||
Write-down of oil and gas properties | $ | $ 0 | 0 | 0 | 0 | ||||
Allowance for doubtful accounts receivable, current | $ | 100 | 100 | 100 | |||||
Accounts receivable, gross | $ | 45,200 | 45,200 | 70,900 | |||||
Accounts receivable related to joint interest owners | $ | 1,400 | 1,400 | 5,600 | |||||
Severance tax receivable | $ | 7,600 | 7,600 | 4,300 | |||||
Other receivables | $ | 10,400 | $ 10,400 | 8,900 | |||||
Percentage of working interest in wells | 100% | |||||||
Total amount of supervision fees charged to wells | $ | $ 2,900 | $ 1,700 | $ 5,500 | $ 3,400 | ||||
Effective Income Tax Rate Reconciliation, Percent | 22% | 4% | 22% | 6% | ||||
Provision (Benefit) for Income Taxes | $ | $ 7,351 | $ 4,366 | $ 34,163 | $ 1,612 | ||||
Oil and gas sales | $ | 126,400 | $ 182,605 | 266,354 | $ 312,261 | ||||
Trade accounts payable | $ | 32,210 | 32,210 | 23,660 | |||||
Accrued operating expenses | $ | 10,565 | 10,565 | 10,572 | |||||
Accrued payroll costs | $ | 2,328 | 2,328 | 4,814 | |||||
Asset retirement obligation - current portion | $ | 1,551 | 1,551 | 1,284 | |||||
Accrued non-income based taxes | $ | 8,957 | 8,957 | 4,849 | |||||
Accrued corporate and legal fees | $ | 260 | 260 | 388 | |||||
WTI contingency payouts - current portion | $ | 975 | 975 | 1,600 | |||||
Payables for Settled Derivatives | $ | 1,016 | 1,016 | 6,026 | |||||
Other payables | $ | 2,281 | 2,281 | 7,007 | |||||
Accounts payable and accrued liabilities | $ | $ 60,143 | $ 60,143 | $ 60,200 | |||||
Purchase of treasury stock (shares) | shares | 5,310 | 126,240 | 16,485 | 96,012 | 131,550 | 112,497 | ||
Treasury Shares Pursuant to Purchase Price Adjustment (shares) | shares | 41,191 | 41,191 | ||||||
Oil sales [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and gas sales | $ | $ 80,151 | $ 44,014 | $ 154,807 | $ 83,755 | ||||
Natural gas sales [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and gas sales | $ | 33,805 | 123,296 | 86,727 | 200,668 | ||||
NGL sales [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and gas sales | $ | $ 12,443 | $ 15,295 | $ 24,820 | $ 27,838 | ||||
Collar Contracts [Member] | Fourth Quarter 2023 | Oil Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 210,242 | 210,242 | ||||||
Derivative, Average Floor Price | 64.09 | 64.09 | ||||||
Derivative, Average Cap Price | 71.97 | 71.97 | ||||||
Collar Contracts [Member] | Fourth Quarter 2023 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 92,000 | |||||||
Derivative, Average Floor Price | 70 | |||||||
Derivative, Average Cap Price | 80.40 | |||||||
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 | ||||||
Derivative, Average Floor Price | 3.87 | 3.87 | ||||||
Derivative, Average Cap Price | 4.80 | 4.80 | ||||||
Collar Contracts [Member] | First Quarter 2024 | Oil Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 228,700 | 228,700 | ||||||
Derivative, Average Floor Price | 56.54 | 56.54 | ||||||
Derivative, Average Cap Price | 68.82 | 68.82 | ||||||
Collar Contracts [Member] | First Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 91,000 | |||||||
Derivative, Average Floor Price | 65 | |||||||
Derivative, Average Cap Price | 79.10 | |||||||
Collar Contracts [Member] | First Quarter 2024 | Natural Gas Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 7,841,000 | 7,841,000 | ||||||
Derivative, Average Floor Price | 4.10 | 4.10 | ||||||
Derivative, Average Cap Price | 6.19 | 6.19 | ||||||
Collar Contracts [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, Average Floor Price | 3.25 | |||||||
Derivative, Average Cap Price | 4.29 | |||||||
Collar Contracts [Member] | Second Quarter 2024 | Oil Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 124,000 | 124,000 | ||||||
Derivative, Average Floor Price | 58.21 | 58.21 | ||||||
Derivative, Average Cap Price | 69.51 | 69.51 | ||||||
Collar Contracts [Member] | Second Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 91,000 | |||||||
Derivative, Average Floor Price | 65 | |||||||
Derivative, Average Cap Price | 79.10 | |||||||
Collar Contracts [Member] | Second Quarter 2024 | Natural Gas Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 2,823,000 | 2,823,000 | ||||||
Derivative, Average Floor Price | 4.05 | 4.05 | ||||||
Derivative, Average Cap Price | 4.91 | 4.91 | ||||||
Collar Contracts [Member] | Second 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, Average Floor Price | 3 | |||||||
Derivative, Average Cap Price | 3.31 | |||||||
Collar Contracts [Member] | Third Quarter 2024 | Oil Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 92,000 | 92,000 | ||||||
Derivative, Average Floor Price | 62 | 62 | ||||||
Derivative, Average Cap Price | 71.95 | 71.95 | ||||||
Collar Contracts [Member] | Third Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 92,000 | |||||||
Derivative, Average Floor Price | 65 | |||||||
Derivative, Average Cap Price | 79.10 | |||||||
Collar Contracts [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 2,958,000 | 2,958,000 | ||||||
Derivative, Average Floor Price | 4 | 4 | ||||||
Derivative, Average Cap Price | 5.10 | 5.10 | ||||||
Collar Contracts [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 920,000 | |||||||
Derivative, Average Floor Price | 3 | |||||||
Derivative, Average Cap Price | 3.65 | |||||||
Collar Contracts [Member] | Fourth Quarter 2024 | Oil Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 92,000 | 92,000 | ||||||
Derivative, Average Floor Price | 61 | 61 | ||||||
Derivative, Average Cap Price | 71.60 | 71.60 | ||||||
Collar Contracts [Member] | Fourth Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 92,000 | |||||||
Derivative, Average Floor Price | 65 | |||||||
Derivative, Average Cap Price | 79.10 | |||||||
Collar Contracts [Member] | Fourth Quarter 2024 | Natural Gas Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 2,945,000 | 2,945,000 | ||||||
Derivative, Average Floor Price | 4.24 | 4.24 | ||||||
Derivative, Average Cap Price | 5.63 | 5.63 | ||||||
Collar Contracts [Member] | Fourth Quarter 2024 | Natural Gas Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 920,000 | |||||||
Derivative, Average Floor Price | 3.25 | |||||||
Derivative, Average Cap Price | 4.40 | |||||||
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 | ||||||
Derivative, Average Floor Price | 64 | 64 | ||||||
Derivative, Average Cap Price | 74.62 | 74.62 | ||||||
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 | ||||||
Derivative, Average Floor Price | 4 | 4 | ||||||
Derivative, Average Cap Price | 5.32 | 5.32 | ||||||
Collar Contracts [Member] | Second Quarter 2025 | Oil Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 91,000 | 91,000 | ||||||
Derivative, Average Floor Price | 60 | 60 | ||||||
Derivative, Average Cap Price | 69.60 | 69.60 | ||||||
Collar Contracts [Member] | Second Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 136,500 | |||||||
Derivative, Average Floor Price | 61.33 | |||||||
Derivative, Average Cap Price | 73.97 | |||||||
Collar Contracts [Member] | Second Quarter 2025 | Natural Gas Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 910,000 | 910,000 | ||||||
Derivative, Average Floor Price | 3.25 | 3.25 | ||||||
Derivative, Average Cap Price | 4.03 | 4.03 | ||||||
Collar Contracts [Member] | Second Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 4,004,000 | |||||||
Derivative, Average Floor Price | 3.25 | |||||||
Derivative, Average Cap Price | 3.97 | |||||||
Collar Contracts [Member] | Third Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 920,000 | |||||||
Derivative, Average Floor Price | 3.25 | |||||||
Derivative, Average Cap Price | 3.99 | |||||||
Collar Contracts [Member] | Fourth Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 920,000 | |||||||
Derivative, Average Floor Price | 3.75 | |||||||
Derivative, Average Cap Price | 4.65 | |||||||
Collar Contracts [Member] | First Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 90,000 | |||||||
Derivative, Average Floor Price | 64 | |||||||
Derivative, Average Cap Price | 71.50 | |||||||
Collar Contracts [Member] | Second Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 91,000 | |||||||
Derivative, Average Floor Price | 64 | |||||||
Derivative, Average Cap Price | 71.50 | |||||||
Collar Contracts [Member] | Third Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 92,000 | |||||||
Derivative, Average Floor Price | 64 | |||||||
Derivative, Average Cap Price | 71.50 | |||||||
Swap [Member] | Fourth Quarter 2023 | Oil Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | bbl | 569,300 | 569,300 | ||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 78.26 | 78.26 | ||||||
Swap [Member] | Fourth Quarter 2023 | Natural Gas Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 3,887,000 | 3,887,000 | ||||||
Derivative, Swap Type, Fixed Price | 4.71 | 4.71 | ||||||
Swap [Member] | First Quarter 2024 | Oil Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | bbl | 227,500 | 227,500 | ||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 80.78 | 80.78 | ||||||
Swap [Member] | First Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | bbl | 273,000 | |||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 75.11 | |||||||
Swap [Member] | First Quarter 2024 | Natural Gas Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 2,711,000 | 2,711,000 | ||||||
Derivative, Swap Type, Fixed Price | 5.15 | 5.15 | ||||||
Swap [Member] | Second Quarter 2024 | Oil Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | bbl | 254,050 | 254,050 | ||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 80.24 | 80.24 | ||||||
Swap [Member] | Second Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | bbl | 273,000 | |||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 75.11 | |||||||
Swap [Member] | Second Quarter 2024 | Natural Gas Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 7,800,000 | 7,800,000 | ||||||
Derivative, Swap Type, Fixed Price | 3.95 | 3.95 | ||||||
Swap [Member] | Third Quarter 2024 | Oil Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | bbl | 273,620 | 273,620 | ||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 76.89 | 76.89 | ||||||
Swap [Member] | Third Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | bbl | 276,000 | |||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 75.11 | |||||||
Swap [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 7,820,000 | 7,820,000 | ||||||
Derivative, Swap Type, Fixed Price | 4.03 | 4.03 | ||||||
Swap [Member] | Fourth Quarter 2024 | Oil Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | bbl | 256,100 | 256,100 | ||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 75.98 | 75.98 | ||||||
Swap [Member] | Fourth Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | bbl | 276,000 | |||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 75.11 | |||||||
Swap [Member] | Fourth Quarter 2024 | Natural Gas Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 7,820,000 | 7,820,000 | ||||||
Derivative, Swap Type, Fixed Price | 4.35 | 4.35 | ||||||
Swap [Member] | First Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | bbl | 270,000 | |||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 70.60 | |||||||
Swap [Member] | First Quarter 2025 | Natural Gas Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 900,000 | 900,000 | ||||||
Derivative, Swap Type, Fixed Price | 5.01 | 5.01 | ||||||
Swap [Member] | Second Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | bbl | 273,000 | |||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 70.60 | |||||||
Swap [Member] | Second Quarter 2025 | Natural Gas Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 910,000 | 910,000 | ||||||
Derivative, Swap Type, Fixed Price | 4.12 | 4.12 | ||||||
Swap [Member] | Third Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | bbl | 276,000 | |||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 70.60 | |||||||
Swap [Member] | Third Quarter 2025 | Natural Gas Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 920,000 | 920,000 | ||||||
Derivative, Swap Type, Fixed Price | 4.27 | 4.27 | ||||||
Swap [Member] | Third Quarter 2025 | 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 | 3.75 | |||||||
Swap [Member] | Fourth Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | bbl | 276,000 | |||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 70.60 | |||||||
Swap [Member] | Fourth Quarter 2025 | Natural Gas Derivative Swaps | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 920,000 | 920,000 | ||||||
Derivative, Swap Type, Fixed Price | 4.70 | 4.70 | ||||||
Swap [Member] | Fourth Quarter 2025 | 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 | 4.16 | |||||||
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 | (0.23) | (0.23) | ||||||
Basis Swap [Member] | First Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 11,830,000 | 11,830,000 | ||||||
Derivative, Swap Type, Fixed Price | 0.01 | 0.01 | ||||||
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 | 0.075 | |||||||
Basis Swap [Member] | Second Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 11,830,000 | 11,830,000 | ||||||
Derivative, Swap Type, Fixed Price | (0.32) | (0.32) | ||||||
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 | (0.261) | |||||||
Basis Swap [Member] | Third Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 11,960,000 | 11,960,000 | ||||||
Derivative, Swap Type, Fixed Price | (0.27) | (0.27) | ||||||
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 | (0.234) | |||||||
Basis Swap [Member] | Fourth Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 11,960,000 | 11,960,000 | ||||||
Derivative, Swap Type, Fixed Price | (0.31) | (0.31) | ||||||
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 | (0.276) | |||||||
Basis Swap [Member] | First Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 1,800,000 | 1,800,000 | ||||||
Derivative, Swap Type, Fixed Price | 0.04 | 0.04 | ||||||
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 | 0.023 | |||||||
Basis Swap [Member] | Second Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 1,820,000 | 1,820,000 | ||||||
Derivative, Swap Type, Fixed Price | (0.29) | (0.29) | ||||||
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 | (0.315) | |||||||
Basis Swap [Member] | Third Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 1,840,000 | 1,840,000 | ||||||
Derivative, Swap Type, Fixed Price | (0.24) | (0.24) | ||||||
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 | (0.240) | |||||||
Basis Swap [Member] | Fourth Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | ||||||||
Summary of Significant Accounting Policies | ||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 1,840,000 | 1,840,000 | ||||||
Derivative, Swap Type, Fixed Price | (0.29) | (0.29) | ||||||
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 | (0.274) | |||||||
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 |
Leases Leases (Details)
Leases Leases (Details) $ in Thousands | Jun. 30, 2023 USD ($) |
Leases [Abstract] | |
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year | $ 4,730 |
Lessee, Operating Lease, Liability, Payments, Due Year Two | 2,607 |
Lessee, Operating Lease, Liability, Payments, Due Year Three | 1,422 |
Lessee, Operating Lease, Liability, Payments, Due Year Four | 955 |
Lessee, Operating Lease, Liability, Payments, Due Year Five | 61 |
Lessee, Operating Lease, Liability, Payments, Due after Year Five | 472 |
Lessee, Operating Lease, Liability, Payments, Due | 10,247 |
Lessee, Operating Lease, Liability, Undiscounted Excess Amount | (710) |
Operating Lease, Liability | $ 9,537 |
Share-Based Compensation (Detai
Share-Based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 6 Months Ended | |||||||||
Jun. 30, 2023 | Feb. 23, 2023 | Feb. 22, 2023 | Feb. 23, 2022 | Feb. 24, 2021 | May 21, 2019 | Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | Dec. 31, 2022 | |
Share-based Compensation (Details Textual) | |||||||||||
Share-based Payment Arrangement, Noncash Expense | $ 2,575 | $ 2,714 | |||||||||
Share-based compensation (capitalized) | $ 100 | $ 100 | 100 | 100 | |||||||
Stock Option Activity | |||||||||||
Options, Exercises in Period | (4,497) | ||||||||||
General and Administrative Expense [Member] | |||||||||||
Share-based Compensation (Details Textual) | |||||||||||
Share-based Payment Arrangement, Noncash Expense | 1,500 | $ 1,700 | 2,600 | $ 2,700 | |||||||
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 | $ 500 | $ 500 | 500 | ||||||||
Remaining contract life of outstanding stock options. | 3 years 10 months 24 days | ||||||||||
Remaining contract life of exercisable stock option | 3 years 10 months 24 days | ||||||||||
Stock option award exercisable aggregate intrinsic value | $ 500 | ||||||||||
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 | $ 5,800 | $ 5,800 | $ 5,800 | ||||||||
Unrecognized compensation expense weighted-average period | 2 years 2 months 12 days | ||||||||||
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 | 192,014 | ||||||||||
Restricted shares granted, weighted average price | $ 23.66 | ||||||||||
Restricted shares forfeited | (1,424) | ||||||||||
Restricted shares forfeited, weighted average price | $ 25.44 | ||||||||||
Restricted shares vested, shares | (136,242) | ||||||||||
Restricted shares vested, weighted average price | $ 17.55 | ||||||||||
Restricted shares outstanding, end of period, shares | 281,462 | 281,462 | 281,462 | ||||||||
Restricted shares outstanding, end of period, weighted average price | $ 24.61 | $ 24.61 | $ 24.61 | ||||||||
Performance Shares [Member] | |||||||||||
Share-based Compensation (Details Textual) | |||||||||||
Stock option award unrecognized compensation | $ 5,600 | $ 5,600 | $ 5,600 | ||||||||
Unrecognized compensation expense weighted-average period | 2 years 1 month 6 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% | 136.28% | 150.93% | 157.60% | 112.90% | 100% | 100% | ||||
Approved payout for performance based stock units | 188% | 117% | |||||||||
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) | |||||||||||
Share-based Compensation, Expected Term | 1 year | ||||||||||
Minimum [Member] | Performance Shares [Member] | |||||||||||
Restricted stock activity | |||||||||||
Percent of payout for performance based stock units | 0% | 0% | 0% | 0% | |||||||
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) | |||||||||||
Share-based Compensation, Expected Term | 5 years | ||||||||||
Maximum [Member] | Performance Shares [Member] | |||||||||||
Restricted stock activity | |||||||||||
Percent of payout for performance based stock units | 200% | 200% | 200% | 200% |
Earnings Per Share (Details)
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2023 | Mar. 31, 2023 | Jun. 30, 2022 | Mar. 31, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | |
Basic EPS: | ||||||
Net Income (Loss) | $ 24,937 | $ 94,492 | $ 88,790 | $ (64,255) | $ 119,429 | $ 24,535 |
Income, share amounts | 22,615 | 17,581 | 22,527 | 17,146 | ||
Earnings Per Share, Basic | $ 1.10 | $ 5.05 | $ 5.30 | $ 1.43 | ||
Diluted EPS: | ||||||
Net Income (Loss) Available to Common Stockholders, Diluted | $ 24,937 | $ 88,790 | $ 119,429 | $ 24,535 | ||
Weighted Average Shares Outstanding - Diluted | 22,674 | 17,938 | 22,654 | 17,506 | ||
Earnings Per Share, Diluted | $ 1.10 | $ 4.95 | $ 5.27 | $ 1.40 | ||
Share-based Payment Arrangement, Option [Member] | ||||||
Dilutive Securities: | ||||||
Dilutive Securities | 7 | 58 | 7 | 30 | ||
Diluted EPS: | ||||||
Antidilutive shares excluded from EPS, shares | 100 | 0 | 100 | 100 | ||
Restricted Stock Units (RSUs) [Member] | ||||||
Dilutive Securities: | ||||||
Dilutive Securities | 33 | 128 | 62 | 188 | ||
Diluted EPS: | ||||||
Antidilutive shares excluded from EPS, shares | 100 | 100 | 100 | 100 | ||
Performance Shares [Member] | ||||||
Dilutive Securities: | ||||||
Dilutive Securities | 19 | 171 | 58 | 142 | ||
Diluted EPS: | ||||||
Antidilutive shares excluded from EPS, shares | 100 | 0 | 100 | 0 |
Long-Term Debt (Details)
Long-Term Debt (Details) $ in Thousands | 3 Months Ended | 6 Months Ended | |||||||||
Jun. 14, 2023 | Mar. 20, 2023 USD ($) | Nov. 29, 2021 USD ($) | Nov. 12, 2021 USD ($) | Jun. 30, 2023 USD ($) | Jun. 30, 2022 USD ($) | Jun. 30, 2023 USD ($) | Jun. 30, 2022 USD ($) | Dec. 31, 2022 USD ($) | Jun. 22, 2022 | Dec. 15, 2017 USD ($) | |
Bank Borrowings | |||||||||||
Long-term Debt, excluding current maturities | $ 722,904 | $ 722,904 | $ 688,531 | ||||||||
Payments of Debt Issuance Costs | 0 | $ 7,207 | |||||||||
Second Lien [Abstract] | |||||||||||
Long-term debt, gross | $ 726,000 | 726,000 | 692,000 | ||||||||
Discount Rate for Estimated Future Net Revenues from Proved Properties | 10% | ||||||||||
Gross interest expense including amortization of debt issuance costs | $ 18,190 | $ 7,902 | 34,935 | 14,459 | |||||||
New Credit Facility [Member] | |||||||||||
Bank Borrowings | |||||||||||
Debt Issuance Costs, Net | 7,600 | 7,600 | 8,700 | ||||||||
Second Lien Notes [Member] | |||||||||||
Bank Borrowings | |||||||||||
Debt Issuance Costs, Net | 2,309 | 2,309 | 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 | $ (787) | $ (787) | (882) | $ (2,000) | |||||||
Repayments of Long-Term Debt | $ 50,000 | ||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 12.75% | 12.75% | |||||||||
Second Lien, Required Security Interest on Proved Reserves | 90% | ||||||||||
Second Lien, Required Security Interest on Oil and Gas Properties | 90% | ||||||||||
Discount Rate for Estimated Future Net Revenues for Proved Properties at 9% | 9% | ||||||||||
Second Lien, Asset Coverage Ratio, Minimum | 1.25 | ||||||||||
Second Lien, Debt to EBITDA Ratio, after March 31, 2022 | 3.25 | ||||||||||
Long-term debt, net | $ 146,900 | $ 146,900 | |||||||||
Gross interest expense including amortization of debt issuance costs | 5,000 | 3,500 | 9,800 | 6,900 | |||||||
Second Lien Notes [Member] | Alternative Base Interest Rate [Member] | |||||||||||
Second Lien [Abstract] | |||||||||||
Debt Instrument, Minimum Margin on SOFR | 1% | ||||||||||
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 | 576,000 | 576,000 | 542,000 | ||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 2,000,000 | 2,000,000 | |||||||||
Line of Credit Facility, Current Borrowing Capacity | 775,000 | 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% | ||||||||||
Debt, Weighted Average Interest Rate | 8.48% | 8.48% | |||||||||
Line of Credit, Required Security Interest on Oil and Gas Properties | 85% | ||||||||||
Line of Credit, Covenant, Debt to EBITDA Ratio | 3 | ||||||||||
Line of Credit, Covenant, Current Ratio, Minimum | 1 | ||||||||||
Line of Credit Facility, Commitment Fee Amount | $ 200 | 300 | $ 500 | 600 | |||||||
Payments of Debt Issuance Costs | 0 | 7,200 | |||||||||
Second Lien [Abstract] | |||||||||||
Gross interest expense including amortization of debt issuance costs | $ 13,200 | $ 4,400 | $ 25,200 | $ 7,600 | |||||||
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 |
Acquisitions and Dispositions_2
Acquisitions and Dispositions Acquisitions and Dispositions (Details) $ in Thousands | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||||||||
Oct. 31, 2022 USD ($) | Aug. 15, 2022 USD ($) | Jun. 30, 2022 USD ($) shares | May 10, 2022 USD ($) shares | Nov. 19, 2021 USD ($) shares | Jun. 30, 2023 USD ($) | Jun. 30, 2022 USD ($) shares | Mar. 31, 2022 shares | Jun. 30, 2023 USD ($) | Jun. 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 | $ 3,935 | $ 3,935 | $ 2,671 | ||||||||
Right of Use Assets | 9,435 | 9,435 | 12,077 | ||||||||
Derivative, Fair Value, Net | 82,800 | 82,800 | 28,200 | ||||||||
Non-current Lease Liability | 3,571 | 3,571 | 3,775 | ||||||||
Asset Retirement Obligations, Noncurrent | 9,619 | 9,619 | 9,171 | ||||||||
WTI Contingency Payout Fair Value | $ 1,900 | ||||||||||
Proceeds from the sale of property and equipment | 0 | $ 2,532 | 4,300 | ||||||||
Gain (Loss) on WTI Contingency Payout | (100) | $ (200) | 900 | (1,500) | |||||||
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 | $ 100 | 200 | 100 | 1,500 | |||||||
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 | 6,766 | 6,800 | |||||||
Asset Acquisition, Total Cost of Transaction | 351,705 | ||||||||||
Other current assets | 4,202 | 4,202 | 4,202 | ||||||||
Allocation of Total Cost, Oil and gas properties | 397,401 | ||||||||||
Right of Use Assets | 890 | 890 | 890 | ||||||||
Allocation of Total cost, Total assets | 402,493 | ||||||||||
Accounts Payable and Accrued Liabilities, Current | 13,687 | 13,687 | 13,687 | ||||||||
Derivative, Fair Value, Net | 33,767 | 33,767 | 33,767 | ||||||||
Non-current Lease Liability | 890 | 890 | 890 | ||||||||
Asset Retirement Obligations, Noncurrent | 2,444 | 2,444 | 2,444 | ||||||||
Allocation of Total Cost, Total Liabilities | 50,788 | ||||||||||
2022 WTI Contingency Payout Fair Value | 7,422 | 7,422 | 7,422 | ||||||||
WTI Annual Earn Out Payment | 7,500 | 7,500 | 7,500 | ||||||||
Account Receivable for purchase price adjustments | $ (1,000) | $ (1,000) | $ (1,000) | ||||||||
WTI Annual Earn Out, Average Monthly Settlement 2022 | 95 | 95 | 95 | ||||||||
2023 WTI Annual Earn Out Payment | $ 7,500 | ||||||||||
WTI Annual Earn Out, Average Monthly Settlement Price 2023 | 85 | 85 | 85 | ||||||||
2024 WTI Annual Earn Out Payment | $ 7,500 | $ 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 |
Price-Risk Management Price-R_4
Price-Risk Management Price-Risk Management (Details) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2023 USD ($) MMBTU bbl $ / MMBTU $ / Boe | Jun. 30, 2022 USD ($) | Jun. 30, 2023 USD ($) MMBTU bbl $ / MMBTU $ / Boe | Jun. 30, 2022 USD ($) | Dec. 31, 2022 USD ($) | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Gain (Loss) on Price Risk Derivatives, Net | $ | $ 18,900 | $ (22,200) | $ 110,200 | $ (161,200) | |
Gain (Loss) on WTI Contingency Payout | $ | (100) | $ (200) | 900 | (1,500) | |
Cash settlements on derivatives | $ | 47,481 | $ (90,603) | |||
Receivables for Settled Derivatives | $ | 10,000 | 10,000 | $ 6,900 | ||
Payables for Settled Derivatives | $ | 1,016 | 1,016 | 6,026 | ||
Derivative, Fair Value, Net | $ | 82,800 | 82,800 | 28,200 | ||
Other Current Assets [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | $ | 72,600 | 72,600 | 52,500 | ||
Other Noncurrent Assets [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | $ | 21,900 | 21,900 | 24,200 | ||
Other Current Liabilities [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | $ | 9,700 | 9,700 | 40,800 | ||
Other Noncurrent Liabilities [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | $ | $ 2,000 | $ 2,000 | $ 7,700 | ||
Swap [Member] | Oil Derivative Swaps | Third Quarter 2023 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 533,980 | 533,980 | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 77.36 | 77.36 | |||
Swap [Member] | Oil Derivative Swaps | Fourth Quarter 2023 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 569,300 | 569,300 | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 78.26 | 78.26 | |||
Swap [Member] | Oil Derivative Swaps | First Quarter 2024 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 227,500 | 227,500 | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 80.78 | 80.78 | |||
Swap [Member] | Oil Derivative Swaps | Second Quarter 2024 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 254,050 | 254,050 | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 80.24 | 80.24 | |||
Swap [Member] | Oil Derivative Swaps | Third Quarter 2024 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 273,620 | 273,620 | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 76.89 | 76.89 | |||
Swap [Member] | Oil Derivative Swaps | Fourth Quarter 2024 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 256,100 | 256,100 | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 75.98 | 75.98 | |||
Swap [Member] | Natural Gas Derivative Swaps | Third Quarter 2023 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 4,816,000 | 4,816,000 | |||
Derivative, Swap Type, Fixed Price | 4.57 | 4.57 | |||
Swap [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2023 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 3,887,000 | 3,887,000 | |||
Derivative, Swap Type, Fixed Price | 4.71 | 4.71 | |||
Swap [Member] | Natural Gas Derivative Swaps | First Quarter 2024 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 2,711,000 | 2,711,000 | |||
Derivative, Swap Type, Fixed Price | 5.15 | 5.15 | |||
Swap [Member] | Natural Gas Derivative Swaps | Second Quarter 2024 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 7,800,000 | 7,800,000 | |||
Derivative, Swap Type, Fixed Price | 3.95 | 3.95 | |||
Swap [Member] | Natural Gas Derivative Swaps | Third Quarter 2024 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 7,820,000 | 7,820,000 | |||
Derivative, Swap Type, Fixed Price | 4.03 | 4.03 | |||
Swap [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2024 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 7,820,000 | 7,820,000 | |||
Derivative, Swap Type, Fixed Price | 4.35 | 4.35 | |||
Swap [Member] | Natural Gas Derivative Swaps | First Quarter 2025 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 900,000 | 900,000 | |||
Derivative, Swap Type, Fixed Price | 5.01 | 5.01 | |||
Swap [Member] | Natural Gas Derivative Swaps | Second Quarter 2025 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 910,000 | 910,000 | |||
Derivative, Swap Type, Fixed Price | 4.12 | 4.12 | |||
Swap [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, Swap Type, Fixed Price | 4.27 | 4.27 | |||
Swap [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, Swap Type, Fixed Price | 4.70 | 4.70 | |||
Swap [Member] | NGL Derivative | Third 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 | 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 | 127,400 | 127,400 | |||
Derivative, Swap Type, Fixed Price | 29.39 | 29.39 | |||
Swap [Member] | NGL Derivative | Second Quarter 2024 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 127,400 | 127,400 | |||
Derivative, Swap Type, Fixed Price | 29.39 | 29.39 | |||
Swap [Member] | NGL Derivative | Third Quarter 2024 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 128,800 | 128,800 | |||
Derivative, Swap Type, Fixed Price | 29.39 | 29.39 | |||
Swap [Member] | NGL Derivative | Fourth Quarter 2024 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 128,800 | 128,800 | |||
Derivative, Swap Type, Fixed Price | 29.39 | 29.39 | |||
Collar Contracts [Member] | Oil Derivative Swaps | Third Quarter 2023 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 210,847 | 210,847 | |||
Derivative, Average Floor Price | 64.55 | 64.55 | |||
Derivative, Average Cap Price | 72.82 | 72.82 | |||
Collar Contracts [Member] | Oil Derivative Swaps | Fourth Quarter 2023 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 210,242 | 210,242 | |||
Derivative, Average Floor Price | 64.09 | 64.09 | |||
Derivative, Average Cap Price | 71.97 | 71.97 | |||
Collar Contracts [Member] | Oil Derivative Swaps | First Quarter 2024 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 228,700 | 228,700 | |||
Derivative, Average Floor Price | 56.54 | 56.54 | |||
Derivative, Average Cap Price | 68.82 | 68.82 | |||
Collar Contracts [Member] | Oil Derivative Swaps | Second Quarter 2024 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 124,000 | 124,000 | |||
Derivative, Average Floor Price | 58.21 | 58.21 | |||
Derivative, Average Cap Price | 69.51 | 69.51 | |||
Collar Contracts [Member] | Oil Derivative Swaps | Third Quarter 2024 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 92,000 | 92,000 | |||
Derivative, Average Floor Price | 62 | 62 | |||
Derivative, Average Cap Price | 71.95 | 71.95 | |||
Collar Contracts [Member] | Oil Derivative Swaps | Fourth Quarter 2024 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 92,000 | 92,000 | |||
Derivative, Average Floor Price | 61 | 61 | |||
Derivative, Average Cap Price | 71.60 | 71.60 | |||
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 | 64 | |||
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 | 91,000 | 91,000 | |||
Derivative, Average Floor Price | 60 | 60 | |||
Derivative, Average Cap Price | 69.60 | 69.60 | |||
Collar Contracts [Member] | Natural Gas Derivative Swaps | Third Quarter 2023 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 11,896,400 | 11,896,400 | |||
Derivative, Average Floor Price | 3.43 | 3.43 | |||
Derivative, Average Cap Price | 4.23 | 4.23 | |||
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 | 7,841,000 | 7,841,000 | |||
Derivative, Average Floor Price | 4.10 | 4.10 | |||
Derivative, Average Cap Price | 6.19 | 6.19 | |||
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 | 2,823,000 | 2,823,000 | |||
Derivative, Average Floor Price | 4.05 | 4.05 | |||
Derivative, Average Cap Price | 4.91 | 4.91 | |||
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 | 2,958,000 | 2,958,000 | |||
Derivative, Average Floor Price | 4 | 4 | |||
Derivative, Average Cap Price | 5.10 | 5.10 | |||
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 | 2,945,000 | 2,945,000 | |||
Derivative, Average Floor Price | 4.24 | 4.24 | |||
Derivative, Average Cap Price | 5.63 | 5.63 | |||
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 | 4 | |||
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 | 910,000 | 910,000 | |||
Derivative, Average Floor Price | 3.25 | 3.25 | |||
Derivative, Average Cap Price | 4.03 | 4.03 | |||
3-Way Collar | Oil Derivative Swaps | Third Quarter 2023 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 9,570 | 9,570 | |||
Derivative, Average Sub Floor Price | 43.08 | 43.08 | |||
Derivative, Average Floor Price | 53.41 | 53.41 | |||
Derivative, Average Cap Price | 63.33 | 63.33 | |||
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 | 45 | |||
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 | 45 | |||
Derivative, Average Floor Price | 57.50 | 57.50 | |||
Derivative, Average Cap Price | 67.85 | 67.85 | |||
3-Way Collar | Natural Gas Derivative Swaps | Third Quarter 2023 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 233,100 | 233,100 | |||
Derivative, Average Sub Floor Price | 2 | 2 | |||
Derivative, Average Floor Price | 2.50 | 2.50 | |||
Derivative, Average Cap Price | 2.95 | 2.95 | |||
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 | 2 | |||
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 | 2 | |||
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 | 2 | |||
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] | Third Quarter 2023 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 14,720,000 | 14,720,000 | |||
Derivative, Swap Type, Fixed Price | (0.21) | (0.21) | |||
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 | 11,830,000 | 11,830,000 | |||
Derivative, Swap Type, Fixed Price | 0.01 | 0.01 | |||
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 | 11,830,000 | 11,830,000 | |||
Derivative, Swap Type, Fixed Price | (0.32) | (0.32) | |||
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 | 11,960,000 | 11,960,000 | |||
Derivative, Swap Type, Fixed Price | (0.27) | (0.27) | |||
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 | 11,960,000 | 11,960,000 | |||
Derivative, Swap Type, Fixed Price | (0.31) | (0.31) | |||
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 | 1,800,000 | 1,800,000 | |||
Derivative, Swap Type, Fixed Price | 0.04 | 0.04 | |||
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 | 1,820,000 | 1,820,000 | |||
Derivative, Swap Type, Fixed Price | (0.29) | (0.29) | |||
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 | 1,840,000 | 1,840,000 | |||
Derivative, Swap Type, Fixed Price | (0.24) | (0.24) | |||
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 | 1,840,000 | 1,840,000 | |||
Derivative, Swap Type, Fixed Price | (0.29) | (0.29) |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - Fair Value, Recurring [Member] - USD ($) $ in Thousands | Jun. 30, 2023 | Dec. 31, 2022 |
Natural Gas Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | $ 59,049 | $ 25,960 |
Derivative Liability | 1,076 | 28,579 |
Natural Gas Basis Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 2,486 | 26,023 |
Derivative Liability | 4,354 | 409 |
Oil Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 21,229 | 14,604 |
Derivative Liability | 6,313 | 19,442 |
2022 WTI Contingency Payout Fair Value | 2,135 | |
2021 WTI Contingency Payout | 1,515 | 1,453 |
NGL Derivative | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 11,729 | 10,134 |
Derivative Liability | 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] | NGL Derivative | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | 0 |
Derivative Liability | 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 | 59,049 | 25,960 |
Derivative Liability | 1,076 | 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 | 2,486 | 26,023 |
Derivative Liability | 4,354 | 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 | 21,229 | 14,604 |
Derivative Liability | 6,313 | 19,442 |
2022 WTI Contingency Payout Fair Value | 2,135 | |
2021 WTI Contingency Payout | 1,515 | 1,453 |
Fair Value, Inputs, Level 2 [Member] | NGL Derivative | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 11,729 | 10,134 |
Derivative Liability | 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] | NGL Derivative | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | $ 0 | 0 |
Derivative Liability | $ 0 |
Asset Retirement Obligations _4
Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | |
Asset Retirement Obligation Disclosure [Abstract] | ||||||
Asset Retirement Obligation | $ 11,170 | $ 11,170 | $ 10,456 | $ 6,050 | ||
Accretion expense | 240 | $ 101 | 464 | $ 200 | 534 | |
Liabilities incurred for new wells and facilities construction | 280 | 3,032 | ||||
Reduction due to sold wells and facilities | (57) | |||||
Reductions due to plugged wells and facilities | (412) | (22) | ||||
Revisions in estimates | 382 | 919 | ||||
Asset retirement obligation - current portion | $ 1,551 | $ 1,551 | $ 1,284 |
Commitments and Contingencies (
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 |