Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2021 | Oct. 29, 2021 | |
Document and Entity Information [Abstract] | ||
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2021 | |
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 $0.01 per share | |
Trading Symbol | SBOW | |
Security Exchange Name | NYSE | |
Entity Filer Category | Non-accelerated Filer | |
Document Quarterly Report | true | |
Document Transition Report | false | |
Entity Emerging Growth Company | false | |
Entity Small Business | true | |
Entity Shell Company | false | |
Entity Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Common Stock, Shares Outstanding | 14,726,605 | |
Entity Central Index Key | 0000351817 | |
Current Fiscal Year End Date | --12-31 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2021 | |
Document Fiscal Period Focus | Q3 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets - USD ($) $ in Thousands | Sep. 30, 2021 | Dec. 31, 2020 |
Current Assets: | ||
Cash and cash equivalents | $ 988 | $ 2,118 |
Accounts receivable, net | 44,190 | 25,850 |
Fair value of commodity derivatives | 668 | 4,821 |
Other current assets | 4,016 | 2,184 |
Total Current Assets | 49,862 | 34,973 |
Property and Equipment: | ||
Property and Equipment, full cost method | 1,476,586 | 1,343,373 |
Less - Accumulated depreciation, depletion, and amortization | (846,822) | (801,279) |
Net Furniture, Fixtures and other equipment | 629,764 | 542,094 |
Right of Use Assets | 15,787 | 4,366 |
Fair value of long-term commodity derivatives | 18 | 281 |
Other Long-Term Assets | 2,904 | 1,421 |
Total Assets | 698,335 | 583,135 |
Current Liabilities: | ||
Accounts payable and accrued liabilities | 38,000 | 26,991 |
Fair value of commodity derivatives | 94,778 | 8,171 |
Accrued capital costs | 20,482 | 7,324 |
Accrued interest | 846 | 983 |
Current lease liability | 6,292 | 3,473 |
Undistributed oil and gas revenues | 17,328 | 11,098 |
Total Current Liabilities | 177,726 | 58,040 |
Long-Term Debt | 393,726 | 424,905 |
Non-current Lease Liability | 9,723 | 951 |
Deferred Tax Liabilities | 303 | 303 |
Asset Retirement Obligation | 4,706 | 4,533 |
Fair value of long-term commodity derivatives | 21,989 | 2,946 |
Other Long-Term Liabilities | 846 | 424 |
Stockholders' Equity: | ||
Preferred Stock, Value, Outstanding | 0 | 0 |
Common stock, $0.01 par value | 136 | 121 |
Additional paid-in capital | 324,106 | 297,712 |
Treasury stock held, at cost | (2,984) | (2,372) |
Retained earnings (Accumulated deficit) | (231,942) | (204,428) |
Total Stockholders' Equity (Deficit) | 89,316 | 91,033 |
Total Liabilities and Stockholders' Equity | $ 698,335 | $ 583,135 |
Condensed Consolidated Balanc_2
Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Sep. 30, 2021 | Dec. 31, 2020 |
Statement of Financial Position [Abstract] | ||
Capitalized Costs, unproved property balance | $ 24,988 | $ 28,090 |
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 value per share (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 40,000,000 | 40,000,000 |
Common stock, shares issued | 13,576,285 | 12,053,763 |
Common stock, shares outstanding | 13,384,615 | 11,936,679 |
Treasury stock shares held, at cost | 191,670 | 117,084 |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2021 | Sep. 30, 2020 | |
Income Statement [Abstract] | ||||
Oil and gas sales | $ 99,249 | $ 45,699 | $ 255,850 | $ 123,921 |
Costs and Expenses [Abstract] | ||||
General and administrative, net | 5,257 | 5,833 | 14,872 | 17,926 |
Depreciation, depletion, and amortization | 16,054 | 13,975 | 45,485 | 51,130 |
Accretion of asset retirement obligation | 77 | 90 | 226 | 263 |
Lease operating costs | 6,978 | 5,211 | 18,767 | 16,023 |
Workovers | 423 | 8 | 512 | 8 |
Transportation and gas processing | 5,913 | 5,094 | 17,175 | 16,291 |
Severance and other taxes | 4,908 | 2,512 | 11,974 | 7,513 |
Write-down of oil and gas properties | 0 | 0 | 0 | 355,948 |
Operating Expenses | 39,610 | 32,723 | 109,011 | 465,102 |
Operating Income (Loss) | 59,639 | 12,976 | 146,839 | (341,181) |
Net gain (loss) on commodity derivatives | (88,554) | (12,944) | (152,879) | 66,884 |
Interest expense, net | (7,433) | (7,444) | (21,888) | (23,876) |
Other Nonoperating Income (Expense) | (3) | (56) | 6 | 50 |
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest | (36,351) | (7,468) | (27,922) | (298,123) |
Provision (Benefit) for Income Taxes | (408) | (572) | (408) | 20,607 |
Net Income (Loss) | $ (35,943) | $ (6,896) | $ (27,514) | $ (318,730) |
Per Share Amounts- | ||||
Earnings Per Share, Basic | $ (2.85) | $ (0.58) | $ (2.24) | $ (26.81) |
Earnings Per Share, Diluted | $ (2.85) | $ (0.58) | $ (2.24) | $ (26.81) |
Weighted Average Shares Outstanding - Basic | 12,629 | 11,935 | 12,283 | 11,890 |
Weighted Average Shares Outstanding - Diluted | 12,629 | 11,935 | 12,283 | 11,890 |
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, 2019 | $ 395,707 | $ 119 | $ 292,916 | $ (2,282) | $ 104,954 |
Purchase of treasury shares | (83) | 0 | 0 | (83) | 0 |
Vesting of share-based compensation | 0 | 1 | (1) | 0 | 0 |
Amortization of share-based compensation | 1,335 | 0 | 1,335 | 0 | 0 |
Net Income (Loss) | (5,858) | 0 | 0 | 0 | (5,858) |
Ending Balance at Mar. 31, 2020 | 391,101 | 120 | 294,250 | (2,365) | 99,096 |
Beginning Balance at Dec. 31, 2019 | 395,707 | 119 | 292,916 | (2,282) | 104,954 |
Net Income (Loss) | (318,730) | ||||
Ending Balance at Sep. 30, 2020 | 80,602 | 121 | 296,629 | (2,372) | (213,776) |
Beginning Balance at Mar. 31, 2020 | 391,101 | 120 | 294,250 | (2,365) | 99,096 |
Shares issued from warrant exercise | 0 | 0 | 0 | 0 | 0 |
Purchase of treasury shares | (3) | 0 | 0 | (3) | 0 |
Vesting of share-based compensation | 0 | 0 | 0 | 0 | 0 |
Amortization of share-based compensation | 1,229 | 0 | 1,229 | 0 | 0 |
Net Income (Loss) | (305,976) | 0 | 0 | 0 | (305,976) |
Ending Balance at Jun. 30, 2020 | 86,351 | 120 | 295,479 | (2,368) | (206,880) |
Purchase of treasury shares | (4) | 0 | 0 | (4) | 0 |
Vesting of share-based compensation | 1 | 1 | 0 | 0 | 0 |
Amortization of share-based compensation | 1,150 | 0 | 1,150 | 0 | 0 |
Net Income (Loss) | (6,896) | 0 | 0 | 0 | (6,896) |
Ending Balance at Sep. 30, 2020 | 80,602 | 121 | 296,629 | (2,372) | (213,776) |
Beginning Balance at Dec. 31, 2020 | 91,033 | 121 | 297,712 | (2,372) | (204,428) |
Purchase of treasury shares | (488) | 0 | 0 | (488) | 0 |
Vesting of share-based compensation | 0 | 2 | (2) | 0 | 0 |
Amortization of share-based compensation | 1,131 | 0 | 1,131 | 0 | 0 |
Net Income (Loss) | 28,380 | 0 | 0 | 0 | 28,380 |
Ending Balance at Mar. 31, 2021 | 120,056 | 123 | 298,841 | (2,860) | (176,048) |
Beginning Balance at Dec. 31, 2020 | 91,033 | 121 | 297,712 | (2,372) | (204,428) |
Net Income (Loss) | (27,514) | ||||
Ending Balance at Sep. 30, 2021 | 89,316 | 136 | 324,106 | (2,984) | (231,942) |
Beginning Balance at Mar. 31, 2021 | 120,056 | 123 | 298,841 | (2,860) | (176,048) |
Purchase of treasury shares | (115) | 0 | 0 | (115) | 0 |
Vesting of share-based compensation | 0 | 1 | (1) | 0 | 0 |
Amortization of share-based compensation | 1,248 | 0 | 1,248 | 0 | 0 |
Net Income (Loss) | (19,951) | 0 | 0 | 0 | (19,951) |
Ending Balance at Jun. 30, 2021 | 101,238 | 124 | 300,088 | (2,975) | (195,999) |
Purchase of treasury shares | (9) | 0 | 0 | (9) | 0 |
Vesting of share-based compensation | 0 | 0 | 0 | 0 | 0 |
Amortization of share-based compensation | 1,251 | 0 | 1,251 | 0 | 0 |
Issuance of common stock | 12,756 | 7 | 12,749 | 0 | 0 |
Issuance pursuant to acquisition | 10,023 | 5 | 10,018 | 0 | 0 |
Net Income (Loss) | (35,943) | 0 | 0 | 0 | (35,943) |
Ending Balance at Sep. 30, 2021 | $ 89,316 | $ 136 | $ 324,106 | $ (2,984) | $ (231,942) |
Condensed Consolidated Statem_3
Condensed Consolidated Statements of Stockholders' Equity (Parenthetical) - shares | 3 Months Ended | |||||
Sep. 30, 2021 | Jun. 30, 2021 | Mar. 31, 2021 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | |
Statement of Stockholders' Equity [Abstract] | ||||||
Warrants exercised (shares) | 5 | |||||
Purchase of treasury stock (shares) | 440 | 13,969 | 60,177 | 958 | 1,098 | 26,675 |
Vesting of share-based compensation (shares) | 1,802 | 51,332 | 283,113 | 3,953 | 49,665 | 105,108 |
Issuance of common stock | 669,600 | |||||
Issuance pursuant to acquisition | 516,675 |
Condensed Consolidated Statem_4
Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2021 | Sep. 30, 2020 | Dec. 31, 2020 | Dec. 31, 2019 | |
Cash Flows from Operating Activities: | ||||||
Net Income (Loss) | $ (35,943) | $ (6,896) | $ (27,514) | $ (318,730) | ||
Adjustments to reconcile net income to net cash provided by operating activities - | ||||||
Depreciation, depletion, and amortization | 16,054 | 13,975 | 45,485 | 51,130 | ||
Write-down of oil and gas properties | 0 | 0 | 0 | 355,948 | ||
Accretion of asset retirement obligation | 77 | 90 | 226 | 263 | $ 354 | |
Deferred income taxes | 0 | 21,087 | ||||
Stock-based compensation expenses | 3,450 | 3,503 | ||||
Loss (gain) on derivatives | 152,879 | (66,884) | ||||
Cash settlement (paid) received on derivatives | (28,976) | 76,150 | ||||
Settlements of asset retirement obligations | (151) | (27) | ||||
Write off of Deferred Debt Issuance Cost | 229 | 459 | ||||
Other Noncash Income (Expense) | 1,883 | 2,436 | ||||
(Increase) decrease in accounts receivable and other current assets | (20,941) | 7,413 | ||||
Increase (decrease) in accounts payable and accrued liabilities | 7,215 | (3,981) | ||||
Increase (Decrease) in Income Taxes Payable | 0 | (480) | ||||
Increase (decrease) in accrued interest | (137) | (505) | ||||
Net Cash Provided by (Used in) Operating Activities | 133,648 | 127,782 | ||||
Cash Flows from Investing Activities: | ||||||
Additions to property and equipment | (98,219) | (102,713) | ||||
Acquisition of oil and gas properties | (13,219) | (3,441) | ||||
Proceeds from Sale of Property, Plant, and Equipment | 0 | (4,752) | ||||
Payments on property sale obligations | (1,084) | (426) | ||||
Net Cash Provided by (Used in) Investing Activities | (112,522) | (101,828) | ||||
Cash Flows from Financing Activities: | ||||||
Proceeds from bank borrowings | 195,000 | 71,000 | ||||
Payments of bank borrowings | (227,000) | (97,000) | ||||
Proceeds from Issuance of Common Stock | 12,756 | 0 | ||||
Purchase of treasury shares | (612) | (90) | ||||
Payments of Debt Issuance Costs | (2,400) | 0 | ||||
Net Cash Provided by (Used in) Financing Activities | (22,256) | (26,090) | ||||
Net increase (decrease) in Cash, Cash Equivalents and Restricted Cash | (1,130) | (136) | ||||
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | $ 988 | $ 1,222 | 988 | 1,222 | $ 2,118 | $ 1,358 |
Supplemental Disclosures of Cash Flows Information: | ||||||
Cash paid during period for interest, net of amounts capitalized | 20,277 | 22,290 | ||||
Changes in capital accounts payable and capital accruals | 11,393 | (25,641) | ||||
Non-cash equity consideration for acquisitions | $ (10,023) | $ 0 |
General Information
General Information | 9 Months Ended |
Sep. 30, 2021 | |
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, 2020. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2021 | |
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 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. COVID-19 . The spread of COVID-19 and its impact on the global supply of and demand for crude oil caused volatility in the market price for crude oil during 2020. The spot price of West Texas Intermediate (“WTI”) crude oil declined over 50% in March and April of 2020 before gradually improving through the rest of 2020 and through the first three quarters of 2021. The spot price of Brent and WTI crude oil closed at approximately $64 and $59 per barrel, respectively, on March 31, 2021, approximately $77 and $74 per barrel, respectively, on June 30, 2021, and approximately $78 and $75 per barrel, respectively, on September 30, 2021. In response to these market conditions, including the COVID-19 pandemic and the volatility in oil prices during 2020, the Company released its sole drilling rig in April 2020 and deferred the completion and placement on production of eight wells until the second half of 2020. In the third quarter of 2020, the Company restarted completions activity and returned to sales all previously curtailed volumes as of December 31, 2020. As a result of the COVID-19 pandemic, the Company operated under a “work from home” policy applicable to all employees other than essential personnel whose physical presence was required either in the office or in the field until March 2021. Effective March 2021, the Company adjusted its “work from home” policy to a flexible work schedule, so that all employees returned to the corporate office, on a weekly rotation, while continuing to work from home. Except as described above regarding the curtailment of production in 2020, SilverBow has not experienced any material interruption to its ordinary course business processes as a result of the COVID-19 pandemic and the volatility in oil and gas prices. The Company will continue to monitor the COVID-19 situation and follow the advice of government and health leaders. Subsequent Events . We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements. On October 1, 2021, we closed on an all-stock transaction to acquire oil and gas assets in the Eagle Ford. The acquired assets include a 100% working interest in approximately 15,000 net oil-weighted acres across Atascosa, Fayette and Lavaca counties, as well as approximately 26,000 net gas-weighted acres directly offsetting our existing position in McMullen and Live Oak counties. After consideration of closing adjustments, we issued 1,341,990 shares of our common stock for an aggregate purchase price of $35.6 million, based on the Company's share price on the closing date. The acquisition is subject to further customary post-closing adjustments. The issuance of the shares of common stock was completed in reliance upon the exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”). The Company is currently evaluating the appropriate accounting treatment for this transaction. On October 8, 2021, the Company entered into another purchase and sale agreement to acquire oil and gas assets in the Eagle Ford. The total aggregate consideration of the acquisition is approximately $75 million, which includes $45 million in cash with the rest to be paid with the greater of (i) 1,351,961 shares of our common stock and (ii) the number of shares equal to $25 million divided by the volume weighted average share price of the Company's common stock for the 30 consecutive trading days ending on and including the first trading day preceding the closing date, subject to customary purchase price adjustments. The acquisition includes 62 net PDP wells with liquids production of approximately 71% (46% of production attributable to oil) and approximately 17,000 net acres across the oil window in La Salle, McMullen, DeWitt and Lavaca counties. Closing of the pending acquisition is expected to occur in the fourth quarter of 2021, subject to the satisfaction of certain conditions set forth in the purchase and sale agreement. The shares of common stock to be issued upon closing in accordance with this purchase and sale agreement will be made in reliance upon the exemption from the registration requirements of the Securities Act. The Company is currently evaluating the appropriate accounting treatment for this transaction upon closing. Through November 4, 2021, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after September 30, 2021: Oil Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2023 Contracts 1Q23 275 $ 69.40 2Q23 575 $ 68.40 3Q23 53,980 $ 66.55 Collar Contracts 2022 Contracts 1Q22 45,000 $ 73.00 $ 79.75 2Q22 45,500 $ 71.00 $ 78.00 3Q22 46,000 $ 70.00 $ 75.40 4Q22 46,000 $ 68.00 $ 73.60 2023 Contracts 1Q23 45,000 $ 65.00 $ 72.80 2Q23 45,500 $ 64.00 $ 70.85 3Q23 46,000 $ 63.00 $ 69.10 4Q23 46,000 $ 62.00 $ 67.55 Natural Gas Derivative Contracts Total Volumes Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Collar Contracts 2021 Contracts 4Q21 310,000 $ 6.00 $ 7.45 2022 Contracts 1Q22 590,000 $ 6.00 $ 7.45 NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2022 Contracts 1Q22 45,000 $ 39.25 2Q22 45,500 $ 32.82 3Q22 46,000 $ 31.29 4Q22 46,000 $ 31.09 There were no other material subsequent events requiring additional disclosure in these condensed consolidated financial statements. Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include: • the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom, and the Ceiling Test impairment calculation, • estimates related to the collectability of accounts receivable and the creditworthiness of our customers, • estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf, • estimates of future costs to develop and produce reserves, • accruals related to oil and gas sales, capital expenditures and lease operating expenses (“LOE”), • estimates in the calculation of share-based compensation expense, • estimates of our ownership in properties prior to final division of interest determination, • the estimated future cost and timing of asset retirement obligations, • estimates made in our income tax calculations, including the valuation of our deferred tax assets, • estimates in the calculation of the fair value of commodity derivative assets and liabilities, • estimates in the assessment of current litigation claims against the Company, • estimates used in the assessment of business combinations and asset purchases, • estimates in amounts due with respect to open state regulatory audits, and • estimates on future lease obligations. While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, reallocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known. We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated. Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended September 30, 2021 and 2020, such internal costs when capitalized totaled $1.2 million and $0.8 million, respectively. For the nine months ended September 30, 2021 and 2020, such internal costs capitalized totaled $3.5 million and $2.8 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 6 of these Notes to Condensed Consolidated Financial Statements for further discussion on capitalized interest costs). The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): September 30, 2021 December 31, 2020 Property and Equipment Proved oil and gas properties $ 1,445,818 $ 1,310,008 Unproved oil and gas properties 24,988 28,090 Furniture, fixtures and other equipment 5,780 5,275 Less – Accumulated depreciation, depletion, amortization & impairment (846,822) (801,279) Property and Equipment, Net $ 629,764 $ 542,094 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. Due to the effects of pricing and timing of projects we reported a non-cash impairment write-down, on a pre-tax basis, of $355.9 million for the nine months ended September 30, 2020 on our oil and natural gas properties. There was no impairment for the three and nine months ended September 30, 2021 and the three months ended September 30, 2020. 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, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both September 30, 2021 and December 31, 2020, we had an allowance for doubtful accounts of less than $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable, net” balance on the accompanying condensed consolidated balance sheets. At September 30, 2021, our “Accounts receivable, net” balance included $41.8 million for oil and gas sales, $0.8 million due from joint interest owners, $1.2 million for severance tax credit receivables and $0.4 million for other receivables. At December 31, 2020, our “Accounts receivable, net” balance included $18.8 million for oil and gas sales, $4.0 million due from joint interest owners, $2.4 million for severance tax credit receivables and $0.7 million for other receivables. Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the nine months ended September 30, 2021 and 2020 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $1.3 million and $1.1 million for the three months ended September 30, 2021 and 2020, respectively, and $3.6 million and $3.2 million for the nine months ended September 30, 2021 and 2020, 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. In March and April 2020, the COVID-19 pandemic caused volatility in the market price for crude oil due to the disruption of global supply and demand. In response to these market conditions and given the decline in oil prices and economic outlook for our Company, during the quarter ended June 30, 2020 management determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other federal deferred tax assets and, accordingly, recorded a full valuation allowance in the second quarter to offset its net federal deferred tax assets in excess of deferred tax liabilities. As a result of the full valuation allowance established at June 30, 2020, we recorded an income tax provision of $20.6 million for the nine months ended September 30, 2020, which was inclusive of state income tax expense. The Company maintains a full valuation allowance against its net federal deferred tax assets in excess of deferred tax liabilities as of September 30, 2021. We recorded an income tax benefit of $0.4 million for both the three and nine months ended September 30, 2021 and $0.6 million for the three months ended September 30, 2020 which were fully attributable to a current state income tax benefit. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At September 30, 2021 and December 31, 2020, 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. On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer-side Social Security payments, net operating loss carryback periods, alternative minimum tax credit refunds and modifications to the net interest deduction limitation. The Company continues to examine the impact that the CARES Act may have on its business but does not currently expect the CARES Act to have a material effect on its financial condition, results of operation, or liquidity. 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 and nine months ended September 30, 2021 and 2020 (in thousands): Three Months Ended September 30, 2021 Three Months Ended September 30, 2020 Nine Months Ended September 30, 2021 Nine Months Ended September 30, 2020 Oil, natural gas and NGLs sales: Oil $ 25,230 $ 17,665 $ 58,587 $ 40,979 Natural gas 62,529 23,595 172,234 73,170 NGLs 11,489 4,439 25,030 9,772 Total $ 99,249 $ 45,699 $ 255,850 $ 123,921 Accounts Payable and Accrued Liabilities . The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): September 30, 2021 December 31, 2020 Trade accounts payable $ 8,423 $ 15,930 Accrued operating expenses 3,585 2,491 Accrued compensation costs 3,955 3,771 Asset retirement obligations – current portion 492 441 Accrued non-income based taxes 6,141 1,819 Accrued corporate and legal fees 132 150 Payable for settled derivatives 13,621 829 Other payables 1,651 1,560 Total accounts payable and accrued liabilities $ 38,000 $ 26,991 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. Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock, held at cost” on the accompanying condensed consolidated balance sheets. For the nine months ended September 30, 2021 and 2020, we purchased 74,586 and 28,731 treasury shares, respectively, to satisfy withholding tax obligations arising upon the vesting of restricted shares. ATM Program. On August 13, 2021, the Company entered into an equity distribution agreement pursuant to which the Company may sell, from time to time in the open market, shares of the Company’s common stock, having aggregate proceeds of up to $40.0 million (the “ATM Program”). The Company intends to use the net proceeds from any sales through the ATM Program for general corporate purposes, including, but not limited to, financing of capital expenditures, repayment or refinancing of outstanding debt, financing acquisitions or investments, financing other business opportunities, and general working capital purposes. During the three months ended September 30, 2021 (from August 13, 2021 through September 30, 2021), the Company sold 669,600 shares of common stock for net proceeds of $12.8 million after deducting sales agents' commissions and other related expenses. |
Leases Leases (Notes)
Leases Leases (Notes) | 9 Months Ended |
Sep. 30, 2021 | |
Leases [Abstract] | |
Lessee, Operating Leases [Text Block] | (3) Leases The Company adopted the standard provided in the Financial Accounting Standards Board's Accounting Standards Update 2016-02 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 September 30, 2021, 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. Leases with an initial term of 12 months or less are not recorded on the balance sheet. The Company recognizes lease expense on a straight-line basis over the lease term. Lease costs represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are classified as follows (in thousands): Three Months Ended September 30, 2021 Three Months Ended September 30, 2020 Nine Months Ended September 30, 2021 Nine Months Ended September 30, 2020 Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets Property, plant and equipment acquisitions - short-term leases $ 1,189 $ — $ 3,009 $ 2,302 Property, plant and equipment acquisitions - operating leases — — — 10 Total lease costs in property, plant and equipment additions $ 1,189 $ — $ 3,009 $ 2,312 Three Months Ended September 30, 2021 Three Months Ended September 30, 2020 Nine Months Ended September 30, 2021 Nine Months Ended September 30, 2020 Lease Costs Included in the Condensed Consolidated Statements of Operations Lease operating expenses - short-term leases $ 314 $ 124 $ 1,399 $ 575 Lease operating expenses - operating leases 1,504 1,397 3,774 4,267 General and administrative, net - operating leases 303 172 653 532 Total lease cost expensed $ 2,121 $ 1,693 $ 5,826 $ 5,374 The lease term and the discount rate related to the Company's leases are as follows: September 30, 2021 Weighted-average remaining lease term (in years) 3.2 Weighted-average discount rate 4.1 % As of September 30, 2021, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands): As of September 30, 2021 2021 (Remaining) $ 1,791 2022 6,767 2023 5,938 2024 776 2025 776 Thereafter 1,176 Total undiscounted lease payments 17,224 Present value adjustment (1,209) Net operating lease liabilities $ 16,015 Supplemental cash flow information related to leases was as follows (in thousands): Nine Months Ended September 30, 2021 Nine Months Ended September 30, 2020 Cash paid for amounts included in the measurement of lease liabilities; Operating cash flows from operating leases $ 4,289 $ 4,793 Investing cash flows from operating leases $ — $ 10 |
Share-Based Compensation
Share-Based Compensation | 9 Months Ended |
Sep. 30, 2021 | |
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 $1.2 million and $1.1 million for the three months ended September 30, 2021 and 2020, respectively, and $3.5 million for both the nine months ended September 30, 2021 and 2020. Capitalized share-based compensation was less than $0.1 million for both the three months ended September 30, 2021 and 2020 and $0.2 million for both the nine months ended September 30, 2021 and 2020. 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 September 30, 2021, we had $0.2 million of unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the nine months ended September 30, 2021: Shares Wtd. Avg. Exer. Price Options outstanding, beginning of period 303,705 $ 27.73 Options forfeited (3,896) $ 16.96 Options expired (23,800) $ 23.25 Options outstanding, end of period 276,009 $ 28.12 Options exercisable, end of period 226,950 $ 28.53 Our outstanding stock option awards had $0.1 million measurable aggregate intrinsic value at September 30, 2021. At September 30, 2021, the weighted-average remaining contract life of stock option awards outstanding was 4.4 years and exercisable was 4.1 years. The total intrinsic value of stock option awards exercisable was less than $0.1 million for the nine months ended September 30, 2021. 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 September 30, 2021, we had $1.3 million unrecognized compensation expense related to our RSUs which is expected to be recognized over a weighted-average period of 0.8 years. The following table provides information regarding RSU activity for the nine months ended September 30, 2021: RSUs Wtd. Avg. Grant Price RSUs outstanding, beginning of period 574,916 $ 9.02 RSUs granted 100,178 $ 8.33 RSUs forfeited (17,802) $ 11.09 RSUs vested (312,447) $ 9.14 RSUs outstanding, end of period 344,845 $ 8.60 Performance-Based Stock Units On February 20, 2018, the Company granted 30,700 PSUs for which the number of shares earned is based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2018 to December 31, 2020. The awards contain market conditions which allow a payout ranging between 0% payout and 200% of the target payout. The fair value as of the date of valuation was $41.66 per unit or 150.61% 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 had a cliff-vesting period of three On May 21, 2019, the Company granted 99,500 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, 2019 to December 31, 2021. The awards contain market conditions which allow 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 have 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 As of September 30, 2021, we had $1.7 million unrecognized compensation expense related to our PSUs based on the assumption of 100% target payout. The remaining weighted-average performance period is 1.1 years while 23,800 shares vested during the nine months ended September 30, 2021. |
Earnings Per Share
Earnings Per Share | 9 Months Ended |
Sep. 30, 2021 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | (5) Earnings Per Share Basic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three and nine months ended September 30, 2021 and 2020 are discussed below. The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts): Three Months Ended September 30, 2021 Three Months Ended September 30, 2020 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ (35,943) 12,629 $ (2.85) $ (6,896) 11,935 $ (0.58) Dilutive Securities: RSU Awards — — Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ (35,943) 12,629 $ (2.85) $ (6,896) 11,935 $ (0.58) Nine Months Ended September 30, 2021 Nine Months Ended September 30, 2020 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ (27,514) 12,283 $ (2.24) $ (318,730) 11,890 $ (26.81) Dilutive Securities: RSU Awards — — Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ (27,514) 12,283 $ (2.24) $ (318,730) 11,890 $ (26.81) Approximately 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for both the three months ended September 30, 2021 and 2020 because they were antidilutive due to the net loss, while 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for both the nine months ended September 30, 2021 and 2020 because they were antidilutive due to the net loss. There were no antidilutive shares of RSUs that could be converted to common shares for the three months ended September 30, 2021, while approximately 0.2 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended September 30, 2020, because they were antidilutive due to the net loss, while less than 0.1 million and 0.2 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the nine months ended September 30, 2021 and 2020 because they were antidilutive due to the net loss. There were no antidilutive shares of PSUs that could be converted to common shares for the three months ended September 30, 2021, while approximately 0.1 million shares of PSUs were not included for the three months ended September 30, 2020 because they were antidilutive due to the net loss, while there were no shares of PSUs that could be converted to common shares for the nine months ended September 30, 2021, while 0.1 million shares of PSUs were not included for the nine months ended September 30, 2020 because they were antidilutive due to the net loss. |
Long-Term Debt
Long-Term Debt | 9 Months Ended |
Sep. 30, 2021 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | (6) Long-Term Debt The Company's long-term debt consisted of the following (in thousands): September 30, 2021 December 31, 2020 Credit Facility Borrowings (1) $ 198,000 $ 230,000 Second Lien Notes due 2024 200,000 200,000 398,000 430,000 Unamortized discount on Second Lien Notes due 2024 (1,086) (1,295) Unamortized debt issuance cost on Second Lien Notes due 2024 (3,188) (3,800) Long-Term Debt, net $ 393,726 $ 424,905 (1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “ Other Long-Term Assets ” in our consolidated balance sheet. As of September 30, 2021 and December 31, 2020, we had $2.8 million and $1.4 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings. Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $198.0 million and $230.0 million as of September 30, 2021 and December 31, 2020, respectively. The Company is a party to a First Amended and Restated Senior Secured Revolving Credit Agreement with JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended (such agreement, the “Credit Agreement” and the borrowing facility provided thereby, the “Credit Facility”). In conjunction with its regularly scheduled semi-annual redetermination, the Company entered into the Seventh Amendment to the Credit Facility, effective April 16, 2021 (the “Seventh Amendment”), which among other things, (i) redetermined the borrowing base under the Credit Facility to $300 million (from $310 million), (ii) extended the maturity of our Credit Facility from April 19, 2022 to April 19, 2024; (iii) increased the applicable margin used to calculate the interest rate under the Credit Facility by 50 basis points, with the specific applicable margins determined by reference to borrowing base utilization; (iv) reduced the permitted ratio of Total Debt to EBITDA (each as defined in the Credit Agreement) from 3.50 to 1.00 (a) to 3.25 to 1.00 for the fiscal quarters ending on or before December 31, 2021 and (b) to 3.00 to 1.00 commencing with the fiscal quarter ending March 31, 2022; (v) implemented a minimum rolling hedge requirement of 50% of reasonably anticipated projected production from proved developed producing reserves for a 24-month period, and (vi) increased the mortgage coverage and title requirements from 85% to 90%. The Credit Facility provides for a maximum credit amount of $600.0 million, subject to the current borrowing base of $300.0 million as of September 30, 2021. The borrowing base is regularly redetermined on or about May and November of each calendar year and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders, in their discretion, in accordance with their oil and gas lending criteria at the time of the relevant redetermination. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to $25 million, which reduces the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit. 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”) or the LIBOR Rate plus the applicable margin (“Eurodollar Loans”). Effective April 16, 2021, the applicable margin ranged from 2.25% to 3.25% for ABR Loans and 3.25% to 4.25% for Eurodollar Loans. The Alternate Base Rate and LIBOR Rate 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. In July 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. At the present time, the Credit Facility is subject to LIBOR rates but has a term that extends beyond the end of 2021 when LIBOR will be phased out. The Credit Agreement currently provides for options in the event LIBOR is discontinued. It is expected that the Credit Agreement will be amended at its upcoming fall redetermination to reference an alternative rate as established by JP Morgan, as Administrative Agent, and the Company. 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 90% 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 (i) 3.25 to 1.00 as of the last day of each fiscal quarter for any fiscal quarter ending on or before December 31, 2021 and (ii) 3.00 to 1.00 as of the last day of each fiscal quarter, commencing with fiscal quarter ending March 31, 2022; and • a current ratio, as defined in the Credit Agreement, which includes in the numerator available borrowings undrawn under the borrowing base, of not less than 1.00 to 1.00 as of the last day of each fiscal quarter. As of September 30, 2021, 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 $2.8 million and $2.9 million for the three months ended September 30, 2021 and 2020, respectively, and $8.1 million and $9.8 million for the nine months ended September 30, 2021 and 2020, respectively. There was no capitalized interest on our unproved properties for both the three months ended September 30, 2021 and 2020, respectively, and for both the nine months ended September 30, 2021 and 2020, 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. The Company has the ability, subject to the satisfaction of certain conditions (including compliance with the Asset Coverage Ratio described below and the agreement of the holders to purchase such additional notes), to issue additional notes in a principal amount not to exceed $100.0 million. The Second Lien matures on December 15, 2024. Interest on the Second Lien is payable quarterly and accrues at LIBOR plus 7.5%; provided that if LIBOR ceases to be available, the Second Lien provides for a mechanism to use ABR (an alternate base rate) plus 6.5% as the applicable interest rate. The definitions of LIBOR and ABR are set forth in the Note Purchase Agreement. To the extent that a payment, insolvency, or, at the holders’ election, another default exists and is continuing, all amounts outstanding under the Second Lien will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. Additionally, to the extent the Company were to default on the Second Lien, this would potentially trigger a cross-default under our Credit Facility. 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, subject to a repayment fee of 1.0% of the principal amount of the Second Lien being prepaid through December 15, 2021; and thereafter, 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 85% of estimated PV-9 (defined below), of proved reserves of the Company and its subsidiary and 85% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions by the administrative agent of the Credit Facility. PV-9 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 9%. 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 4.5 to 1.0 as of the last day of each fiscal quarter. As of September 30, 2021, the Company was in compliance with all financial covenants under the Second Lien. The Second Lien contains certain customary representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Second Lien contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Second Lien to be immediately due and payable. As of September 30, 2021, total net amounts recorded for the Second Lien were $195.7 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $4.6 million for both the three months ended September 30, 2021 and 2020, respectively, and $13.8 million and $14.1 million for the nine months ended September 30, 2021 and 2020, respectively. |
Acquisitions and Dispositions A
Acquisitions and Dispositions Acquisitions and Dispostions | 9 Months Ended |
Sep. 30, 2021 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Acquisitions and Dispositions | (7) Acquisitions and Dispositions Effective December 22, 2017, the Company closed a purchase and sale contract to sell the Company's wellbores and facilities in the Bay De Chene field and recorded a $16.3 million obligation related to the funding of certain plugging and abandonment costs. Of the $16.3 million original obligation, $1.1 million and $0.4 million was paid during the nine months ended September 30, 2021 and 2020, respectively. The remaining obligation under this contract is $0.5 million and is carried in the accompanying condensed consolidated balance sheet current liability in “Accounts payable and accrued liabilities” as of September 30, 2021. On August 3, 2021, the Company acquired the remaining working interest in 12 wells that SilverBow operates and additional Eagle Ford La Mesa assets and 850 net acres in our Webb County Dry Gas play. The total aggregate consideration was approximately $24 million, consisting of $13.2 million in cash and 516,675 shares of common stock valued at approximately $10.0 million on the closing date. The Company accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. As a result, we allocated the purchase price to proved oil and gas properties. The issuance of the shares of common stock of the Company was completed in reliance upon the exemption from the registration requirements of the Securities Act. |
Price-Risk Management Price-Ris
Price-Risk Management Price-Risk Management (Notes) | 9 Months Ended |
Sep. 30, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Price-Risk Management Activities | (8) Price-Risk Management Activities Derivatives are recorded on the balance sheet at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. The Company's price-risk management policy is to use derivative instruments to protect against declines in oil and natural gas prices, primarily through the purchase of commodity price swaps and collars as well as basis swaps. During the three months ended September 30, 2021 and 2020, the Company recorded losses of $88.6 million and losses of $12.9 million, respectively, on its commodity derivatives. During the nine months ended September 30, 2021 and 2020, the Company recorded losses of $152.9 million and gains of $66.9 million, respectively. The Company made cash payments of $29.0 million and collected cash payments of $76.1 million for settled derivative contracts during the nine months ended September 30, 2021 and 2020, respectively. Included in our collected cash payments during the nine months ended September 30, 2020 was $38.3 million for monetized derivative contracts. At September 30, 2021 and December 31, 2020, there were less than $0.1 million and $0.8 million, respectively, in receivables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts receivable, net” and were subsequently collected in October 2021 and January 2021, respectively. At September 30, 2021 and December 31, 2020, we also had $13.6 million and $0.8 million, respectively, in payables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts payable and accrued liabilities” and were subsequently paid in October 2021 and January 2021, 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 and are periodically verified against quotes from brokers. At September 30, 2021, there was $0.7 million and less than $0.1 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $94.8 million and $22.0 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2020, there was $4.8 million and $0.3 million in current and long-term unsettled derivative assets, respectively, and $8.2 million and $2.9 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 $116.1 million net fair value liability at September 30, 2021, and a $6.0 million net fair value liability at December 31, 2020. For further discussion related to the fair value of the Company's derivatives, refer to Note 9 of these Notes to Condensed Consolidated Financial Statements. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of September 30, 2021: Oil Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2021 Contracts 4Q21 272,662 $ 57.50 2022 Contracts 1Q22 223,455 $ 49.32 2Q22 136,500 $ 56.66 3Q22 246,100 $ 49.63 4Q22 184,000 $ 54.84 2023 Contracts 1Q23 81,900 $ 55.70 Collar Contracts 2021 Contracts 4Q21 84,640 $ 34.70 $ 41.01 2022 Contracts 1Q22 40,500 $ 40.00 $ 45.55 2Q22 115,850 $ 39.25 $ 46.20 2023 Contracts 2Q23 65,975 $ 56.00 $ 63.20 Natural Gas Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2021 Contracts 4Q21 1,530,000 $ 3.60 2022 Contracts 1Q22 232,500 $ 4.00 2Q22 3,795,000 $ 2.99 3Q22 4,142,100 $ 3.02 4Q22 2,760,000 $ 3.14 Collar Contracts 2021 Contracts 4Q21 9,301,000 $ 2.73 $ 3.15 2022 Contracts 1Q22 9,055,000 $ 2.87 $ 3.55 2Q22 6,156,500 $ 2.29 $ 2.74 3Q22 6,739,000 $ 2.60 $ 2.98 4Q22 7,765,076 $ 2.69 $ 3.20 2023 Contracts 1Q23 8,347,000 $ 2.89 $ 3.52 2Q23 4,125,000 $ 2.49 $ 2.92 3Q23 1,380,000 $ 2.60 $ 3.13 Natural Gas Basis Derivative Swaps Total Volumes Weighted-Average Price 2021 Contracts 4Q21 11,040,000 $ (0.013) 2022 Contracts 1Q22 8,100,000 $ 0.093 2Q22 3,640,000 $ (0.051) 3Q22 3,680,000 $ (0.043) 4Q22 3,680,000 $ (0.048) Oil Basis Swaps Total Volumes (Bbls) Weighted-Average Price 2021 Contracts 4Q21 241,500 $ 1.28 Calendar Monthly Roll Differential Swaps 2021 Contracts 4Q21 241,500 $ (0.33) 2022 Contracts 1Q22 261,000 $ 0.19 2Q22 263,900 $ 0.19 3Q22 266,800 $ 0.19 4Q22 266,800 $ 0.19 NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2021 Contracts 4Q21 192,324 $ 24.26 2022 Contracts 1Q22 135,000 $ 25.75 2Q22 91,000 $ 26.87 3Q22 92,000 $ 26.87 4Q22 92,000 $ 26.87 |
Fair Value Measurements
Fair Value Measurements | 9 Months Ended |
Sep. 30, 2021 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | (9) Fair Value Measurements Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien. 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 and are periodically verified against quotes from brokers. 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). 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 September 30, 2021 and December 31, 2020, 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 millions) Total Quoted Prices in Significant Other Significant September 30, 2021 Assets Natural Gas Basis Derivatives $ 0.6 $ — $ 0.6 $ — Oil Basis Derivatives 0.1 — 0.1 — Liabilities Natural Gas Derivatives 80.3 — 80.3 — Natural Gas Basis Derivatives 2.6 — 2.6 — Oil Derivatives 26.3 — 26.3 — Oil Basis Derivatives 0.8 — 0.8 — NGL Derivatives 6.7 — 6.7 — December 31, 2020 Assets Natural Gas Derivatives 1.5 — 1.5 — Natural Gas Basis Derivatives 1.1 — 1.1 — Oil Derivatives 2.5 — 2.5 — Liabilities Natural Gas Derivatives 4.0 — 4.0 — Natural Gas Basis Derivatives 0.4 — 0.4 — Oil Derivatives 5.9 — 5.9 — Oil Basis Derivatives 0.8 — 0.8 — 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) | 9 Months Ended |
Sep. 30, 2021 | |
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, 2020 and the nine months ended September 30, 2021 (in thousands): Asset Retirement Obligations as of December 31, 2019 $ 4,447 Accretion expense 354 Liabilities incurred for new wells and facilities construction 281 Reductions due to plugged wells and facilities (103) Revisions in estimates (5) Asset Retirement Obligations as of December 31, 2020 $ 4,974 Accretion expense 226 Liabilities incurred for new wells, acquired wells and facilities construction 347 Reductions due to plugged wells and facilities (192) Revisions in estimates (157) Asset Retirement Obligations as of September 30, 2021 $ 5,198 At September 30, 2021 and December 31, 2020, approximately $0.5 million and $0.4 million, respectively, of our asset retirement obligations 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 | 9 Months Ended |
Sep. 30, 2021 | |
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. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 9 Months Ended |
Sep. 30, 2021 | |
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 trend in Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of the assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying condensed consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying condensed consolidated financial statements. |
Use of Estimates | Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include: • the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom, and the Ceiling Test impairment calculation, • estimates related to the collectability of accounts receivable and the creditworthiness of our customers, • estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf, • estimates of future costs to develop and produce reserves, • accruals related to oil and gas sales, capital expenditures and lease operating expenses (“LOE”), • estimates in the calculation of share-based compensation expense, • estimates of our ownership in properties prior to final division of interest determination, • the estimated future cost and timing of asset retirement obligations, • estimates made in our income tax calculations, including the valuation of our deferred tax assets, • estimates in the calculation of the fair value of commodity derivative assets and liabilities, • estimates in the assessment of current litigation claims against the Company, • estimates used in the assessment of business combinations and asset purchases, • estimates in amounts due with respect to open state regulatory audits, and • estimates on future lease obligations. While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, reallocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known. We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated. |
Property and Equipment | Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended September 30, 2021 and 2020, such internal costs when capitalized totaled $1.2 million and $0.8 million, respectively. For the nine months ended September 30, 2021 and 2020, such internal costs capitalized totaled $3.5 million and $2.8 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 6 of these Notes to Condensed Consolidated Financial Statements for further discussion on capitalized interest costs). The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): September 30, 2021 December 31, 2020 Property and Equipment Proved oil and gas properties $ 1,445,818 $ 1,310,008 Unproved oil and gas properties 24,988 28,090 Furniture, fixtures and other equipment 5,780 5,275 Less – Accumulated depreciation, depletion, amortization & impairment (846,822) (801,279) Property and Equipment, Net $ 629,764 $ 542,094 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 | Full-Cost Ceiling Test . At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10% and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”). The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. |
Accounts Receivable, Net | Accounts Receivable, Net. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both September 30, 2021 and December 31, 2020, we had an allowance for doubtful accounts of less than $0.1 million. The allowance for doubtful accounts 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. In March and April 2020, the COVID-19 pandemic caused volatility in the market price for crude oil due to the disruption of global supply and demand. In response to these market conditions and given the decline in oil prices and economic outlook for our Company, during the quarter ended June 30, 2020 management determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other federal deferred tax assets and, accordingly, recorded a full valuation allowance in the second quarter to offset its net federal deferred tax assets in excess of deferred tax liabilities. As a result of the full valuation allowance established at June 30, 2020, we recorded an income tax provision of $20.6 million for the nine months ended September 30, 2020, which was inclusive of state income tax expense. The Company maintains a full valuation allowance against its net federal deferred tax assets in excess of deferred tax liabilities as of September 30, 2021. We recorded an income tax benefit of $0.4 million for both the three and nine months ended September 30, 2021 and $0.6 million for the three months ended September 30, 2020 which were fully attributable to a current state income tax benefit. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At September 30, 2021 and December 31, 2020, 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. On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer-side Social Security payments, net operating loss carryback periods, alternative minimum tax credit refunds and modifications to the net interest deduction limitation. The Company continues to examine the impact that the CARES Act may have on its business but does not currently expect the CARES Act to have a material effect on its financial condition, results of operation, or liquidity. |
Revenue Recognition | Revenue Recognition. Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. Natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers. |
Accounts Payable and Accrued Liabilities | Accounts Payable and Accrued Liabilities . The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): September 30, 2021 December 31, 2020 Trade accounts payable $ 8,423 $ 15,930 Accrued operating expenses 3,585 2,491 Accrued compensation costs 3,955 3,771 Asset retirement obligations – current portion 492 441 Accrued non-income based taxes 6,141 1,819 Accrued corporate and legal fees 132 150 Payable for settled derivatives 13,621 829 Other payables 1,651 1,560 Total accounts payable and accrued liabilities $ 38,000 $ 26,991 |
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. |
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) | 9 Months Ended |
Sep. 30, 2021 | |
Leases [Abstract] | |
Lessee, Leases [Policy Text Block] | Leases The Company adopted the standard provided in the Financial Accounting Standards Board's Accounting Standards Update 2016-02 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 September 30, 2021, all of the Company’s leases were operating leases. |
Share-Based Compensation Share-
Share-Based Compensation Share-Based Compensation (Policies) | 9 Months Ended |
Sep. 30, 2021 | |
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) | 9 Months Ended |
Sep. 30, 2021 | |
Earnings Per Share [Abstract] | |
Earnings Per Share, Policy | Earnings Per ShareBasic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three and nine months ended September 30, 2021 and 2020 are discussed below. |
Long-Term Debt Long-Term Debt (
Long-Term Debt Long-Term Debt (Policies) | 9 Months Ended |
Sep. 30, 2021 | |
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) | 9 Months Ended |
Sep. 30, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Price-Risk Management Activities, Policy | Price-Risk Management Activities Derivatives are recorded on the 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) | 9 Months Ended |
Sep. 30, 2021 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments, Policy | Fair Value Measurements Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien. 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 and are periodically verified against quotes from brokers. 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). 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) | 9 Months Ended |
Sep. 30, 2021 | |
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) | 9 Months Ended |
Sep. 30, 2021 | |
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) | 9 Months Ended |
Sep. 30, 2021 | |
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. On October 1, 2021, we closed on an all-stock transaction to acquire oil and gas assets in the Eagle Ford. The acquired assets include a 100% working interest in approximately 15,000 net oil-weighted acres across Atascosa, Fayette and Lavaca counties, as well as approximately 26,000 net gas-weighted acres directly offsetting our existing position in McMullen and Live Oak counties. After consideration of closing adjustments, we issued 1,341,990 shares of our common stock for an aggregate purchase price of $35.6 million, based on the Company's share price on the closing date. The acquisition is subject to further customary post-closing adjustments. The issuance of the shares of common stock was completed in reliance upon the exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”). The Company is currently evaluating the appropriate accounting treatment for this transaction. On October 8, 2021, the Company entered into another purchase and sale agreement to acquire oil and gas assets in the Eagle Ford. The total aggregate consideration of the acquisition is approximately $75 million, which includes $45 million in cash with the rest to be paid with the greater of (i) 1,351,961 shares of our common stock and (ii) the number of shares equal to $25 million divided by the volume weighted average share price of the Company's common stock for the 30 consecutive trading days ending on and including the first trading day preceding the closing date, subject to customary purchase price adjustments. The acquisition includes 62 net PDP wells with liquids production of approximately 71% (46% of production attributable to oil) and approximately 17,000 net acres across the oil window in La Salle, McMullen, DeWitt and Lavaca counties. Closing of the pending acquisition is expected to occur in the fourth quarter of 2021, subject to the satisfaction of certain conditions set forth in the purchase and sale agreement. The shares of common stock to be issued upon closing in accordance with this purchase and sale agreement will be made in reliance upon the exemption from the registration requirements of the Securities Act. The Company is currently evaluating the appropriate accounting treatment for this transaction upon closing. Through November 4, 2021, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after September 30, 2021: Oil Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2023 Contracts 1Q23 275 $ 69.40 2Q23 575 $ 68.40 3Q23 53,980 $ 66.55 Collar Contracts 2022 Contracts 1Q22 45,000 $ 73.00 $ 79.75 2Q22 45,500 $ 71.00 $ 78.00 3Q22 46,000 $ 70.00 $ 75.40 4Q22 46,000 $ 68.00 $ 73.60 2023 Contracts 1Q23 45,000 $ 65.00 $ 72.80 2Q23 45,500 $ 64.00 $ 70.85 3Q23 46,000 $ 63.00 $ 69.10 4Q23 46,000 $ 62.00 $ 67.55 Natural Gas Derivative Contracts Total Volumes Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Collar Contracts 2021 Contracts 4Q21 310,000 $ 6.00 $ 7.45 2022 Contracts 1Q22 590,000 $ 6.00 $ 7.45 NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2022 Contracts 1Q22 45,000 $ 39.25 2Q22 45,500 $ 32.82 3Q22 46,000 $ 31.29 4Q22 46,000 $ 31.09 There were no other material subsequent events requiring additional disclosure in these condensed consolidated financial statements. |
Property and Equipment | The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): September 30, 2021 December 31, 2020 Property and Equipment Proved oil and gas properties $ 1,445,818 $ 1,310,008 Unproved oil and gas properties 24,988 28,090 Furniture, fixtures and other equipment 5,780 5,275 Less – Accumulated depreciation, depletion, amortization & impairment (846,822) (801,279) Property and Equipment, Net $ 629,764 $ 542,094 |
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 and nine months ended September 30, 2021 and 2020 (in thousands): Three Months Ended September 30, 2021 Three Months Ended September 30, 2020 Nine Months Ended September 30, 2021 Nine Months Ended September 30, 2020 Oil, natural gas and NGLs sales: Oil $ 25,230 $ 17,665 $ 58,587 $ 40,979 Natural gas 62,529 23,595 172,234 73,170 NGLs 11,489 4,439 25,030 9,772 Total $ 99,249 $ 45,699 $ 255,850 $ 123,921 |
Accounts Payable and Accrued Liabilities | The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): September 30, 2021 December 31, 2020 Trade accounts payable $ 8,423 $ 15,930 Accrued operating expenses 3,585 2,491 Accrued compensation costs 3,955 3,771 Asset retirement obligations – current portion 492 441 Accrued non-income based taxes 6,141 1,819 Accrued corporate and legal fees 132 150 Payable for settled derivatives 13,621 829 Other payables 1,651 1,560 Total accounts payable and accrued liabilities $ 38,000 $ 26,991 |
Leases Leases (Tables)
Leases Leases (Tables) | 9 Months Ended |
Sep. 30, 2021 | |
Leases [Abstract] | |
Lease, Cost [Table Text Block] | Lease costs represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are classified as follows (in thousands): Three Months Ended September 30, 2021 Three Months Ended September 30, 2020 Nine Months Ended September 30, 2021 Nine Months Ended September 30, 2020 Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets Property, plant and equipment acquisitions - short-term leases $ 1,189 $ — $ 3,009 $ 2,302 Property, plant and equipment acquisitions - operating leases — — — 10 Total lease costs in property, plant and equipment additions $ 1,189 $ — $ 3,009 $ 2,312 Three Months Ended September 30, 2021 Three Months Ended September 30, 2020 Nine Months Ended September 30, 2021 Nine Months Ended September 30, 2020 Lease Costs Included in the Condensed Consolidated Statements of Operations Lease operating expenses - short-term leases $ 314 $ 124 $ 1,399 $ 575 Lease operating expenses - operating leases 1,504 1,397 3,774 4,267 General and administrative, net - operating leases 303 172 653 532 Total lease cost expensed $ 2,121 $ 1,693 $ 5,826 $ 5,374 |
Lessee, Operating Lease, Disclosure [Table Text Block] | The lease term and the discount rate related to the Company's leases are as follows: September 30, 2021 Weighted-average remaining lease term (in years) 3.2 Weighted-average discount rate 4.1 % |
Lessee, Operating Lease, Liability, Maturity [Table Text Block] | As of September 30, 2021, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands): As of September 30, 2021 2021 (Remaining) $ 1,791 2022 6,767 2023 5,938 2024 776 2025 776 Thereafter 1,176 Total undiscounted lease payments 17,224 Present value adjustment (1,209) Net operating lease liabilities $ 16,015 |
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block] | Supplemental cash flow information related to leases was as follows (in thousands): Nine Months Ended September 30, 2021 Nine Months Ended September 30, 2020 Cash paid for amounts included in the measurement of lease liabilities; Operating cash flows from operating leases $ 4,289 $ 4,793 Investing cash flows from operating leases $ — $ 10 |
Share-Based Compensation (Table
Share-Based Compensation (Tables) | 9 Months Ended |
Sep. 30, 2021 | |
Share-based Payment Arrangement [Abstract] | |
Stock option activity | The following table provides information regarding stock option award activity for the nine months ended September 30, 2021: Shares Wtd. Avg. Exer. Price Options outstanding, beginning of period 303,705 $ 27.73 Options forfeited (3,896) $ 16.96 Options expired (23,800) $ 23.25 Options outstanding, end of period 276,009 $ 28.12 Options exercisable, end of period 226,950 $ 28.53 |
Restricted stock activity | The following table provides information regarding RSU activity for the nine months ended September 30, 2021: RSUs Wtd. Avg. Grant Price RSUs outstanding, beginning of period 574,916 $ 9.02 RSUs granted 100,178 $ 8.33 RSUs forfeited (17,802) $ 11.09 RSUs vested (312,447) $ 9.14 RSUs outstanding, end of period 344,845 $ 8.60 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2021 | |
Earnings Per Share [Abstract] | |
Reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS | The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts): Three Months Ended September 30, 2021 Three Months Ended September 30, 2020 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ (35,943) 12,629 $ (2.85) $ (6,896) 11,935 $ (0.58) Dilutive Securities: RSU Awards — — Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ (35,943) 12,629 $ (2.85) $ (6,896) 11,935 $ (0.58) Nine Months Ended September 30, 2021 Nine Months Ended September 30, 2020 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ (27,514) 12,283 $ (2.24) $ (318,730) 11,890 $ (26.81) Dilutive Securities: RSU Awards — — Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ (27,514) 12,283 $ (2.24) $ (318,730) 11,890 $ (26.81) |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 9 Months Ended |
Sep. 30, 2021 | |
Debt Disclosure [Abstract] | |
Schedule of Long-term Debt Instruments | The Company's long-term debt consisted of the following (in thousands): September 30, 2021 December 31, 2020 Credit Facility Borrowings (1) $ 198,000 $ 230,000 Second Lien Notes due 2024 200,000 200,000 398,000 430,000 Unamortized discount on Second Lien Notes due 2024 (1,086) (1,295) Unamortized debt issuance cost on Second Lien Notes due 2024 (3,188) (3,800) Long-Term Debt, net $ 393,726 $ 424,905 (1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “ Other Long-Term Assets ” in our consolidated balance sheet. As of September 30, 2021 and December 31, 2020, we had $2.8 million and $1.4 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings. |
Price-Risk Management Price-R_3
Price-Risk Management Price-Risk Management (Tables) | 9 Months Ended |
Sep. 30, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Derivative Instruments [Table Text Block] | The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of September 30, 2021: Oil Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2021 Contracts 4Q21 272,662 $ 57.50 2022 Contracts 1Q22 223,455 $ 49.32 2Q22 136,500 $ 56.66 3Q22 246,100 $ 49.63 4Q22 184,000 $ 54.84 2023 Contracts 1Q23 81,900 $ 55.70 Collar Contracts 2021 Contracts 4Q21 84,640 $ 34.70 $ 41.01 2022 Contracts 1Q22 40,500 $ 40.00 $ 45.55 2Q22 115,850 $ 39.25 $ 46.20 2023 Contracts 2Q23 65,975 $ 56.00 $ 63.20 Natural Gas Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2021 Contracts 4Q21 1,530,000 $ 3.60 2022 Contracts 1Q22 232,500 $ 4.00 2Q22 3,795,000 $ 2.99 3Q22 4,142,100 $ 3.02 4Q22 2,760,000 $ 3.14 Collar Contracts 2021 Contracts 4Q21 9,301,000 $ 2.73 $ 3.15 2022 Contracts 1Q22 9,055,000 $ 2.87 $ 3.55 2Q22 6,156,500 $ 2.29 $ 2.74 3Q22 6,739,000 $ 2.60 $ 2.98 4Q22 7,765,076 $ 2.69 $ 3.20 2023 Contracts 1Q23 8,347,000 $ 2.89 $ 3.52 2Q23 4,125,000 $ 2.49 $ 2.92 3Q23 1,380,000 $ 2.60 $ 3.13 Natural Gas Basis Derivative Swaps Total Volumes Weighted-Average Price 2021 Contracts 4Q21 11,040,000 $ (0.013) 2022 Contracts 1Q22 8,100,000 $ 0.093 2Q22 3,640,000 $ (0.051) 3Q22 3,680,000 $ (0.043) 4Q22 3,680,000 $ (0.048) Oil Basis Swaps Total Volumes (Bbls) Weighted-Average Price 2021 Contracts 4Q21 241,500 $ 1.28 Calendar Monthly Roll Differential Swaps 2021 Contracts 4Q21 241,500 $ (0.33) 2022 Contracts 1Q22 261,000 $ 0.19 2Q22 263,900 $ 0.19 3Q22 266,800 $ 0.19 4Q22 266,800 $ 0.19 NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2021 Contracts 4Q21 192,324 $ 24.26 2022 Contracts 1Q22 135,000 $ 25.75 2Q22 91,000 $ 26.87 3Q22 92,000 $ 26.87 4Q22 92,000 $ 26.87 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended |
Sep. 30, 2021 | |
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 September 30, 2021 and December 31, 2020, 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 millions) Total Quoted Prices in Significant Other Significant September 30, 2021 Assets Natural Gas Basis Derivatives $ 0.6 $ — $ 0.6 $ — Oil Basis Derivatives 0.1 — 0.1 — Liabilities Natural Gas Derivatives 80.3 — 80.3 — Natural Gas Basis Derivatives 2.6 — 2.6 — Oil Derivatives 26.3 — 26.3 — Oil Basis Derivatives 0.8 — 0.8 — NGL Derivatives 6.7 — 6.7 — December 31, 2020 Assets Natural Gas Derivatives 1.5 — 1.5 — Natural Gas Basis Derivatives 1.1 — 1.1 — Oil Derivatives 2.5 — 2.5 — Liabilities Natural Gas Derivatives 4.0 — 4.0 — Natural Gas Basis Derivatives 0.4 — 0.4 — Oil Derivatives 5.9 — 5.9 — Oil Basis Derivatives 0.8 — 0.8 — |
Asset Retirement Obligations _3
Asset Retirement Obligations Asset Retirement Obligations (Tables) | 9 Months Ended |
Sep. 30, 2021 | |
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, 2020 and the nine months ended September 30, 2021 (in thousands): Asset Retirement Obligations as of December 31, 2019 $ 4,447 Accretion expense 354 Liabilities incurred for new wells and facilities construction 281 Reductions due to plugged wells and facilities (103) Revisions in estimates (5) Asset Retirement Obligations as of December 31, 2020 $ 4,974 Accretion expense 226 Liabilities incurred for new wells, acquired wells and facilities construction 347 Reductions due to plugged wells and facilities (192) Revisions in estimates (157) Asset Retirement Obligations as of September 30, 2021 $ 5,198 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies (Details) $ in Thousands | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2021USD ($)bblMMBTU$ / MMBTU$ / Boe | Sep. 30, 2020USD ($) | Sep. 30, 2021USD ($)bblMMBTU$ / MMBTU$ / Boe | Sep. 30, 2020USD ($) | Nov. 04, 2021bblMMBTU$ / MMBTU$ / Boe | Dec. 31, 2020USD ($) | |
Property and Equipment | ||||||
Proved oil and gas properties | $ | $ 1,445,818 | $ 1,445,818 | $ 1,310,008 | |||
Unproved oil and gas properties | $ | 24,988 | 24,988 | 28,090 | |||
Furniture, fixtures, and other equipment | $ | 5,780 | 5,780 | 5,275 | |||
Less - Accumulated depreciation, depletion, and amortization | $ | (846,822) | (846,822) | (801,279) | |||
Net Furniture, Fixtures and other equipment | $ | 629,764 | 629,764 | 542,094 | |||
Disaggregation of Revenue [Line Items] | ||||||
Oil and gas sales | $ | 99,249 | $ 45,699 | 255,850 | $ 123,921 | ||
Accounts Payable and Accrued Liabilities | ||||||
Trade accounts payable | $ | 8,423 | 8,423 | 15,930 | |||
Accrued operating expenses | $ | 3,585 | 3,585 | 2,491 | |||
Accrued compensation costs | $ | 3,955 | 3,955 | 3,771 | |||
Asset retirement obligation - current portion | $ | 492 | 492 | 441 | |||
Accrued non-income based taxes | $ | 6,141 | 6,141 | 1,819 | |||
Accrued corporate and legal fees | $ | 132 | 132 | 150 | |||
Payables for Settled Derivatives | $ | 13,621 | 13,621 | 829 | |||
Other payables | $ | 1,651 | 1,651 | 1,560 | |||
Total Accounts payable and accrued liabilities | $ | 38,000 | 38,000 | $ 26,991 | |||
Oil sales [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Oil and gas sales | $ | 25,230 | 17,665 | 58,587 | 40,979 | ||
Natural gas sales [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Oil and gas sales | $ | 62,529 | 23,595 | 172,234 | 73,170 | ||
NGL sales [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Oil and gas sales | $ | $ 11,489 | $ 4,439 | $ 25,030 | $ 9,772 | ||
Swap [Member] | Fourth Quarter 2021 [Member] | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 272,662 | 272,662 | ||||
Derivative, Swap Type, Fixed Price | $ / Boe | 57.50 | 57.50 | ||||
Swap [Member] | Fourth Quarter 2021 [Member] | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 1,530,000 | 1,530,000 | ||||
Derivative, Swap Type, Fixed Price | 3.60 | 3.60 | ||||
Swap [Member] | Fourth Quarter 2021 [Member] | NGL Derivative | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 192,324 | 192,324 | ||||
Derivative, Swap Type, Fixed Price | 24.26 | 24.26 | ||||
Swap [Member] | First Quarter 2022 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 223,455 | 223,455 | ||||
Derivative, Swap Type, Fixed Price | $ / Boe | 49.32 | 49.32 | ||||
Swap [Member] | First Quarter 2022 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 232,500 | 232,500 | ||||
Derivative, Swap Type, Fixed Price | 4 | 4 | ||||
Swap [Member] | First Quarter 2022 | NGL Derivative | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 135,000 | 135,000 | ||||
Derivative, Swap Type, Fixed Price | 25.75 | 25.75 | ||||
Swap [Member] | First Quarter 2022 | NGL Derivative | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 45,000 | |||||
Derivative, Swap Type, Fixed Price | 39.25 | |||||
Swap [Member] | Second Quarter 2022 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 136,500 | 136,500 | ||||
Derivative, Swap Type, Fixed Price | $ / Boe | 56.66 | 56.66 | ||||
Swap [Member] | Second Quarter 2022 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 3,795,000 | 3,795,000 | ||||
Derivative, Swap Type, Fixed Price | 2.99 | 2.99 | ||||
Swap [Member] | Second Quarter 2022 | NGL Derivative | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 91,000 | 91,000 | ||||
Derivative, Swap Type, Fixed Price | 26.87 | 26.87 | ||||
Swap [Member] | Second Quarter 2022 | NGL Derivative | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 45,500 | |||||
Derivative, Swap Type, Fixed Price | 32.82 | |||||
Swap [Member] | Third Quarter 2022 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 246,100 | 246,100 | ||||
Derivative, Swap Type, Fixed Price | $ / Boe | 49.63 | 49.63 | ||||
Swap [Member] | Third Quarter 2022 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 4,142,100 | 4,142,100 | ||||
Derivative, Swap Type, Fixed Price | 3.02 | 3.02 | ||||
Swap [Member] | Third Quarter 2022 | NGL Derivative | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 92,000 | 92,000 | ||||
Derivative, Swap Type, Fixed Price | 26.87 | 26.87 | ||||
Swap [Member] | Third Quarter 2022 | NGL Derivative | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 46,000 | |||||
Derivative, Swap Type, Fixed Price | 31.29 | |||||
Swap [Member] | Fourth Quarter 2022 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 184,000 | 184,000 | ||||
Derivative, Swap Type, Fixed Price | $ / Boe | 54.84 | 54.84 | ||||
Swap [Member] | Fourth Quarter 2022 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 2,760,000 | 2,760,000 | ||||
Derivative, Swap Type, Fixed Price | 3.14 | 3.14 | ||||
Swap [Member] | Fourth Quarter 2022 | NGL Derivative | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 92,000 | 92,000 | ||||
Derivative, Swap Type, Fixed Price | 26.87 | 26.87 | ||||
Swap [Member] | Fourth Quarter 2022 | NGL Derivative | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 46,000 | |||||
Derivative, Swap Type, Fixed Price | 31.09 | |||||
Swap [Member] | First Quarter 2023 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 81,900 | 81,900 | ||||
Derivative, Swap Type, Fixed Price | $ / Boe | 55.70 | 55.70 | ||||
Swap [Member] | First Quarter 2023 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 275 | |||||
Derivative, Swap Type, Fixed Price | $ / Boe | 69.40 | |||||
Swap [Member] | Second Quarter 2023 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 575 | |||||
Derivative, Swap Type, Fixed Price | $ / Boe | 68.40 | |||||
Swap [Member] | Third Quarter 2023 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 53,980 | |||||
Derivative, Swap Type, Fixed Price | $ / Boe | 66.55 | |||||
Collar Contracts [Member] | Fourth Quarter 2021 [Member] | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 84,640 | 84,640 | ||||
Derivative, Average Floor Price | 34.70 | 34.70 | ||||
Derivative, Average Cap Price | 41.01 | 41.01 | ||||
Collar Contracts [Member] | Fourth Quarter 2021 [Member] | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 9,301,000 | 9,301,000 | ||||
Derivative, Average Floor Price | 2.73 | 2.73 | ||||
Derivative, Average Cap Price | 3.15 | 3.15 | ||||
Collar Contracts [Member] | Fourth Quarter 2021 [Member] | Natural Gas Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 310,000 | |||||
Derivative, Average Floor Price | 6 | |||||
Derivative, Average Cap Price | 7.45 | |||||
Collar Contracts [Member] | First Quarter 2022 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 40,500 | 40,500 | ||||
Derivative, Average Floor Price | 40 | 40 | ||||
Derivative, Average Cap Price | 45.55 | 45.55 | ||||
Collar Contracts [Member] | First Quarter 2022 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 45,000 | |||||
Derivative, Average Floor Price | 73 | |||||
Derivative, Average Cap Price | 79.75 | |||||
Collar Contracts [Member] | First Quarter 2022 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 9,055,000 | 9,055,000 | ||||
Derivative, Average Floor Price | 2.87 | 2.87 | ||||
Derivative, Average Cap Price | 3.55 | 3.55 | ||||
Collar Contracts [Member] | First Quarter 2022 | Natural Gas Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 590,000 | |||||
Derivative, Average Floor Price | 6 | |||||
Derivative, Average Cap Price | 7.45 | |||||
Collar Contracts [Member] | Second Quarter 2022 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 115,850 | 115,850 | ||||
Derivative, Average Floor Price | 39.25 | 39.25 | ||||
Derivative, Average Cap Price | 46.20 | 46.20 | ||||
Collar Contracts [Member] | Second Quarter 2022 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 45,500 | |||||
Derivative, Average Floor Price | 71 | |||||
Derivative, Average Cap Price | 78 | |||||
Collar Contracts [Member] | Second Quarter 2022 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 6,156,500 | 6,156,500 | ||||
Derivative, Average Floor Price | 2.29 | 2.29 | ||||
Derivative, Average Cap Price | 2.74 | 2.74 | ||||
Collar Contracts [Member] | Third Quarter 2022 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 46,000 | |||||
Derivative, Average Floor Price | 70 | |||||
Derivative, Average Cap Price | 75.40 | |||||
Collar Contracts [Member] | Third Quarter 2022 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 6,739,000 | 6,739,000 | ||||
Derivative, Average Floor Price | 2.60 | 2.60 | ||||
Derivative, Average Cap Price | 2.98 | 2.98 | ||||
Collar Contracts [Member] | Fourth Quarter 2022 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 46,000 | |||||
Derivative, Average Floor Price | 68 | |||||
Derivative, Average Cap Price | 73.60 | |||||
Collar Contracts [Member] | Fourth Quarter 2022 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 7,765,076 | 7,765,076 | ||||
Derivative, Average Floor Price | 2.69 | 2.69 | ||||
Derivative, Average Cap Price | 3.20 | 3.20 | ||||
Collar Contracts [Member] | First Quarter 2023 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 45,000 | |||||
Derivative, Average Floor Price | 65 | |||||
Derivative, Average Cap Price | 72.80 | |||||
Collar Contracts [Member] | First Quarter 2023 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 8,347,000 | 8,347,000 | ||||
Derivative, Average Floor Price | 2.89 | 2.89 | ||||
Derivative, Average Cap Price | 3.52 | 3.52 | ||||
Collar Contracts [Member] | Second Quarter 2023 | Oil Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 65,975 | 65,975 | ||||
Derivative, Average Floor Price | 56 | 56 | ||||
Derivative, Average Cap Price | 63.20 | 63.20 | ||||
Collar Contracts [Member] | Second Quarter 2023 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 45,500 | |||||
Derivative, Average Floor Price | 64 | |||||
Derivative, Average Cap Price | 70.85 | |||||
Collar Contracts [Member] | Second Quarter 2023 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 4,125,000 | 4,125,000 | ||||
Derivative, Average Floor Price | 2.49 | 2.49 | ||||
Derivative, Average Cap Price | 2.92 | 2.92 | ||||
Collar Contracts [Member] | Third Quarter 2023 | Oil Derivative Swaps | Subsequent Event [Member] | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | bbl | 46,000 | |||||
Derivative, Average Floor Price | 63 | |||||
Derivative, Average Cap Price | 69.10 | |||||
Collar Contracts [Member] | Third Quarter 2023 | Natural Gas Derivative Swaps | ||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||
Oil and Gas Production Hedged Volumes | MMBTU | 1,380,000 | 1,380,000 | ||||
Derivative, Average Floor Price | 2.60 | 2.60 | ||||
Derivative, Average Cap Price | 3.13 | 3.13 | ||||
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 | bbl | 46,000 | |||||
Derivative, Average Floor Price | 62 | |||||
Derivative, Average Cap Price | 67.55 |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies (Details Textual) $ in Thousands | Oct. 08, 2021USD ($)shares | Oct. 01, 2021USD ($)shares | Sep. 30, 2021USD ($)bblMMBTU$ / MMBTU$ / Boeshares | Jun. 30, 2021shares | Mar. 31, 2021shares | Sep. 30, 2020USD ($)shares | Jun. 30, 2020shares | Mar. 31, 2020shares | Sep. 30, 2021USD ($)bblMMBTU$ / MMBTU$ / Boeshares | Sep. 30, 2020USD ($)shares | Nov. 04, 2021bblMMBTU$ / MMBTU$ / Boe | Aug. 13, 2021USD ($) | Dec. 31, 2020USD ($) |
Summary of Significant Accounting Policies | |||||||||||||
Brent Spot Price | 78 | 77 | 64 | 78 | |||||||||
WTI Spot Price | 75 | 74 | 59 | 75 | |||||||||
Stock Issued During Period, Shares, Acquisitions | shares | 516,675 | ||||||||||||
Acquisition of oil and gas properties | $ | $ 13,219 | $ 3,441 | |||||||||||
Total capitalized internal costs | $ | $ 1,200 | $ 800 | 3,500 | 2,800 | |||||||||
Proved oil and gas properties | $ | 1,445,818 | 1,445,818 | $ 1,310,008 | ||||||||||
Unproved oil and gas properties | $ | 24,988 | 24,988 | 28,090 | ||||||||||
Furniture, fixtures, and other equipment | $ | 5,780 | 5,780 | 5,275 | ||||||||||
Less - Accumulated depreciation, depletion, and amortization | $ | (846,822) | (846,822) | (801,279) | ||||||||||
Net Furniture, Fixtures and other equipment | $ | 629,764 | 629,764 | 542,094 | ||||||||||
Write-down of oil and gas properties | $ | 0 | 0 | 0 | 355,948 | |||||||||
Allowance for doubtful accounts receivable, current | $ | 100 | 100 | 100 | ||||||||||
Accounts receivable, gross | $ | 41,800 | 41,800 | 18,800 | ||||||||||
Accounts receivable related to joint interest owners | $ | 800 | 800 | 4,000 | ||||||||||
Severance tax receivable | $ | 1,200 | 1,200 | 2,400 | ||||||||||
Other receivables | $ | 400 | $ 400 | 700 | ||||||||||
Percentage of working interest in wells | 100.00% | ||||||||||||
Total amount of supervision fees charged to wells | $ | 1,300 | 1,100 | $ 3,600 | 3,200 | |||||||||
Provision (Benefit) for Income Taxes | $ | (408) | (572) | (408) | 20,607 | |||||||||
Oil and gas sales | $ | 99,249 | $ 45,699 | 255,850 | $ 123,921 | |||||||||
Trade accounts payable | $ | 8,423 | 8,423 | 15,930 | ||||||||||
Accrued operating expenses | $ | 3,585 | 3,585 | 2,491 | ||||||||||
Accrued payroll costs | $ | 3,955 | 3,955 | 3,771 | ||||||||||
Asset retirement obligation - current portion | $ | 492 | 492 | 441 | ||||||||||
Accrued non-income based taxes | $ | 6,141 | 6,141 | 1,819 | ||||||||||
Accrued corporate and legal fees | $ | 132 | 132 | 150 | ||||||||||
Payables for Settled Derivatives | $ | 13,621 | 13,621 | 829 | ||||||||||
Other payables | $ | 1,651 | 1,651 | 1,560 | ||||||||||
Accounts payable and accrued liabilities | $ | $ 38,000 | $ 38,000 | $ 26,991 | ||||||||||
Purchase of treasury stock (shares) | shares | 440 | 13,969 | 60,177 | 958 | 1,098 | 26,675 | 74,586 | 28,731 | |||||
ATM Program , Maximum Proceeds | $ | $ 40,000 | ||||||||||||
Stock Issued During Period, Shares, New Issues | shares | 669,600 | ||||||||||||
Stock Issued During Period, Value, New Issues | $ | $ 12,756 | ||||||||||||
Oil sales [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and gas sales | $ | 25,230 | $ 17,665 | $ 58,587 | $ 40,979 | |||||||||
Natural gas sales [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and gas sales | $ | 62,529 | 23,595 | 172,234 | 73,170 | |||||||||
NGL sales [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and gas sales | $ | $ 11,489 | $ 4,439 | $ 25,030 | $ 9,772 | |||||||||
Subsequent Event [Member] | Post Oak Acquisition | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Working Interest Acquired | 1 | ||||||||||||
Net Oil Weighted Acres Acquired | 15,000 | ||||||||||||
Net Gas Weighted Acres Acquired | 26,000 | ||||||||||||
Stock Issued During Period, Shares, Acquisitions | shares | 1,341,990 | ||||||||||||
Asset Acquisition, Consideration Transferred | $ | $ 35,600 | ||||||||||||
Subsequent Event [Member] | Teal Acquisition | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Net Oil Weighted Acres Acquired | 17,000 | ||||||||||||
Asset Acquisition, Consideration Transferred | $ | $ 75,000 | ||||||||||||
Acquisition of oil and gas properties | $ | $ 45,000 | ||||||||||||
Wells Purchased | 62 | ||||||||||||
Asset Acquisition, Percentage of Liquids Production Acquired | 0.71 | ||||||||||||
Asset Acquisition, Percentage of Oil Production Acquired | 0.46 | ||||||||||||
Subsequent Event [Member] | Teal Acquisition | Asset Acquisition, Shares Issuable | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Stock Issued During Period, Shares, Acquisitions | shares | 1,351,961 | ||||||||||||
Subsequent Event [Member] | Teal Acquisition | Asset Acquisition, Share Value Issuable | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Asset Acquisition, Consideration Transferred, Contingent Consideration | $ | $ 25,000 | ||||||||||||
Swap [Member] | Fourth Quarter 2021 [Member] | Oil Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 272,662 | 272,662 | |||||||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 57.50 | 57.50 | |||||||||||
Swap [Member] | Fourth Quarter 2021 [Member] | Natural Gas Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 1,530,000 | 1,530,000 | |||||||||||
Derivative, Swap Type, Fixed Price | 3.60 | 3.60 | |||||||||||
Swap [Member] | Fourth Quarter 2021 [Member] | NGL Derivative | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 192,324 | 192,324 | |||||||||||
Derivative, Swap Type, Fixed Price | 24.26 | 24.26 | |||||||||||
Swap [Member] | First Quarter 2022 | Oil Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 223,455 | 223,455 | |||||||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 49.32 | 49.32 | |||||||||||
Swap [Member] | First Quarter 2022 | Natural Gas Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 232,500 | 232,500 | |||||||||||
Derivative, Swap Type, Fixed Price | 4 | 4 | |||||||||||
Swap [Member] | First Quarter 2022 | NGL Derivative | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 135,000 | 135,000 | |||||||||||
Derivative, Swap Type, Fixed Price | 25.75 | 25.75 | |||||||||||
Swap [Member] | First Quarter 2022 | NGL Derivative | Subsequent Event [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 45,000 | ||||||||||||
Derivative, Swap Type, Fixed Price | 39.25 | ||||||||||||
Swap [Member] | Second Quarter 2022 | Oil Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 136,500 | 136,500 | |||||||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 56.66 | 56.66 | |||||||||||
Swap [Member] | Second Quarter 2022 | Natural Gas Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 3,795,000 | 3,795,000 | |||||||||||
Derivative, Swap Type, Fixed Price | 2.99 | 2.99 | |||||||||||
Swap [Member] | Second Quarter 2022 | NGL Derivative | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 91,000 | 91,000 | |||||||||||
Derivative, Swap Type, Fixed Price | 26.87 | 26.87 | |||||||||||
Swap [Member] | Second Quarter 2022 | NGL Derivative | Subsequent Event [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 45,500 | ||||||||||||
Derivative, Swap Type, Fixed Price | 32.82 | ||||||||||||
Swap [Member] | Third Quarter 2022 | Oil Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 246,100 | 246,100 | |||||||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 49.63 | 49.63 | |||||||||||
Swap [Member] | Third Quarter 2022 | Natural Gas Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 4,142,100 | 4,142,100 | |||||||||||
Derivative, Swap Type, Fixed Price | 3.02 | 3.02 | |||||||||||
Swap [Member] | Third Quarter 2022 | NGL Derivative | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 92,000 | 92,000 | |||||||||||
Derivative, Swap Type, Fixed Price | 26.87 | 26.87 | |||||||||||
Swap [Member] | Third Quarter 2022 | NGL Derivative | Subsequent Event [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 46,000 | ||||||||||||
Derivative, Swap Type, Fixed Price | 31.29 | ||||||||||||
Swap [Member] | Fourth Quarter 2022 | Oil Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 184,000 | 184,000 | |||||||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 54.84 | 54.84 | |||||||||||
Swap [Member] | Fourth Quarter 2022 | Natural Gas Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 2,760,000 | 2,760,000 | |||||||||||
Derivative, Swap Type, Fixed Price | 3.14 | 3.14 | |||||||||||
Swap [Member] | Fourth Quarter 2022 | NGL Derivative | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 92,000 | 92,000 | |||||||||||
Derivative, Swap Type, Fixed Price | 26.87 | 26.87 | |||||||||||
Swap [Member] | Fourth Quarter 2022 | NGL Derivative | Subsequent Event [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 46,000 | ||||||||||||
Derivative, Swap Type, Fixed Price | 31.09 | ||||||||||||
Swap [Member] | First Quarter 2023 | Oil Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 81,900 | 81,900 | |||||||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 55.70 | 55.70 | |||||||||||
Swap [Member] | First Quarter 2023 | Oil Derivative Swaps | Subsequent Event [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 275 | ||||||||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 69.40 | ||||||||||||
Swap [Member] | Second Quarter 2023 | Oil Derivative Swaps | Subsequent Event [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 575 | ||||||||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 68.40 | ||||||||||||
Swap [Member] | Third Quarter 2023 | Oil Derivative Swaps | Subsequent Event [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 53,980 | ||||||||||||
Derivative, Swap Type, Fixed Price | $ / Boe | 66.55 | ||||||||||||
Collar Contracts [Member] | Fourth Quarter 2021 [Member] | Oil Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 84,640 | 84,640 | |||||||||||
Derivative, Average Floor Price | 34.70 | 34.70 | |||||||||||
Derivative, Average Cap Price | 41.01 | 41.01 | |||||||||||
Collar Contracts [Member] | Fourth Quarter 2021 [Member] | Natural Gas Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 9,301,000 | 9,301,000 | |||||||||||
Derivative, Average Floor Price | 2.73 | 2.73 | |||||||||||
Derivative, Average Cap Price | 3.15 | 3.15 | |||||||||||
Collar Contracts [Member] | Fourth Quarter 2021 [Member] | Natural Gas Derivative Swaps | Subsequent Event [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 310,000 | ||||||||||||
Derivative, Average Floor Price | 6 | ||||||||||||
Derivative, Average Cap Price | 7.45 | ||||||||||||
Collar Contracts [Member] | First Quarter 2022 | Oil Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 40,500 | 40,500 | |||||||||||
Derivative, Average Floor Price | 40 | 40 | |||||||||||
Derivative, Average Cap Price | 45.55 | 45.55 | |||||||||||
Collar Contracts [Member] | First Quarter 2022 | Oil Derivative Swaps | Subsequent Event [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 45,000 | ||||||||||||
Derivative, Average Floor Price | 73 | ||||||||||||
Derivative, Average Cap Price | 79.75 | ||||||||||||
Collar Contracts [Member] | First Quarter 2022 | Natural Gas Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 9,055,000 | 9,055,000 | |||||||||||
Derivative, Average Floor Price | 2.87 | 2.87 | |||||||||||
Derivative, Average Cap Price | 3.55 | 3.55 | |||||||||||
Collar Contracts [Member] | First Quarter 2022 | Natural Gas Derivative Swaps | Subsequent Event [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 590,000 | ||||||||||||
Derivative, Average Floor Price | 6 | ||||||||||||
Derivative, Average Cap Price | 7.45 | ||||||||||||
Collar Contracts [Member] | Second Quarter 2022 | Oil Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 115,850 | 115,850 | |||||||||||
Derivative, Average Floor Price | 39.25 | 39.25 | |||||||||||
Derivative, Average Cap Price | 46.20 | 46.20 | |||||||||||
Collar Contracts [Member] | Second Quarter 2022 | Oil Derivative Swaps | Subsequent Event [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 45,500 | ||||||||||||
Derivative, Average Floor Price | 71 | ||||||||||||
Derivative, Average Cap Price | 78 | ||||||||||||
Collar Contracts [Member] | Second Quarter 2022 | Natural Gas Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 6,156,500 | 6,156,500 | |||||||||||
Derivative, Average Floor Price | 2.29 | 2.29 | |||||||||||
Derivative, Average Cap Price | 2.74 | 2.74 | |||||||||||
Collar Contracts [Member] | Third Quarter 2022 | Oil Derivative Swaps | Subsequent Event [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 46,000 | ||||||||||||
Derivative, Average Floor Price | 70 | ||||||||||||
Derivative, Average Cap Price | 75.40 | ||||||||||||
Collar Contracts [Member] | Third Quarter 2022 | Natural Gas Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 6,739,000 | 6,739,000 | |||||||||||
Derivative, Average Floor Price | 2.60 | 2.60 | |||||||||||
Derivative, Average Cap Price | 2.98 | 2.98 | |||||||||||
Collar Contracts [Member] | Fourth Quarter 2022 | Oil Derivative Swaps | Subsequent Event [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 46,000 | ||||||||||||
Derivative, Average Floor Price | 68 | ||||||||||||
Derivative, Average Cap Price | 73.60 | ||||||||||||
Collar Contracts [Member] | Fourth Quarter 2022 | Natural Gas Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 7,765,076 | 7,765,076 | |||||||||||
Derivative, Average Floor Price | 2.69 | 2.69 | |||||||||||
Derivative, Average Cap Price | 3.20 | 3.20 | |||||||||||
Collar Contracts [Member] | First Quarter 2023 | Oil Derivative Swaps | Subsequent Event [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 45,000 | ||||||||||||
Derivative, Average Floor Price | 65 | ||||||||||||
Derivative, Average Cap Price | 72.80 | ||||||||||||
Collar Contracts [Member] | First Quarter 2023 | Natural Gas Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 8,347,000 | 8,347,000 | |||||||||||
Derivative, Average Floor Price | 2.89 | 2.89 | |||||||||||
Derivative, Average Cap Price | 3.52 | 3.52 | |||||||||||
Collar Contracts [Member] | Second Quarter 2023 | Oil Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 65,975 | 65,975 | |||||||||||
Derivative, Average Floor Price | 56 | 56 | |||||||||||
Derivative, Average Cap Price | 63.20 | 63.20 | |||||||||||
Collar Contracts [Member] | Second Quarter 2023 | Oil Derivative Swaps | Subsequent Event [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 45,500 | ||||||||||||
Derivative, Average Floor Price | 64 | ||||||||||||
Derivative, Average Cap Price | 70.85 | ||||||||||||
Collar Contracts [Member] | Second Quarter 2023 | Natural Gas Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 4,125,000 | 4,125,000 | |||||||||||
Derivative, Average Floor Price | 2.49 | 2.49 | |||||||||||
Derivative, Average Cap Price | 2.92 | 2.92 | |||||||||||
Collar Contracts [Member] | Third Quarter 2023 | Oil Derivative Swaps | Subsequent Event [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 46,000 | ||||||||||||
Derivative, Average Floor Price | 63 | ||||||||||||
Derivative, Average Cap Price | 69.10 | ||||||||||||
Collar Contracts [Member] | Third Quarter 2023 | Natural Gas Derivative Swaps | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | MMBTU | 1,380,000 | 1,380,000 | |||||||||||
Derivative, Average Floor Price | 2.60 | 2.60 | |||||||||||
Derivative, Average Cap Price | 3.13 | 3.13 | |||||||||||
Collar Contracts [Member] | Fourth Quarter 2023 | Oil Derivative Swaps | Subsequent Event [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Oil and Gas Production Hedged Volumes | bbl | 46,000 | ||||||||||||
Derivative, Average Floor Price | 62 | ||||||||||||
Derivative, Average Cap Price | 67.55 | ||||||||||||
Minimum [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Estimated useful lives of property | 2 years | ||||||||||||
Maximum [Member] | |||||||||||||
Summary of Significant Accounting Policies | |||||||||||||
Estimated useful lives of property | 20 years |
Leases Leases (Details)
Leases Leases (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2021 | Sep. 30, 2020 | |
Lessee, Lease, Description [Line Items] | ||||
Lease, Cost | $ 2,121 | $ 1,693 | $ 5,826 | $ 5,374 |
Operating Lease, Weighted Average Remaining Lease Term | 3 years 2 months 12 days | 3 years 2 months 12 days | ||
Operating Lease, Weighted Average Discount Rate, Percent | 4.10% | 4.10% | ||
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year | $ 1,791 | $ 1,791 | ||
Lessee, Operating Lease, Liability, Payments, Due Year Two | 6,767 | 6,767 | ||
Lessee, Operating Lease, Liability, Payments, Due Year Three | 5,938 | 5,938 | ||
Lessee, Operating Lease, Liability, Payments, Due Year Four | 776 | 776 | ||
Lessee, Operating Lease, Liability, Payments, Due Year Five | 776 | 776 | ||
Lessee, Operating Lease, Liability, Payments, Due after Year Five | 1,176 | 1,176 | ||
Lessee, Operating Lease, Liability, Payments, Due | 17,224 | 17,224 | ||
Lessee, Operating Lease, Liability, Undiscounted Excess Amount | (1,209) | (1,209) | ||
Operating Lease, Liability | 16,015 | 16,015 | ||
Operating Lease, Payments | 4,289 | 4,793 | ||
Operating Lease, Payments, Use | 0 | 10 | ||
Lease Operating Expense [Member] | ||||
Lessee, Lease, Description [Line Items] | ||||
Short-term Lease, Cost | 314 | 124 | 1,399 | 575 |
Operating Lease, Cost | 1,504 | 1,397 | 3,774 | 4,267 |
General and Administrative Expense [Member] | ||||
Lessee, Lease, Description [Line Items] | ||||
Operating Lease, Cost | 303 | 172 | 653 | 532 |
Property, Plant and Equipment [Member] | ||||
Lessee, Lease, Description [Line Items] | ||||
Short-term Lease, Cost | 1,189 | 0 | 3,009 | 2,302 |
Operating Lease, Cost | 0 | 0 | 0 | 10 |
Lease, Cost | $ 1,189 | $ 0 | $ 3,009 | $ 2,312 |
Share-Based Compensation (Detai
Share-Based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Thousands | Sep. 30, 2021 | Feb. 24, 2021 | May 21, 2019 | Feb. 20, 2018 | Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2021 | Sep. 30, 2020 | Dec. 31, 2020 |
Share-based Compensation (Details Textual) | |||||||||
Stock-based compensation expenses | $ 3,450 | $ 3,503 | |||||||
Share-based compensation (capitalized) | $ 100 | $ 100 | 200 | 200 | |||||
Share-based Payment Arrangement, Option [Member] | |||||||||
Share-based Compensation (Details Textual) | |||||||||
Stock option award unrecognized compensation | $ 200 | 200 | 200 | ||||||
Stock option award outstanding aggregate intrinsic value | $ 100 | $ 100 | 100 | ||||||
Remaining contract life of outstanding stock options. | 4 years 4 months 24 days | ||||||||
Remaining contract life of exercisable stock option | 4 years 1 month 6 days | ||||||||
Stock option award exercisable aggregate intrinsic value | $ 100 | ||||||||
Stock Option Activity | |||||||||
Options outstanding, beginning of period, shares | 276,009 | 276,009 | 276,009 | 303,705 | |||||
Options outstanding, beginning of period, weighted average price | $ 28.12 | $ 28.12 | $ 28.12 | $ 27.73 | |||||
Options Forfeitures in Period | (3,896) | ||||||||
Options forfeited, weighted average price | $ 16.96 | ||||||||
Options expired, shares | (23,800) | ||||||||
Options expired, weighted average price | $ 23.25 | ||||||||
Options exercisable, end of period, shares | 226,950 | 226,950 | 226,950 | ||||||
Options exercisable, end of period, weighted average price | $ 28.53 | $ 28.53 | $ 28.53 | ||||||
Restricted Stock Units (RSUs) [Member] | |||||||||
Share-based Compensation (Details Textual) | |||||||||
Stock option award unrecognized compensation | $ 1,300 | $ 1,300 | $ 1,300 | ||||||
Unrecognized compensation expense weighted-average period | 9 months 18 days | ||||||||
Restricted stock activity | |||||||||
Restricted shares outstanding, beginning of period, shares | 574,916 | ||||||||
Restricted shares outstanding, beginning of period, weighted average price | $ 9.02 | ||||||||
Restricted shares granted, shares | 100,178 | ||||||||
Restricted shares granted, weighted average price | $ 8.33 | ||||||||
Restricted shares forfeited, weighted average price | (17,802) | ||||||||
Restricted shares forfeited, weighted average price | $ 11.09 | ||||||||
Restricted shares vested, shares | (312,447) | ||||||||
Restricted shares vested, weighted average price | $ 9.14 | ||||||||
Restricted shares outstanding, end of period, shares | 344,845 | 344,845 | 344,845 | ||||||
Restricted shares outstanding, end of period, weighted average price | $ 8.60 | $ 8.60 | $ 8.60 | ||||||
Performance-based stock unit [Member] | |||||||||
Share-based Compensation (Details Textual) | |||||||||
Stock option award unrecognized compensation | $ 1,700 | $ 1,700 | $ 1,700 | ||||||
Unrecognized compensation expense weighted-average period | 1 year 1 month 6 days | ||||||||
Restricted stock activity | |||||||||
Restricted shares granted, shares | 161,389 | 99,500 | 30,700 | ||||||
Restricted shares granted, weighted average price | $ 13.13 | $ 18.86 | $ 41.66 | ||||||
Restricted shares vested, shares | (23,800) | ||||||||
Restricted shares outstanding, end of period, shares | 83,600 | 83,600 | 83,600 | ||||||
Percent of payout for performance based stock units | 100.00% | 157.60% | 112.90% | 150.61% | 100.00% | 100.00% | |||
Minimum [Member] | Share-based Payment Arrangement, Option [Member] | |||||||||
Share-based Compensation (Details Textual) | |||||||||
Stock option award vesting period | 1 year | ||||||||
Minimum [Member] | Restricted Stock Units (RSUs) [Member] | |||||||||
Share-based Compensation (Details Textual) | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term | 1 year | ||||||||
Minimum [Member] | Performance-based stock unit [Member] | |||||||||
Restricted stock activity | |||||||||
Percent of payout for performance based stock units | 0.00% | 0.00% | 0.00% | ||||||
Maximum [Member] | Share-based Payment Arrangement, Option [Member] | |||||||||
Share-based Compensation (Details Textual) | |||||||||
Stock option award vesting period | 5 years | ||||||||
Maximum [Member] | Restricted Stock Units (RSUs) [Member] | |||||||||
Share-based Compensation (Details Textual) | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term | 5 years | ||||||||
Maximum [Member] | Performance-based stock unit [Member] | |||||||||
Share-based Compensation (Details Textual) | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term | 2 years | 3 years | 3 years | ||||||
Restricted stock activity | |||||||||
Percent of payout for performance based stock units | 200.00% | 200.00% | 200.00% | ||||||
General and Administrative Expense [Member] | |||||||||
Share-based Compensation (Details Textual) | |||||||||
Stock-based compensation expenses | $ 1,200 | $ 1,100 | $ 3,500 | $ 3,500 |
Earnings Per Share (Details)
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2021 | Jun. 30, 2021 | Mar. 31, 2021 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Sep. 30, 2021 | Sep. 30, 2020 | |
Basic EPS: | ||||||||
Net Income (Loss) | $ (35,943) | $ (19,951) | $ 28,380 | $ (6,896) | $ (305,976) | $ (5,858) | $ (27,514) | $ (318,730) |
Income, share amounts | 12,629 | 11,935 | 12,283 | 11,890 | ||||
Earnings Per Share, Basic | $ (2.85) | $ (0.58) | $ (2.24) | $ (26.81) | ||||
Dilutive Securities: | ||||||||
Dilutive RSUs | 0 | 0 | 0 | 0 | ||||
Diluted EPS: | ||||||||
Net Income (Loss) Available to Common Stockholders, Diluted | $ (35,943) | $ (6,896) | $ (27,514) | $ (318,730) | ||||
Weighted Average Number of Shares Outstanding, Diluted | 12,629 | 11,935 | 12,283 | 11,890 | ||||
Earnings Per Share, Diluted | $ (2.85) | $ (0.58) | $ (2.24) | $ (26.81) | ||||
Stock Options [Member] | ||||||||
Earnings Per Share (Textual) | ||||||||
Antidilutive shares excluded from EPS, shares | 300 | 300 | 300 | 300 | ||||
Restricted Stock Units (RSUs) [Member] | ||||||||
Earnings Per Share (Textual) | ||||||||
Antidilutive shares excluded from EPS, shares | 0 | 200 | 100 | 200 | ||||
Performance Shares [Member] | ||||||||
Earnings Per Share (Textual) | ||||||||
Antidilutive shares excluded from EPS, shares | 0 | 100 | 0 | 100 |
Long-Term Debt (Details)
Long-Term Debt (Details) $ in Thousands | Apr. 16, 2021USD ($) | Nov. 02, 2020USD ($) | Dec. 15, 2017USD ($) | Sep. 30, 2021USD ($) | Sep. 30, 2020USD ($) | Sep. 30, 2021USD ($) | Sep. 30, 2020USD ($) | Dec. 31, 2020USD ($) |
Bank Borrowings | ||||||||
Long-term Debt, excluding current maturities | $ 393,726 | $ 393,726 | $ 424,905 | |||||
Gross interest expense including amortization of debt issuance costs | 7,433 | $ 7,444 | 21,888 | $ 23,876 | ||||
Capitalized interest on our unproved properties | 0 | 0 | 0 | 0 | ||||
Payments of Debt Issuance Costs | 2,400 | 0 | ||||||
Write off of Debt Issuance Cost | 229 | 459 | ||||||
Second Lien [Abstract] | ||||||||
Long-term debt, gross | 398,000 | 398,000 | 430,000 | |||||
New Credit Facility [Member] | ||||||||
Bank Borrowings | ||||||||
Debt Issuance Costs, Net | 2,800 | 2,800 | 1,400 | |||||
Second Lien Notes [Member] | ||||||||
Bank Borrowings | ||||||||
Debt Issuance Costs, Net | 3,188 | 3,188 | 3,800 | |||||
Long-term Debt, excluding current maturities | $ 198,000 | 200,000 | 200,000 | 200,000 | ||||
Gross interest expense including amortization of debt issuance costs | 4,600 | 4,600 | 13,800 | 14,100 | ||||
Second Lien [Abstract] | ||||||||
Long-term debt, gross | 200,000 | |||||||
Debt Instrument, Unamortized Discount | (2,000) | (1,086) | (1,086) | (1,295) | ||||
Additional notes issuable | $ 100,000 | |||||||
Additional interest in the event of default | 0.020 | |||||||
Make whole premium during year 4 | 0.010 | |||||||
Second Lien, Required Security Interest on Proved Reserves | 85.00% | |||||||
Second Lien, Required Security Interest on Oil and Gas Properties | 85.00% | |||||||
Discount Rate for Estimated Future Net Revenues for Proved Properties at 9% | 9.00% | |||||||
Second Lien, Asset Coverage Ratio, Minimum | 1.25 | |||||||
Discount Rate for Estimated Future Net Revenues from Proved Properties | 10.00% | |||||||
Second Lien, Covenant, Debt to EBITDA Ratio, Minimum | 4.5 | |||||||
Long-term debt, net | 195,700 | 195,700 | ||||||
Second Lien Notes [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||||||
Bank Borrowings | ||||||||
Debt instrument escalating basis spread on base rate | 0.075 | |||||||
Second Lien Notes [Member] | Alternative Base Interest Rate [Member] | ||||||||
Bank Borrowings | ||||||||
Debt instrument escalating basis spread on base rate | 0.065 | |||||||
Line of Credit [Member] | New Credit Facility [Member] | ||||||||
Bank Borrowings | ||||||||
Long-term Debt, excluding current maturities | 198,000 | 198,000 | $ 230,000 | |||||
Line of Credit Facility, Current Borrowing Capacity | $ 300,000 | $ 310,000 | ||||||
Line of Credit, Basis Point Increase | 50 | |||||||
Line of Credit, Covenant, Debt to EBITDA Ratio, On or Before December 31, 2020 | 3.50 | |||||||
Line of Credit, Covenant, Debt to EBITDA Ratio, On or Before December 31, 2021 | 3.25 | |||||||
Line of Credit, Covenant, Debt to EBITDA Ratio, On or Before March 31, 2022 | 3 | |||||||
Line of Credit, Minimum Rolling Hedge Requirement | 0.50 | |||||||
Line of Credit, Required Security Interest on Oil and Gas Properties | 90.00% | 85.00% | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 600,000 | |||||||
Line of Credit, Letters of Credit Issuable | $ 25,000 | |||||||
Commitment fee basis points for the credit facility | 0.50% | |||||||
Line of Credit, Additional Interest Due to Payment Default | 2.00% | |||||||
Line of Credit, Covenant, Current Ratio, Minimum | 1 | |||||||
Gross interest expense including amortization of debt issuance costs | $ 2,800 | $ 2,900 | 8,100 | $ 9,800 | ||||
Payments of Debt Issuance Costs | 2,400 | |||||||
Write off of Debt Issuance Cost | $ 200 | |||||||
Line of Credit [Member] | New Credit Facility [Member] | Minimum [Member] | Alternative Base Interest Rate [Member] | ||||||||
Bank Borrowings | ||||||||
Debt instrument escalating basis spread on base rate | 0.0225 | |||||||
Debt Instrument Escalating Rates for Eurodollar Rate Loans | 0.0325 | |||||||
Line of Credit [Member] | New Credit Facility [Member] | Maximum [Member] | Alternative Base Interest Rate [Member] | ||||||||
Bank Borrowings | ||||||||
Debt instrument escalating basis spread on base rate | 0.0325 | |||||||
Debt Instrument Escalating Rates for Eurodollar Rate Loans | 0.0425 |
Acquisitions and Dispositions_2
Acquisitions and Dispositions Acquisitions and Dispositions (Details) $ in Thousands | Aug. 03, 2021USD ($) | Sep. 30, 2021USD ($)shares | Sep. 30, 2021USD ($) | Sep. 30, 2020USD ($) | Dec. 22, 2017USD ($) |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Payments for (Proceeds from) Other Investing Activities | $ 1,084 | $ 426 | |||
Acquisition of oil and gas properties | 13,219 | 3,441 | |||
Stock Issued During Period, Shares, Acquisitions | shares | 516,675 | ||||
Non-cash equity consideration for acquisitions | 10,023 | 0 | |||
La Mesa | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Wells Purchased | 12 | ||||
Net Acres Acquired | 850 | ||||
Asset Acquisition, Consideration Transferred | $ 24,000 | ||||
Acquisition of oil and gas properties | 13,200 | ||||
Stock Issued During Period, Shares, Acquisitions | shares | 516,675 | ||||
Non-cash equity consideration for acquisitions | 10,000 | ||||
Bay De Chene [Member] | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Purchase and sale contract | $ 16,300 | ||||
Payments for (Proceeds from) Other Investing Activities | 1,100 | $ 400 | |||
Cash to be released for purchase and sale contract | $ 500 | $ 500 |
Price-Risk Management Price-R_4
Price-Risk Management Price-Risk Management (Details) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2021USD ($)bblMMBTU$ / MMBTU$ / Boe | Sep. 30, 2020USD ($) | Sep. 30, 2021USD ($)bblMMBTU$ / MMBTU$ / Boe | Sep. 30, 2020USD ($) | Dec. 31, 2020USD ($) | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Gain (Loss) on Price Risk Derivatives, Net | $ | $ (88,600) | $ (12,900) | $ (152,900) | $ 66,900 | |
Cash settlement (paid) received on derivatives | $ | (28,976) | 76,150 | |||
Cash Received (Paid) On Monetized Derivative Contracts | $ | 38,300 | ||||
Receivables for Settled Derivatives | $ | 100 | 100 | $ 800 | ||
Payables for Settled Derivatives | $ | 13,621 | 13,621 | 829 | ||
Derivative, Fair Value, Net | $ | (116,100) | (116,100) | (6,000) | ||
Cash settlements on derivatives | $ | (29,000) | $ 76,100 | |||
Other Current Assets [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | $ | 700 | 700 | 4,800 | ||
Other Noncurrent Assets [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | $ | 100 | 100 | 300 | ||
Other Current Liabilities [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | $ | 94,800 | 94,800 | 8,200 | ||
Other Noncurrent Liabilities [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | $ | $ 22,000 | $ 22,000 | $ 2,900 | ||
Swap [Member] | Oil Derivative Swaps | Fourth Quarter 2021 [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 272,662 | 272,662 | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 57.50 | 57.50 | |||
Swap [Member] | Oil Derivative Swaps | First Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 223,455 | 223,455 | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 49.32 | 49.32 | |||
Swap [Member] | Oil Derivative Swaps | Second Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 136,500 | 136,500 | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 56.66 | 56.66 | |||
Swap [Member] | Oil Derivative Swaps | Third Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 246,100 | 246,100 | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 49.63 | 49.63 | |||
Swap [Member] | Oil Derivative Swaps | Fourth Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 184,000 | 184,000 | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 54.84 | 54.84 | |||
Swap [Member] | Oil Derivative Swaps | First Quarter 2023 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 81,900 | 81,900 | |||
Derivative, Swap Type, Fixed Price | $ / Boe | 55.70 | 55.70 | |||
Swap [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2021 [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 1,530,000 | 1,530,000 | |||
Derivative, Swap Type, Fixed Price | 3.60 | 3.60 | |||
Swap [Member] | Natural Gas Derivative Swaps | First Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 232,500 | 232,500 | |||
Derivative, Swap Type, Fixed Price | 4 | 4 | |||
Swap [Member] | Natural Gas Derivative Swaps | Second Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 3,795,000 | 3,795,000 | |||
Derivative, Swap Type, Fixed Price | 2.99 | 2.99 | |||
Swap [Member] | Natural Gas Derivative Swaps | Third Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 4,142,100 | 4,142,100 | |||
Derivative, Swap Type, Fixed Price | 3.02 | 3.02 | |||
Swap [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 2,760,000 | 2,760,000 | |||
Derivative, Swap Type, Fixed Price | 3.14 | 3.14 | |||
Swap [Member] | NGL Derivative | Fourth Quarter 2021 [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 192,324 | 192,324 | |||
Derivative, Swap Type, Fixed Price | 24.26 | 24.26 | |||
Swap [Member] | NGL Derivative | First Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 135,000 | 135,000 | |||
Derivative, Swap Type, Fixed Price | 25.75 | 25.75 | |||
Swap [Member] | NGL Derivative | Second Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 91,000 | 91,000 | |||
Derivative, Swap Type, Fixed Price | 26.87 | 26.87 | |||
Swap [Member] | NGL Derivative | Third Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 92,000 | 92,000 | |||
Derivative, Swap Type, Fixed Price | 26.87 | 26.87 | |||
Swap [Member] | NGL Derivative | Fourth Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 92,000 | 92,000 | |||
Derivative, Swap Type, Fixed Price | 26.87 | 26.87 | |||
Collar Contracts [Member] | Oil Derivative Swaps | Fourth Quarter 2021 [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 84,640 | 84,640 | |||
Derivative, Average Floor Price | 34.70 | 34.70 | |||
Derivative, Average Cap Price | 41.01 | 41.01 | |||
Collar Contracts [Member] | Oil Derivative Swaps | First Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 40,500 | 40,500 | |||
Derivative, Average Floor Price | 40 | 40 | |||
Derivative, Average Cap Price | 45.55 | 45.55 | |||
Collar Contracts [Member] | Oil Derivative Swaps | Second Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 115,850 | 115,850 | |||
Derivative, Average Floor Price | 39.25 | 39.25 | |||
Derivative, Average Cap Price | 46.20 | 46.20 | |||
Collar Contracts [Member] | Oil Derivative Swaps | Second Quarter 2023 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 65,975 | 65,975 | |||
Derivative, Average Floor Price | 56 | 56 | |||
Derivative, Average Cap Price | 63.20 | 63.20 | |||
Collar Contracts [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2021 [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 9,301,000 | 9,301,000 | |||
Derivative, Average Floor Price | 2.73 | 2.73 | |||
Derivative, Average Cap Price | 3.15 | 3.15 | |||
Collar Contracts [Member] | Natural Gas Derivative Swaps | First Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 9,055,000 | 9,055,000 | |||
Derivative, Average Floor Price | 2.87 | 2.87 | |||
Derivative, Average Cap Price | 3.55 | 3.55 | |||
Collar Contracts [Member] | Natural Gas Derivative Swaps | Second Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 6,156,500 | 6,156,500 | |||
Derivative, Average Floor Price | 2.29 | 2.29 | |||
Derivative, Average Cap Price | 2.74 | 2.74 | |||
Collar Contracts [Member] | Natural Gas Derivative Swaps | Third Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 6,739,000 | 6,739,000 | |||
Derivative, Average Floor Price | 2.60 | 2.60 | |||
Derivative, Average Cap Price | 2.98 | 2.98 | |||
Collar Contracts [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 7,765,076 | 7,765,076 | |||
Derivative, Average Floor Price | 2.69 | 2.69 | |||
Derivative, Average Cap Price | 3.20 | 3.20 | |||
Collar Contracts [Member] | Natural Gas Derivative Swaps | First Quarter 2023 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 8,347,000 | 8,347,000 | |||
Derivative, Average Floor Price | 2.89 | 2.89 | |||
Derivative, Average Cap Price | 3.52 | 3.52 | |||
Collar Contracts [Member] | Natural Gas Derivative Swaps | Second Quarter 2023 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 4,125,000 | 4,125,000 | |||
Derivative, Average Floor Price | 2.49 | 2.49 | |||
Derivative, Average Cap Price | 2.92 | 2.92 | |||
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 | 1,380,000 | 1,380,000 | |||
Derivative, Average Floor Price | 2.60 | 2.60 | |||
Derivative, Average Cap Price | 3.13 | 3.13 | |||
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2021 [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 11,040,000 | 11,040,000 | |||
Derivative, Swap Type, Fixed Price | (0.013) | (0.013) | |||
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | First Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 8,100,000 | 8,100,000 | |||
Derivative, Swap Type, Fixed Price | 0.093 | 0.093 | |||
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Second Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 3,640,000 | 3,640,000 | |||
Derivative, Swap Type, Fixed Price | (0.051) | (0.051) | |||
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Third Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 3,680,000 | 3,680,000 | |||
Derivative, Swap Type, Fixed Price | (0.043) | (0.043) | |||
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | MMBTU | 3,680,000 | 3,680,000 | |||
Derivative, Swap Type, Fixed Price | (0.048) | (0.048) | |||
Basis Swap [Member] | Oil Basis Derivative [Member] | Fourth Quarter 2021 [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 241,500 | 241,500 | |||
Derivative, Swap Type, Fixed Price | 1.28 | 1.28 | |||
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Fourth Quarter 2021 [Member] | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 241,500 | 241,500 | |||
Derivative, Swap Type, Fixed Price | (0.33) | (0.33) | |||
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | First Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 261,000 | 261,000 | |||
Derivative, Swap Type, Fixed Price | 0.19 | 0.19 | |||
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Second Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 263,900 | 263,900 | |||
Derivative, Swap Type, Fixed Price | 0.19 | 0.19 | |||
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Third Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 266,800 | 266,800 | |||
Derivative, Swap Type, Fixed Price | 0.19 | 0.19 | |||
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Fourth Quarter 2022 | |||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||||
Oil and Gas Production Hedged Volumes | bbl | 266,800 | 266,800 | |||
Derivative, Swap Type, Fixed Price | 0.19 | 0.19 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - Fair Value, Recurring [Member] - USD ($) $ in Millions | Sep. 30, 2021 | Dec. 31, 2020 |
Natural Gas Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | $ 1.5 | |
Derivative Liability | $ 80.3 | 4 |
Natural Gas Basis Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0.6 | 1.1 |
Derivative Liability | 2.6 | 0.4 |
Oil Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 2.5 | |
Derivative Liability | 26.3 | 5.9 |
Oil Basis Derivative [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0.1 | |
Derivative Liability | 0.8 | 0.8 |
NGL Derivative | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Liability | 6.7 | |
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 | |
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 | |
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | Oil Basis Derivative [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | |
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | NGL Derivative | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
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 | 1.5 | |
Derivative Liability | 80.3 | 4 |
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 | 0.6 | 1.1 |
Derivative Liability | 2.6 | 0.4 |
Fair Value, Inputs, Level 2 [Member] | Oil Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 2.5 | |
Derivative Liability | 26.3 | 5.9 |
Fair Value, Inputs, Level 2 [Member] | Oil Basis Derivative [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0.1 | |
Derivative Liability | 0.8 | 0.8 |
Fair Value, Inputs, Level 2 [Member] | NGL Derivative | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Liability | 6.7 | |
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 | |
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 | |
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Oil Basis Derivative [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | |
Derivative Liability | 0 | $ 0 |
Fair Value, Inputs, Level 3 [Member] | NGL Derivative | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Liability | $ 0 |
Asset Retirement Obligations _4
Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2021 | Sep. 30, 2020 | Sep. 30, 2021 | Sep. 30, 2020 | Dec. 31, 2020 | Dec. 31, 2019 | |
Asset Retirement Obligation Disclosure [Abstract] | ||||||
Asset Retirement Obligation | $ 5,198 | $ 5,198 | $ 4,974 | $ 4,447 | ||
Accretion expense | 77 | $ 90 | 226 | $ 263 | 354 | |
Liabilities incurred for new wells and facilities construction | 347 | 281 | ||||
Reductions due to plugged wells and facilities | (192) | (103) | ||||
Revisions in estimates | (157) | (5) | ||||
Asset retirement obligation - current portion | $ 492 | $ 492 | $ 441 |