Document And Entity Information
Document And Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Jun. 01, 2020 | Jun. 30, 2019 | |
Document Information [Line Items] | |||
Entity Registrant Name | ABRAXAS PETROLEUM CORP | ||
Entity Central Index Key | 0000867665 | ||
Trading Symbol | axas | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Accelerated Filer | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Emerging Growth Company | false | ||
Entity Small Business | false | ||
Entity Interactive Data Current | Yes | ||
Entity Common Stock, Shares Outstanding (in shares) | 168,069,305 | ||
Entity Public Float | $ 168,413,268 | ||
Entity Shell Company | false | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2019 | ||
Document Fiscal Year Focus | 2019 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Title of 12(b) Security | Common Stock, par value $.01 per share |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Current assets: | ||
Cash and cash equivalents | $ 867 | |
Accounts receivable: | ||
Joint owners, net | 2,397 | 17,110 |
Oil and gas production sales | 16,985 | 21,991 |
Other | 263 | 535 |
Total accounts receivable | 19,645 | 39,636 |
Derivative asset - short-term | 83 | 9,602 |
Other current assets | 1,193 | 626 |
Total current assets | 20,921 | 50,731 |
Proved oil and gas properties, full cost method | 1,162,094 | 1,091,905 |
Other property and equipment | 39,295 | 39,453 |
Total | 1,201,389 | 1,131,358 |
Less accumulated depreciation, depletion, amortization and impairment | (872,431) | (768,140) |
Total property and equipment - net | 328,958 | 363,218 |
Operating lease right-of-use assets | 327 | |
Derivative asset, long-term | 4,170 | 10,527 |
Other assets | 255 | 265 |
Total assets | 354,631 | 424,741 |
Current liabilities: | ||
Accounts payable | 19,280 | 39,571 |
Joint interest oil and gas production payable | 18,050 | 23,063 |
Accrued interest | 133 | 335 |
Other accrued liabilities | 361 | 511 |
Derivative liabilities - short-term | 10,688 | 616 |
Right of use liability | 98 | |
Current maturities of long-term debt | 280 | 267 |
Other current liabilities | 582 | |
Total current liabilities | 49,472 | 64,363 |
Long-term debt - less current maturities | 192,718 | 181,942 |
Derivative liabilities long-term | 999 | 4,434 |
Operating lease liabilities - long-term | 203 | |
Future site restoration | 7,420 | 7,492 |
Total liabilities | 250,812 | 258,231 |
Commitments and contingencies (Note 8) | ||
Stockholders' Equity | ||
Preferred stock, par value $0.01 per share - authorized 1,000,000 shares; - 0- shares issued and outstanding | ||
Common stock, par value $0.01 per share, authorized 400,000,000 shares; 166,713,784 and 168,361,061 issued and outstanding at December 31, 2018 and 2019, respectively | 1,684 | 1,667 |
Additional paid-in capital | 420,140 | 417,844 |
Accumulated deficit | (318,005) | (253,001) |
Total stockholders' equity | 103,819 | 166,510 |
Total liabilities and stockholders' equity | $ 354,631 | $ 424,741 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parentheticals) - $ / shares | Dec. 31, 2019 | Dec. 31, 2018 |
Preferred stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock, authorized (in shares) | 1,000,000 | 1,000,000 |
Preferred stock, issued (in shares) | 0 | 0 |
Preferred stock, outstanding (in shares) | 0 | 0 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, authorized (in shares) | 400,000,000 | 400,000,000 |
Common stock, issued (in shares) | 166,713,784 | 165,889,901 |
Common stock, outstanding (in shares) | 166,713,784 | 165,889,901 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Revenues: | |||
Other | $ 154 | $ 137 | $ 75 |
Revenues | 129,146 | 149,167 | 86,264 |
Operating costs and expenses | |||
Lease operating | 27,619 | 24,300 | 15,197 |
Production and ad valorem taxes | 10,610 | 12,023 | 7,228 |
Rig expense | 1,333 | ||
Depreciation, depletion, amortization and accretion | 52,703 | 43,275 | 26,677 |
Proved property impairment | 51,293 | ||
General and administrative (including stock-based compensation of $3,238, $2,366 and $1,911, respectively) | 11,304 | 12,041 | 16,276 |
Total operating costs and expenses | 154,862 | 91,639 | 65,378 |
Operating (loss) income | (25,716) | 57,528 | 20,886 |
Other (income) expense: | |||
Interest income | (65) | (1) | (1) |
Interest expense | 12,335 | 7,053 | 2,497 |
Amortization of deferred financing fees | 543 | 440 | 423 |
Loss (gain) on derivative contracts | 26,831 | (8,060) | 1,849 |
Loss (gain) on sale of non-oil and gas assets | 33 | 181 | (102) |
Other | (389) | 94 | 214 |
Total other (income) expense | 39,288 | (293) | 4,880 |
Income (loss) before income tax | (65,004) | 57,821 | 16,006 |
Income tax (expense) benefit | 0 | 0 | 0 |
Net income (loss) | $ (65,004) | $ 57,821 | $ 16,006 |
Net income (loss) per common share - basic (in dollars per share) | $ (0.39) | $ 0.35 | $ 0.10 |
Net income (loss) per common share - diluted (in dollars per share) | $ (0.39) | $ 0.34 | $ 0.10 |
Weighted average shares outstanding | |||
Basic (in shares) | 166,247 | 165,635 | 161,141 |
Diluted (in shares) | 166,312 | 167,689 | 162,844 |
Oil Revenues [Member] | |||
Revenues: | |||
Revenues | $ 124,503 | $ 132,904 | $ 73,584 |
Gas Revenues [Member] | |||
Revenues: | |||
Revenues | 2,579 | 7,854 | 6,898 |
Natural Gas Liquids Revenues [Member] | |||
Revenues: | |||
Revenues | $ 1,910 | $ 8,272 | $ 5,707 |
Consolidated Statements of Op_2
Consolidated Statements of Operations (Parentheticals) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Stock-based Compensation | $ 1,911 | $ 2,366 | $ 3,238 |
Consolidated Statements of Stoc
Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands | Common Stock [Member] | Additional Paid-in Capital [Member] | Retained Earnings [Member] | Total |
Balance (in shares) at Dec. 31, 2016 | 135,094,017 | |||
Balance at Dec. 31, 2016 | $ 1,351 | $ 343,982 | $ (326,828) | $ 18,505 |
Net income (loss) | 16,006 | 16,006 | ||
Stock issuance (in shares) | 28,750,000 | |||
Stock issuance | $ 288 | 64,936 | 65,224 | |
Stock issued for acquisition of oil and gas properties (in shares) | 2,000,000 | |||
Stock issued for acquisition of oil and gas properties | $ 20 | 3,315 | 3,335 | |
Stock-based compensation | 3,238 | 3,238 | ||
Stock options exercised (in shares) | 2,634 | |||
Stock options exercised | ||||
Restricted stock issued, net of forfeitures (in shares) | 43,250 | |||
Restricted stock issued, net of forfeitures | ||||
Balance (in shares) at Dec. 31, 2017 | 165,889,901 | |||
Balance at Dec. 31, 2017 | $ 1,659 | 415,471 | (310,822) | 106,308 |
Net income (loss) | 57,821 | 57,821 | ||
Stock-based compensation | 2,366 | 2,366 | ||
Stock options exercised (in shares) | 150,327 | |||
Stock options exercised | $ 1 | 13 | 14 | |
Restricted stock issued, net of forfeitures (in shares) | 673,556 | |||
Restricted stock issued, net of forfeitures | $ 7 | (6) | $ 1 | |
Balance (in shares) at Dec. 31, 2018 | 166,713,784 | 165,889,901 | ||
Balance at Dec. 31, 2018 | $ 1,667 | 417,844 | (253,001) | $ 166,510 |
Net income (loss) | (65,004) | (65,004) | ||
Stock-based compensation | 1,911 | 1,911 | ||
Stock options exercised (in shares) | 423,369 | |||
Stock options exercised | $ 4 | 398 | 402 | |
Restricted stock issued, net of forfeitures (in shares) | 1,223,908 | |||
Restricted stock issued, net of forfeitures | $ 13 | (13) | ||
Balance (in shares) at Dec. 31, 2019 | 168,361,061 | 166,713,784 | ||
Balance at Dec. 31, 2019 | $ 1,684 | $ 420,140 | $ (318,005) | $ 103,819 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Operating Activities: | |||
Net income (loss) | $ (65,004) | $ 57,821 | $ 16,006 |
Adjustments to reconcile net (loss) income to net cash provided by operating activities: | |||
Loss (gain) on sale of non-oil and gas assets | 33 | 181 | (102) |
Net loss (gain) on derivative contracts | 26,831 | (8,060) | 1,849 |
Net cash settlements received (paid) on derivative contracts | (4,317) | (20,241) | 2,450 |
Depreciation, depletion and amortization | 52,267 | 42,759 | 26,226 |
Proved property impairment | 51,293 | ||
Amortization of deferred financing fees and issuance discount | 738 | 440 | 423 |
Accretion expense and other | 436 | 516 | 451 |
Plugging cost | (890) | (488) | (488) |
Stock-based Compensation | 1,911 | 2,366 | 3,238 |
Changes in operating assets and liabilities: | |||
Accounts receivable | 19,991 | (7,543) | (18,569) |
Other assets | 1,092 | 18 | 155 |
Accounts payable | (10,491) | 11,576 | 6,231 |
Accrued expenses | (243) | 655 | 253 |
Net cash provided by operating activities | 73,647 | 80,000 | 38,123 |
Investing Activities | |||
Capital expenditures, including purchase and development of properties | (108,673) | (179,509) | (108,236) |
Proceeds from the sale of oil and gas properties | 23,434 | 3,279 | 16,979 |
Proceeds from the sale of non-oil and gas assets | 272 | 26 | 204 |
Net cash used in investing activities | (84,967) | (176,204) | (91,053) |
Financing Activities | |||
Proceeds from exercise of stock options and restricted stock | 402 | 14 | |
Proceeds from issuance of common stock, net of offering cost of $3.8 million, respectively | 65,224 | ||
Payments of long-term borrowings | (124,692) | (31,258) | (91,786) |
Deferred financing fees | (1,960) | (303) | (890) |
Net cash provided by financing activities | 10,453 | 95,453 | 54,548 |
Increase (decrease) in cash and cash equivalents | (867) | (751) | 1,618 |
Cash and cash equivalents at beginning of period | 867 | 1,618 | |
Cash and cash equivalents at end of period | 867 | 1,618 | |
Supplemental disclosure of cash flow information: | |||
Interest paid | 12,340 | 6,858 | 2,401 |
Income tax paid | |||
Non-cash investing and financing activities | |||
Change in asset retirement obligation cost and liabilities | 855 | 471 | 1,252 |
Asset retirement obligations associated with dispositions | (473) | (1,844) | (1,018) |
Issuance of stock for acquisition of oil and gas properties | 3,335 | ||
Change in capital expenditures included in accounts payable | (16,489) | (6,014) | 23,507 |
Line of Credit [Member] | |||
Financing Activities | |||
Proceeds from long-term borrowings | 40,203 | 127,000 | 82,000 |
Second Lien Credit Facility [Member] | |||
Financing Activities | |||
Proceeds from long-term borrowings | $ 96,500 |
Consolidated Statements of Ca_2
Consolidated Statements of Cash Flows (Parentheticals) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Common stock issuance, offering costs | $ 3.8 |
Note 1 - Organization and Signi
Note 1 - Organization and Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2019 | |
Notes to Financial Statements | |
Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Text Block] | 1. Nature of Operations We are an independent energy company primarily engaged in the acquisition, exploitation, development and production of oil and gas in the United States. Our oil and gas assets are located in two The terms “Abraxas,” “Abraxas Petroleum,” “we,” “us,” “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its subsidiaries, including Raven Drilling LLC (“Raven Drilling”). Rig Accounting In accordance with SEC Regulation S- X, no not 2019 Use of Estimates The consolidated financial statements of the Company have been prepared by management in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The most significant estimates pertain to proved oil, gas and NGL reserves and related cash flow estimates used in impairment tests of oil and gas properties, the fair value of assets and liabilities acquired in business combinations, derivative contracts, the provision for income taxes including uncertain tax positions, stock based compensation, asset retirement obligations, accrued oil and gas revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ from those estimates. The process of estimating oil and gas reserves in accordance with SEC requirements is complex and involves decisions and assumptions in evaluating the available geological, geophysical, engineering and economic data. Accordingly, these estimates are imprecise. Actual future production, oil and gas prices, differentials, revenues, taxes, capital expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may Reclassifications Certain prior year balances have been reclassified for consistency with current year classifications. Such reclassifications had no Concentration of Credit Risk Financial instruments which potentially expose the Company to credit risk consist principally of trade receivables and derivative contracts. Accounts receivable are generally from companies with significant oil and gas marketing or operating activities. The Company performs ongoing credit evaluations and, generally, requires no The Company maintains any cash and cash equivalents in excess of federally insured limits in prominent financial institutions considered by the Company to be of high credit quality. Cash and Cash Equivalents Cash and cash equivalents include cash on hand, demand deposits and short-term investments with original maturities of three Accounts Receivable Accounts receivable are reported net of an allowance for doubtful accounts of approximately $0.5 $0.1 December 31, 2018 2019 Industry Segment and Geographic Information The Company operates in one no Oil and Gas Properties The Company follows the full cost method of accounting for oil and gas properties. Under this method, certain direct costs and indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves. Net capitalized costs of oil and gas properties, less related deferred taxes, are limited by country, to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10%, not No not December 31, 2017 2018 not December 31, 2019 $51.3 Other Property and Equipment Other property and equipment are recorded at cost. Depreciation of other property and equipment is provided over the estimated useful lives using the straight-line method. Major renewals and improvements are recorded as additions to the property and equipment accounts. Repairs that do not Estimates of Proved Oil and Gas Reserves Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of: • the quality and quantity of available data; • the interpretation of that data; • the accuracy of various mandated economic assumptions; and • the judgment of the persons preparing the estimate. Our proved reserve information included in this report was based on studies performed by our independent petroleum engineers assisted by the engineering and operations departments of Abraxas. Estimates prepared by other third may may may In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on the average of oil and gas prices based on the unweighted average 12 first may The estimates of proved reserves materially impact depreciation, depletion and amortization, or DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may may Derivative Instruments and Hedging Activities The Company enters into agreements to hedge the risk of future oil and gas price fluctuations. Such agreements are typically in the form of fixed price commodity and basis swaps, which limit the impact of price fluctuations with respect to the Company’s sale of oil and gas. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions could arise where actual production is less than estimated which could result in over hedged volumes. All derivative instruments are recorded on the Consolidated Balance Sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. The derivative instruments the Company utilizes are based on index prices that may 815. not Fair Value of Financial Instruments The Company includes fair value information in the notes to consolidated financial statements when the fair value of its financial instruments is materially different from the carrying value. The carrying value of those financial instruments that are classified as current, except for derivative instruments, approximates fair value because of the short maturity of these instruments. For noncurrent financial instruments, the Company uses quoted market prices or, to the extent that there are no Share-Based Payments Options granted are valued at the date of grant and expense is recognized over the vesting period. The Company currently utilizes a standard option pricing model (Black-Scholes) to measure the fair value of stock options granted to employees and directors. Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the restrictions. The value of such restricted stock is determined using the market price on the grant date and expense is recorded over the vesting period. For the years ended December 31, 2017 2018 2019 $3.2 $2.4 $1.9 Restoration, Removal and Environmental Liabilities The Company is subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may no Liabilities for expenditures of a noncapital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component are fixed or reliably determinable. The fair value of a liability for an asset's retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period and the capitalized cost is depreciated over the estimated useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and we amortize these costs as a component of our depletion expense in the accompanying consolidated financial statements. Each year, the Company reviews, and to the extent necessary, revises its asset retirement obligation estimates. The following table (in thousands) summarizes changes in the Company’s future site restoration obligations during the two December 31: 2018 2019 Beginning future site restoration obligation $ 8,775 $ 7,492 New wells placed on production and other 612 80 Deletions related to property disposals (1,844 ) (473 ) Deletions related to plugging costs (426 ) (890 ) Accretion expense and other 516 436 Revisions and other (141 ) 775 Ending future site restoration obligation $ 7,492 $ 7,420 Revenue Recognition and Major Purchasers The Company recognizes oil and gas revenue from its interest in producing wells as oil and gas is sold from those wells, net of royalties. The Company recognizes oil and gas revenues from its interests in producing wells when control has transferred to the purchaser and to the extent the selling price is reasonably determinable. The Company had no December 31, 2018 2019 During 2017 three 69% 2018 two 57% 2019 two 71% Deferred Financing Fees Deferred financing fees are being amortized on the effective yield basis over the term of the related debt. Income Taxes Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to be in effect with respect to taxable income in the years in which those temporary differences are expected to be recovered or settled. Uncertainties exist as to the future utilization of the operating loss carryforwards. Therefore, we have established a valuation allowance of $76.2 December 31, 2019 On December 22, 2017, 115 97, 35% 21%, December 22, 2017. not Accounting for Uncertainty in Income Taxes Evaluation of a tax position is a two first not second not 50% Tax positions that previously failed to meet the more-likely-than- not first no not first no no December 31, 2019 Adoption of New Accounting Standard In February 2016, The new standard was effective in the first 2019 January 1, 2019. no ● Not 12 ● Not ● Not January 1, 2019. The impact of adoption of this new standard on our balance sheet was as follows: January 1, 2019 (in thousands) Operating lease ROU asset $ 687 Operating lease liability - current $ (108 ) Operating lease liability - long-term $ (579 ) Leases acquired to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are not 13. |
Note 2 - Revenue From Contracts
Note 2 - Revenue From Contracts With Customers | 12 Months Ended |
Dec. 31, 2019 | |
Notes to Financial Statements | |
Revenue from Contract with Customer [Text Block] | 2. Revenue Recognition Sales of oil, gas and NGL are recognized at the point in time when control of the product is transferred to the customer and collectability is reasonably assured. The Company's contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, physical location, quality of the oil or gas, and prevailing supply and demand conditions. As a result, the price of the oil, gas and NGL fluctuates to remain competitive with other available oil, gas and NGL supplies in the market. The Company believes that the pricing provisions of our oil, gas and NGL contracts are customary in the industry. Oil sales The Company's oil sales contracts are generally structured such that it sells its oil production to a purchaser at a contractually specified delivery point at or near the wellhead. The crude oil production is priced on the delivery date based upon prevailing index prices less certain deductions related to oil quality, physical location and transportation costs incurred by the purchaser subsequent to delivery. The Company recognizes revenue when control transfers to the purchaser upon delivery at or near the wellhead at the net price received from the purchaser. Payment terms as customarily and normally paid on the twentieth Gas and NGL Sales Under the Company's gas processing contracts, it delivers wet gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. There are no third In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. With respect to the Company's gas purchase contracts, the Company has concluded that it is the agent, and thus, the midstream processing entity is its customer. Accordingly, the Company recognizes revenue upon delivery to the midstream processing entity based on the net amount of the proceeds received from the midstream processing entity. Imbalances The Company had no December 31, 2018 2019. Disaggregation of Revenue The Company is focused on the development of oil and natural gas properties primarily located in the following three Years Ended December 31, 2017 2018 2019 Oil Gas NGL Oil Gas NGL Oil Gas NGL (In thousands) Operating Region Permian/Delaware Basin $ 17,722 $ 3,028 $ 1,840 $ 47,175 $ 2,698 $ 2,884 $ 52,789 $ 494 $ 602 Rocky Mountain $ 49,670 $ 2,694 $ 3,774 $ 77,664 $ 3,913 $ 5,253 $ 68,555 $ 1,480 $ 1,305 South Texas $ 6,192 $ 1,176 $ 93 $ 8,065 $ 1,243 $ 135 $ 3,159 $ 605 $ 3 Significant Judgments Principal versus agent The Company engages in various types of transactions in which midstream entities process the Company's gas and subsequently market resulting NGL and residue gas to third Transaction price allocated to remaining performance obligations A significant number of the Company's product sales are short-term in nature with a contract term of one 606 10 50 14 one For product sales that have a contract term greater than one 606 10 50 14 not not Contract balances Under the Company's product sales contracts, the Company is entitled to payment from purchasers once its performance obligations have been satisfied upon delivery of the product, at which point payment is unconditional. The Company records invoiced amounts as “Accounts receivable - Oil and gas production sales” in the accompanying condensed consolidated balance sheet. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not third not 2014 09. December 31, 2018 December 31, 2019 $22.0 $17.0 Prior-period performance obligations The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain gas and NGL sales may not 30 60 not third The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between its revenue estimates and actual revenue received historically have not December 31, 2019 not |
Note 3 - Acquisition and Divest
Note 3 - Acquisition and Divestitures of Properties | 12 Months Ended |
Dec. 31, 2019 | |
Notes to Financial Statements | |
Mergers, Acquisitions and Dispositions Disclosures [Text Block] | 3. During the year ended December 31, 2018, 2,721 $40.4 $21,000 During 2018 $3.3 2019, $23.4 No During 2017, $4.6 No |
Note 4 - Long-term Debt
Note 4 - Long-term Debt | 12 Months Ended |
Dec. 31, 2019 | |
Notes to Financial Statements | |
Long-term Debt [Text Block] | 4. The following is a description of the Company’s debt as of December 31, 2018 2019 Years Ended December 31, 2018 2019 (In thousands) First Lien Credit Facility $ 180,000 $ 95,778 Second Lien Credit Facility - 100,000 Real estate lien note 3,358 3,091 183,358 198,869 Less current maturities (267 ) (280 ) 183,091 198,589 Deferred financing fees, net of accumulated amortization (1,149 ) (5,871 ) Total long-term debt, net of deferred financing fees $ 181,942 $ 192,718 Maturities of long-term debt are as follows: Years ending December 31, (In thousands) 2020 $ 280 2021 295 2022 196,088 2023 2,206 2024 - Thereafter - Total $ 198,869 First Lien Credit Facility The Company has a senior secured First Lien Credit Facility with Société Générale, as administrative agent and issuing lender, and certain other lenders. As of December 31, 2019 $95.8 November 13, 2019 June 25, 2020, 14. Prior to the refinancing described in Note 14, $200.0 December 31, 2019 $135.0 14, one one may one six one six not may not $200.0 x 0.5%, one 1.5% 2.5%, 2.5% 3.5% 3.0% December 31, 2019 4.8% Subject to earlier termination rights and events of default, the stated maturity date of the First Lien Credit Facility is May 16, 2022. not Each of the Company's subsidiaries has guaranteed our obligations under the First Lien Credit Facility on a senior secured basis. Obligations under the First Lien Credit Facility are secured by a first December 31, 2019, 90% 9 95% 9 Under the First Lien Credit Facility, the Company is subject to customary covenants, including certain financial covenants and reporting requirements. Prior to the refinancing described in Note 14, not 1.00 1.00 not 2.50 1.00. 14, not 3.50 1.00. four four November 13, 2019 14, 9 9 20% 14, not 1.45 1.00 March 31, 2021 December 31, 2021) not 1.55 1.00 December 31, 2021). At December 31, 2019 December 31, 2019 6.22 1.00, 2.61 1.00, 1.28 1.00 1.56 1.00. not September 30, 2019, not not The First Lien Credit Facility contains a number of covenants that, among other things, restrict our ability to: • incur or guarantee additional indebtedness; • transfer or sell assets; • create liens on assets; • pay dividends of make other distributions on capital stock or make other restricted payments; • engage in transactions with affiliates other than on an “arm’s length” basis; • make any change in the principal nature of our business; and • permit a change of control. The First Lien Credit Facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities. See further information in Note 14 Second Lien Credit Facility On November 13, 2019, $100.0 November 13, 2019, $95.0 December 31, 2019, $100.0 14, x 0.5%, three 2.75%, 8.00% x 1.75%, 9.0% 3% December 31, 2019, 10.9% 3.50% The stated maturity date of the Second Lien Credit Facility is November 13, 2022. 14 three November 13, 2020, November 13, 2020 Each of our subsidiaries has guaranteed our obligations under the Second Lien Credit Facility. Obligations under the Second Lien Credit Facility are secured by a first December 31, 2019, 90% 9 95% 9 Under the Second Lien Credit Facility, the Company is subject to customary covenants, including certain financial covenants and reporting requirements. Prior to the refinancing described in Note 14, not 1.00 1.00 not 4.00 1.00. 14 not 1.25 1.00 December 31, 2019 December 31, 2020), not 1.45 1.00 March 31, 2021 December 31, 2021), not 1.55 1.00 December 31, 2021). four 9 9 20% At December 31, 2019, December 31, 2019 6.24 1.00, 2.61 1.00, 1.28 1.00 1.56 1.00. 10 December 31, 2019 no 90 2L March 31, 2020, 2L not 14 The Second Lien Credit Facility contains a number of covenants that, among other things, restrict our ability to: ● incur or guarantee additional indebtedness; ● transfer or sell assets; ● create liens on assets; ● pay dividends or make other distributions on capital stock or make other restricted payments; ● engage in transactions with affiliates other than on an “arm’s length” basis; ● make any change in the principal nature of our business; and ● permit a change of control The Second Lien Credit Facility also contains customary events of default, including nonpayment of principal or interest, violation of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities. Real Estate Lien Note We have a real estate lien note secured by a first 4.9%. $35,672. July 20, 2023. December 31, 2018 2019 $3.4 $3.1 |
Note 5 - Property and Equipment
Note 5 - Property and Equipment | 12 Months Ended |
Dec. 31, 2019 | |
Notes to Financial Statements | |
Property, Plant and Equipment Disclosure [Text Block] | 5. The major components of property and equipment, at cost, are as follows: Estimated December 31, Useful life 2018 2019 Years (In thousands) Oil and gas properties (1) $ 1,091,905 $ 1,162,094 Equipment and other 3-39 15,369 15,187 Drilling rig 15 24,084 24,108 1,131,358 1,201,389 Accumulated depreciation, depletion, amortization and impairment (768,140) (872,431) Net Property and Equipment $ 363,218 $ 328,958 ( 1 |
Note 6 - Stock-based Compensati
Note 6 - Stock-based Compensation and Option Plans | 12 Months Ended |
Dec. 31, 2019 | |
Notes to Financial Statements | |
Share-based Payment Arrangement [Text Block] | 6. The Company’s Amended and Restated 2005 12.6 may not 10 may 1 one 2 3 4 Stock Options The Company utilizes a standard option pricing model (Black-Scholes) to measure the fair value of stock options granted to employees and directors. The fair value for these options was estimated at the date of grant using the following weighted average assumptions for 2017 2018 2019 2017 2018 2019 (6) Weighted average value per option granted during the period $ 1.81 $ 1.87 $ - Assumptions: Forfeiture rate (1) 2.0 % 1.7 % - Expected dividend yield (2) 0.0 % 0.0 % - Volatility (3) 67.6 % 66.5 % - Risk free interest rate (4) 2.2 % 2.9 % - Expected life (years) (5) 6.9 7.3 - Fair value of options granted (in thousands) $ 574 $ 841 $ - ______________________ ( 1 The estimated future forfeiture rate is based on the Company’s historical forfeiture rate on similar grants of stock options. ( 2 The dividend yield is based on the fact the Company does not ( 3 The volatility is based on the historical volatility of our stock for a period approximating the expected life. ( 4 The risk-free interest rate is based on the observed U.S. Treasury yield curve in effect at the time the options were granted for a period approximating the expected life of the option. ( 5 The expected life was derived based on a weighting between (a) the Company’s historical exercise and forfeiture activity and (b) the average midpoint between vesting and the contractual term. ( 6 There were no 2019 The Company grants options to its officers, directors, and other employees under various stock option and incentive plans. The following table is a summary of the Company’s stock option activity for the three December 31: Options Weighted average Weighted average Intrinsic value (000s) exercise price remaining life per share Options outstanding December 31, 2016 8,154 $ 2.39 Granted 317 1.81 Exercised (5 ) 0.97 Forfeited/Expired (149 ) 3.58 Options outstanding December 31, 2017 8,317 $ 2.35 Granted 300 2.80 Exercised (379 ) 1.71 Forfeited/Expired (689 ) 2.70 Options outstanding December 31, 2018 7,549 $ 2.37 Granted - - Exercised (469 ) 0.98 Forfeited/Expired (1,154 ) 2.40 Options outstanding December 31, 2019 5,926 $ 2.47 4.6 $ 0.00 Exercisable at end of year 5,446 $ 1.83 4.4 $ 0.00 Other information pertaining to the Company’s stock option activity for the three December 31: 2017 2018 2019 Weighted average grant date fair value of stock options granted (per share) $ 1.81 $ 1.87 $ - Total fair value of options vested (000's) $ 2,795 $ 2,054 $ 732 Total intrinsic value of options exercised (000's) $ 5 $ 395 $ 141 As of December 31, 2019 not $0.2 2020 2022. December 31, 2017 2018 2019 $1.8 $1.4 $0.4 The following table represents the range of stock option prices and the weighted average remaining life of outstanding options as of December 31, 2019 Outstanding Options Exercisable Weighted Weighted Weighted Weighted average average average average Number remaining exercise Number remaining exercise Range of stock option prices Outstanding life price Outstanding life price 0.97 - 1.99 2,167,750 5.8 $ 1.17 1,764,500 5.7 $ 1.20 2.00 - 2.99 1,282,075 3.6 $ 2.46 1,205,075 3.3 $ 2.45 3.00 - 3.99 1,925,448 4.3 $ 3.30 1,925,448 4.3 $ 3.30 4.00 - 4.99 453,000 3.0 $ 4.55 453,000 3.0 $ 4.55 5.00 - 5.99 97,000 4.3 $ 5.38 97,000 4.3 $ 5.38 6.00 - 6.28 1,000 4.5 $ 6.28 1,000 4.5 $ 6.28 5,926,273 4.6 $ 2.47 5,446,023 4.4 $ 2.57 Restricted Stock Awards Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the restrictions. The value of such stock is determined using the market price on the grant date. Compensation expense is recorded over the applicable restricted stock vesting periods. As of December 31, 2019 not $1.9 2020 2022. December 31, 2017 2018 2019 $1.4 $0.7 $1.0 The following table is a summary of the Company’s restricted stock activity for the three December 31, 2019 Number of Shares Weighted average grant date fair value Unvested December 31, 2016 1,492 $ 3.47 Granted 44 1.75 Vested/Released (56 ) 3.14 Forfeited (1 ) 2.63 Unvested December 31, 2017 1,479 $ 3.43 Granted 861 2.17 Vested/Released (1,326 ) 3.43 Forfeited (187 ) 3.22 Unvested December 31, 2018 827 $ 2.15 Granted 1,315 1.34 Vested/Released (270 ) 2.15 Forfeited (91 ) 1.54 Unvested December 31, 2019 1,781 $ 1.58 Performance Based Restricted Stock Awards Effective on April 1, 2018, 2005 2021 three zero 200% The table below provides a summary of Performance Based Restricted Stock as of the date indicated (shares in thousands): Number of Shares Weighted average grant date fair value Unvested December 31, 2017 - $ - Granted 464 2.37 Vested/Released - - Forfeited (59 ) 2.37 Unvested December 31, 2018 405 $ 2.37 Granted 803 1.34 Vested/Released - - Forfeited (54 ) 1.52 Unvested December 31, 2019 1,154 $ 1.69 Compensation expense associated with the performance based restricted stock is based on the grant date fair value of a single share as determined using a Monte Carlo Simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As the Compensation Committee intends to settle the performance based restricted stock awards with shares of the Company's common stock, the awards are accounted for as equity awards and the expense is calculated on the grant date assuming a 100% As of December 31, 2019 not $0.7 2020 2022. December 31, 2018 2019, $0.2 $0.5 Director Stock Awards The 2005 2.9 2005 first $12,000, one 100,000 no 100% At December 31, 2019 8.7 |
Note 7 - Income Taxes
Note 7 - Income Taxes | 12 Months Ended |
Dec. 31, 2019 | |
Notes to Financial Statements | |
Income Tax Disclosure [Text Block] | 7. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of the Company’s deferred tax liabilities and assets are as follows: As of December 31, 2018 2019 (In thousands) Deferred tax liabilities: Hedge contracts $ 3,167 $ - Other 2,977 2,967 Total deferred tax liabilities 6,144 2,967 Deferred tax assets: US full cost pool 4,310 9,015 Capital loss carryforwards 3,980 - Depletion carryforward 3,098 3,497 U.S. net operating loss carryforward 61,309 65,073 Alternative minimum tax credit 757 6 Hedge contracts - 1,561 Total deferred tax assets 73,454 79,152 Valuation allowance for deferred tax assets (67,310 ) (76,185 ) Net deferred tax assets 6,144 2,967 Net deferred tax $ - $ - Significant components of the provision (benefit) for income taxes are as follows: Years Ended December 31, 2017 2018 2019 (In thousands) Current: Federal $ - $ - $ - State - - - $ - $ - $ - Deferred: Federal $ - $ - $ - $ - $ - $ - At December 31, 2019 $245.2 2018 $64.7 2018 2018 2022 2037, not 100% 2018, 2019 2020 five 100% January 1, 2021 80% December 31, 2020. January 1, 2021, 80% no January 1, 2018). The use of our NOLs will be limited if there is an "ownership change" in our common stock, generally a cumulative ownership change exceeding 50% three 382 December 31, 2019 not 382. $80.4 December 31, 2017 $67.3 December 31, 2018 $76.2 December 31, 2019 The reconciliation of income tax computed at the U.S. federal statutory tax rates to income tax expense is: Years Ended December 31, 2017 2018 2019 (In thousands) Tax (expense) benefit at U.S. Statutory rates $ (5,602 ) $ (12,142 ) $ 13,651 (Increase) decrease in deferred tax asset valuation allowance 57,309 13,135 (8,875 ) Alternative minimum tax expense - - (745 ) Expired capital loss carryover - - (3,966 ) Permanent differences (1,134 ) (500 ) (403 ) Return to provision estimated revision 2,494 (470 ) 341 Change in deferred tax rate (53,125 ) - - Other 58 (23 ) (3 ) $ - $ - $ - As of December 31, 2017 2018 2019 not 2014 2019 New tax legislation, commonly referred to as the Tax Cuts and Jobs Act (H.R. 1 December 22, 2017. 21% not may 30% 2017 80% 2017, 100% not may 14 March 2020, 19 |
Note 8 - Commitments and Contin
Note 8 - Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2019 | |
Notes to Financial Statements | |
Commitments and Contingencies Disclosure [Text Block] | 8. Operating Leases The Company leased office space in Dickinson, North Dakota, Lusk, Wyoming and Denver, Colorado. During 2017 2018 $27,840, $23,200, October 31, 2018 not 2017 2018 $9,000 December 31, 2018 not 2017 $13,837. December 31, 2017 not Litigation and Contingencies From time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business. At December 31, 2019 not |
Note 9 - Earnings Per Share
Note 9 - Earnings Per Share | 12 Months Ended |
Dec. 31, 2019 | |
Notes to Financial Statements | |
Earnings Per Share [Text Block] | 9. The following table sets forth the computation of basic and diluted earnings per share: Years Ended December 31, 2017 2018 2019 (in thousands, except per share data) Numerator: Net income (loss) $ 16,006 $ 57,821 $ (65,004 ) Denominator for basic earnings per share - weighted-average common shares outstanding 161,141 165,635 166,247 Effect of dilutive securities: Stock options, restricted shares and performance based shares 1,703 2,054 65 Denominator for diluted earnings per share - adjusted weighted-average shares and assumed exercise of options, restricted shares and performance based shares 162,844 167,689 166,312 Net (loss) income per common share - basic $ 0.10 $ 0.35 $ (0.39 ) Net (loss) income per common share - diluted $ 0.10 $ 0.34 $ (0.39 ) Basic earnings per share, excluding any dilutive effects of stock options and unvested restricted stock, is computed by dividing net income (loss) available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted income (loss) per share is computed similar to basic; however diluted income (loss) per share reflects the assumed conversion of all potentially dilutive securities. For the year December 31, 2017 2018, 5,018 4,007 December 31, 2019, 76 |
Note 10 - Benefit Plans
Note 10 - Benefit Plans | 12 Months Ended |
Dec. 31, 2019 | |
Notes to Financial Statements | |
Compensation and Employee Benefit Plans [Text Block] | 10. The Company has a defined contribution plan ( 401 2017 2018 2019 $330,415, $331,957 $284,905, 401 first 1% 50 5%. may 2017 $18,000 50 $24,000 50 2018 $18,500 50 $24,500 50 2019 $19,000 50 $25,000 50 |
Note 11 - Hedging Program and D
Note 11 - Hedging Program and Derivatives | 12 Months Ended |
Dec. 31, 2019 | |
Notes to Financial Statements | |
Derivative Instruments and Hedging Activities Disclosure [Text Block] | 11. Hedging Program and Derivatives The derivative instruments we utilize are based on index prices that may not 815; no no The following table sets forth the summary position of our derivative contracts as of December 31, 2019 Oil - WTI Contract Periods Daily Volume (Bbl) Swap Price (per Bbl) Fixed Swaps January - December 2020 3,777 $ 55.23 January - December 2021 2,808 $ 57.82 Basis Swaps January - December 2020 4,000 $ 2.98 The following table illustrates the impact of derivative contracts on the Company’s balance sheet: Fair Value Derivative Contracts as of December 31, 2018 Asset Derivatives Liability Derivatives Derivatives not designated as hedging instruments Balance Sheet Location Fair Value Balance Sheet Location Fair Value Commodity price derivatives Derivatives - current $ 9,602 Derivatives - current $ 616 Commodity price derivatives Derivatives - long-term 10,527 Derivatives - long-term 4,434 $ 20,129 $ 5,050 Fair Value Derivative Contracts as of December 31, 2019 Asset Derivatives Liability Derivatives Derivatives not designated as hedging instruments Balance Sheet Location Fair Value Balance Sheet Location Fair Value Commodity price derivatives Derivatives - current $ 83 Derivatives - current $ 10,688 Commodity price derivatives Derivatives - long-term 4,170 Derivatives - long-term 999 $ 4,253 $ 11,687 Gains and losses from derivative activities are reflected as “Loss (gain) on derivative contracts” in the accompanying Consolidated Statements of Operations. The net estimated value of our commodity derivative contracts was a liability of approximately $7.4 December 31, 2019 December 31, 2019 $26.8 $6.0 $20.8 December 31, 2018 $8.1 $19.0 $27.1 |
Note 12 - Financial Instruments
Note 12 - Financial Instruments | 12 Months Ended |
Dec. 31, 2019 | |
Notes to Financial Statements | |
Fair Value Disclosures [Text Block] | 12. There is a three one three three • Level 1 • Level 2 • Level 3 A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Company is further required to assess the creditworthiness of the counter-party to the derivative contract. The results of the assessment of non-performance risk, based on the counter-party’s credit risk, could result in an adjustment of the carrying value of the derivative instrument. The following tables sets forth information about the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2018 2019 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance as of December 31, 2018 Assets: NYMEX fixed price derivative contracts $ - $ 18,172 $ - $ 18,172 NYMEX basis differential swap - - 1,957 1,957 Total Assets $ - $ 18,172 $ 1,957 $ 20,129 Liabilities: NYMEX fixed price derivative contracts $ - $ - $ - $ - NYMEX basis differential swap - - 5,050 5,050 Total Liabilities $ - $ - $ 5,050 $ 5,050 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance as of December 31, 2019 Assets: NYMEX fixed price derivative contracts $ - $ 4,253 $ - $ 4,253 NYMEX basis differential swap - - - - Total Assets $ - $ 4,253 $ - $ 4,253 Liabilities: NYMEX fixed price derivative contracts $ - $ 5,583 $ - $ 5,583 NYMEX basis differential swap - - 6,104 6,104 Total Liabilities $ - $ 5,583 $ 6,104 $ 11,687 The Company’s derivative contracts at December 31, 2019 December 31, 2018 2. third third not 3. Additional information for the Company's recurring fair value measurements using significant unobservable inputs (Level 3 December 31, 2019 (In thousands) Fair value at January 1, 2019 $ (3,093 ) Changes in market value (5,794 ) Settlements during the period 2,783 Fair value at December 31, 2019 $ (6,104 ) There were no 3 2019 Nonrecurring Fair Value Measurements Non-financial assets and liabilities measured at fair value on a nonrecurring basis included certain non-financial assets and liabilities as may The asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no 3. 1. Other Financial Instruments The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable and accounts payable approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. The carrying value of our debt approximates fair value as the interest rates are market rates and this debt is considered Level 2. |
Note 13 - Lease Accounting Stan
Note 13 - Lease Accounting Standard | 12 Months Ended |
Dec. 31, 2019 | |
Notes to Financial Statements | |
Lessee, Operating Leases [Text Block] | 13. We determine if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. We currently do not January 1, 2019 one not Our operating leases are reflected as operating lease ROU assets, operating lease liability - current and long-term operating lease liabilities on our consolidated balance sheet. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement and initial direct cost incurred less any lease incentives. Lease expense for operating leases is recognized on a straight-line basis over the lease term. Nature of Leases We lease certain real estate, field equipment and other equipment under cancelable and non-cancelable leases to support our operations. A more detailed description of our significant lease types is included below. Real Estate Leases We rent a residence in North Dakota from a third five August 31, 2024. not Field Equipment We rent compressors and coolers from third one thirty not twelve not third thirty not Discount Rate Our leases typically do not Practical Expedients and Accounting Policy Elections Certain of our lease agreements include lease and non-lease components. For all existing asset classes with multiple component types, we have utilized the practical expedient that exempts us from separating lease components from non-lease components. Accordingly, we account for the lease and non-lease components in an arrangement as a single lease component. In addition, for all of our existing asset classes, we have made an accounting policy election not 12 not not None The components of our total lease expense for the year ended December 31, 2019 Year Ended December 31, 2019 (in thousands) Operating lease cost $ 478 Short-term lease expense (1) 1,992 Total lease expense $ 2,470 Short-term lease costs (2) $ 4,900 ( 1 Short-term lease expense represents expense related to leases with a contract term of 12 ( 2 These short-term lease costs are related to leases with a contract term of 12 Supplemental balance sheet information related to our operating leases is included in the table below: December 31, 2019 (in thousands) Operating lease ROU assets $ 327 Operating lease liability - current $ 98 Operating lease liabilities - long-term $ 203 Our weighted average remaining lease term and weighted average discount rate for our operating leases are as follows: December 31, 2019 Weighted Average Remaining Lease Term (in years) 8.66 Weighted Average Discount Rate 6 % Our lease liabilities with enforceable contract terms that are greater than one Operating Leases (in thousands) 2020 $ 113 2021 63 2022 48 2023 41 2024 28 Thereafter 102 Total lease payments 395 Less imputed interest (94 ) Total lease liability $ 301 As of December 31, 2018, 840 December 31, 2018 one no December 31, 2018. Supplemental cash flow information related to our operating leases is included in the table below: Year Ended December 31, 2019 (in thousands) Cash paid for amounts included in the measurement of lease liabilities $ 478 ROU assets added in exchange for lease obligations (since adoption) $ 770 |
Note 14 - Subsequent Events
Note 14 - Subsequent Events | 12 Months Ended |
Dec. 31, 2019 | |
Notes to Financial Statements | |
Subsequent Events [Text Block] | 14. In January 2020, Oil - WTI Contract Periods Daily Volume (Bbl) Swap Price (per Bbl) Fixed Swaps April - July 2020 80 $ 50.60 January - December 2021 82 $ 50.60 January - December 2022 2,412 $ 50.60 January - December 2023 1,498 $ 50.60 January - December 2024 1,589 $ 50.60 On January 30, 2020, 19” March 2020, 19 March 2020, Subsequent to December 31, 2019 19 Consumer demand has decreased since the spread of the COVID- 19 2020. 2020 20% 40% 5% 20%. In early March 2020, may The "Coronavirus Aid, Relief, and Economic Security (CARES) Act" that was enacted March 27, 2020 no On May 4, 2020, $1.4 1.0% two seventeen first seven eight 75% not Amendments to First Lien Credit Facility and Second Lien Credit Facility Waiver and Amendment No. 10 June 25, 2020, No. 10 “1L December 31, 2019 not 90 March 31, 2020 not 45 not 60 19 10 December 31, 2019 no 90 10 March 31, 2020 no 45 1L 1L not 1L $3.0 six no six first not 2.75 1.00 first 15 9 15 20% not 1.15 1.00 December 31, 2020, 1.25 1.00 $3.0 four four June 30, 2020 1, 2 3 June 30, 2020, September 30, 2020 December 31, 2020, 1 first 1.60 1.00, 2 first 3 $50.0 4 no 5 $7.5 60 $2.0 90 $1.0 may four $9.0 four June 30, 2020, $8.25 four September 30, 2020, $6.9 four December 31, 2020, $6.5 March 31, 2021 December 31, 2021 $5.0 $25.0 1L $135.0 $102.0 Waiver and Second Amendment to Term Loan Credit Agreemen June 25, 2020, “2L 10 December 31, 2019 no 90 2L March 31, 2020 not 60 2L 2L 2L March 31, 2020, 2L 10.01 9.19 2L March 31, 2020 ( not 2L 200bps 500bps 15 9 15 20% not 1.45 1.00 September 30, 2021 December 31, 2021, 1.55 1.00 first September 30, 2021; ( $7.5 60 $2.0 90 $1.0 may four $9.0 four June 30, 2020, $8.25 four September 30, 2020, $6.5 March 31, 2021 December 31, 2021, $5.0 Fee Letter June 25, 2020, 2L 2L $10,000,000 $0.01 19.9% one Future compliance with the covenants under the First Lien Credit Facility and Second Lien Credit Facility is reliant upon our ability to successfully implement cost reductions, control capital expenditures and restart production that has been shut in. In the event of a future covenant violation, we would attempt to obtain waivers or amendments of the related agreements; however, it is uncertain if such waivers or amendments could be obtained on acceptable terms or at all. In the event we default under the First Lien Credit Facility or Second Lien Credit Facility, amounts outstanding would become due and payable at the option of the lenders. |
Note 15 - Quarterly Results of
Note 15 - Quarterly Results of Operations (Unaudited) | 12 Months Ended |
Dec. 31, 2019 | |
Notes to Financial Statements | |
Quarterly Financial Information [Text Block] | 15. Selected results of operations for each of the fiscal quarters during the years ended December 31, 2018 2019 1st 2nd 3rd 4th Quarter Quarter Quarter Quarter (In thousands, except per share data) Year Ended December 31, 2018 Net revenue $ 40,630 $ 30,916 $ 41,625 $ 35,996 Operating income $ 20,090 $ 10,931 $ 17,735 $ 8,722 Net income (loss) $ 10,779 $ (10,554 ) $ 1,777 $ 55,819 Net income (loss) per common share - basic $ 0.07 $ (0.06 ) $ 0.01 $ 0.34 Net income (loss) per common share - diluted $ 0.06 $ (0.06 ) $ 0.01 $ 0.33 Year Ended December 31, 2019 Net revenue $ 34,514 $ 34,820 $ 31,536 $ 28,276 Operating income (loss) $ 6,708 $ 8,935 $ 8,053 $ (49,412 ) Net income (loss) $ (25,455 ) $ 11,678 $ 17,041 $ (68,268 ) Net income (loss) per common share - basic $ (0.15 ) $ 0.07 $ 0.10 $ (0.41 ) Net income (loss) per common share - diluted $ (0.15 ) $ 0.07 $ 0.10 $ (0.41 ) |
Note 16 - Supplemental Oil and
Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) | 12 Months Ended |
Dec. 31, 2019 | |
Notes to Financial Statements | |
Oil and Gas Exploration and Production Industries Disclosures [Text Block] | 16. The accompanying tables (in thousands) presents information concerning the Company’s oil and gas producing activities “Disclosures about Oil and Gas Producing Activities.” Capitalized costs relating to oil and gas producing activities are as follows as of December 31: Years Ended December 31, 2018 2019 Proved oil and gas properties $ 1,091,905 $ 1,162,094 Unproved properties - - Total 1,091,905 1,162,094 Accumulated depreciation, depletion, amortization and impairment (748,773 ) (851,107 ) Net capitalized costs $ 343,132 $ 310,987 Cost incurred in oil and gas property acquisition and development activities were as follows for the years ended December 31 ( 2017 2018 2019 Development costs $ 94,478 $ 131,271 $ 92,884 Exploration costs 8,509 - - Property acquisition costs 31,409 41,465 - $ 134,396 $ 172,736 $ 92,884 Results of operations from oil and gas producing activities were as follows for the years ended December 31: 2017 2018 2019 Revenues $ 86,189 $ 149,030 $ 128,992 Production costs (22,425 ) (36,323 ) (38,229 ) Depreciation, depletion and amortization (25,676 ) (42,237 ) (51,041 ) Accretion of future site restoration (451 ) (516 ) (436 ) Proved property impairment - - (51,293 ) Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs) $ 37,637 $ 69,954 $ (12,007 ) Depletion rate per barrel of oil equivalent $ 9.52 $ 11.80 $ 14.12 Estimated Quantities of Proved Oil and Gas Reserves Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. The estimates have been predominately prepared by independent petroleum reserve engineers. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. All of the Company’s proved reserves are located in the continental United States. Proved reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no 12 first The following set forth changes in estimated net proved reserves for the years ended December 31, 2017 2018 2019 Oil Oil NGL Gas Equivalents (MBbl) (MBbl) (MMcf) (Mboe) Change in Proved Reserves Balance at December 31, 2016 24,209 8,644 70,829 44,657 Revisions of previous estimates 259 1,269 19,311 4,747 Extensions and discoveries 14,533 2,813 14,534 19,768 Purchases of minerals in place 8 14 1,001 189 Sales of minerals in place (364 ) (289 ) (3,958 ) (1,312 ) Production (1,574 ) (476 ) (3,889 ) (2,698 ) Balance at December 31, 2017 37,071 11,975 97,828 65,351 Revisions of previous estimates (4,206 ) (1,927 ) (2,618 ) (6,570 ) Extensions and discoveries 11,270 1,797 11,475 14,979 Purchases of minerals in place 688 - 1,137 877 Sales of minerals in place (278 ) (1,303 ) (13,491 ) (3,829 ) Production (2,308 ) (508 ) (4,587 ) (3,580 ) Balance at December 31, 2018 42,237 10,034 89,744 67,228 Revisions of previous estimates (15,616 ) (2,713 ) (23,178 ) (22,192 ) Extensions and discoveries 13,477 2,285 14,073 18,109 Sales of minerals in place (1,431 ) (86 ) (9,898 ) (3,167 ) Production (2,388 ) (548 ) (4,076 ) (3,616 ) Balance at December 31, 2019 36,279 8,972 66,665 56,362 The following is a summary of the changes to the Company’s proved reserves that occurred during 2019 Revisions to prior estimates There was a decrease of 8,790 2019. eight A1 twenty-four A2 one 3rd two 2019 13,402 no five Extensions, discoveries and other additions The Company added two nine 3rd 3,776 eighteen A1 twenty-four 3rd one 2019 14,333 Purchases: The Company did not 2019. Sales: The Company sold all its holdings in the Gulf Coast Area accounting for 1,839 fourteen 42 1,268 18 Production: The Company produced 3,616 2019. The following is a summary of the changes to the Company’s proved reserves that occurred during 2018: Revisions to prior estimates There was a decrease of 45 2018. thirteen 2 nd 2018 6,525 no five Extensions, discoveries and other additions The Company added nineteen 8,130 two 838 two 1,523 five 2,670 2018 three 1,692 six 126 Purchases: In the Wolfcamp/3 rd 2019 four 877 Sales: The Company sold substantially all its holdings in the Ira Area accounting for 203 one two 3,558 68 Production: The Company produced 3,580 2018. The following is a summary of the changes to the Company’s proved reserves that occurred during 2017 Revisions to prior estimates There was an increase of 621 2017. 1,951 2,698 2017. seven no five 523 Extensions, discoveries and other additions The Company added three 1,229 three 2017 2,028 27 four two 11,928 ten 2017 4,343 240 Purchases The company purchased wells and acquired additional interest in existing wells which added 189 Sales: The Company sold substantially all of its holdings in the Powder River Basin of Wyoming during 2017. 1,312 Production The Company produced 2,698 2017. The following table presents the Company's estimate of its net proved developed and undeveloped oil and gas reserves as of December 31, 2017 2018 2019 Total Oil OIl NGL Gas Equilavents (MBbl) (MBbl) (MMcf) (Mboe) Proved Developed Reserves: December 31, 2017 10,820 3,794 39,974 21,720 December 31, 2018 13,586 3,804 43,271 24,602 December 31, 2019 10,964 2,699 21,439 17,237 Proved Undeveloped Reserves: December 31, 2017 25,808 8,181 57,854 43,631 December 31, 2018 28,651 6,230 46,473 42,626 December 31, 2019 25,315 6,273 45,226 39,125 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The Company’s proved oil and gas reserves have been estimated by the independent petroleum engineering firm, DeGolyer & MacNaughton, assisted by the engineering and operations departments of the Company as of December 31, 2017 December 31, 2019 December 31, 2018. 12 first No. 2010 03, 932 not 2017 2018 2019 The technical personnel responsible for preparing the reserve estimates at DeGolyer & MacNaughton meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. DeGolyer & MacNaughton is an independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists; they do not not February 27, 2020, 99.1 Estimates of proved reserves at December 31, 2017 2018 2019 41 The projections should not not Future net cash inflows after income taxes were discounted using a 10% three December 31, 2017 2018 2019 Years Ended December 31, 2017 2018 2019 Future cash inflows $ 2,035,619 $ 2,876,976 $ 1,890,579 Future production costs (609,921 ) (849,063 ) (598,714 ) Future development costs (461,619 ) (547,163 ) (544,111 ) Future income tax expense (83,915 ) (181,224 ) - Future net cash flows 880,164 1,299,526 747,754 Discount $ (474,423 ) $ (647,642 ) $ (440,142 ) Standardized Measure of discounted future net cash relating to proved reserves $ 405,741 $ 651,884 $ 307,612 Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The following is an analysis of the changes in the Standardized Measure for the periods indicated (in thousands): Years Ended December 31, 2017 2018 2019 Standardized Measure, beginning of year $ 160,600 $ 405,741 $ 651,884 Sales and transfers of oil and gas produced, net of production costs (63,764 ) (112,707 ) (90,763 ) Net change in prices and development and production costs from prior year 159,661 268,942 (218,092 ) Extensions, discoveries, and improved recovery, less related costs 129,277 153,544 98,780 Sales of minerals in place (8,583 ) (39,253 ) (17,276 ) Purchases of minerals in place 1,238 8,990 - Revisions of previous estimates 31,044 (67,345 ) (227,477 ) Change in timing and other 1,908 30,811 (13,744 ) Change in future income tax expense (21,700 ) (37,413 ) 59,112 Accretion of discount 16,060 40,574 65,188 Standardized Measure, end of year $ 405,741 $ 651,884 $ 307,612 The standardized measure is based on the following oil and gas prices over the life of the properties as of the following dates: Years Ended December 31, 2017 2018 2019 Oil (per Bbl) (1) $ 51.34 $ 65.56 $ 55.73 Gas (per Mmbtu) (2) $ 2.99 $ 3.05 $ 2.54 Oil (per Bbl) (3) $ 46.83 $ 56.95 $ 52.14 Gas (per Mmbtu) (4) $ 1.79 $ 1.76 $ 0.63 NGL's (per Bbl) (5) $ 13.19 $ 19.95 $ 3.48 _____________________ ( 1 The quoted oil price for the year ended December 31 2017 2018 2019 12 first 2017 2018 2019 ( 2 The quoted gas price for the year ended December 31, 2017 2018 2019 12 first 2017 2018 2019 ( 3 The oil price is the realized price at the wellhead as of December 31 ( 4 The gas price is the realized price at the wellhead as of December 31 ( 5 The NGL price is the realized price as of December 31 |
Significant Accounting Policies
Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Consolidation, Policy [Policy Text Block] | Nature of Operations We are an independent energy company primarily engaged in the acquisition, exploitation, development and production of oil and gas in the United States. Our oil and gas assets are located in two The terms “Abraxas,” “Abraxas Petroleum,” “we,” “us,” “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its subsidiaries, including Raven Drilling LLC (“Raven Drilling”). |
Rig Accounting [Policy Text Block] | Rig Accounting In accordance with SEC Regulation S- X, no not 2019 |
Use of Estimates, Policy [Policy Text Block] | Use of Estimates The consolidated financial statements of the Company have been prepared by management in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The most significant estimates pertain to proved oil, gas and NGL reserves and related cash flow estimates used in impairment tests of oil and gas properties, the fair value of assets and liabilities acquired in business combinations, derivative contracts, the provision for income taxes including uncertain tax positions, stock based compensation, asset retirement obligations, accrued oil and gas revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ from those estimates. The process of estimating oil and gas reserves in accordance with SEC requirements is complex and involves decisions and assumptions in evaluating the available geological, geophysical, engineering and economic data. Accordingly, these estimates are imprecise. Actual future production, oil and gas prices, differentials, revenues, taxes, capital expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may |
Reclassification, Comparability Adjustment [Policy Text Block] | Reclassifications Certain prior year balances have been reclassified for consistency with current year classifications. Such reclassifications had no |
Concentration Risk, Credit Risk, Policy [Policy Text Block] | Concentration of Credit Risk Financial instruments which potentially expose the Company to credit risk consist principally of trade receivables and derivative contracts. Accounts receivable are generally from companies with significant oil and gas marketing or operating activities. The Company performs ongoing credit evaluations and, generally, requires no The Company maintains any cash and cash equivalents in excess of federally insured limits in prominent financial institutions considered by the Company to be of high credit quality. |
Cash and Cash Equivalents, Policy [Policy Text Block] | Cash and Cash Equivalents Cash and cash equivalents include cash on hand, demand deposits and short-term investments with original maturities of three |
Accounts Receivable [Policy Text Block] | Accounts Receivable Accounts receivable are reported net of an allowance for doubtful accounts of approximately $0.5 $0.1 December 31, 2018 2019 |
Segment Reporting, Policy [Policy Text Block] | Industry Segment and Geographic Information The Company operates in one no |
Full Cost Method Using Gross Revenue Method, Policy [Policy Text Block] | Oil and Gas Properties The Company follows the full cost method of accounting for oil and gas properties. Under this method, certain direct costs and indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves. Net capitalized costs of oil and gas properties, less related deferred taxes, are limited by country, to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10%, not No not December 31, 2017 2018 not December 31, 2019 $51.3 |
Property, Plant and Equipment, Policy [Policy Text Block] | Other Property and Equipment Other property and equipment are recorded at cost. Depreciation of other property and equipment is provided over the estimated useful lives using the straight-line method. Major renewals and improvements are recorded as additions to the property and equipment accounts. Repairs that do not |
Estimate of Proved Oil and Gas Reserves Policy [Policy Text Block] | Estimates of Proved Oil and Gas Reserves Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of: • the quality and quantity of available data; • the interpretation of that data; • the accuracy of various mandated economic assumptions; and • the judgment of the persons preparing the estimate. Our proved reserve information included in this report was based on studies performed by our independent petroleum engineers assisted by the engineering and operations departments of Abraxas. Estimates prepared by other third may may may In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on the average of oil and gas prices based on the unweighted average 12 first may The estimates of proved reserves materially impact depreciation, depletion and amortization, or DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may may |
Derivatives, Policy [Policy Text Block] | Derivative Instruments and Hedging Activities The Company enters into agreements to hedge the risk of future oil and gas price fluctuations. Such agreements are typically in the form of fixed price commodity and basis swaps, which limit the impact of price fluctuations with respect to the Company’s sale of oil and gas. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions could arise where actual production is less than estimated which could result in over hedged volumes. All derivative instruments are recorded on the Consolidated Balance Sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. The derivative instruments the Company utilizes are based on index prices that may 815. not |
Fair Value of Financial Instruments, Policy [Policy Text Block] | Fair Value of Financial Instruments The Company includes fair value information in the notes to consolidated financial statements when the fair value of its financial instruments is materially different from the carrying value. The carrying value of those financial instruments that are classified as current, except for derivative instruments, approximates fair value because of the short maturity of these instruments. For noncurrent financial instruments, the Company uses quoted market prices or, to the extent that there are no |
Share-based Payment Arrangement [Policy Text Block] | Share-Based Payments Options granted are valued at the date of grant and expense is recognized over the vesting period. The Company currently utilizes a standard option pricing model (Black-Scholes) to measure the fair value of stock options granted to employees and directors. Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the restrictions. The value of such restricted stock is determined using the market price on the grant date and expense is recorded over the vesting period. For the years ended December 31, 2017 2018 2019 $3.2 $2.4 $1.9 |
Asset Retirement Obligation and Environmental Cost [Policy Text Block] | Restoration, Removal and Environmental Liabilities The Company is subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may no Liabilities for expenditures of a noncapital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component are fixed or reliably determinable. The fair value of a liability for an asset's retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period and the capitalized cost is depreciated over the estimated useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and we amortize these costs as a component of our depletion expense in the accompanying consolidated financial statements. Each year, the Company reviews, and to the extent necessary, revises its asset retirement obligation estimates. The following table (in thousands) summarizes changes in the Company’s future site restoration obligations during the two December 31: 2018 2019 Beginning future site restoration obligation $ 8,775 $ 7,492 New wells placed on production and other 612 80 Deletions related to property disposals (1,844 ) (473 ) Deletions related to plugging costs (426 ) (890 ) Accretion expense and other 516 436 Revisions and other (141 ) 775 Ending future site restoration obligation $ 7,492 $ 7,420 |
Revenue [Policy Text Block] | Revenue Recognition and Major Purchasers The Company recognizes oil and gas revenue from its interest in producing wells as oil and gas is sold from those wells, net of royalties. The Company recognizes oil and gas revenues from its interests in producing wells when control has transferred to the purchaser and to the extent the selling price is reasonably determinable. The Company had no December 31, 2018 2019 During 2017 three 69% 2018 two 57% 2019 two 71% |
Deferred Charges, Policy [Policy Text Block] | Deferred Financing Fees Deferred financing fees are being amortized on the effective yield basis over the term of the related debt. |
Income Tax, Policy [Policy Text Block] | Income Taxes Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to be in effect with respect to taxable income in the years in which those temporary differences are expected to be recovered or settled. Uncertainties exist as to the future utilization of the operating loss carryforwards. Therefore, we have established a valuation allowance of $76.2 December 31, 2019 On December 22, 2017, 115 97, 35% 21%, December 22, 2017. not |
Income Tax Uncertainties, Policy [Policy Text Block] | Accounting for Uncertainty in Income Taxes Evaluation of a tax position is a two first not second not 50% Tax positions that previously failed to meet the more-likely-than- not first no not first no no December 31, 2019 |
New Accounting Pronouncements, Policy [Policy Text Block] | Adoption of New Accounting Standard In February 2016, The new standard was effective in the first 2019 January 1, 2019. no ● Not 12 ● Not ● Not January 1, 2019. The impact of adoption of this new standard on our balance sheet was as follows: January 1, 2019 (in thousands) Operating lease ROU asset $ 687 Operating lease liability - current $ (108 ) Operating lease liability - long-term $ (579 ) Leases acquired to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are not 14. |
Note 1 - Organization and Sig_2
Note 1 - Organization and Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Notes Tables | |
Schedule of Change in Asset Retirement Obligation [Table Text Block] | 2018 2019 Beginning future site restoration obligation $ 8,775 $ 7,492 New wells placed on production and other 612 80 Deletions related to property disposals (1,844 ) (473 ) Deletions related to plugging costs (426 ) (890 ) Accretion expense and other 516 436 Revisions and other (141 ) 775 Ending future site restoration obligation $ 7,492 $ 7,420 |
Accounting Standards Update and Change in Accounting Principle [Table Text Block] | January 1, 2019 (in thousands) Operating lease ROU asset $ 687 Operating lease liability - current $ (108 ) Operating lease liability - long-term $ (579 ) |
Note 2 - Revenue From Contrac_2
Note 2 - Revenue From Contracts With Customers (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Notes Tables | |
Disaggregation of Revenue [Table Text Block] | Years Ended December 31, 2017 2018 2019 Oil Gas NGL Oil Gas NGL Oil Gas NGL (In thousands) Operating Region Permian/Delaware Basin $ 17,722 $ 3,028 $ 1,840 $ 47,175 $ 2,698 $ 2,884 $ 52,789 $ 494 $ 602 Rocky Mountain $ 49,670 $ 2,694 $ 3,774 $ 77,664 $ 3,913 $ 5,253 $ 68,555 $ 1,480 $ 1,305 South Texas $ 6,192 $ 1,176 $ 93 $ 8,065 $ 1,243 $ 135 $ 3,159 $ 605 $ 3 |
Note 4 - Long-term Debt (Tables
Note 4 - Long-term Debt (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Notes Tables | |
Schedule of Long-term Debt Instruments [Table Text Block] | Years Ended December 31, 2018 2019 (In thousands) First Lien Credit Facility $ 180,000 $ 95,778 Second Lien Credit Facility - 100,000 Real estate lien note 3,358 3,091 183,358 198,869 Less current maturities (267 ) (280 ) 183,091 198,589 Deferred financing fees, net of accumulated amortization (1,149 ) (5,871 ) Total long-term debt, net of deferred financing fees $ 181,942 $ 192,718 |
Contractual Obligation, Fiscal Year Maturity [Table Text Block] | Years ending December 31, (In thousands) 2020 $ 280 2021 295 2022 196,088 2023 2,206 2024 - Thereafter - Total $ 198,869 |
Note 5 - Property and Equipme_2
Note 5 - Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Notes Tables | |
Property, Plant and Equipment [Table Text Block] | Estimated December 31, Useful life 2018 2019 Years (In thousands) Oil and gas properties (1) $ 1,091,905 $ 1,162,094 Equipment and other 3-39 15,369 15,187 Drilling rig 15 24,084 24,108 1,131,358 1,201,389 Accumulated depreciation, depletion, amortization and impairment (768,140) (872,431) Net Property and Equipment $ 363,218 $ 328,958 |
Note 6 - Stock-based Compensa_2
Note 6 - Stock-based Compensation and Option Plans (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Notes Tables | |
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block] | 2017 2018 2019 (6) Weighted average value per option granted during the period $ 1.81 $ 1.87 $ - Assumptions: Forfeiture rate (1) 2.0 % 1.7 % - Expected dividend yield (2) 0.0 % 0.0 % - Volatility (3) 67.6 % 66.5 % - Risk free interest rate (4) 2.2 % 2.9 % - Expected life (years) (5) 6.9 7.3 - Fair value of options granted (in thousands) $ 574 $ 841 $ - |
Share-based Payment Arrangement, Option, Activity [Table Text Block] | Options Weighted average Weighted average Intrinsic value (000s) exercise price remaining life per share Options outstanding December 31, 2016 8,154 $ 2.39 Granted 317 1.81 Exercised (5 ) 0.97 Forfeited/Expired (149 ) 3.58 Options outstanding December 31, 2017 8,317 $ 2.35 Granted 300 2.80 Exercised (379 ) 1.71 Forfeited/Expired (689 ) 2.70 Options outstanding December 31, 2018 7,549 $ 2.37 Granted - - Exercised (469 ) 0.98 Forfeited/Expired (1,154 ) 2.40 Options outstanding December 31, 2019 5,926 $ 2.47 4.6 $ 0.00 Exercisable at end of year 5,446 $ 1.83 4.4 $ 0.00 2017 2018 2019 Weighted average grant date fair value of stock options granted (per share) $ 1.81 $ 1.87 $ - Total fair value of options vested (000's) $ 2,795 $ 2,054 $ 732 Total intrinsic value of options exercised (000's) $ 5 $ 395 $ 141 |
Share-based Payment Arrangement, Option, Exercise Price Range [Table Text Block] | Outstanding Options Exercisable Weighted Weighted Weighted Weighted average average average average Number remaining exercise Number remaining exercise Range of stock option prices Outstanding life price Outstanding life price 0.97 - 1.99 2,167,750 5.8 $ 1.17 1,764,500 5.7 $ 1.20 2.00 - 2.99 1,282,075 3.6 $ 2.46 1,205,075 3.3 $ 2.45 3.00 - 3.99 1,925,448 4.3 $ 3.30 1,925,448 4.3 $ 3.30 4.00 - 4.99 453,000 3.0 $ 4.55 453,000 3.0 $ 4.55 5.00 - 5.99 97,000 4.3 $ 5.38 97,000 4.3 $ 5.38 6.00 - 6.28 1,000 4.5 $ 6.28 1,000 4.5 $ 6.28 5,926,273 4.6 $ 2.47 5,446,023 4.4 $ 2.57 |
Schedule of Nonvested Restricted Stock Units Activity [Table Text Block] | Number of Shares Weighted average grant date fair value Unvested December 31, 2016 1,492 $ 3.47 Granted 44 1.75 Vested/Released (56 ) 3.14 Forfeited (1 ) 2.63 Unvested December 31, 2017 1,479 $ 3.43 Granted 861 2.17 Vested/Released (1,326 ) 3.43 Forfeited (187 ) 3.22 Unvested December 31, 2018 827 $ 2.15 Granted 1,315 1.34 Vested/Released (270 ) 2.15 Forfeited (91 ) 1.54 Unvested December 31, 2019 1,781 $ 1.58 |
Schedule of Nonvested Performance-based Units Activity [Table Text Block] | Number of Shares Weighted average grant date fair value Unvested December 31, 2017 - $ - Granted 464 2.37 Vested/Released - - Forfeited (59 ) 2.37 Unvested December 31, 2018 405 $ 2.37 Granted 803 1.34 Vested/Released - - Forfeited (54 ) 1.52 Unvested December 31, 2019 1,154 $ 1.69 |
Note 7 - Income Taxes (Tables)
Note 7 - Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Notes Tables | |
Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | As of December 31, 2018 2019 (In thousands) Deferred tax liabilities: Hedge contracts $ 3,167 $ - Other 2,977 2,967 Total deferred tax liabilities 6,144 2,967 Deferred tax assets: US full cost pool 4,310 9,015 Capital loss carryforwards 3,980 - Depletion carryforward 3,098 3,497 U.S. net operating loss carryforward 61,309 65,073 Alternative minimum tax credit 757 6 Hedge contracts - 1,561 Total deferred tax assets 73,454 79,152 Valuation allowance for deferred tax assets (67,310 ) (76,185 ) Net deferred tax assets 6,144 2,967 Net deferred tax $ - $ - |
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | Years Ended December 31, 2017 2018 2019 (In thousands) Current: Federal $ - $ - $ - State - - - $ - $ - $ - Deferred: Federal $ - $ - $ - $ - $ - $ - |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | Years Ended December 31, 2017 2018 2019 (In thousands) Tax (expense) benefit at U.S. Statutory rates $ (5,602 ) $ (12,142 ) $ 13,651 (Increase) decrease in deferred tax asset valuation allowance 57,309 13,135 (8,875 ) Alternative minimum tax expense - - (745 ) Expired capital loss carryover - - (3,966 ) Permanent differences (1,134 ) (500 ) (403 ) Return to provision estimated revision 2,494 (470 ) 341 Change in deferred tax rate (53,125 ) - - Other 58 (23 ) (3 ) $ - $ - $ - |
Note 9 - Earnings Per Share (Ta
Note 9 - Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Notes Tables | |
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | Years Ended December 31, 2017 2018 2019 (in thousands, except per share data) Numerator: Net income (loss) $ 16,006 $ 57,821 $ (65,004 ) Denominator for basic earnings per share - weighted-average common shares outstanding 161,141 165,635 166,247 Effect of dilutive securities: Stock options, restricted shares and performance based shares 1,703 2,054 65 Denominator for diluted earnings per share - adjusted weighted-average shares and assumed exercise of options, restricted shares and performance based shares 162,844 167,689 166,312 Net (loss) income per common share - basic $ 0.10 $ 0.35 $ (0.39 ) Net (loss) income per common share - diluted $ 0.10 $ 0.34 $ (0.39 ) |
Note 11 - Hedging Program and_2
Note 11 - Hedging Program and Derivatives (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Notes Tables | |
Schedule of Derivative Instruments [Table Text Block] | Oil - WTI Contract Periods Daily Volume (Bbl) Swap Price (per Bbl) Fixed Swaps January - December 2020 3,777 $ 55.23 January - December 2021 2,808 $ 57.82 Basis Swaps January - December 2020 4,000 $ 2.98 |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block] | Fair Value Derivative Contracts as of December 31, 2018 Asset Derivatives Liability Derivatives Derivatives not designated as hedging instruments Balance Sheet Location Fair Value Balance Sheet Location Fair Value Commodity price derivatives Derivatives - current $ 9,602 Derivatives - current $ 616 Commodity price derivatives Derivatives - long-term 10,527 Derivatives - long-term 4,434 $ 20,129 $ 5,050 Fair Value Derivative Contracts as of December 31, 2019 Asset Derivatives Liability Derivatives Derivatives not designated as hedging instruments Balance Sheet Location Fair Value Balance Sheet Location Fair Value Commodity price derivatives Derivatives - current $ 83 Derivatives - current $ 10,688 Commodity price derivatives Derivatives - long-term 4,170 Derivatives - long-term 999 $ 4,253 $ 11,687 |
Note 12 - Financial Instrumen_2
Note 12 - Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Notes Tables | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance as of December 31, 2018 Assets: NYMEX fixed price derivative contracts $ - $ 18,172 $ - $ 18,172 NYMEX basis differential swap - - 1,957 1,957 Total Assets $ - $ 18,172 $ 1,957 $ 20,129 Liabilities: NYMEX fixed price derivative contracts $ - $ - $ - $ - NYMEX basis differential swap - - 5,050 5,050 Total Liabilities $ - $ - $ 5,050 $ 5,050 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance as of December 31, 2019 Assets: NYMEX fixed price derivative contracts $ - $ 4,253 $ - $ 4,253 NYMEX basis differential swap - - - - Total Assets $ - $ 4,253 $ - $ 4,253 Liabilities: NYMEX fixed price derivative contracts $ - $ 5,583 $ - $ 5,583 NYMEX basis differential swap - - 6,104 6,104 Total Liabilities $ - $ 5,583 $ 6,104 $ 11,687 |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block] | (In thousands) Fair value at January 1, 2019 $ (3,093 ) Changes in market value (5,794 ) Settlements during the period 2,783 Fair value at December 31, 2019 $ (6,104 ) |
Note 13 - Lease Accounting St_2
Note 13 - Lease Accounting Standard (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Notes Tables | |
Lease, Cost [Table Text Block] | Year Ended December 31, 2019 (in thousands) Operating lease cost $ 478 Short-term lease expense (1) 1,992 Total lease expense $ 2,470 Short-term lease costs (2) $ 4,900 December 31, 2019 Weighted Average Remaining Lease Term (in years) 8.66 Weighted Average Discount Rate 6 % Year Ended December 31, 2019 (in thousands) Cash paid for amounts included in the measurement of lease liabilities $ 478 ROU assets added in exchange for lease obligations (since adoption) $ 770 |
Schedule of Operating Leased Assets [Table Text Block] | December 31, 2019 (in thousands) Operating lease ROU assets $ 327 Operating lease liability - current $ 98 Operating lease liabilities - long-term $ 203 |
Lessee, Operating Lease, Liability, Maturity [Table Text Block] | Operating Leases (in thousands) 2020 $ 113 2021 63 2022 48 2023 41 2024 28 Thereafter 102 Total lease payments 395 Less imputed interest (94 ) Total lease liability $ 301 |
Note 14 - Subsequent Events (Ta
Note 14 - Subsequent Events (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Notes Tables | |
Schedule of Fixed Price Derivatives [Table Text Block] | Oil - WTI Contract Periods Daily Volume (Bbl) Swap Price (per Bbl) Fixed Swaps April - July 2020 80 $ 50.60 January - December 2021 82 $ 50.60 January - December 2022 2,412 $ 50.60 January - December 2023 1,498 $ 50.60 January - December 2024 1,589 $ 50.60 |
Note 15 - Quarterly Results o_2
Note 15 - Quarterly Results of Operations (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Notes Tables | |
Quarterly Financial Information [Table Text Block] | 1st 2nd 3rd 4th Quarter Quarter Quarter Quarter (In thousands, except per share data) Year Ended December 31, 2018 Net revenue $ 40,630 $ 30,916 $ 41,625 $ 35,996 Operating income $ 20,090 $ 10,931 $ 17,735 $ 8,722 Net income (loss) $ 10,779 $ (10,554 ) $ 1,777 $ 55,819 Net income (loss) per common share - basic $ 0.07 $ (0.06 ) $ 0.01 $ 0.34 Net income (loss) per common share - diluted $ 0.06 $ (0.06 ) $ 0.01 $ 0.33 Year Ended December 31, 2019 Net revenue $ 34,514 $ 34,820 $ 31,536 $ 28,276 Operating income (loss) $ 6,708 $ 8,935 $ 8,053 $ (49,412 ) Net income (loss) $ (25,455 ) $ 11,678 $ 17,041 $ (68,268 ) Net income (loss) per common share - basic $ (0.15 ) $ 0.07 $ 0.10 $ (0.41 ) Net income (loss) per common share - diluted $ (0.15 ) $ 0.07 $ 0.10 $ (0.41 ) |
Note 16 - Supplemental Oil an_2
Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Notes Tables | |
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block] | Years Ended December 31, 2018 2019 Proved oil and gas properties $ 1,091,905 $ 1,162,094 Unproved properties - - Total 1,091,905 1,162,094 Accumulated depreciation, depletion, amortization and impairment (748,773 ) (851,107 ) Net capitalized costs $ 343,132 $ 310,987 |
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block] | 2017 2018 2019 Development costs $ 94,478 $ 131,271 $ 92,884 Exploration costs 8,509 - - Property acquisition costs 31,409 41,465 - $ 134,396 $ 172,736 $ 92,884 |
Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block] | 2017 2018 2019 Revenues $ 86,189 $ 149,030 $ 128,992 Production costs (22,425 ) (36,323 ) (38,229 ) Depreciation, depletion and amortization (25,676 ) (42,237 ) (51,041 ) Accretion of future site restoration (451 ) (516 ) (436 ) Proved property impairment - - (51,293 ) Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs) $ 37,637 $ 69,954 $ (12,007 ) Depletion rate per barrel of oil equivalent $ 9.52 $ 11.80 $ 14.12 |
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block] | Oil Oil NGL Gas Equivalents (MBbl) (MBbl) (MMcf) (Mboe) Change in Proved Reserves Balance at December 31, 2016 24,209 8,644 70,829 44,657 Revisions of previous estimates 259 1,269 19,311 4,747 Extensions and discoveries 14,533 2,813 14,534 19,768 Purchases of minerals in place 8 14 1,001 189 Sales of minerals in place (364 ) (289 ) (3,958 ) (1,312 ) Production (1,574 ) (476 ) (3,889 ) (2,698 ) Balance at December 31, 2017 37,071 11,975 97,828 65,351 Revisions of previous estimates (4,206 ) (1,927 ) (2,618 ) (6,570 ) Extensions and discoveries 11,270 1,797 11,475 14,979 Purchases of minerals in place 688 - 1,137 877 Sales of minerals in place (278 ) (1,303 ) (13,491 ) (3,829 ) Production (2,308 ) (508 ) (4,587 ) (3,580 ) Balance at December 31, 2018 42,237 10,034 89,744 67,228 Revisions of previous estimates (15,616 ) (2,713 ) (23,178 ) (22,192 ) Extensions and discoveries 13,477 2,285 14,073 18,109 Sales of minerals in place (1,431 ) (86 ) (9,898 ) (3,167 ) Production (2,388 ) (548 ) (4,076 ) (3,616 ) Balance at December 31, 2019 36,279 8,972 66,665 56,362 Total Oil OIl NGL Gas Equilavents (MBbl) (MBbl) (MMcf) (Mboe) Proved Developed Reserves: December 31, 2017 10,820 3,794 39,974 21,720 December 31, 2018 13,586 3,804 43,271 24,602 December 31, 2019 10,964 2,699 21,439 17,237 Proved Undeveloped Reserves: December 31, 2017 25,808 8,181 57,854 43,631 December 31, 2018 28,651 6,230 46,473 42,626 December 31, 2019 25,315 6,273 45,226 39,125 |
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block] | Years Ended December 31, 2017 2018 2019 Future cash inflows $ 2,035,619 $ 2,876,976 $ 1,890,579 Future production costs (609,921 ) (849,063 ) (598,714 ) Future development costs (461,619 ) (547,163 ) (544,111 ) Future income tax expense (83,915 ) (181,224 ) - Future net cash flows 880,164 1,299,526 747,754 Discount $ (474,423 ) $ (647,642 ) $ (440,142 ) Standardized Measure of discounted future net cash relating to proved reserves $ 405,741 $ 651,884 $ 307,612 |
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block] | Years Ended December 31, 2017 2018 2019 Standardized Measure, beginning of year $ 160,600 $ 405,741 $ 651,884 Sales and transfers of oil and gas produced, net of production costs (63,764 ) (112,707 ) (90,763 ) Net change in prices and development and production costs from prior year 159,661 268,942 (218,092 ) Extensions, discoveries, and improved recovery, less related costs 129,277 153,544 98,780 Sales of minerals in place (8,583 ) (39,253 ) (17,276 ) Purchases of minerals in place 1,238 8,990 - Revisions of previous estimates 31,044 (67,345 ) (227,477 ) Change in timing and other 1,908 30,811 (13,744 ) Change in future income tax expense (21,700 ) (37,413 ) 59,112 Accretion of discount 16,060 40,574 65,188 Standardized Measure, end of year $ 405,741 $ 651,884 $ 307,612 |
Oil and Gas Prices Considered in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block] | Years Ended December 31, 2017 2018 2019 Oil (per Bbl) (1) $ 51.34 $ 65.56 $ 55.73 Gas (per Mmbtu) (2) $ 2.99 $ 3.05 $ 2.54 Oil (per Bbl) (3) $ 46.83 $ 56.95 $ 52.14 Gas (per Mmbtu) (4) $ 1.79 $ 1.76 $ 0.63 NGL's (per Bbl) (5) $ 13.19 $ 19.95 $ 3.48 |
Note 1 - Organization and Sig_3
Note 1 - Organization and Significant Accounting Policies (Details Textual) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | |
Accounts Receivable, Allowance for Credit Loss, Ending Balance | $ 100 | $ 500 | |
Discount Rate Used in Future Net Cash Flows Relating to Proved Oil and Gas Reserves | 10.00% | ||
Impairment of Oil and Gas Properties | $ 51,293 | ||
Share-based Payment Arrangement, Noncash Expense, Total | 1,911 | 2,366 | 3,238 |
Deferred Tax Assets, Valuation Allowance, Total | $ 76,185 | $ 67,310 | $ 80,400 |
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21.00% | 35.00% | |
Revenue Benchmark [Member] | Customer Concentration Risk [Member] | |||
Entity Wide Revenue Number of Major Purchasers of Oil and Gas | 2 | 2 | 3 |
Revenue Benchmark [Member] | Customer Concentration Risk [Member] | Three Purchasers [Member] | |||
Concentration Risk, Percentage | 69.00% | ||
Revenue Benchmark [Member] | Customer Concentration Risk [Member] | Two Purchasers [Member] | |||
Concentration Risk, Percentage | 71.00% | 57.00% |
Note 1 - Organization and Sig_4
Note 1 - Organization and Significant Accounting Policies - Future Site Restoration Obligation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Beginning future site restoration obligation | $ 7,492 | $ 8,775 | |
New wells placed on production and other | 80 | 612 | |
Deletions related to property disposals | (473) | (1,844) | |
Deletions related to plugging costs | (890) | (426) | |
Accretion expense and other | 436 | 516 | $ 451 |
Revisions and other | 775 | (141) | |
Ending future site restoration obligation | $ 7,420 | $ 7,492 | $ 8,775 |
Note 1 - Organization and Sig_5
Note 1 - Organization and Significant Accounting Policies - Impact of Adoption (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Jan. 01, 2019 | Dec. 31, 2018 |
Operating lease ROU asset | $ 327 | ||
Operating lease liability - current | (98) | ||
Operating lease liability - long-term | $ (203) | ||
Accounting Standards Update 2016-02 [Member] | |||
Operating lease ROU asset | $ 687 | ||
Operating lease liability - current | (108) | ||
Operating lease liability - long-term | $ (579) |
Note 2 - Revenue From Contrac_3
Note 2 - Revenue From Contracts With Customers (Details Textual) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Accounts Receivable, before Allowance for Credit Loss, Current | $ 16,985 | $ 21,991 |
Note 2 - Revenue From Contrac_4
Note 2 - Revenue From Contracts With Customers - Disaggregation of Revenue (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Oil Revenues [Member] | |||
Revenue | $ 124,503 | $ 132,904 | $ 73,584 |
Gas Revenues [Member] | |||
Revenue | 2,579 | 7,854 | 6,898 |
Natural Gas Liquids Revenues [Member] | |||
Revenue | 1,910 | 8,272 | 5,707 |
Permian / Delaware Basin [Member] | Oil Revenues [Member] | |||
Revenue | 52,789 | 47,175 | 17,722 |
Permian / Delaware Basin [Member] | Gas Revenues [Member] | |||
Revenue | 494 | 2,698 | 3,028 |
Permian / Delaware Basin [Member] | Natural Gas Liquids Revenues [Member] | |||
Revenue | 602 | 2,884 | 1,840 |
Rocky Mountain [Member] | Oil Revenues [Member] | |||
Revenue | 68,555 | 77,664 | 49,670 |
Rocky Mountain [Member] | Gas Revenues [Member] | |||
Revenue | 1,480 | 3,913 | 2,694 |
Rocky Mountain [Member] | Natural Gas Liquids Revenues [Member] | |||
Revenue | 1,305 | 5,253 | 3,774 |
South Texas [Member] | Oil Revenues [Member] | |||
Revenue | 3,159 | 8,065 | 6,192 |
South Texas [Member] | Gas Revenues [Member] | |||
Revenue | 605 | 1,243 | 1,176 |
South Texas [Member] | Natural Gas Liquids Revenues [Member] | |||
Revenue | $ 3 | $ 135 | $ 93 |
Note 3 - Acquisition and Dive_2
Note 3 - Acquisition and Divestitures of Properties (Details Textual) | 12 Months Ended | ||
Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($)a | Dec. 31, 2017USD ($) | |
Leasehold and Working Interests in Permian Basin Region [Member] | |||
Mineral Area Acquired (Acre) | a | 2,721 | ||
Property, Plant and Equipment, Additions | $ 40,400,000 | ||
Capital Expenditures Incurred but Not yet Paid | 21,000 | ||
Non-core Properties [Member] | |||
Proceeds from Sale of Property, Plant, and Equipment, Total | $ 23,400,000 | $ 3,300,000 | |
Gain (Loss) on Disposition of Property Plant Equipment, Total | $ 0 | ||
Powder River Basin Assets [Member] | |||
Proceeds from Sale of Property, Plant, and Equipment, Total | $ 4,600,000 | ||
Gain (Loss) on Disposition of Property Plant Equipment, Total | $ 0 |
Note 4 - Long-term Debt (Detail
Note 4 - Long-term Debt (Details Textual) | Nov. 13, 2019USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) |
Long-term Debt, Total | $ 192,718,000 | $ 181,942,000 | |
Construction Loans [Member] | |||
Debt Instrument, Interest Rate, Stated Percentage | 4.90% | ||
Debt Instrument, Periodic Payment, Total | $ 35,672 | ||
Long-term Debt, Total | 3,100,000 | $ 3,400,000 | |
First Lien Credit Facility [Member] | Line of Credit [Member] | |||
Long-term Line of Credit, Total | 95,800,000 | ||
Line of Credit Facility, Maximum Borrowing Capacity | 200,000,000 | ||
Line of Credit Facility, Current Borrowing Capacity | $ 135,000,000 | ||
Debt Instrument, Interest Rate, Event of Default Exists | 3.00% | ||
Line of Credit Facility, Interest Rate at Period End | 4.80% | ||
Debt Instrument, Collateral Eligible, Minimum Percent of PV-10 Required | 90.00% | ||
Debt Instrument, Collateral Eligible, Minimum Percent of PV-9 Required of PDP Reserves | 95.00% | ||
Financial Covenants, Minimum Current Ratio | 1 | ||
Financial Covenants, Interest Coverage Ratio | 2.5 | ||
Financial Covenants, Total Debt to EBITDAX Ratio | 3.5 | ||
Financial Covenants, Minimum Asset Coverage Ratio in Year Two | 1.45 | ||
Financial Covenants, Minimum Asset Coverage Ratio Thereafter | 1.55 | ||
Interest Coverage Ratio | 6.22 | ||
Total Debt to EBITDAX Ratio | 2.61 | ||
Asset Coverage Ratio | 1.28 | ||
Current Ratio | 1.56 | ||
First Lien Credit Facility [Member] | Line of Credit [Member] | Federal Funds Rate [Member] | |||
Debt Instrument, Spread on Elected Variable Rate | 0.50% | ||
First Lien Credit Facility [Member] | Line of Credit [Member] | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member] | |||
Debt Instrument, Spread on Elected Variable Rate | 1.50% | ||
First Lien Credit Facility [Member] | Line of Credit [Member] | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member] | |||
Debt Instrument, Spread on Elected Variable Rate | 2.50% | ||
First Lien Credit Facility [Member] | Line of Credit [Member] | Eurodollar [Member] | Minimum [Member] | |||
Debt Instrument, Spread on Elected Variable Rate | 2.50% | ||
First Lien Credit Facility [Member] | Line of Credit [Member] | Eurodollar [Member] | Maximum [Member] | |||
Debt Instrument, Spread on Elected Variable Rate | 3.50% | ||
Second Lien Credit Facility [Member] | Line of Credit [Member] | |||
Long-term Line of Credit, Total | $ 100,000,000 | ||
Line of Credit Facility, Maximum Borrowing Capacity | $ 100,000,000 | ||
Financial Covenants, Minimum Current Ratio | 1 | ||
Financial Covenants, Total Debt to EBITDAX Ratio | 4 | ||
Financial Covenants, Minimum Asset Coverage Ratio in Year Two | 1.45 | ||
Financial Covenants, Minimum Asset Coverage Ratio Thereafter | 1.55 | ||
Asset Coverage Ratio | 1.28 | ||
Proceeds from Lines of Credit, Total | $ 95,000,000 | ||
Debt Instrument Reference Rate Floor | 2.75% | ||
Debt Instrument Reference Rate Floor | 1.75% | ||
Line of Credit, Default, Minimum Interest Rate | 3.00% | ||
Debt Instrument, Original Issue Discount | 3.50% | ||
Debt Instrument, Collateral Eligible, Minimum Percent of PV-9 Proven Reserves | 90.00% | ||
Debt Instrument, Collateral Eligible, Minimum Percent of PV-9 Required PDP Reserves | 95.00% | ||
Financial Covenants, Minimum Asset Coverage Ratio in Year One | 1.25 | ||
Leverage Ratio | 2.61 | ||
Second Lien Credit Facility [Member] | Line of Credit [Member] | Federal Funds Rate [Member] | |||
Debt Instrument, Spread on Elected Variable Rate | 0.50% | ||
Second Lien Credit Facility [Member] | Line of Credit [Member] | London Interbank Offered Rate (LIBOR) [Member] | |||
Debt Instrument, Spread on Elected Variable Rate | 8.00% | ||
Second Lien Credit Facility [Member] | Line of Credit [Member] | Eurodollar [Member] | |||
Debt Instrument, Spread on Elected Variable Rate | 9.00% | ||
Second Lien Credit Facility [Member] | Line of Credit [Member] | Company's Reference Rate [Member] | |||
Debt Instrument, Spread on Elected Variable Rate | 8.00% | ||
Second Lien Credit Facility [Member] | Line of Credit [Member] | Debt Instrument Spread On Elected Variable Rate [Member] | |||
Debt Instrument, Spread on Elected Variable Rate | 9.00% |
Note 4 - Long-term Debt - Debt
Note 4 - Long-term Debt - Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Long-term debt | $ 198,869 | $ 183,358 |
Less current maturities | (280) | (267) |
Long-term Debt, Noncurrent, Gross | 198,589 | 183,091 |
Deferred financing fees, net of accumulated amortization | (5,871) | (1,149) |
Total long-term debt, net of deferred financing fees | 192,718 | 181,942 |
First Lien Credit Facility [Member] | ||
Long-term debt | 95,778 | 180,000 |
Second Lien Credit Facility [Member] | ||
Long-term debt | 100,000 | |
Mortgages [Member] | ||
Long-term debt | $ 3,091 | $ 3,358 |
Note 4 - Long-term Debt - Matur
Note 4 - Long-term Debt - Maturities of Long-term Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
2020 | $ 280 | |
2021 | 295 | |
2022 | 196,088 | |
2023 | 2,206 | |
2024 | ||
Thereafter | ||
Total | $ 198,869 | $ 183,358 |
Note 5 - Property and Equipme_3
Note 5 - Property and Equipment - Property and Equipment (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | |||
Property and equipment | $ 1,201,389 | $ 1,131,358 | ||
Accumulated depreciation, depletion, amortization and impairment | (872,431) | (768,140) | ||
Net Property and Equipment | $ 328,958 | 363,218 | ||
Oil and Gas Properties [Member] | ||||
Estimated useful life (Year) | [1] | |||
Property and equipment | $ 1,162,094 | 1,091,905 | [1] | |
Equipment and Other [Member] | ||||
Property and equipment | $ 15,187 | |||
Equipment and Other [Member] | Minimum [Member] | ||||
Estimated useful life (Year) | 3 years | |||
Equipment and Other [Member] | Maximum [Member] | ||||
Property and equipment | 15,369 | |||
Drilling Rig [Member] | ||||
Estimated useful life (Year) | 15 years | |||
Property and equipment | $ 24,108 | $ 24,084 | ||
[1] | Oil and gas properties are amortized utilizing the units of production method. |
Note 6 - Stock-based Compensa_3
Note 6 - Stock-based Compensation and Option Plans (Details Textual) - USD ($) | Apr. 01, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross (in shares) | 0 | |||
Share-based Payment Arrangement, Noncash Expense, Total | $ 1,911,000 | $ 2,366,000 | $ 3,238,000 | |
Common Stock, Capital Shares Reserved for Future Issuance (in shares) | 8,700,000 | |||
Directors Plan 2005 [Member] | ||||
Common Stock, Capital Shares Reserved for Future Issuance (in shares) | 2,900,000 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares Per Employee (in shares) | 100,000 | |||
Percentage of Exercise Price Awarded | 100.00% | |||
Share-based Payment Arrangement, Option [Member] | ||||
Deferred Compensation Arrangement with Individual, Common Stock Reserved for Future Issuance (in shares) | 12,600,000 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period (Year) | 10 years | |||
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount, Total | $ 200,000 | |||
Share-based Payment Arrangement, Noncash Expense, Total | 400,000 | 1,400,000 | 1,800,000 | |
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount | 1,900,000 | |||
Restricted Stock [Member] | ||||
Share-based Payment Arrangement, Noncash Expense, Total | 1,000,000 | 700,000 | $ 1,400,000 | |
Restricted Stock [Member] | Directors Plan 2005 [Member] | Share-based Payment Arrangement, Nonemployee [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Amount Approved for Issuance Per Participant | 12,000 | |||
Performance Shares [Member] | ||||
Share-based Payment Arrangement, Noncash Expense, Total | 500,000 | $ 200,000 | ||
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount | $ 700,000 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period (Year) | 3 years | |||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Target Payout Rate | 100.00% | |||
Performance Shares [Member] | Minimum [Member] | ||||
Share-based Compensation Awards, Vesting, Requirement, TSR, Percentage | 0.00% | |||
Performance Shares [Member] | Maximum [Member] | ||||
Share-based Compensation Awards, Vesting, Requirement, TSR, Percentage | 200.00% |
Note 6 - Stock-based Compensa_4
Note 6 - Stock-based Compensation and Option Plans - Stock Option Valuation Assumptions (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |||
Weighted average value per option granted during the period (in dollars per share) | [1] | $ 1.87 | $ 1.81 | ||
Forfeiture rate (1) | [1],[2] | 1.70% | 2.00% | ||
Expected dividend yield (2) | [3] | [1] | 0.00% | 0.00% | |
Volatility (3) | [4] | [1] | 66.50% | 67.60% | |
Risk free interest rate (4) | [5] | [1] | 2.90% | 2.20% | |
Expected life (years) (5) (Year) | [1],[6] | 7 years 109 days | 6 years 328 days | ||
Fair value of options granted (in thousands) | [1] | $ 841 | $ 574 | ||
[1] | There were no grants of stock options in 2019 | ||||
[2] | The estimated future forfeiture rate is based on the Company's historical forfeiture rate on similar grants of stock options. | ||||
[3] | The dividend yield is based on the fact the Company does not pay any dividends. | ||||
[4] | The volatility is based on the historical volatility of our stock for a period approximating the expected life. | ||||
[5] | The risk-free interest rate is based on the observed U.S. Treasury yield curve in effect at the time the options were granted for a period approximating the expected life of the option. | ||||
[6] | The expected life was derived based on a weighting between (a) the Company's historical exercise and forfeiture activity and (b) the average midpoint between vesting and the contractual term. |
Note 6 - Stock-based Compensa_5
Note 6 - Stock-based Compensation and Option Plans - Stock Option Activity (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Weighted average value per option granted during the period (in dollars per share) | [1] | $ 1.87 | $ 1.81 | |
Share-based Payment Arrangement, Option [Member] | ||||
Balance (in shares) | 7,549 | 8,317 | 8,154 | |
Balance, weighted average exercise price (in dollars per share) | $ 2.37 | $ 2.35 | $ 2.39 | |
Granted (in shares) | 300 | 317 | ||
Granted, weighted average exercise price (in dollars per share) | $ 2.80 | $ 1.81 | ||
Exercised (in shares) | (469) | (379) | (5) | |
Exercised, weighted average exercise price (in dollars per share) | $ 0.98 | $ 1.71 | $ 0.97 | |
Forfeited/Expired (in shares) | (1,154) | (689) | (149) | |
Forfeited/Expired, weighted average exercise price (in dollars per share) | $ 2.40 | $ 2.70 | $ 3.58 | |
Balance (in shares) | 5,926 | 7,549 | 8,317 | |
Balance, weighted average exercise price (in dollars per share) | $ 2.47 | $ 2.37 | $ 2.35 | |
Options outstanding, weighted average remaining life (Year) | 4 years 219 days | |||
Options outstanding, intrinsic value per share (in dollars per share) | $ 0 | |||
Exercisable at end of year (in shares) | 5,446 | |||
Exercisable, weighted average exercise price (in dollars per share) | $ 1.83 | |||
Exercisable, weighted average remaining life (Year) | 4 years 146 days | |||
Exercisable, intrinsic value per share (in dollars per share) | $ 0 | |||
Weighted average value per option granted during the period (in dollars per share) | $ 1.87 | $ 1.81 | ||
Total fair value of options vested (000's) | $ 732 | $ 2,054 | $ 2,795 | |
Total intrinsic value of options exercised (000's) | $ 141 | $ 395 | $ 5 | |
[1] | There were no grants of stock options in 2019 |
Note 6 - Stock-based Compensa_6
Note 6 - Stock-based Compensation and Option Plans - Stock Options Outstanding (Details) | 12 Months Ended |
Dec. 31, 2019$ / sharesshares | |
Outstanding options, number outstanding (in shares) | shares | 5,926,273 |
Outstanding options, weighted average remaining life (Year) | 4 years 219 days |
Outstanding options, weighted average exercise price (in dollars per share) | $ 2.47 |
Exercisable, number outstanding (in shares) | shares | 5,446,023 |
Exercisable, weighted average remaining life (Year) | 4 years 146 days |
Exercisable, weighted average exercise price (in dollars per share) | $ 2.57 |
Range One [Member] | |
Exercise price range, lower limit (in dollars per share) | 0.97 |
Exercise price range, upper limit (in dollars per share) | $ 1.99 |
Outstanding options, number outstanding (in shares) | shares | 2,167,750 |
Outstanding options, weighted average remaining life (Year) | 5 years 292 days |
Outstanding options, weighted average exercise price (in dollars per share) | $ 1.17 |
Exercisable, number outstanding (in shares) | shares | 1,764,500 |
Exercisable, weighted average remaining life (Year) | 5 years 255 days |
Exercisable, weighted average exercise price (in dollars per share) | $ 1.20 |
Range Two [Member] | |
Exercise price range, lower limit (in dollars per share) | 2 |
Exercise price range, upper limit (in dollars per share) | $ 2.99 |
Outstanding options, number outstanding (in shares) | shares | 1,282,075 |
Outstanding options, weighted average remaining life (Year) | 3 years 219 days |
Outstanding options, weighted average exercise price (in dollars per share) | $ 2.46 |
Exercisable, number outstanding (in shares) | shares | 1,205,075 |
Exercisable, weighted average remaining life (Year) | 3 years 109 days |
Exercisable, weighted average exercise price (in dollars per share) | $ 2.45 |
Range Three [Member] | |
Exercise price range, lower limit (in dollars per share) | 3 |
Exercise price range, upper limit (in dollars per share) | $ 3.99 |
Outstanding options, number outstanding (in shares) | shares | 1,925,448 |
Outstanding options, weighted average remaining life (Year) | 4 years 109 days |
Outstanding options, weighted average exercise price (in dollars per share) | $ 3.30 |
Exercisable, number outstanding (in shares) | shares | 1,925,448 |
Exercisable, weighted average remaining life (Year) | 4 years 109 days |
Exercisable, weighted average exercise price (in dollars per share) | $ 3.30 |
Range Four [Member] | |
Exercise price range, lower limit (in dollars per share) | 4 |
Exercise price range, upper limit (in dollars per share) | $ 4.99 |
Outstanding options, number outstanding (in shares) | shares | 453,000 |
Outstanding options, weighted average remaining life (Year) | 3 years |
Outstanding options, weighted average exercise price (in dollars per share) | $ 4.55 |
Exercisable, number outstanding (in shares) | shares | 453,000 |
Exercisable, weighted average remaining life (Year) | 3 years |
Exercisable, weighted average exercise price (in dollars per share) | $ 4.55 |
Range Five [Member] | |
Exercise price range, lower limit (in dollars per share) | 5 |
Exercise price range, upper limit (in dollars per share) | $ 5.99 |
Outstanding options, number outstanding (in shares) | shares | 97,000 |
Outstanding options, weighted average remaining life (Year) | 4 years 109 days |
Outstanding options, weighted average exercise price (in dollars per share) | $ 5.38 |
Exercisable, number outstanding (in shares) | shares | 97,000 |
Exercisable, weighted average remaining life (Year) | 4 years 109 days |
Exercisable, weighted average exercise price (in dollars per share) | $ 5.38 |
Range Six [Member] | |
Exercise price range, lower limit (in dollars per share) | 6 |
Exercise price range, upper limit (in dollars per share) | $ 6.28 |
Outstanding options, number outstanding (in shares) | shares | 1,000 |
Outstanding options, weighted average remaining life (Year) | 4 years 182 days |
Outstanding options, weighted average exercise price (in dollars per share) | $ 6.28 |
Exercisable, number outstanding (in shares) | shares | 1,000 |
Exercisable, weighted average remaining life (Year) | 4 years 182 days |
Exercisable, weighted average exercise price (in dollars per share) | $ 6.28 |
Note 6 - Stock-based Compensa_7
Note 6 - Stock-based Compensation and Option Plans - Restricted Stock Activity (Details) - Restricted Stock [Member] - $ / shares | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Unvested (in shares) | 827 | 1,479 | 1,492 |
Unvested, weighted average grant date fair value (in dollars per share) | $ 2.15 | $ 3.43 | $ 3.47 |
Granted (in shares) | 1,315 | 861 | 44 |
Granted, weighted average grant date fair value (in dollars per share) | $ 1.34 | $ 2.17 | $ 1.75 |
Vested/Released (in shares) | (270) | (1,326) | (56) |
Vested/Released, weighted average grant date fair value (in dollars per share) | $ 2.15 | $ 3.43 | $ 3.14 |
Forfeited (in shares) | (91) | (187) | (1) |
Forfeited, weighted average grant date fair value (in dollars per share) | $ 1.54 | $ 3.22 | $ 2.63 |
Unvested (in shares) | 1,781 | 827 | 1,479 |
Unvested, weighted average grant date fair value (in dollars per share) | $ 1.58 | $ 2.15 | $ 3.43 |
Note 6 - Stock-based Compensa_8
Note 6 - Stock-based Compensation and Option Plans - Performance Based Restricted Stock Awards (Details) - Performance Shares [Member] - $ / shares | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Unvested (in shares) | 405 | |
Unvested, weighted average grant date fair value (in dollars per share) | $ 2.37 | |
Granted (in shares) | 803 | 464 |
Granted, weighted average grant date fair value (in dollars per share) | $ 1.34 | $ 2.37 |
Vested/Released (in shares) | ||
Vested/Released, weighted average grant date fair value (in dollars per share) | ||
Forfeited (in shares) | (54) | (59) |
Forfeited, weighted average grant date fair value (in dollars per share) | $ 1.52 | $ 2.37 |
Unvested (in shares) | 1,154 | 405 |
Unvested, weighted average grant date fair value (in dollars per share) | $ 1.69 | $ 2.37 |
Note 7 - Income Taxes (Details
Note 7 - Income Taxes (Details Textual) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2017 | Dec. 31, 2018 | |
Deferred Tax Assets, Valuation Allowance, Total | $ 76,185 | $ 80,400 | $ 67,310 |
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued, Total | $ 0 | $ 0 | $ 0 |
Open Tax Year | 2014 2015 2016 2017 2018 2019 | ||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21.00% | 35.00% | |
Pre 2018 [Member] | Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member] | |||
Operating Loss Carryforwards, Total | $ 245,200 | ||
Tax Year 2018 [Member] | Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member] | |||
Operating Loss Carryforwards, Total | $ 64,700 | ||
Latest Tax Year [Member] | |||
Operating Loss Carryforwards, Expiration Date | Dec. 31, 2037 |
Note 7 - Income Taxes - Deferre
Note 7 - Income Taxes - Deferred Tax Liabilities and Assets (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Hedge contracts | $ 3,167 | ||
Other | 2,967 | 2,977 | |
Total deferred tax liabilities | 2,967 | 6,144 | |
US full cost pool | 9,015 | 4,310 | |
Capital loss carryforwards | 3,980 | ||
Depletion carryforward | 3,497 | 3,098 | |
U.S. net operating loss carryforward | 65,073 | 61,309 | |
Alternative minimum tax credit | 6 | 757 | |
Hedge contracts | 1,561 | ||
Total deferred tax assets | 79,152 | 73,454 | |
Valuation allowance for deferred tax assets | (76,185) | (67,310) | $ (80,400) |
Net deferred tax assets | 2,967 | 6,144 | |
Net deferred tax |
Note 7 - Income Taxes - Provisi
Note 7 - Income Taxes - Provision (Benefit) for Income Taxes (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Federal | |||
State | |||
Federal |
Note 7 - Income Taxes - Reconci
Note 7 - Income Taxes - Reconciliation of Income Tax (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Tax (expense) benefit at U.S. Statutory rates | $ 13,651 | $ (12,142) | $ (5,602) |
(Increase) decrease in deferred tax asset valuation allowance | (8,875) | 13,135 | 57,309 |
Alternative minimum tax expense | (745) | ||
Expired capital loss carryover | (3,966) | ||
Permanent differences | (403) | (500) | (1,134) |
Return to provision estimated revision | 341 | (470) | 2,494 |
Change in deferred tax rate | (53,125) | ||
Other | $ (3) | $ (23) | $ 58 |
Note 8 - Commitments and Cont_2
Note 8 - Commitments and Contingencies (Details Textual) - USD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Office Space in Dickinson, North Dakota [Member] | ||
Operating Lease, Expense | $ 23,200 | $ 27,840 |
Office Space in Lusk, Wyoming [Member] | ||
Operating Lease, Expense | $ 9,000 | 9,000 |
Office Space in Denver, Colorado [Member] | ||
Operating Lease, Expense | $ 13,837 |
Note 9 - Earnings Per Share (De
Note 9 - Earnings Per Share (Details Textual) - shares | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount (in shares) | 76 | 4,007 | 5,018 |
Note 9 - Earnings Per Share - C
Note 9 - Earnings Per Share - Computation of Basic and Diluted Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Net income (loss) | $ (68,268) | $ 17,041 | $ 11,678 | $ (25,455) | $ 55,819 | $ 1,777 | $ (10,554) | $ 10,779 | $ (65,004) | $ 57,821 | $ 16,006 |
Basic (in shares) | 166,247 | 165,635 | 161,141 | ||||||||
Effect of dilutive securities: Stock options, restricted shares and performance based shares (in shares) | 65 | 2,054 | 1,703 | ||||||||
Denominator for diluted earnings per share - adjusted weighted-average shares and assumed exercise of options, restricted shares and performance based shares (in shares) | 166,312 | 167,689 | 162,844 | ||||||||
Net income (loss) per common share - basic (in dollars per share) | $ (0.41) | $ 0.10 | $ 0.07 | $ (0.15) | $ 0.34 | $ 0.01 | $ (0.06) | $ 0.07 | $ (0.39) | $ 0.35 | $ 0.10 |
Net income (loss) per common share - diluted (in dollars per share) | $ (0.41) | $ 0.10 | $ 0.07 | $ (0.15) | $ 0.33 | $ 0.01 | $ (0.06) | $ 0.06 | $ (0.39) | $ 0.34 | $ 0.10 |
Note 10 - Benefit Plans (Detail
Note 10 - Benefit Plans (Details Textual) | 12 Months Ended | ||
Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | |
Deferred Compensation Arrangement with Individual, Contributions by Employer | $ 284,905 | $ 331,957 | $ 330,415 |
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay | 1.00% | ||
Defined Contribution Plan, Employer Matching Contribution, Amount of Cents Per Dollar Increase for Each Additional Percentage Point | 50 | ||
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent | 5.00% | ||
Defined Contribution Plan Employee Contribution Limit Below 50 Years of Age | $ 19,000 | 18,500 | 18,000 |
Defined Contribution Plan Employee Contribution Limit 50 Years of Age or Older | $ 25,000 | $ 24,500 | $ 24,000 |
Note 11 - Hedging Program and_3
Note 11 - Hedging Program and Derivatives (Details Textual) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Derivative Asset, Total | $ 4,253 | $ 20,129 |
Commodity Contract [Member] | ||
Derivative Asset, Total | 7,400 | |
Commodity Contract [Member] | (Gain) Loss on Derivative Contracts [Member] | ||
Gain (Loss) on Sale of Derivatives | (26,800) | 8,100 |
Commodity Closed Contracts [Member] | (Gain) Loss on Derivative Contracts [Member] | ||
Gain (Loss) on Sale of Derivatives | (6,000) | (19,000) |
Commodity Open Contracts [Member] | (Gain) Loss on Derivative Contracts [Member] | ||
Gain (Loss) on Sale of Derivatives | $ (20,800) | $ 27,100 |
Note 11 - Hedging Program and_4
Note 11 - Hedging Program and Derivatives - Summary Position of Derivative Contracts (Details) - Oil - WTI [Member] | 12 Months Ended |
Dec. 31, 2019bbl | |
Fixed Swap, Contract Period 2020 January - December [Member] | |
Daily volume (Barrel of Oil) | 3,777 |
Swap price | 55.23 |
Fixed Swap, Contract Period 2021 January - December [Member] | |
Daily volume (Barrel of Oil) | 2,808 |
Swap price | 57.82 |
Basis Swap, Contract Period 2020 January - December [Member] | |
Daily volume (Barrel of Oil) | 4,000 |
Swap price | 2.98 |
Note 11 - Hedging Program and_5
Note 11 - Hedging Program and Derivatives - Impact of Derivative Contracts on Balance Sheet (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Derivative asset, current | $ 83 | $ 9,602 |
Derivative liability, current | 10,688 | 616 |
Derivative asset, long-term | 4,170 | 10,527 |
Derivative liability, long-term | 999 | 4,434 |
Derivative Asset, Total | 4,253 | 20,129 |
Derivative liability | 11,687 | 5,050 |
Commodity Contract [Member] | ||
Derivative Asset, Total | 7,400 | |
Commodity Contract [Member] | Derivative Assets Current [Member] | ||
Derivative asset, current | 83 | 9,602 |
Commodity Contract [Member] | Derivative Liabilities Current [Member] | ||
Derivative liability, current | 10,688 | 616 |
Commodity Contract [Member] | Derivative Assets Noncurrent [Member] | ||
Derivative asset, long-term | 4,170 | 10,527 |
Commodity Contract [Member] | Derivative Liabilities Noncurrent [Member] | ||
Derivative liability, long-term | $ 999 | $ 4,434 |
Note 12 - Financial Instrumen_3
Note 12 - Financial Instruments - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Derivative assets | $ 4,253 | $ 20,129 |
Derivative liabilities | 11,687 | 5,050 |
Fair Value, Recurring [Member] | ||
Derivative assets | 4,253 | 20,129 |
Derivative liabilities | 11,687 | 5,050 |
Fair Value, Recurring [Member] | Fixed Price Derivative Contracts [Member] | ||
Derivative assets | 4,253 | 18,172 |
Derivative liabilities | 5,583 | |
Fair Value, Recurring [Member] | Basis Swap [Member] | ||
Derivative assets | 1,957 | |
Derivative liabilities | 6,104 | 5,050 |
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Derivative assets | ||
Derivative liabilities | ||
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Fixed Price Derivative Contracts [Member] | ||
Derivative assets | ||
Derivative liabilities | ||
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Basis Swap [Member] | ||
Derivative assets | ||
Derivative liabilities | ||
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Derivative assets | 4,253 | 18,172 |
Derivative liabilities | 5,583 | |
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Fixed Price Derivative Contracts [Member] | ||
Derivative assets | 4,253 | 18,172 |
Derivative liabilities | 5,583 | |
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Basis Swap [Member] | ||
Derivative assets | ||
Derivative liabilities | ||
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Derivative assets | 1,957 | |
Derivative liabilities | 6,104 | 5,050 |
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Fixed Price Derivative Contracts [Member] | ||
Derivative assets | ||
Derivative liabilities | ||
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Basis Swap [Member] | ||
Derivative assets | 1,957 | |
Derivative liabilities | $ 6,104 | $ 5,050 |
Note 12 - Financial Instrumen_4
Note 12 - Financial Instruments - Recurring Fair Value Measurements Using Significant Unobservable Inputs (Details) - Fair Value, Inputs, Level 3 [Member] $ in Thousands | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Fair value at January 1, 2019 | $ (3,093) |
Changes in market value | (5,794) |
Settlements during the period | 2,783 |
Fair value at December 31, 2019 | $ (6,104) |
Note 13 - Lease Accounting St_3
Note 13 - Lease Accounting Standard (Details Textual) | Dec. 31, 2019 |
Lease for Residence in North Dakota [Member] | |
Lessee, Operating Lease, Term of Contract (Year) | 5 years |
Note 13 - Lease Accounting St_4
Note 13 - Lease Accounting Standard - Total Lease Expense (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019USD ($) | ||
Operating lease cost | $ 478 | |
Short-term lease expense | 1,992 | [1] |
Total lease expense | $ 2,470 | |
Weighted Average Remaining Lease Term (in years) (Year) | 8 years 240 days | |
Weighted Average Discount Rate | 6.00% | |
Cash paid for amounts included in the measurement of lease liabilities | $ 478 | |
ROU assets added in exchange for lease obligations (since adoption) | 770 | |
Drilling Rig [Member] | ||
Short-term lease expense | $ 4,900 | [2] |
[1] | Short-term lease expense represents expense related to leases with a contract term of 12 months or less. | |
[2] | These short-term lease costs are related to leases with a contract term of 12 months or less which are related to drilling rigs and are capitalized as part of natural gas and oil properties on our balance sheet. |
Note 13 - Lease Accounting St_5
Note 13 - Lease Accounting Standard - Balance Sheet Information (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Operating lease ROU asset | $ 327 | |
Operating lease liability - current | 98 | |
Operating lease liabilities - long-term | $ 203 |
Note 13 - Lease Accounting St_6
Note 13 - Lease Accounting Standard - Lease Liabilities Maturity (Details) $ in Thousands | Dec. 31, 2019USD ($) |
2020 | $ 113 |
2021 | 63 |
2022 | 48 |
2023 | 41 |
2024 | 28 |
Thereafter | 102 |
Total lease payments | 395 |
Less imputed interest | (94) |
Total lease liability | $ 301 |
Note 14 - Subsequent Events (De
Note 14 - Subsequent Events (Details Textual) | Jun. 25, 2020USD ($)$ / sharesRate | Jun. 25, 2020USD ($)$ / shares | May 04, 2020USD ($) | Nov. 13, 2019 | Jun. 25, 2020USD ($)$ / shares | Mar. 31, 2022USD ($) | Mar. 31, 2021USD ($) | Dec. 31, 2020USD ($) | Sep. 30, 2020USD ($) | Jun. 30, 2020USD ($) | Dec. 31, 2019USD ($) | Jan. 01, 2022 | Dec. 31, 2021 | Sep. 30, 2021 |
First Lien Credit Facility [Member] | Line of Credit [Member] | ||||||||||||||
Financial Covenants, Total Debt to EBITDAX Ratio | 3.5 | |||||||||||||
Line of Credit Facility, Current Borrowing Capacity | $ 135,000,000 | |||||||||||||
First Lien Credit Facility [Member] | Forecast [Member] | ||||||||||||||
Debt Instrument Covenant General and Administrative Expense Limitation | $ 6,500,000 | $ 6,900,000 | $ 8,250,000 | $ 9,000,000 | ||||||||||
Second Lien Credit Facility [Member] | Line of Credit [Member] | ||||||||||||||
Financial Covenants, Total Debt to EBITDAX Ratio | 4 | |||||||||||||
Second Lien Credit Facility [Member] | Forecast [Member] | ||||||||||||||
Debt Instrument Covenant General and Administrative Expense Limitation | $ 5,000,000 | $ 6,500,000 | $ 8,250,000 | $ 9,000,000 | ||||||||||
Second Lien Credit Facility [Member] | Forecast [Member] | Line of Credit [Member] | ||||||||||||||
Financial Covenants, Minimum Asset Coverage Ratio | 1.55 | 1.45 | 1.45 | |||||||||||
Subsequent Event [Member] | ||||||||||||||
Proceeds From Paycheck Protection Program Under CARES Act | $ 1,400,000 | |||||||||||||
Working Capital Reserve | $ 3,000,000 | |||||||||||||
Subsequent Event [Member] | Angelo Gordon Energy Servicer, LLC [Member] | ||||||||||||||
Payments for Exit Fee | $ 10,000,000 | |||||||||||||
Percentage of Fully Diluted Common Equity | 19.90% | 19.90% | 19.90% | |||||||||||
Subsequent Event [Member] | Angelo Gordon Energy Servicer, LLC [Member] | Warrant In Connection With Fee Letter [Member] | ||||||||||||||
Class of Warrant or Right, Exercise Price of Warrants or Rights (in dollars per share) | $ / shares | $ 0.01 | $ 0.01 | $ 0.01 | |||||||||||
Subsequent Event [Member] | First Lien Credit Facility [Member] | ||||||||||||||
Financial Covenants, Total Debt to EBITDAX Ratio | 2.75 | |||||||||||||
Debt Instrument Covenant Minimum First Lien Asset Coverage Ratio Year One (Rate) | Rate | 115.00% | |||||||||||||
Debt Instrument Covenant Minimum First Lien Asset Coverage Ratio After Year One (Rate) | Rate | 125.00% | |||||||||||||
Debt Instrument Covenant Capital Expenditures Limit | $ 3,000,000 | |||||||||||||
Debt Instrument, Covenant, Capital Expenditures Limit Exceptions, Asset Coverage Ratio | 1.6 | 1.6 | 1.6 | |||||||||||
Debt Instrument, Covenant, Capital Expenditures Limit Exceptions, Maximum Outstanding Amount | $ 50,000,000 | $ 50,000,000 | $ 50,000,000 | |||||||||||
Debt Instrument Covenant Accounts Payable Limit | 7,500,000 | |||||||||||||
Debt Instrument Covenant Accounts Payable Outstanding for More Than 60 Days Limit | 2,000,000 | |||||||||||||
Debt Instrument Covenant Accounts Payable Outstanding for More Than 90 Days Limit | 1,000,000 | |||||||||||||
Subsequent Event [Member] | First Lien Credit Facility [Member] | Subordinated Debt [Member] | ||||||||||||||
Debt Instrument Covenant Additional Debt for Capital Expenditures Permitted Amount | 25,000,000 | |||||||||||||
Subsequent Event [Member] | First Lien Credit Facility [Member] | Line of Credit [Member] | ||||||||||||||
Line of Credit Facility, Current Borrowing Capacity | $ 102,000,000 | $ 102,000,000 | $ 102,000,000 | |||||||||||
Subsequent Event [Member] | Second Lien Credit Facility [Member] | ||||||||||||||
Debt Instrument, Interest Rate, Increase (Decrease) | 2.00% | |||||||||||||
Subsequent Event [Member] | Second Lien Credit Facility [Member] | Line of Credit [Member] | ||||||||||||||
Debt Instrument Covenant Accounts Payable Limit | $ 7,500,000 | |||||||||||||
Debt Instrument Covenant Accounts Payable Outstanding for More Than 60 Days Limit | 2,000,000 | |||||||||||||
Debt Instrument Covenant Accounts Payable Outstanding for More Than 90 Days Limit | $ 1,000,000 | |||||||||||||
Minimum [Member] | Subsequent Event [Member] | ||||||||||||||
Percentage of Officers' Compensation, Decreased During Period | 20.00% | |||||||||||||
Percentage of Other Salaries, Decreased During Period | 5.00% | |||||||||||||
Maximum [Member] | Subsequent Event [Member] | ||||||||||||||
Percentage of Officers' Compensation, Decreased During Period | 40.00% | |||||||||||||
Percentage of Other Salaries, Decreased During Period | 20.00% | |||||||||||||
Maximum [Member] | Subsequent Event [Member] | Second Lien Credit Facility [Member] | ||||||||||||||
Debt Instrument, Interest Rate, Increase (Decrease), Interest Payable in Kind | 5.00% |
Note 14 - Subsequent Events - D
Note 14 - Subsequent Events - Derivative Contracts (Details) - Subsequent Event [Member] | 1 Months Ended |
Jan. 31, 2020$ / bbl | |
Fixed Swap 2020 [Member] | |
Daily volume | 80 |
Swap price (in USD per Barrel of Oil) | 50.6 |
Fixed Swap 2021 [Member] | |
Daily volume | 82 |
Swap price (in USD per Barrel of Oil) | 50.6 |
Fixed Swap 2022 [Member] | |
Daily volume | 2,412 |
Swap price (in USD per Barrel of Oil) | 50.6 |
Fixed Swap 2023 [Member] | |
Daily volume | 1,498 |
Swap price (in USD per Barrel of Oil) | 50.6 |
Fixed Swap 2024 [Member] | |
Daily volume | 1,589 |
Swap price (in USD per Barrel of Oil) | 50.6 |
Note 15 - Quarterly Results o_3
Note 15 - Quarterly Results of Operations (Unaudited) - Results of Operations for Fiscal Quarters (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Revenues | $ 28,276 | $ 31,536 | $ 34,820 | $ 34,514 | $ 35,996 | $ 41,625 | $ 30,916 | $ 40,630 | $ 129,146 | $ 149,167 | $ 86,264 |
Operating income | (49,412) | 8,053 | 8,935 | 6,708 | 8,722 | 17,735 | 10,931 | 20,090 | (25,716) | 57,528 | 20,886 |
Net income (loss) | $ (68,268) | $ 17,041 | $ 11,678 | $ (25,455) | $ 55,819 | $ 1,777 | $ (10,554) | $ 10,779 | $ (65,004) | $ 57,821 | $ 16,006 |
Net income (loss) per common share - basic (in dollars per share) | $ (0.41) | $ 0.10 | $ 0.07 | $ (0.15) | $ 0.34 | $ 0.01 | $ (0.06) | $ 0.07 | $ (0.39) | $ 0.35 | $ 0.10 |
Net income (loss) per common share - diluted (in dollars per share) | $ (0.41) | $ 0.10 | $ 0.07 | $ (0.15) | $ 0.33 | $ 0.01 | $ (0.06) | $ 0.06 | $ (0.39) | $ 0.34 | $ 0.10 |
Note 16 - Supplemental Oil an_3
Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) (Details Textual) Boe in Thousands | 12 Months Ended | ||
Dec. 31, 2019Boe | Dec. 31, 2018Boe | Dec. 31, 2017Boe | |
Proved Developed and Undeveloped Reserves Sales of Minerals in Place, Energy (Barrel of Oil Equivalent) | 1,312 | ||
Proved Developed and Undeveloped Reserves Production, Energy (Barrel of Oil Equivalent) | 3,616 | 3,580 | 2,698 |
Proved Developed and Undeveloped Reserve, Purchase of Mineral in Place (Energy) (Barrel of Oil Equivalent) | 189 | ||
Other Miscellaneous Asset [Member] | |||
Proved Developed and Undeveloped Reserves Sales of Minerals in Place, Energy (Barrel of Oil Equivalent) | 18 | 68 | |
Ira Area [Member] | |||
Proved Developed and Undeveloped Reserves Sales of Minerals in Place, Energy (Barrel of Oil Equivalent) | 203 | ||
Delaware Locations in Ward County, TX [Member] | |||
Number of Producing Locations Sold | 1 | ||
Number of Undeveloped Locations Sold | 2 | ||
Ward County, TX [Member] | |||
Proved Developed and Undeveloped Reserves Sales of Minerals in Place, Energy (Barrel of Oil Equivalent) | 3,558 | ||
Change in Projections [Member] | |||
Proved Developed and Undeveloped Reserves Revisions of Previous Estimates, Energy (Barrel of Oil Equivalent) | 8,790 | (45) | 621 |
Conversion of Probable Undeveloped Locations to Proved Producing Reserves [Member] | |||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Location | 3 | ||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Energy (Barrel of Oil Equivalent) | 2,028 | ||
Conversion of Probable Undeveloped Locations to Proved Producing Reserves [Member] | Ward County, Texas [Member] | |||
Proved Developed and Undeveloped Reserves Revisions of Previous Estimates, Energy (Barrel of Oil Equivalent) | 13,402 | ||
Conversion of Probable Undeveloped Locations to Proved Producing Reserves [Member] | Three Fork 2nd bench Locations [Member] | |||
Proved Developed and Undeveloped Reserves Revisions of Previous Estimates, Energy (Barrel of Oil Equivalent) | 6,525 | ||
Proved Developed and Undeveloped Reserves Revisions of Previous Estimates, Location | 13 | ||
Addition of Proved Undeveloped Non-operated Locations [Member] | |||
Proved Developed and Undeveloped Reserves Revisions of Previous Estimates, Energy (Barrel of Oil Equivalent) | 3,776 | ||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Location | 2 | 2 | |
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Energy (Barrel of Oil Equivalent) | 838 | ||
Three Forks Location in McKenzie County, North Dakota [Member] | |||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Energy (Barrel of Oil Equivalent) | 14,333 | ||
Gulf Coast Area Holdings [Member] | |||
Proved Developed and Undeveloped Reserves Sales of Minerals in Place, Energy (Barrel of Oil Equivalent) | 1,839 | ||
Permian Locations in Marion, Pecos, and Reeves Counties, Texas [Member] | |||
Proved Developed and Undeveloped Reserves Sales of Minerals in Place, Energy (Barrel of Oil Equivalent) | 42 | ||
Number of Non-operated Holdings Sold | 14 | ||
Bakken Area Holdings [Member] | |||
Proved Developed and Undeveloped Reserves Sales of Minerals in Place, Energy (Barrel of Oil Equivalent) | 1,268 | ||
Addition of Proved Undeveloped Operated Locations [Member] | |||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Location | 19 | ||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Energy (Barrel of Oil Equivalent) | 8,130 | ||
Conversion of Probable Undeveloped Locations to Producing Reserves [Member] | |||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Location | 2 | ||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Energy (Barrel of Oil Equivalent) | 1,523 | ||
Conversion of Probable Undeveloped Locations to Proved Undeveloped Reserves [Member] | |||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Location | 5 | ||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Energy (Barrel of Oil Equivalent) | 2,670 | ||
Conversion of Probable Undeveloped Locations to Proved Undeveloped Reserves [Member] | Ward County, TX [Member] | |||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Location | 10 | ||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Energy (Barrel of Oil Equivalent) | 4,343 | ||
Unit Line Well Configurations [Member] | |||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Location | 3 | ||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Energy (Barrel of Oil Equivalent) | 1,692 | ||
Non-operated Proved Non-producintg Locations [Member] | |||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Location | 6 | ||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Energy (Barrel of Oil Equivalent) | 126 | ||
Minerals Purchased in Place [Member] | |||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Energy (Barrel of Oil Equivalent) | 877 | ||
Increase in Projections [Member] | Ward County, TX [Member] | |||
Proved Developed and Undeveloped Reserves Revisions of Previous Estimates, Energy (Barrel of Oil Equivalent) | 1,951 | ||
Increase in Economic Life Expectations [Member] | Ward County, TX [Member] | |||
Proved Developed and Undeveloped Reserves Revisions of Previous Estimates, Energy (Barrel of Oil Equivalent) | 523 | ||
Proved Developed and Undeveloped Reserves Production, Energy (Barrel of Oil Equivalent) | 2,698 | ||
Proved Developed and Undeveloped Reserves Revisions of Previous Estimates, Location | 7 | ||
Addition of New Producing Wells [Member] | Ward County, TX [Member] | |||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Location | 3 | ||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Energy (Barrel of Oil Equivalent) | 1,229 | ||
Addition of New Producing Wells [Member] | Atascosa County, TX [Member] | |||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Energy (Barrel of Oil Equivalent) | 240 | ||
Addition of Proved Undeveloped Locations [Member] | Ward County, TX [Member] | |||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Energy (Barrel of Oil Equivalent) | 11,928 | ||
Addition of Proved Undeveloped Locations [Member] | Proved Undeveloped Wolfcamp A locations [Member] | |||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Location | 27 | ||
Addition of Proved Undeveloped Locations [Member] | Third Bone Spring locations [Member] | |||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Location | 4 | ||
Addition of Proved Undeveloped Locations [Member] | Wolfcamp B Locations [Member] | |||
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Location | 2 |
Note 16 - Supplemental Oil an_4
Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) - Capitalized Costs (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Proved oil and gas properties | $ 1,162,094 | $ 1,091,905 |
Unproved properties | ||
Total | 1,162,094 | 1,091,905 |
Accumulated depreciation, depletion, amortization and impairment | (851,107) | (748,773) |
Net capitalized costs | $ 310,987 | $ 343,132 |
Note 16 - Supplemental Oil an_5
Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) - Cost Incurred (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Development costs | $ 92,884 | $ 131,271 | $ 94,478 |
Exploration costs | 8,509 | ||
Property acquisition costs | 41,465 | 31,409 | |
Costs Incurred, Acquisition of Oil and Gas Properties, Total | $ 92,884 | $ 172,736 | $ 134,396 |
Note 16 - Supplemental Oil an_6
Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) - Results of Operations (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019USD ($)$ / bbl | Dec. 31, 2018USD ($)$ / bbl | Dec. 31, 2017USD ($)$ / bbl | |
Revenues | $ 128,992 | $ 149,030 | $ 86,189 |
Production costs | (38,229) | (36,323) | (22,425) |
Depreciation, depletion and amortization | (51,041) | (42,237) | (25,676) |
Accretion of future site restoration | (436) | (516) | (451) |
Proved property impairment | (51,293) | ||
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs) | $ (12,007) | $ 69,954 | $ 37,637 |
Depletion rate per barrel of oil equivalent (in USD per Barrel of Oil) | $ / bbl | 14.12 | 11.8 | 9.52 |
Note 16 - Supplemental Oil an_7
Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) - Proved Developed and Undeveloped Reserves (Details) - bbl bbl in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Oil [Member] | |||
Balance (Barrel of Oil) | 42,237 | 37,071 | 24,209 |
Revisions of previous estimates (Barrel of Oil) | (15,616) | (4,206) | 259 |
Extensions and discoveries (Barrel of Oil) | 13,477 | 11,270 | 14,533 |
Purchases of minerals in place (Barrel of Oil) | 688 | 8 | |
Sales of minerals in place (Barrel of Oil) | (1,431) | (278) | (364) |
Production (Barrel of Oil) | (2,388) | (2,308) | (1,574) |
Balance (Barrel of Oil) | 36,279 | 42,237 | 37,071 |
Proved developed reserves (Barrel of Oil) | 10,964 | 13,586 | 10,820 |
Porved undeveloped reserves (Barrel of Oil) | 25,315 | 28,651 | 25,808 |
Natural Gas Liquids [Member] | |||
Balance (Barrel of Oil) | 10,034 | 11,975 | 8,644 |
Revisions of previous estimates (Barrel of Oil) | (2,713) | (1,927) | 1,269 |
Extensions and discoveries (Barrel of Oil) | 2,285 | 1,797 | 2,813 |
Purchases of minerals in place (Barrel of Oil) | 14 | ||
Sales of minerals in place (Barrel of Oil) | (86) | (1,303) | (289) |
Production (Barrel of Oil) | (548) | (508) | (476) |
Balance (Barrel of Oil) | 8,972 | 10,034 | 11,975 |
Proved developed reserves (Barrel of Oil) | 2,699 | 3,804 | 3,794 |
Porved undeveloped reserves (Barrel of Oil) | 6,273 | 6,230 | 8,181 |
Natural Gas [Member] | |||
Balance (Barrel of Oil) | 89,744 | 97,828 | 70,829 |
Revisions of previous estimates (Barrel of Oil) | (23,178) | (2,618) | 19,311 |
Extensions and discoveries (Barrel of Oil) | 14,073 | 11,475 | 14,534 |
Purchases of minerals in place (Barrel of Oil) | 1,137 | 1,001 | |
Sales of minerals in place (Barrel of Oil) | (9,898) | (13,491) | (3,958) |
Production (Barrel of Oil) | (4,076) | (4,587) | (3,889) |
Balance (Barrel of Oil) | 66,665 | 89,744 | 97,828 |
Proved developed reserves (Barrel of Oil) | 21,439 | 43,271 | 39,974 |
Porved undeveloped reserves (Barrel of Oil) | 45,226 | 46,473 | 57,854 |
Oil Equivalents [Member] | |||
Balance (Barrel of Oil) | 67,228 | 65,351 | 44,657 |
Revisions of previous estimates (Barrel of Oil) | (22,192) | (6,570) | 4,747 |
Extensions and discoveries (Barrel of Oil) | 18,109 | 14,979 | 19,768 |
Purchases of minerals in place (Barrel of Oil) | 877 | 189 | |
Sales of minerals in place (Barrel of Oil) | (3,167) | (3,829) | (1,312) |
Production (Barrel of Oil) | (3,616) | (3,580) | (2,698) |
Balance (Barrel of Oil) | 56,362 | 67,228 | 65,351 |
Proved developed reserves (Barrel of Oil) | 17,237 | 24,602 | 21,720 |
Porved undeveloped reserves (Barrel of Oil) | 39,125 | 42,626 | 43,631 |
Note 16 - Supplemental Oil an_8
Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) - Future Net Cash Inflows (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Future cash inflows | $ 1,890,579 | $ 2,876,976 | $ 2,035,619 | |
Future production costs | (598,714) | (849,063) | (609,921) | |
Future development costs | (544,111) | (547,163) | (461,619) | |
Future income tax expense | (181,224) | (83,915) | ||
Future net cash flows | 747,754 | 1,299,526 | 880,164 | |
Discount | (440,142) | (647,642) | (474,423) | |
Standardized Measure of discounted future net cash relating to proved reserves | $ 307,612 | $ 651,884 | $ 405,741 | $ 160,600 |
Note 16 - Supplemental Oil an_9
Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) - Changes in the Standardized Measure (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Standardized Measure, beginning of year | $ 651,884 | $ 405,741 | $ 160,600 |
Sales and transfers of oil and gas produced, net of production costs | (90,763) | (112,707) | (63,764) |
Net change in prices and development and production costs from prior year | (218,092) | 268,942 | 159,661 |
Extensions, discoveries, and improved recovery, less related costs | 98,780 | 153,544 | 129,277 |
Sales of minerals in place | (17,276) | (39,253) | (8,583) |
Purchases of minerals in place | 8,990 | 1,238 | |
Revisions of previous estimates | (227,477) | (67,345) | 31,044 |
Change in timing and other | (13,744) | 30,811 | 1,908 |
Change in future income tax expense | 59,112 | (37,413) | (21,700) |
Accretion of discount | 65,188 | 40,574 | 16,060 |
Standardized Measure, end of year | $ 307,612 | $ 651,884 | $ 405,741 |
Note 16 - Supplemental Oil a_10
Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) - Oil and Gas Prices (Details) | 12 Months Ended | |||
Dec. 31, 2019$ / bbl$ / BTU | Dec. 31, 2018$ / bbl$ / BTU | Dec. 31, 2017$ / bbl$ / BTU | ||
Oil (per Bbl) (1) (in USD per Barrel of Oil) | [1] | 55.73 | 65.56 | 51.34 |
Gas (per Mmbtu) (2) (in USD per British Thermal Unit) | $ / BTU | [2] | 2.54 | 3.05 | 2.99 |
Oil (per Bbl) (3) (in USD per Barrel of Oil) | [3] | 52.14 | 56.95 | 46.83 |
Gas (per Mmbtu) (4) (in USD per British Thermal Unit) | $ / BTU | [4] | 0.63 | 1.76 | 1.79 |
NGL's (per Bbl) (5) (in USD per Barrel of Oil) | [5] | 3.48 | 19.95 | 13.19 |
[1] | The quoted oil price for the year ended December 31 of each year, 2017, 2018 and 2019 is the 12-month unweighted average first-day-of-the-month West Texas Intermediate spot price for each month of 2017, 2018 and 2019. | |||
[2] | The quoted gas price for the year ended December 31, 2017, 2018 and 2019 is the 12-month unweighted average first-day-of-the-month Henry Hub spot price for each month of 2017, 2018 and 2019. | |||
[3] | The oil price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied. | |||
[4] | The gas price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied. | |||
[5] | The NGL price is the realized price as of December 31 of each year after the appropriate differentials have been applied. |