Document and Entity Information
Document and Entity Information - shares | 3 Months Ended | |
Mar. 31, 2018 | May 07, 2018 | |
Document and Entity Information [Abstract] | ||
Entity Registrant Name | ABRAXAS PETROLEUM CORP | |
Entity Central Index Key | 867,665 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | Mar. 31, 2018 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q1 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 166,572,157 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEET - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 5,645 | $ 1,618 |
Accounts receivable: | ||
Joint owners, net | 6,816 | 14,218 |
Oil and gas production sales | 17,873 | 17,789 |
Other | 937 | 86 |
Total accounts receivable | 25,626 | 32,093 |
Derivative asset | 7 | 0 |
Other current assets | 719 | 778 |
Total current assets | 31,997 | 34,489 |
Oil and gas properties, full cost method of accounting: | ||
Proved | 954,762 | 923,237 |
Other property and equipment | 39,292 | 39,136 |
Total | 994,054 | 962,373 |
Less accumulated depreciation, depletion, amortization and impairment | (735,066) | (724,606) |
Total property and equipment, net | 258,988 | 237,767 |
Deferred financing fees, net | 1,380 | 1,285 |
Derivative asset | 19 | 0 |
Other assets | 265 | 265 |
Total assets | 292,649 | 273,806 |
Current liabilities: | ||
Accounts payable | 24,257 | 45,570 |
Joint interest oil and gas production payable | 14,890 | 11,502 |
Accrued interest | 187 | 140 |
Other accrued expenses | 752 | 539 |
Derivative liability | 14,221 | 10,837 |
Current maturities of long-term debt | 264 | 262 |
Total current liabilities | 54,571 | 68,850 |
Long-term debt – less current maturities | 107,287 | 87,354 |
Other liabilities | 132 | 132 |
Derivative liability long-term | 3,750 | 2,387 |
Future site restoration | 9,225 | 8,775 |
Total liabilities | 174,965 | 167,498 |
Commitments and contingencies (Note 9) | ||
Stockholders’ Equity: | ||
Preferred stock, par value $0.01 per share – authorized 1,000,000 shares; -0- shares issued and outstanding | 0 | 0 |
Common stock, par value $0.01 per share, authorized 400,000,000 shares; 165,881,694 and 165,889,901 issued and outstanding at March 31, 2018 and December 31, 2017, respectively | 1,659 | 1,659 |
Additional paid-in capital | 416,068 | 415,471 |
Accumulated deficit | (300,043) | (310,822) |
Total stockholders’ equity | 117,684 | 106,308 |
Total liabilities and stockholders’ equity | $ 292,649 | $ 273,806 |
CONDENSED CONSOLIDATED BALANCE3
CONDENSED CONSOLIDATED BALANCE SHEET (Parenthetical) - $ / shares | Mar. 31, 2018 | Dec. 31, 2017 |
Stockholders’ Equity: | ||
Preferred stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized (in shares) | 1,000,000 | 1,000,000 |
Preferred stock, shares issued (in shares) | 0 | 0 |
Preferred stock, shares outstanding (in shares) | 0 | 0 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 400,000,000 | 200,000,000 |
Common stock, shares issued (in shares) | 165,881,694 | 165,889,901 |
Common stock, shares outstanding (in shares) | 165,881,694 | 165,889,901 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Revenues: | ||
Oil and gas production revenues | $ 40,594,000 | $ 18,787,000 |
Other | 36,000 | 15,000 |
Revenues | 40,630,000 | 18,802,000 |
Operating costs and expenses: | ||
Lease operating | 4,569,000 | 4,118,000 |
Production and ad valorem taxes | 3,113,000 | 1,620,000 |
Depreciation, depletion, and amortization | 10,130,000 | 5,374,000 |
General and administrative (including stock-based compensation of $586 and $770, respectively) | 2,728,000 | 2,737,000 |
Operating costs and expenses | 20,540,000 | 13,849,000 |
Operating income | 20,090,000 | 4,953,000 |
Other (income) expense: | ||
Interest expense | 1,329,000 | 507,000 |
Amortization of deferred financing fees | 96,000 | 137,000 |
Loss (gain) on derivative contracts | 7,883,000 | (9,381,000) |
Loss on sale of non-oil and gas assets | 3,000 | 0 |
Total other (income) expense | 9,311,000 | (8,737,000) |
Income before income tax | 10,779,000 | 13,690,000 |
Income tax (expense) benefit | 0 | 0 |
Net income | $ 10,779,000 | $ 13,690,000 |
Net (loss) income per common share | ||
Net income (loss) per common share - basic (in usd per share | $ 0.07 | $ 0.09 |
Net income (loss) per common share - diluted (in usd per share) | $ 0.06 | $ 0.09 |
Weighted average shares outstanding: | ||
Weighted average shares outstanding, basic (shares) | 165,133 | 154,118 |
Weighted average shares outstanding, diluted (shares) | 167,243 | 156,813 |
Oil [Member] | ||
Revenues: | ||
Oil and gas production revenues | $ 35,994,000 | $ 15,502,000 |
Natural Gas [Member] | ||
Revenues: | ||
Oil and gas production revenues | 2,377,000 | 1,982,000 |
Natural Gas Liquids [Member] | ||
Revenues: | ||
Oil and gas production revenues | $ 2,223,000 | $ 1,303,000 |
CONDENSED CONSOLIDATED STATEME5
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Operating costs and expenses: | ||
Stock-based compensation | $ 586 | $ 770 |
CONDENSED CONSOLIDATED STATEME6
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Operating Activities | ||
Net income | $ 10,779,000 | $ 13,690,000 |
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | ||
Loss on sale of non-oil and gas assets | 3,000 | 0 |
Net loss (gain) on derivative contracts | 7,883,000 | (9,381,000) |
Derivative contract settlements | (3,789,000) | 621,000 |
Depreciation, depletion, and amortization | 10,130,000 | 5,374,000 |
Amortization of deferred financing fees | 96,000 | 137,000 |
Accretion of future site restoration | 130,000 | 112,000 |
Stock-based compensation | 586,000 | 770,000 |
Changes in operating assets and liabilities: | ||
Accounts receivable | 6,467,000 | 4,216,000 |
Other assets | 686,000 | (727,000) |
Accounts payable and accrued expenses | (741,000) | (4,609,000) |
Net cash provided by operating activities | 32,230,000 | 10,203,000 |
Investing Activities | ||
Capital expenditures, including purchases and development of properties | (47,959,000) | (9,379,000) |
Proceeds from the sale of oil and gas properties | 0 | 10,622,000 |
Proceeds from the sale of non-oil and gas assets | 1,000 | 0 |
Net cash used in provided by investing activities | (47,958,000) | 1,243,000 |
Financing Activities | ||
Proceeds from long-term borrowings | 26,000,000 | 6,000,000 |
Payments on long-term borrowings | (6,065,000) | (81,598,000) |
Proceeds from issuance of common stock | 0 | 65,223,000 |
Deferred financing fees | (191,000) | (10,000) |
Exercise of stock options | 11,000 | 0 |
Net cash (used in) provided by financing activities | 19,755,000 | (10,385,000) |
Increase in cash and cash equivalents | 4,027,000 | 1,061,000 |
Cash and cash equivalents at beginning of period | 1,618,000 | 0 |
Cash and cash equivalents at end of period | 5,645,000 | 1,061,000 |
Supplemental disclosure of cash flow information: | ||
Interest paid | 1,020,000 | 507,000 |
Non-cash investing and financing activities | ||
Change in capital expenditures included in accounts payable | (16,924,000) | 1,578,000 |
Increase in Asset Retirement Obligation in capital expenditures | 320,000 | 0 |
Non-cash investing and financing activities | $ (16,604,000) | $ 1,578,000 |
Basis of Presentation
Basis of Presentation | 3 Months Ended |
Mar. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation | Basis of Presentation The accounting policies followed by Abraxas Petroleum Corporation and its subsidiaries (the “Company”) are set forth in the notes to the Company’s audited consolidated financial statements in the Annual Report on Form 10-K for the year ended December 31, 2017 filed with the SEC on March 16, 2018. Such policies have been continued without change. Also, refer to the notes to those financial statements for additional details of the Company’s financial condition, results of operations, and cash flows. All material items included in those notes have not changed except as a result of normal transactions in the interim, or as disclosed within this report. The accompanying interim condensed consolidated financial statements have not been audited by our independent registered public accountants, and in the opinion of management, reflect all adjustments necessary for a fair presentation of the financial position and results of operations. Any and all adjustments are of a normal and recurring nature. Although management believes the unaudited interim related disclosures in these condensed consolidated financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") have been condensed or omitted pursuant to the rules and regulations of the SEC. The results of operations and the cash flows for the three month period ended March 31, 2018 are not necessarily indicative of the results to be expected for the full year. The condensed consolidated financial statements included herein should be read in conjunction with the consolidated audited financial statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017. Reclassifications Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations. Consolidation Principles 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 income is to be recognized in connection with contractual drilling services performed in connection with properties in which the Company or its affiliates hold an ownership, or other economic interest. Any income not recognized as a result of this limitation is to be credited to the full cost pool and recognized through lower amortization as reserves are produced. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Recently Adopted Accounting Standards and Disclosures I n May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update, ("ASU") No. 2014-09, Revenue from Contracts with Customers . The Company completed a detailed analysis of its revenue streams at the individual contract level to evaluate the impact of the new revenue standard on its consolidated financial statements. Based on these completed assessments, adoption of this standard did not impact our net earnings. The Company adopted this new standard on January 1, 2018, using the modified retrospective method. No cumulative adjustment to retained earnings resulted from the adoption of this standard. See Note 2. "Impact of ASC 606 Adoption" and Note 3. "Revenue from Contracts with Customers" for further details related to the Company's adoption of this standard. Recent Accounting Standards and Disclosures Not Yet Adopted In February 2016, the FASB issued ASU 2016-02 “ Leases, " which supersedes ASC 840 “Leases ” and creates a new topic, ASC 842 "Leases." This update requires lessees to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. This update is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with earlier application permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are currently in the process of identifying our leases and evaluating the effect of this update on our consolidated financial statements and related disclosures. Stock-Based Compensation and Option Plans Stock Options The Company currently utilizes a standard option-pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors. The following table summarizes the Company’s stock-based compensation expense related to stock options for the periods presented: Three Months Ended 2018 2017 $ 339 $ 434 The following table summarizes the Company’s stock option activity for the three months ended March 31, 2018 (shares in thousands): Number of Shares (thousands) Weighted Average Option Exercise Price Per Share Weighted Average Grant Date Fair Value Per Share Outstanding, December 31, 2017 8,317 $ 2.35 $ 1.67 Granted — — — Exercised (21 ) $ 1.58 $ 1.12 Forfeited (78 ) $ 3.01 $ 2.12 Outstanding, March 31, 2018 8,218 2.34 2.17 As of March 31, 2018 , there was approximately $1.3 million of unamortized compensation expense related to outstanding stock options that will be recognized from 2018 through 2021. 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 recipiant of the award terminates employment with the Company prior to the lapse of the restrictions. The fair value of such stock was determined using the closing price on the grant date and compensation expense is recorded over the applicable vesting periods. The following table summarizes the Company’s restricted stock activity for the three months ended March 31, 2018 : Number of Shares (thousands) Weighted Average Grant Date Fair Value Per Share Unvested, December 31, 2017 1,479 $ 3.43 Granted — — Vested/Released (712 ) $ 3.15 Forfeited (20 ) $ 3.83 Unvested, March 31, 2018 747 $ 3.68 The following table summarizes the Company’s stock-based compensation expense related to restricted stock for the periods presented: Three Months Ended 2018 2017 $ 247 $ 336 As of March 31, 2018 , there was approximately $0.4 million of unamortized compensation expense relating to outstanding restricted shares that will be recognized in 2018 through 2021. Oil and Gas Properties The Company follows the full cost method of accounting for oil and gas properties. Under this method, all direct costs and certain indirect costs associated with the 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% , plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. Costs in excess of the present value of estimated net revenue from proved reserves discounted at 10% are charged to proved property impairment expense. No gain or loss is recognized upon sale or disposition of oil and gas properties for full cost accounting companies with proceeds accounted for as an adjustment of capitalized cost. An exception to this rule occurs when the adjustment to the full cost pool results in a significant alteration of the relationship between capitalized cost and proved reserves. The Company applies the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. At March 31, 2018 and 2017, our net capitalized costs of oil and gas properties did not exceed the cost ceiling of our estimated proved reserves. 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 require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a non-capital 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 is fixed or reliably determinable. The Company accounts for future site restoration obligations based on the guidance of ASC 410 which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. ASC 410 requires that the fair value of a liability for an asset's retirement obligation be 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 amortize these costs as a component of our depletion expense in the accompanying condensed consolidated financial statements. The following table summarizes the Company’s future site restoration obligation transactions for the three months ended March 31, 2018 and the year ended December 31, 2017: March 31, 2018 December 31, 2017 Beginning future site restoration obligation $ 8,775 $ 8,623 New wells placed on production and other 357 1,088 Deletions related to property disposals and plugging costs (61 ) (1,551 ) Accretion expense 130 451 Revisions and other 24 164 Ending future site restoration obligation $ 9,225 $ 8,775 |
Income Taxes
Income Taxes | 3 Months Ended |
Mar. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes The Company records income taxes using the liability method. Under this method, deferred tax assets and liabilities are determined based on differences between financial reporting and tax basis of assets and liabilities and are measured using the tax rates and laws expected to be in effect when the differences are expected to reverse. For the three months ended March 31, 2018 and 2017, there was no income tax benefit due to net operating loss carryforwards ("NOLs") and the Company recorded a full valuation allowance against its net deferred taxes. At December 31, 2017, the Company had, subject to the limitation discussed below, $255 million of net operating loss carryforwards for U.S. tax purposes. The Company's pre-2018 NOL's will expire in varying amounts from 2023 through 2037, if not utilized; and can offset 100% of future taxable income for regular tax purposes. Any NOLs arising after January 1, 2018 can generally be carried forward indefinitely and can offset up to 80% of future taxable income for regular tax purposes, (the alternative minimum tax no longer applies to corporations since January 1, 2018). The use of the Company's NOLs will be limited if there is an "ownership change" in its common stock, generally a cumulative ownership change exceeding 50% during a three year period, as determined under Section 382 of the Internal Revenue Code. As of March 31, 2018, the Company has not had an ownership change as defined by Section 382. Given historical losses, uncertainties exist as to the future utilization of the NOL carryforwards. Therefore, the Company has established a valuation allowance of $80.4 million for deferred tax assets at December 31, 2017. As of March 31, 2018 , the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years 2013 through 2017 remain open to examination by the tax jurisdictions to which the Company is subject. New tax legislation, commonly referred to as the Tax Cuts and Jobs Act (H.R. 1), was enacted on December 22, 2017. ASC740, Accounting for Income Taxes , requires companies to recognize the effect of tax law changes in the period of enactment even though the effective date for most provisions is for tax years beginning after December 31, 2017. Since our federal deferred tax asset was fully offset by a valuation allowance, the reduction in the U.S. corporate income tax rate to 21% did not materially affect the Company's financial statements. Significant provisions that are not yet effective but may impact income taxes in future years include: the repeal of the corporate Alternative Minimum Tax, the limitation on the current deductibility of net interest expense in excess of 30% of adjusted taxable income for levered balance sheets, a limitation on utilization of NOLs generated after tax year 2017 to 80% of taxable income, the unlimited carryforward of NOLs generated after tax year 2017, temporary 100% expensing of certain business assets, additional limitations on certain general and administrative expenses, and changes in determining the excessive compensation limitation. Currently, the Company does not anticipate paying cash federal income taxes in the near term due to any of the legislative changes, primarily due to the availability of our NOL carryforwards. Future interpretations relating to the recently enacted U.S. federal income tax legislation which vary from our current interpretation and possible changes to state tax laws in response to the recently enacted federal legislation may have a significant effect on this projection. |
Impact of ASC 606 Adoption
Impact of ASC 606 Adoption | 3 Months Ended |
Mar. 31, 2018 | |
Accounting Changes and Error Corrections [Abstract] | |
Impact of ASC 606 Adoption | Impact of ASC 606 Adoption On January 1, 2018, the Company adopted ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”) using the modified retrospective method of transition. Under this method of transition, the Company applied ASU 2014-09 to all new contracts entered into on and after January 1, 2018 and all existing contracts for which all (or substantially all) of the revenue attributable to a contract had not been recognized under legacy revenue guidance. ASU 2014-09 supersedes nearly all existing revenue recognition guidance under U.S. GAAP and includes a five step process to recognize revenue when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. For the three months ended March 31, 2018, there was no impact to the Company's reported revenues, operating costs and expenses or net income as a result of adopting ASU 2014-09, as compared to legacy revenue guidance. In addition, no cumulative catch-up adjustment to accumulated deficit was required on January 1, 2018 as a result of adopting ASU 2014-09. |
Revenue From Contracts With Cus
Revenue From Contracts With Customers Revenue From Contracts With Customers | 3 Months Ended |
Mar. 31, 2018 | |
Revenue Recognition [Abstract] | |
Revenue From Contracts With Customers | Revenue from Contracts with Customers Revenue Recognition Sales of oil, gas and natural gas liquids (“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. 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. The midstream processing entity processes the natural gas and remits proceeds to the Company based upon either (i) the resulting sales price of NGL and residue gas received by the midstream processing entity from third party customers or (ii) the prevailing index prices for NGL and residue gas in the month of delivery to the midstream processing entity. Gathering, processing, transportation and other expenses incurred by the midstream processing entity are typically deducted from the proceeds that the Company receives. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. In 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 utilizes the sales method to account for gas production imbalances. Under this method, income is recorded based on the Company’s net revenue interest in production taken for delivery. The Company had no material gas imbalances at March 31, 2018 and 2017. Disaggregation of Revenue The Company is focused on the development of oil and natural gas properties primarily located in the following three operating regions in the United States: (i) the Permian/Delaware Basin, (ii) Rocky Mountain and (iii) South Texas. Revenue attributable to each of those regions is disaggregated in the table below. Three Months Ended March 31, 2018 2017 Oil Gas NGL Oil Gas NGL Operating Regions: Permian/Delaware Basin $ 14,374 $ 920 $ 798 $ 2,488 $ 756 $ 389 Rocky Mountain $ 19,240 $ 1,127 $ 1,403 $ 11,397 $ 871 $ 894 South Texas $ 2,380 $ 330 $ 22 $ 1,617 $ 355 $ 20 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-party customers on behalf of the Company, such as the Company's percentage-of-proceeds and gas purchase contracts. These types of transactions require judgment to determine whether we are the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. 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 year or less. For those contracts, the Company has utilized the practical expedient in ASC Topic 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC Topic 606-10-50-14(a) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. 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 received from third parties, the expected sales volumes and prices for those properties are estimated and also recorded as “Accounts receivable - Oil and gas production sales” in the accompanying condensed consolidated balance sheets. In this scenario, payment is also unconditional, as the Company has satisfied its performance obligations through delivery of the relevant product. As a result, the Company has concluded that its product sales do not give rise to contract assets or liabilities under ASU 2014-09. At March 31, 2018 and December 31, 2017, our receivables from contracts with customers were $17.9 million and $17.8 million , respectively. 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 be received for 30 to 60 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the midstream purchaser and the price that will be received for the sale of the product. Additionally, to the extent actual volumes and prices of oil are unavailable for a given reporting period because of timing or information not received from third party purchasers, the expected sales volumes and prices for those barrels of oil are also estimated. 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 been significant. For the three months ended March 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. |
Long-Term Debt
Long-Term Debt | 3 Months Ended |
Mar. 31, 2018 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Long-Term Debt The following is a description of the Company’s debt as of March 31, 2018 and December 31, 2017, respectively: March 31, 2018 December 31, 2017 Senior secured credit facility $ 104,000 $ 84,000 Real estate lien note 3,551 3,616 107,551 87,616 Less current maturities (264 ) (262 ) $ 107,287 $ 87,354 Credit Facility The Company has a senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer to as the credit facility. As of March 31, 2018 , $104.0 million was outstanding under the credit facility. The credit facility has a maximum commitment of $300.0 million and availability is subject to a borrowing base. At March 31, 2018 , the Company had a borrowing base of $175.0 million . The borrowing base is determined semi-annually by the lenders based upon the Company's reserve reports, one of which must be prepared by its independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of the Company's proved reserves securing the facility utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, are able to make one additional borrowing base redetermination during any six-month period between scheduled redeterminations and the Company is able to request one redetermination during any six-month period between scheduled redeterminations. Outstanding borrowings in excess of the borrowing base must be repaid immediately or the Company must pledge additional oil and gas properties or other assets as collateral. The Company does not currently have any substantial unpledged assets and it may not have the financial resources to make any mandatory principal payments. In addition, a reduction of the borrowing base could also cause the Company to fail to be in compliance with the financial covenants described below. The Company's borrowing base will be automatically reduced in connection with any sales of producing properties with a market value of 5% or more of its then-current borrowing base and in connection with any hedge termination which could reduce the collateral value by 5% or more. The Company's borrowing base can never exceed the $300.0 million maximum commitment amount. Outstanding amounts under the credit facility bear interest (a) at any time an event of default exists, at 3% per annum plus the amounts set forth below, and (b) at all other times, at the greater of (x) the reference rate announced from time to time by Société Générale, (y) the Federal Funds Rate plus 0.5% , and (z) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (i) 1.5% - 2.5% , depending on the utilization of the borrowing base, or (ii) if we elect, LIBOR plus, in each case, 2.5% - 3.5% depending on the utilization of the borrowing base. At March 31, 2018 , the interest rate on the credit facility was approximately 4.85% assuming LIBOR borrowings. Subject to earlier termination rights and events of default, the stated maturity date of the credit facility is May 16, 2021 . Interest is payable quarterly on reference rate advances and not less than quarterly on LIBOR advances. The Company is permitted to terminate the credit facility and is able, from time to time, to permanently reduce the lenders’ aggregate commitment under the credit facility in compliance with certain notice and dollar increment requirements. Each of the Company's subsidiaries has guaranteed our obligations under the credit facility on a senior secured basis. Obligations under the credit facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of our and our subsidiary guarantors’ material property and assets. The collateral is required to include properties comprising at least 90% of the PV-10 of our proven reserves. The Company has also granted our lenders a security interest in our headquarters building. Under the credit facility, the Company is subject to customary covenants, including certain financial covenants and reporting requirements. The Company is required to maintain a current ratio, as defined in the credit facility, as of the last day of each quarter of not less than 1.00 to 1.00 and an interest coverage ratio of not less than 2.50 to 1.00. The Company is also required as of the last day of each quarter to maintain a total debt to EBITDAX ratio of not more than 3.50 to 1.00. The current ratio is defined as the ratio of consolidated current assets to consolidated current liabilities. For the purposes of this calculation, current assets include the portion of the borrowing base which is undrawn but excludes any cash deposited with a counter-party to a hedging arrangement and any assets representing a valuation account arising from the application of ASC 815 and ASC 410-20 and current liabilities exclude the current portion of long-term debt and any liabilities representing a valuation account arising from the application of ASC 815 and ASC 410-20. The interest coverage ratio is defined as the ratio of consolidated EBITDAX to consolidated interest expense for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, EBITDAX is defined as the sum of consolidated net income plus interest expense, oil and gas exploration expenses, income, franchise or margin taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of ASC 718, ASC 815 and ASC 410-20 plus all realized net cash proceeds arising from the settlement or monetization of any hedge contracts plus expenses incurred in connection with the negotiation, execution, delivery and performance of the credit facility plus expenses incurred in connection with any acquisition permitted under the credit facility plus expenses incurred in connection with any offering of senior unsecured notes, subordinated debt or equity plus up to $1.0 million of extraordinary expenses in any 12-month period plus extraordinary losses minus all non-cash items of income which were included in determining consolidated net loss, including all non-cash items resulting from the application of ASC 815 and ASC 410-20. Interest expense includes total interest, letter of credit fees and other fees and expenses incurred in connection with any debt. The total debt to EBITDAX ratio is defined as the ratio of total debt to consolidated EBITDAX for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, total debt is the outstanding principal amount of debt, excluding debt associated with the headquarters building and obligations with respect to surety bonds and derivative contracts . At March 31, 2018 , the Company was in compliance with all of these financial covenants. As of March 31, 2018 , the interest coverage ratio was 21.12 to 1.00, the total debt to EBITDAX ratio was 1.50 to 1.00, and our current ratio was 2.57 to 1.00. The 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; • 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 credit facility also contains certain additional covenants including requirements that: • 100% of the net proceeds from any terminations of derivative contracts must be used to repay amounts outstanding under the credit facility; and • if the sum of our cash on hand plus liquid investments exceeds $10.0 million , then the amount in excess of $10.0 million must be used to pay amounts outstanding under the credit facility. The 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. As of March 31, 2018 , the Company was in compliance with all of the terms of the credit facility. Real Estate Lien Note The Company has a real estate lien note secured by a first lien deed of trust on the property and improvements which serves as its corporate headquarters. The note bears interest at a fixed rate of 4.25% and is payable in monthly installments of $ 34,354 . Beginning August 20, 2018, the interest rate will adjust to the bank's then current prime rate plus 1.00% with a maximum rate of 7.25% . The maturity date of the note is July 20, 2023 . As of March 31, 2018 , and December 31, 2017 , $3.6 million , was outstanding on the note. |
Earnings per Share
Earnings per Share | 3 Months Ended |
Mar. 31, 2018 | |
Earnings Per Share [Abstract] | |
Earnings per Share | Earnings per Share The following table sets forth the computation of basic and diluted earnings per share: Three Months Ended March 31, 2018 2017 (In thousands, except per share data) Numerator: Net income $ 10,779 $ 13,690 Denominator: Denominator for basic earnings per share – weighted-average common shares outstanding 165,133 154,118 Effect of dilutive securities: Stock options and restricted shares 2,110 2,695 Denominator for diluted earnings per share – adjusted weighted-average shares and assumed exercise of options and restricted shares 167,243 156,813 Net income per common share - basic $ 0.07 $ 0.09 Net income per common share - diluted $ 0.06 $ 0.09 Basic net income per share, excluding any dilutive effects of stock options and unvested restricted stock, is computed by dividing net income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted net income per share is computed in a manner similar to basic; however diluted net income per share reflects the assumed conversion of all potentially dilutive securities. |
Hedging Program and Derivatives
Hedging Program and Derivatives | 3 Months Ended |
Mar. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Hedging Program and Derivatives | Hedging Program and Derivatives The derivative contracts the Company utilizes are based on index prices that may and often do differ from the actual oil and gas prices realized in our operations. The Company's derivative contracts do not qualify for hedge accounting; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. There are no netting agreements relating to these derivative contracts and there is no policy to offset. The following table sets forth the summary position of our derivative contracts as of March 31, 2018 : Oil - WTI Contract Periods Daily Volume (Bbl) Swap Price (per Bbl) Fixed Swaps 2018 April - December 4,426 $ 53.69 2019 January - December 2,800 $ 55.66 2020 January - December 2,200 $ 54.34 The following table illustrates the impact of derivative contracts on the Company’s balance sheet: Fair Value of Derivative Contracts as of March 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 $ 7 Derivatives – current $ 14,221 Commodity price derivatives Derivatives – long-term 19 Derivatives – long-term 3,750 $ 26 $ 17,971 Fair Value of Derivative Contracts as of December 31, 2017 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 $ — Derivatives – current $ 10,837 Commodity price derivatives Derivatives – long-term — Derivatives – long-term 2,387 $ — $ 13,224 |
Financial Instruments
Financial Instruments | 3 Months Ended |
Mar. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Financial Instruments | Financial Instruments Assets and liabilities measured at fair value are categorized into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: • Level 1 – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. • Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. • Level 3 - inputs to the valuation methodology are unobservable and significant to the fair value measurement. 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 March 31, 2018 and December 31, 2017 , and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance as of March 31, 2018 Assets: NYMEX fixed price derivative contracts $ — $ 26 $ — $ 26 Total Assets $ — $ 26 $ — $ 26 Liabilities: NYMEX fixed price derivative contracts $ — $ 17,971 $ — $ 17,971 Total Liabilities $ — $ 17,971 $ — $ 17,971 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, 2017 Assets: NYMEX fixed price derivative contracts $ — $ — $ — $ — Total Assets $ — $ — $ — $ — Liabilities: NYMEX fixed price derivative contracts $ — $ 13,208 $ — $ 13,208 NYMEX basis differential swaps — — 16 16 Total Liabilities $ — $ 13,208 $ 16 $ 13,224 The Company’s derivative contracts consisted of NYMEX-based fixed price swaps as of March 31, 2018 , and NYMEX-based fixed price swaps and a basis differential swap as of December 31, 2017. Under fixed price swaps, the Company receives a fixed price for its production and pays a variable market price to the contract counter-party. Under a basis differential swap, if the market price is above the fixed price the Company pays the counter-party, if the market price is below the fixed price, the counter-party pays the Company. The NYMEX-based fixed price derivative swaps and basis swaps contracts are indexed to NYMEX futures contracts, which are actively traded, for the underlying commodity and are commonly used in the energy industry. A number of financial institutions and large energy companies act as counter-parties to these type of derivative contracts. As the fair value of NYMEX-based fixed price swaps are based on a number of inputs, including contractual volumes and prices stated in each derivative contract, current and future NYMEX commodity prices, and quantitative models that are based upon readily observable market parameters that are actively quoted and can be validated through external sources, we have characterized these derivative contracts as Level 2. In order to verify the third party valuation, the Company enters the various inputs into a model and compares our results to the third party for reasonableness. The fair value of the collar and basis differential swap instruments are based on inputs that are not as observable as the fixed price swaps. In addition to the actively quoted market price, variables such as time value, volatility and other unobservable inputs are used. Accordingly, these instruments have been classified as Level 3. The following is additional information for the Company's recurring fair value measurements using significant unobservable inputs (Level 3 inputs) for the three months ended March 31, 2018 . Unobservable inputs at January 1, 2018 $ (16 ) Changes in market value — Settlements during the period 16 Unobservable inputs at March 31, 2018 $ — Nonrecurring Fair Value Measurements The Company follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a nonrecurring basis. As it relates to the Company, ASC 820-10 applies to certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value and the initial recognition of asset retirement obligations for which fair value is used. The asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of the Company’s asset retirement obligation is presented in Note 1. Other Financial Instruments The carrying amounts of the Company's 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. |
Contingencies and Contingencies
Contingencies and Contingencies | 3 Months Ended |
Mar. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments 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 March 31, 2018 , the Company was not involved in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on its financial position or results of operations. |
Acquisitions and Divestitures
Acquisitions and Divestitures | 3 Months Ended |
Mar. 31, 2018 | |
Business Combinations [Abstract] | |
Acquisitions and Divestitures | Acquisitions and Divestitures On February 28, 2018, the Company closed on the acquisition of 944 mineral acres in Winkler County, Texas. The purchase price for this acquisition was $14.3 million . This acquisition does not meet the criteria for a business acquisition and accordingly was accounted for as an asset acquisition. |
Basis of Presentation (Policies
Basis of Presentation (Policies) | 3 Months Ended |
Mar. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Reclassifications | Reclassifications Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations. |
Consolidation Principles | Consolidation Principles 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 | Rig Accounting In accordance with SEC Regulation S-X, no income is to be recognized in connection with contractual drilling services performed in connection with properties in which the Company or its affiliates hold an ownership, or other economic interest. Any income not recognized as a result of this limitation is to be credited to the full cost pool and recognized through lower amortization as reserves are produced. |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. |
Recently Accounting Standards and Disclosures | Recently Adopted Accounting Standards and Disclosures I n May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update, ("ASU") No. 2014-09, Revenue from Contracts with Customers . The Company completed a detailed analysis of its revenue streams at the individual contract level to evaluate the impact of the new revenue standard on its consolidated financial statements. Based on these completed assessments, adoption of this standard did not impact our net earnings. The Company adopted this new standard on January 1, 2018, using the modified retrospective method. No cumulative adjustment to retained earnings resulted from the adoption of this standard. See Note 2. "Impact of ASC 606 Adoption" and Note 3. "Revenue from Contracts with Customers" for further details related to the Company's adoption of this standard. Recent Accounting Standards and Disclosures Not Yet Adopted In February 2016, the FASB issued ASU 2016-02 “ Leases, " which supersedes ASC 840 “Leases ” and creates a new topic, ASC 842 "Leases." This update requires lessees to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. This update is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with earlier application permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are currently in the process of identifying our leases and evaluating the effect of this update on our consolidated financial statements and related disclosures. S |
Stock Options | Stock Options The Company currently utilizes a standard option-pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors. |
Restricted Stock Awards | 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 recipiant of the award terminates employment with the Company prior to the lapse of the restrictions. The fair value of such stock was determined using the closing price on the grant date and compensation expense is recorded over the applicable vesting periods. |
Oil and Gas properties | Oil and Gas Properties The Company follows the full cost method of accounting for oil and gas properties. Under this method, all direct costs and certain indirect costs associated with the 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% , plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. Costs in excess of the present value of estimated net revenue from proved reserves discounted at 10% are charged to proved property impairment expense. No gain or loss is recognized upon sale or disposition of oil and gas properties for full cost accounting companies with proceeds accounted for as an adjustment of capitalized cost. An exception to this rule occurs when the adjustment to the full cost pool results in a significant alteration of the relationship between capitalized cost and proved reserves. The Company applies the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. At March 31, 2018 and 2017, our net capitalized costs of oil and gas properties did not exceed the cost ceiling of our estimated proved reserves. |
Restoration, Removal and Environmental Liabilities | 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 require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a non-capital 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 is fixed or reliably determinable. The Company accounts for future site restoration obligations based on the guidance of ASC 410 which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. ASC 410 requires that the fair value of a liability for an asset's retirement obligation be 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 amortize these costs as a component of our depletion expense in the accompanying condensed consolidated financial statements. |
Basis of Presentation (Tables)
Basis of Presentation (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Stock Options Activity and Related Compensation Expense | The following table summarizes the Company’s stock-based compensation expense related to stock options for the periods presented: Three Months Ended 2018 2017 $ 339 $ 434 The following table summarizes the Company’s stock option activity for the three months ended March 31, 2018 (shares in thousands): Number of Shares (thousands) Weighted Average Option Exercise Price Per Share Weighted Average Grant Date Fair Value Per Share Outstanding, December 31, 2017 8,317 $ 2.35 $ 1.67 Granted — — — Exercised (21 ) $ 1.58 $ 1.12 Forfeited (78 ) $ 3.01 $ 2.12 Outstanding, March 31, 2018 8,218 2.34 2.17 |
Schedule of Unvested Restricted Stock Activity and Related Compensation Expense | The following table summarizes the Company’s restricted stock activity for the three months ended March 31, 2018 : Number of Shares (thousands) Weighted Average Grant Date Fair Value Per Share Unvested, December 31, 2017 1,479 $ 3.43 Granted — — Vested/Released (712 ) $ 3.15 Forfeited (20 ) $ 3.83 Unvested, March 31, 2018 747 $ 3.68 The following table summarizes the Company’s stock-based compensation expense related to restricted stock for the periods presented: Three Months Ended 2018 2017 $ 247 $ 336 |
Asset Retirement Obligations | The following table summarizes the Company’s future site restoration obligation transactions for the three months ended March 31, 2018 and the year ended December 31, 2017: March 31, 2018 December 31, 2017 Beginning future site restoration obligation $ 8,775 $ 8,623 New wells placed on production and other 357 1,088 Deletions related to property disposals and plugging costs (61 ) (1,551 ) Accretion expense 130 451 Revisions and other 24 164 Ending future site restoration obligation $ 9,225 $ 8,775 |
Revenue From Contracts With C19
Revenue From Contracts With Customers (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Revenue Recognition [Abstract] | |
Disaggregation of Revenue | Revenue attributable to each of those regions is disaggregated in the table below. Three Months Ended March 31, 2018 2017 Oil Gas NGL Oil Gas NGL Operating Regions: Permian/Delaware Basin $ 14,374 $ 920 $ 798 $ 2,488 $ 756 $ 389 Rocky Mountain $ 19,240 $ 1,127 $ 1,403 $ 11,397 $ 871 $ 894 South Texas $ 2,380 $ 330 $ 22 $ 1,617 $ 355 $ 20 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Debt Disclosure [Abstract] | |
Long-term Debt | The following is a description of the Company’s debt as of March 31, 2018 and December 31, 2017, respectively: March 31, 2018 December 31, 2017 Senior secured credit facility $ 104,000 $ 84,000 Real estate lien note 3,551 3,616 107,551 87,616 Less current maturities (264 ) (262 ) $ 107,287 $ 87,354 |
Earnings per Share (Tables)
Earnings per Share (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Earnings Per Share [Abstract] | |
Computation of Basic and Diluted Net Income (Loss) Per Share | The following table sets forth the computation of basic and diluted earnings per share: Three Months Ended March 31, 2018 2017 (In thousands, except per share data) Numerator: Net income $ 10,779 $ 13,690 Denominator: Denominator for basic earnings per share – weighted-average common shares outstanding 165,133 154,118 Effect of dilutive securities: Stock options and restricted shares 2,110 2,695 Denominator for diluted earnings per share – adjusted weighted-average shares and assumed exercise of options and restricted shares 167,243 156,813 Net income per common share - basic $ 0.07 $ 0.09 Net income per common share - diluted $ 0.06 $ 0.09 |
Hedging Program and Derivativ22
Hedging Program and Derivatives (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Contract Position | The following table sets forth the summary position of our derivative contracts as of March 31, 2018 : Oil - WTI Contract Periods Daily Volume (Bbl) Swap Price (per Bbl) Fixed Swaps 2018 April - December 4,426 $ 53.69 2019 January - December 2,800 $ 55.66 2020 January - December 2,200 $ 54.34 |
Impact of Derivative Contracts on Balance Sheet | The following table illustrates the impact of derivative contracts on the Company’s balance sheet: Fair Value of Derivative Contracts as of March 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 $ 7 Derivatives – current $ 14,221 Commodity price derivatives Derivatives – long-term 19 Derivatives – long-term 3,750 $ 26 $ 17,971 Fair Value of Derivative Contracts as of December 31, 2017 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 $ — Derivatives – current $ 10,837 Commodity price derivatives Derivatives – long-term — Derivatives – long-term 2,387 $ — $ 13,224 |
Financial Instruments (Tables)
Financial Instruments (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Assets and Liabilities Measured at Fair Value | The following tables sets forth information about the Company’s assets and liabilities measured at fair value on a recurring basis as of March 31, 2018 and December 31, 2017 , and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance as of March 31, 2018 Assets: NYMEX fixed price derivative contracts $ — $ 26 $ — $ 26 Total Assets $ — $ 26 $ — $ 26 Liabilities: NYMEX fixed price derivative contracts $ — $ 17,971 $ — $ 17,971 Total Liabilities $ — $ 17,971 $ — $ 17,971 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, 2017 Assets: NYMEX fixed price derivative contracts $ — $ — $ — $ — Total Assets $ — $ — $ — $ — Liabilities: NYMEX fixed price derivative contracts $ — $ 13,208 $ — $ 13,208 NYMEX basis differential swaps — — 16 16 Total Liabilities $ — $ 13,208 $ 16 $ 13,224 |
Schedule of Reciuring Fair Value Measurements Using Significant Unobservable Inputs | The following is additional information for the Company's recurring fair value measurements using significant unobservable inputs (Level 3 inputs) for the three months ended March 31, 2018 . Unobservable inputs at January 1, 2018 $ (16 ) Changes in market value — Settlements during the period 16 Unobservable inputs at March 31, 2018 $ — |
Basis of Presentation (Details)
Basis of Presentation (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2017 | |
Share-Based Payments | |||
Stock-based compensation expense | $ 586 | $ 770 | |
Weighted Average Grant Date Fair Value Per Share (in US$ per share) | |||
Discount rate used in future net cash flows relating to proved oil and gas reserves (percent) | 10.00% | ||
Entity's asset retirement obligation transactions [Roll Forward] | |||
Beginning future site restoration obligation | $ 8,775 | 8,623 | $ 8,623 |
New wells placed on production and other | 357 | 1,088 | |
Deletions related to property disposals and plugging costs | (61) | (1,551) | |
Accretion expense | 130 | 112 | 451 |
Revisions and other | 24 | 164 | |
Ending future site restoration obligation | 9,225 | $ 8,775 | |
Employee Stock Option [Member] | |||
Share-Based Payments | |||
Stock-based compensation expense | 339 | 434 | |
Unamortized compensation cost expected to be recognized in 2016 through 2020 | $ 1,300 | ||
Number of Shares (thousands) | |||
Outstanding, December 31, 2017 | 8,317 | ||
Granted | 0 | ||
Exercised | (21) | ||
Cancelled | (78) | ||
Outstanding, March 31, 2018 | 8,218 | 8,317 | |
Weighted Average Option Exercise Price Per Share | |||
Outstanding, December 31, 2017 | $ 2.35 | ||
Granted | 0 | ||
Exercised | 1.58 | ||
Forfeited | 3.01 | ||
Outstanding, March 31, 2018 | 2.34 | $ 2.35 | |
Weighted Average Grant Date Fair Value Per Share | |||
Outstanding, December 31, 2017 | 1.67 | ||
Granted | 0 | ||
Exercised | 1.12 | ||
Cancelled | 2.12 | ||
Outstanding, March 31, 2018 | $ 2.17 | $ 1.67 | |
Restricted Stock [Member] | |||
Share-Based Payments | |||
Stock-based compensation expense | $ 247 | $ 336 | |
Unamortized compensation cost expected to be recognized in 2016 through 2020 | $ 400 | ||
Number of Shares (thousands) | |||
Unvested, December 31, 2017 | 1,479 | ||
Granted | 0 | ||
Vested/Released | (712) | ||
Forfeited | (20) | ||
Unvested, March 31, 2018 | 747 | 1,479 | |
Weighted Average Grant Date Fair Value Per Share (in US$ per share) | |||
Unvested, December 31, 2017 | $ 3.43 | ||
Granted | 0 | ||
Vested/Released | 3.15 | ||
Forfeited | 3.83 | ||
Unvested, March 31, 2018 | $ 3.68 | $ 3.43 | |
Gas and Natural Gas Liquid Sales [Member] | Product Concentration Risk [Member] | Sales Revenue, Net [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Percentage of total revenue (percent) | 15.00% |
Income Taxes (Details)
Income Taxes (Details) - USD ($) | 3 Months Ended | ||
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |||
Income tax (expense) benefit | $ 0 | $ 0 | |
Net operating loss carryforward | $ 255,000,000 | ||
Deferred tax asset valuation allowance | $ 80,400,000 | ||
Accrued interest or penalties related to uncertain tax positions | $ 0 |
Revenue From Contracts With C26
Revenue From Contracts With Customers (Details) - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2017 | |
Revenue, Major Customer [Line Items] | |||
Oil and gas production revenues | $ 40,594 | $ 18,787 | |
Receivables from contract with customers | 17,873 | $ 17,789 | |
Natural Gas Liquids [Member] | |||
Revenue, Major Customer [Line Items] | |||
Oil and gas production revenues | 2,223 | 1,303 | |
Oil [Member] | |||
Revenue, Major Customer [Line Items] | |||
Oil and gas production revenues | 35,994 | 15,502 | |
Natural Gas [Member] | |||
Revenue, Major Customer [Line Items] | |||
Oil and gas production revenues | 2,377 | 1,982 | |
Permian / Delaware Basin [Member] | Natural Gas Liquids [Member] | |||
Revenue, Major Customer [Line Items] | |||
Oil and gas production revenues | 798 | 389 | |
Permian / Delaware Basin [Member] | Oil [Member] | |||
Revenue, Major Customer [Line Items] | |||
Oil and gas production revenues | 14,374 | 2,488 | |
Permian / Delaware Basin [Member] | Natural Gas [Member] | |||
Revenue, Major Customer [Line Items] | |||
Oil and gas production revenues | 920 | 756 | |
Rocky Mountain [Member] | Natural Gas Liquids [Member] | |||
Revenue, Major Customer [Line Items] | |||
Oil and gas production revenues | 1,403 | 894 | |
Rocky Mountain [Member] | Oil [Member] | |||
Revenue, Major Customer [Line Items] | |||
Oil and gas production revenues | 19,240 | 11,397 | |
Rocky Mountain [Member] | Natural Gas [Member] | |||
Revenue, Major Customer [Line Items] | |||
Oil and gas production revenues | 1,127 | 871 | |
South Texas [Member] | Natural Gas Liquids [Member] | |||
Revenue, Major Customer [Line Items] | |||
Oil and gas production revenues | 22 | 20 | |
South Texas [Member] | Oil [Member] | |||
Revenue, Major Customer [Line Items] | |||
Oil and gas production revenues | 2,380 | 1,617 | |
South Texas [Member] | Natural Gas [Member] | |||
Revenue, Major Customer [Line Items] | |||
Oil and gas production revenues | $ 330 | $ 355 |
Long-Term Debt (Details)
Long-Term Debt (Details) | Apr. 01, 2016USD ($) | Mar. 31, 2018USD ($)report | Dec. 31, 2017USD ($) |
Long-term debt [Abstract] | |||
Long-term debt | $ 107,551,000 | $ 87,616,000 | |
Less current maturities | (264,000) | (262,000) | |
Long-term debt – less current maturities | 107,287,000 | 87,354,000 | |
Credit Facility [Abstract] | |||
Maximum borrowing capacity | 300,000,000 | ||
Current borrowing base | $ 175,000,000 | ||
Number of reserve reports prepared by independent petroleum engineers | report | 1 | ||
Number of reserve report prepared internally | report | 1 | ||
Financial Covenants, Minimum Current Ratio | 1 | ||
Financial covenants, interest coverage ratio | 2.5 | ||
Financial covenants, total debt To EBITDAX ratio | 3.5 | ||
Extraordinary expenses that can be included in determining EBITDAX | $ 1,000,000 | ||
Interest Coverage Ratio | 21.12 | ||
Total debt to ebitdax ratio | 1.50 | ||
Current Ratio | 2.57 | ||
Line of Credit, Covenant, Cash and Liquid Investments Triggering Credit Repayment | $ 10,000,000 | ||
Senior Secured Credit Facility [Member] | |||
Long-term debt [Abstract] | |||
Long-term debt | $ 104,000,000 | 84,000,000 | |
Credit Facility [Abstract] | |||
Market value of property (in hundredths) | 5.00% | ||
Reduced collateral value (in hundredths) | 5.00% | ||
Percentage added to variable rate (in hundredths) | 0.50% | ||
Interest rate on credit facility (in hundredths) | 4.85% | ||
Line of Credit, Minimum Default Interest Rate | 3.00% | ||
Senior Secured Credit Facility [Member] | Minimum [Member] | |||
Credit Facility [Abstract] | |||
Percentage added to reference rate (in hundredths) | 1.50% | ||
Percentage added to variable rate (in hundredths) | 2.50% | ||
Senior Secured Credit Facility [Member] | Maximum [Member] | |||
Credit Facility [Abstract] | |||
Percentage added to reference rate (in hundredths) | 2.50% | ||
Percentage added to variable rate (in hundredths) | 3.50% | ||
Real Estate Lien Note [Member] | |||
Long-term debt [Abstract] | |||
Long-term debt | $ 3,551,000 | $ 3,616,000 | |
Credit Facility [Abstract] | |||
Maturity date of debt instrument | Jul. 20, 2023 | ||
Real Estate Lien Note [Abstract] | |||
Fixed interest rate on note (in hundredths) | 4.25% | ||
Monthly installments of principal and interest | $ 34,354 | ||
Interest rate adjustment over prime (in hundredths) | 1.00% | ||
Real Estate Lien Note [Member] | Maximum [Member] | |||
Real Estate Lien Note [Abstract] | |||
Interest rate adjustment over prime (in hundredths) | 7.25% |
Earnings per Share (Details)
Earnings per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Numerator [Abstract] | ||
Net income | $ 10,779 | $ 13,690 |
Denominator [Abstract] | ||
Denominator for basic earnings per share – weighted-average common shares outstanding (shares) | 165,133 | 154,118 |
Effect of dilutive securities: Stock options and restricted shares (shares) | 2,110 | 2,695 |
Dilutive potential common shares [Abstract] | ||
Denominator for diluted earnings per share - adjusted weighted-average shares and assumed exercise of options, restricted shares and warrants (in shares) | 167,243 | 156,813 |
Earnings Per Share, Basic [Abstract] | ||
Net income per common share - basic (in usd per share | $ 0.07 | $ 0.09 |
Earnings Per Share, Diluted [Abstract] | ||
Net income per common share - diluted (in usd per share) | $ 0.06 | $ 0.09 |
Hedging Program and Derivativ29
Hedging Program and Derivatives (Details) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018USD ($)bbl$ / bbl | Dec. 31, 2017USD ($) | |
Impact of derivative contracts on balance sheet [Abstract] | ||
Derivative asset - current | $ 7 | $ 0 |
Derivative asset - long-term | 19 | 0 |
Derivative Assets | 26 | 0 |
Derivative liability - current | 14,221 | 10,837 |
Derivative liability - long-term | 3,750 | 2,387 |
Derivative Liabilities | $ 17,971 | 13,224 |
Fixed Swap [Member] | Oil - WTI [Member] | 2018 April - December | ||
Oil and Gas Delivery Commitments and Contracts [Line Items] | ||
Daily Volume (Bbl) | bbl | 4,426 | |
Fixed price swap price | $ / bbl | 53.69 | |
Fixed Swap [Member] | Oil - WTI [Member] | 2019 January - December | ||
Oil and Gas Delivery Commitments and Contracts [Line Items] | ||
Daily Volume (Bbl) | bbl | 2,800 | |
Fixed price swap price | $ / bbl | 55.66 | |
Fixed Swap [Member] | Oil - WTI [Member] | 2019 | ||
Oil and Gas Delivery Commitments and Contracts [Line Items] | ||
Daily Volume (Bbl) | bbl | 2,200 | |
Fixed price swap price | $ / bbl | 54.34 | |
Commodity Price Derivatives [Member] | Derivative Asset - Current [Member] | ||
Impact of derivative contracts on balance sheet [Abstract] | ||
Derivative asset - current | $ 7 | 0 |
Commodity Price Derivatives [Member] | Derivative Asset - Long-Term [Member] | ||
Impact of derivative contracts on balance sheet [Abstract] | ||
Derivative asset - long-term | 19 | 0 |
Commodity Price Derivatives [Member] | Derivative Liability - Current [Member] | ||
Impact of derivative contracts on balance sheet [Abstract] | ||
Derivative liability - current | 14,221 | 10,837 |
Commodity Price Derivatives [Member] | Derivative Liability - Long-Term [Member] | ||
Impact of derivative contracts on balance sheet [Abstract] | ||
Derivative liability - long-term | $ 3,750 | $ 2,387 |
Financial Instruments (Details)
Financial Instruments (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Dec. 31, 2017 | |
Assets [Abstract] | ||
NYMEX Fixed Price Derivative contracts | $ 26 | $ 0 |
Liabilities [Abstract] | ||
NYMEX Fixed Price Derivative contracts | 17,971 | 13,224 |
Significant Unobservable Inputs (Level 3) [Member] | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | ||
Unobservable inputs at January 1, 2018 | (16) | |
Changes in market value | 0 | |
Settlements during the period | 16 | |
Unobservable inputs at March 31, 2018 | 0 | |
Recurring Basis [Member] | ||
Assets [Abstract] | ||
Total Assets | 26 | 0 |
Liabilities [Abstract] | ||
Total Liabilities | 17,971 | 13,224 |
Recurring Basis [Member] | Fixed Price Derivative Contracts [Member] | ||
Assets [Abstract] | ||
NYMEX Fixed Price Derivative contracts | 26 | 0 |
Liabilities [Abstract] | ||
NYMEX Fixed Price Derivative contracts | 17,971 | 13,208 |
Recurring Basis [Member] | Collars [Member] | ||
Liabilities [Abstract] | ||
NYMEX Fixed Price Derivative contracts | 16 | |
Recurring Basis [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | ||
Assets [Abstract] | ||
Total Assets | 0 | 0 |
Liabilities [Abstract] | ||
Total Liabilities | 0 | 0 |
Recurring Basis [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Fixed Price Derivative Contracts [Member] | ||
Assets [Abstract] | ||
NYMEX Fixed Price Derivative contracts | 0 | 0 |
Liabilities [Abstract] | ||
NYMEX Fixed Price Derivative contracts | 0 | 0 |
Recurring Basis [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Collars [Member] | ||
Liabilities [Abstract] | ||
NYMEX Fixed Price Derivative contracts | 0 | |
Recurring Basis [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Assets [Abstract] | ||
Total Assets | 26 | 0 |
Liabilities [Abstract] | ||
Total Liabilities | 17,971 | 13,208 |
Recurring Basis [Member] | Significant Other Observable Inputs (Level 2) [Member] | Fixed Price Derivative Contracts [Member] | ||
Assets [Abstract] | ||
NYMEX Fixed Price Derivative contracts | 26 | 0 |
Liabilities [Abstract] | ||
NYMEX Fixed Price Derivative contracts | 17,971 | 13,208 |
Recurring Basis [Member] | Significant Other Observable Inputs (Level 2) [Member] | Collars [Member] | ||
Liabilities [Abstract] | ||
NYMEX Fixed Price Derivative contracts | 0 | |
Recurring Basis [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||
Assets [Abstract] | ||
Total Assets | 0 | 0 |
Liabilities [Abstract] | ||
Total Liabilities | 0 | 16 |
Recurring Basis [Member] | Significant Unobservable Inputs (Level 3) [Member] | Fixed Price Derivative Contracts [Member] | ||
Assets [Abstract] | ||
NYMEX Fixed Price Derivative contracts | 0 | 0 |
Liabilities [Abstract] | ||
NYMEX Fixed Price Derivative contracts | $ 0 | 0 |
Recurring Basis [Member] | Significant Unobservable Inputs (Level 3) [Member] | Collars [Member] | ||
Liabilities [Abstract] | ||
NYMEX Fixed Price Derivative contracts | $ 16 |
Acquisitions and Divestitures -
Acquisitions and Divestitures - Narrative (Details) - Property in Winkler County, Texas [Member] $ in Millions | Feb. 28, 2018USD ($)a |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |
Net mineral acres acquired | a | 944 |
Closing purchase price of acquired oil and gas properties | $ | $ 14.3 |