Document And Entity Information
Document And Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Mar. 17, 2017 | Jun. 30, 2016 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2016 | ||
Trading Symbol | LONE | ||
Document Fiscal Year Focus | 2,016 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | Lonestar Resources US Inc. | ||
Entity Central Index Key | 1,661,920 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Smaller Reporting Company | ||
Entity Public Float | $ 30 | ||
Entity Common Stock, Shares Outstanding | 21,822,015 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Current assets | ||
Cash and cash equivalents | $ 6,068 | $ 4,322 |
Accounts receivable: | ||
Oil, natural gas liquid and natural gas sales | 4,680 | 5,043 |
Joint interest owners and other, net | 867 | 1,305 |
Related parties | 847 | 279 |
Derivative financial instruments | 1,730 | 33,219 |
Prepaid expenses and other | 2,631 | 724 |
Total current assets | 16,823 | 44,892 |
Oil and gas properties, net, using the successful efforts method of accounting | 439,228 | 488,100 |
Other property and equipment, net | 1,421 | 2,223 |
Derivative financial instruments | 2,864 | |
Other noncurrent assets | 1,561 | 1,580 |
Restricted certificates of deposit | 76 | 77 |
Total assets | 459,109 | 539,736 |
Current liabilities | ||
Accounts payable | 14,894 | 18,027 |
Accounts payable – related parties | 1,135 | 45 |
Oil, natural gas liquid and natural gas sales payable | 3,568 | 3,870 |
Accrued liabilities | 9,947 | 8,276 |
Accrued liabilities – related parties | 224 | 125 |
Derivative financial instruments | 2,985 | |
Total current liabilities | 32,753 | 30,343 |
Long-term debt | 204,122 | 301,926 |
Long-term debt - related parties | 3,400 | |
Deferred tax liability | 38,020 | 16,013 |
Other non-current liabilities | 6,052 | 1,000 |
Equity warrant liability | 1,565 | |
Equity warrant liability - related parties | 2,994 | |
Asset retirement obligations | 2,683 | 7,488 |
Derivative financial instruments | 1,125 | |
Total liabilities | 292,714 | 356,770 |
Commitments and contingencies | ||
Stockholders’ equity | ||
Additional paid-in capital | 87,260 | 10,270 |
Accumulated other comprehensive loss | (760) | |
Retained (deficit) earnings | (63,517) | 30,818 |
Total stockholders’ equity | 166,395 | 182,966 |
Total liabilities and stockholders’ equity | 459,109 | 539,736 |
Class A Voting Common Stock | ||
Stockholders’ equity | ||
Common stock | $ 142,652 | $ 142,638 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2016 | Dec. 31, 2015 |
Class A Voting Common Stock | ||
Common stock, par value | $ 0.001 | $ 0.001 |
Common stock, shares authorized | 100,000,000 | 100,000,000 |
Common stock, shares issued | 21,822,015 | 7,521,788 |
Common stock, shares outstanding | 21,822,015 | 7,521,788 |
Class B Non-Voting Common Stock | ||
Common stock, par value | $ 0.001 | $ 0.001 |
Common stock, shares authorized | 5,000 | 5,000 |
Common stock, shares issued | 2,500 | 0 |
Common stock, shares outstanding | 2,500 | 0 |
Consolidated Statements of Oper
Consolidated Statements of Operations & Comprehensive Loss - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Revenues | ||
Oil sales | $ 46,954,000 | $ 70,739,000 |
Natural gas sales | 7,165,000 | 6,823,000 |
Natural gas liquid sales | 3,853,000 | 1,928,000 |
Total revenues | 57,972,000 | 79,490,000 |
Costs and expenses | ||
Lease operating and gas gathering | 16,232,000 | 17,190,000 |
Production, ad valorem, and severance taxes | 3,287,000 | 4,982,000 |
Rig standby expense | 2,261,000 | 663,000 |
Depletion, depreciation, and amortization | 46,888,000 | 58,828,000 |
Accretion of asset retirement obligations | 180,000 | 214,000 |
Gain on sale of oil and gas properties | (74,000) | |
Impairment of oil and gas properties | 33,893,000 | 28,623,000 |
Stock-based compensation | 448,000 | 2,585,000 |
General and administrative | 11,319,000 | 10,825,000 |
Other expense | 1,261,000 | |
Total costs and expenses | 115,695,000 | 123,910,000 |
Loss from operations | (57,723,000) | (44,420,000) |
Other income (expense) | ||
Interest expense | (29,583,000) | (24,577,000) |
Gain on redemption of bonds | 28,480,000 | |
Unrealized gain on warrants | 568,000 | |
(Loss) gain on derivative financial instruments | (8,672,000) | 27,609,000 |
Other expense | (1,066,000) | |
Total other income (expense), net | (9,207,000) | 1,966,000 |
Loss before income taxes | (66,930,000) | (42,454,000) |
Income tax (expense) benefit | (27,405,000) | 15,121,000 |
Net loss | $ (94,335,000) | $ (27,333,000) |
Net loss common share-basic and diluted | $ (11.64) | $ (3.63) |
Weighted average common shares outstanding–basic and diluted | 8,106,931 | 7,521,788 |
Other comprehensive (loss) income: | ||
Net loss | $ (94,335,000) | $ (27,333,000) |
Foreign currency translation adjustments | 12,000 | |
Comprehensive loss | $ (94,335,000) | $ (27,321,000) |
Consolidated Statements of Chan
Consolidated Statements of Changes in Stockholders' Equity - USD ($) $ in Thousands | Total | Class A Voting Common Stock | Common StockClass A Voting Common Stock | Additional Paid-in Capital | Retained Earnings | Accumulated other comprehensive loss |
Beginning balance, after reverse stock splits at Dec. 31, 2014 | $ 207,702 | $ 142,638 | $ 7,685 | $ 58,151 | $ (772) | |
Beginning balance, after reverse stock splits (in shares) at Dec. 31, 2014 | 7,521,788 | |||||
Stock-based compensation | 2,585 | 2,585 | ||||
Foreign currency translation | 12 | 12 | ||||
Net loss | (27,333) | (27,333) | ||||
Ending balance at Dec. 31, 2015 | 182,966 | $ 142,638 | 10,270 | 30,818 | (760) | |
Ending balance (in shares) at Dec. 31, 2015 | 7,521,788 | 7,521,788 | ||||
Sale of common stock, net of offering costs | 71,817 | $ 14 | 71,803 | |||
Sale of common stock, net of offering costs (in shares) | 13,800,000 | |||||
Shares issued for asset acquisition | 5,499 | 5,499 | ||||
Shares issued for asset acquisition (in shares) | 500,227 | |||||
Stock-based compensation | 448 | 448 | ||||
Foreign currency translation | (760) | $ 760 | ||||
Net loss | (94,335) | (94,335) | ||||
Ending balance at Dec. 31, 2016 | $ 166,395 | $ 142,652 | $ 87,260 | $ (63,517) | ||
Ending balance (in shares) at Dec. 31, 2016 | 21,822,015 | 21,822,015 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Operating activities | ||
Net loss | $ (94,335) | $ (27,333) |
Adjustments to reconcile net loss to net cash provided by operating activities: | ||
Loss on disposal of oil and gas properties | 35 | 629 |
Accretion of asset retirement obligations | 180 | 214 |
Depletion, depreciation, and amortization | 46,888 | 58,828 |
Stock-based compensation | 448 | 2,585 |
Deferred taxes | 27,059 | (15,497) |
Loss (gain) on derivative financial instruments | 8,672 | (27,609) |
Settlements of derivative financial instruments | 29,790 | 35,284 |
Gain on redemption of bonds | (28,480) | |
Impairment of oil and gas properties | 33,893 | 28,623 |
Non-cash interest expense | 7,581 | 1,100 |
Unrealized gain on warrants | (568) | |
Changes in operating assets and liabilities: | ||
Accounts receivable | 234 | 10,857 |
Prepaid expenses and other assets | (1,856) | 223 |
Accounts payable and accrued expenses | (5,272) | (17,065) |
Net cash provided by operating activities | 24,269 | 50,839 |
Investing activities | ||
Acquisition of oil and gas properties | (4,340) | (8,723) |
Development of oil and gas properties | (39,382) | (85,458) |
Proceeds from sales of oil and gas properties | 16,174 | |
Purchases of other property and equipment | (233) | (337) |
Net cash used in investing activities | (27,781) | (94,518) |
Financing activities | ||
Proceeds from borrowings and related party borrowings | 72,063 | 140,514 |
Payments on borrowings and related party borrowings | (134,697) | (102,514) |
Proceeds from sale of common stock, net of offering costs | 72,807 | |
Payments of debt issuance\settlement costs | (4,912) | |
Payments on other notes payable | (3) | (3) |
Net cash provided by financing activities | 5,258 | 37,997 |
Effect of exchange rate changes on cash and cash equivalents | 12 | |
Increase (decrease) in cash and cash equivalents | 1,746 | (5,670) |
Cash and cash equivalents, beginning of the period | 4,322 | 9,992 |
Cash and cash equivalents, end of the period | $ 6,068 | $ 4,322 |
Nature of Business and Presenta
Nature of Business and Presentation | 12 Months Ended |
Dec. 31, 2016 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Nature of Business and Presentation | 1. Nature of Business and Presentation Lonestar Resources US Inc. (the “Successor”) was incorporated in Delaware in December 2015 for purposes of effecting our corporate reorganization, which was completed on July 5, 2016 (the “Reorganization”), pursuant to a Scheme Implementation Agreement (the “Scheme”), dated December 28, 2015, between the Successor and Lonestar Resources Limited (the “Predecessor”), an Australian company. Prior to the Reorganization, our business was owned and operated under our Predecessor, whose ordinary shares were listed on the Australian Securities Exchange (“ASX”). Pursuant to the Scheme, the Successor acquired all of the issued and outstanding ordinary shares of our Predecessor, and each of our Predecessor’s shareholders received one share of our Class A voting common stock (“Class A common stock”) for every two ordinary shares of our Predecessor such shareholder held. Prior to the Reorganization, the Successor had no business or operations, and following the Reorganization, the business and the operations of the Successor consist solely of the business and operations of the subsidiaries of the Predecessor. The reorganization was treated as a transaction among parties under common control and no gain or loss was recorded. Lonestar Resources America, Inc. (“LRAI”) is a Delaware registered U.S. holding company formed on January 31, 2013, which is engaged in the exploration, development, production, acquisition, and sale of oil, natural gas liquid (“NGL”) and natural gas primarily in the Eagle Ford Shale Play in South Texas, Conventional properties in North Texas and Bakken properties in Montana through its wholly owned subsidiaries, Lonestar Resources, Inc. and Amadeus Petroleum, Inc. Its executive offices are located in Fort Worth, Texas. LRAI was a wholly owned subsidiary of the Predecessor, prior to the reorganization described below. The majority of the activities of the Predecessor was carried out through LRAI. Unless the context otherwise requires, references to “Lonestar,” “we,” “us,” “our,” and “the Company” refer to (i) Lonestar Resources Limited and its subsidiaries prior to the Reorganization and (ii) Lonestar Resources US Inc. and its subsidiaries upon completion of the Reorganization, as applicable. Basis of Accounting The accounts are maintained and the consolidated financial statements have been prepared using the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). Use of Estimates The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect certain reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from these estimates and assumptions. Reserve estimates are inexact and may change as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production and timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Accordingly, there can be no assurance that ultimately, the reserves will be produced, nor can there be assurance that the proved undeveloped reserves will be developed within the period anticipated. Principles of Consolidation The accompanying consolidated financial statements include the accounts of the Company’s wholly owned subsidiaries: Lonestar Resources America, Inc. (“LRAI”), Lonestar Resources, Inc. (“LRI”), Lonestar Resources Intermediate, Inc. (“LRII”) LNR America, Inc. (“LNRA”), Barnett Gas, LLC (“Barnett Gas”), Eagleford Gas, LLC (“Eagleford Gas”), Poplar Energy, LLC (“Poplar”), Eagleford Gas 2, LLC (“Eagleford Gas 2”), Eagleford Gas 3, LLC (“Eagleford Gas 3”), Eagleford Gas 4, LLC (“Eagleford Gas 4”), Eagleford Gas 5, LLC (“Eagleford Gas 5”), Eagleford Gas 6, LLC (“Eagleford Gas 6”), Eagleford Gas 7, LLC (“Eagleford Gas 7”), Eagleford Gas 8, LLC (“Eagleford Gas 8”), Eagleford Gas 9, LLC (“Eagleford Gas 9”) Lonestar Operating, LLC (“LNO”), Lonestar BR Disposal, LLC (“LBRD”) La Salle Eagle Ford Gathering Line, LLC (“LSGL”) Amadeus Petroleum, Inc. (“API”), T-N-T Engineering, Inc. (“TNT”) and Albany Services, LLC (“Albany”). All significant intercompany balances and transactions have been eliminated in consolidation. Reclassifications Certain prior year amounts which were determined to be immaterial have been reclassified to conform to current year presentation, with no effect on the previously reported results of operations. Cash Equivalents The Company considers all highly liquid investments with original maturities of three months or less when purchased to be cash equivalents. Concentrations and Credit Risk The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents and accounts receivable. The Company places its cash and cash equivalents with reputable financial institutions. At times, the balances deposited may exceed amounts covered by insurance provided by the U.S. Federal Deposit Insurance Corporation (“FDIC”). The Company has not incurred any losses related to amounts in excess of FDIC limits. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, NGL and natural gas or working interest partners in oil and natural gas wells for which a subsidiary of the Company serves as the operator. Generally, operators of oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. The Company’s receivables are generally unsecured. The Company has experienced no material credit losses since its inception, however, an allowance for uncollectible amounts of approximately $196,000 was recorded at December 31, 2016, relating to receivables from joint interest owners of our conventional properties that were sold in the second half of 2016. Oil, NGL and natural gas revenues from Shell Trading (US) Company, Texla Energy Management, Inc., Trafigura AG, and BP Products North America LLC for the year ended December 31, 2016, represented 40%, 21%, 18% and 10%, respectively, of total revenues. Oil, NGL and natural gas revenues from Trafigura AG, BP Products North America LLC, Shell Trading (US) Company and Texla Energy Management, Inc. for the year ended December 31, 2015, represented 38%, 20%, 16% and 11%, respectively, of total revenues. Accounts receivable relating to oil, NGL and natural gas sales from Shell Trading, Trafigura AG and Texla Energy Management, Inc. represented 49%, 30% and 13%, respectively, of total receivables at December 31, 2016. Accounts receivable relating to oil, NGL and natural gas sales from Shell Trading, Trafigura AG and Texla Energy Management, Inc. represented 26%, 25% and 23%, respectively, of total receivables at December 31, 2015. Prepaid Expenses Prepaid expenses generally relate to prepaid drilling and completion costs that will be capitalized into oil and gas properties. Oil and Natural Gas Properties The Company uses the successful efforts method of accounting to account for its oil and gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The Company’s policy is to expense the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred, whether productive or nonproductive. Capitalized costs attributed to the proved properties are subject to depreciation and depletion. Depreciation and depletion of the cost of oil and gas properties is calculated using the units-of-production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For development costs, the reserve base used to calculate depletion and depreciation is proved developed reserves only. Unproved properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as an impairment of oil and gas properties in the consolidated statement of operations, as applicable. Unproved oil and gas property costs are transferred to proven oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, future plans to develop acreage, and other relevant factors. On the sale or retirement of a complete or partial unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and any gain or loss is recognized. Other Property and Equipment Other property and equipment, consisting primarily of office, transportation and computer equipment, is carried at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 5 years. Major renewals and improvements are capitalized, while expenditures for maintenance and repairs are expensed as incurred. Upon sale or abandonment, the cost of the equipment and related accumulated depreciation are removed from the accounts, and any gain or loss is recognized. Impairment of Long-Lived Assets The carrying value of the oil and gas properties and other related property and equipment is periodically evaluated under the provisions of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 360, Property, Plant, and Equipment Under ASC 360, the Company evaluates impairment of proved and unproved oil and gas properties on an area basis. On this basis, certain fields may be impaired because they are not expected to recover their entire carrying value from future net cash flows. As a result of this evaluation, the Company recorded impairment of unproved oil and gas properties of approximately $4.8 million and $8.9 million for the years ended December 31, 2016 and 2015, respectively, and impairment of proven oil and gas properties of $29.1 million and $19.7 million for the years ended December 31, 2016 and 2015, respectively. If pricing declines, it is reasonably likely that the Company may have to record impairment of its oil and gas properties subsequent to December 31, 2016. Asset Retirement Obligations The Company accounts for asset retirement obligations under ASC 410, Asset Retirement and Environmental Obligations Revenue Recognition Oil, NGL and natural gas revenues are recognized when title to the product transfers to the purchaser. The Company follows the sales method of accounting for its crude oil, NGL and natural gas revenue, whereby revenue is recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. There were no imbalances at December 31, 2016 or 2015. Fair Value of Financial Instruments In accordance with the reporting requirements of ASC 825, Financial Instruments Income Taxes The Company follows the asset and liability method in accounting for income taxes in accordance with ASC 740, Income Taxes Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which these temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. The Company periodically evaluates the realizable tax benefits of deferred tax assets and records a valuation allowance, if required, based on an estimate of the amount of deferred tax assets the Company believes does not meet the more likely than not criteria of being realized. In certain circumstances, the deferred tax asset may exceed the amount permissible to be used under the tax law, for example, a net operating loss carryforward. In such cases it is appropriate to write-off the excess net operating loss. At December 31, 2016, the Company wrote off $141.7 million of its net operating loss carryforward. The Company evaluates uncertain tax positions, which requires significant judgments and estimates regarding the recoverability of deferred tax assets, the likelihood of the outcome of examinations of tax positions that may or may not be currently under review, and potential scenarios involving settlements of such matters. Changes in these estimates could materially impact the consolidated financial statements. No liability for material uncertain tax positions existed as of December 31, 2016 or 2015. Share-Based Payments The Company accounts for equity-based awards in accordance with ASC 718, Compensation-Stock Compensation |
Recently Issued Accounting Pron
Recently Issued Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Changes And Error Corrections [Abstract] | |
Recently Issued Accounting Pronouncements | 2. Recently Issued Accounting Pronouncements In January 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2017-01, "Business Combinations (Topic 805): Clarifying the Definition of a Business" in order to clarify the definition of a business as it relates to whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public entities, this ASU is effective for annual periods beginning after December 15, 2017, and interim periods within those years and early adoption is permitted under certain circumstances. We expect to adopt this guidance in the first quarter of 2018. The impact is not expected to be material. In November 2016, the FASB issued ASU 2016-18, "Statement of Cash Flows (Topic 230): Restricted Cash" require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. For public entities, this ASU is effective for annual periods beginning after December 15, 2017, and interim periods within those years and early adoption is permitted under certain circumstances. We expect to adopt this guidance in the first quarter of 2018. Management is evaluating the provisions of this accounting standards update but considers it to have minimal impact on our consolidated statements of cash flows given the immaterial amount of restricted cash on our balance sheet. In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)" in order, to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The update addresses eight different transaction types and clarifies how to classify each in the statement of cash flows, where previously there was unclear or no specific guidance. For public entities, this ASU is effective for annual periods beginning after December 15, 2017, and interim periods within those years and early adoption is permitted in the year prior to the effective date. We expect to adopt this guidance in the first quarter of 2018. Management is evaluating the provisions of this accounting standards update and assessing the impact it may have on our consolidated statements of cash flows and related disclosures. In June 2016, the FASB issued ASU 2016-13, "Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments", which introduces new guidance for estimating credit losses on certain types of financial instruments based on expected losses and the timing of the recognition of such losses. For public entities, this ASU is effective for annual periods beginning after December 15, 2019, and interim periods within those years and early adoption is permitted in the year prior to the effective date. We expect to adopt this guidance in the first quarter of 2020. Management is evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows. In March 2016, the FASB issued ASU No. 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting” (“Update 2016-09”), which seeks to simplify several aspects of the accounting for share-based payment award transactions, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. For public entities, Update 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We will adopt this standard during the first quarter of 2017; we do not believe it will have a material effect on our consolidated results of operations, financial position or cash flows. In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842)” which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases. This ASU is effective for the annual period ending after December 15, 2018, and for annual interim periods thereafter. Early adoption is permitted. Management is currently evaluating the new guidance to determine the impact it will have on our consolidated results of operations, financial position or cash flows and anticipates adopting the guidance on the effective date of January 1, 2018. In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes” to simplify income tax accounting. The update requires that all deferred tax assets and liabilities be classified as noncurrent on the balance sheet instead of separating deferred taxes into current and noncurrent amounts. This update is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and may be adopted earlier on a voluntary basis. Effective January 1, 2016, the Company early adopted ASU 2015-17 which was applied prospectively and therefore the adoption had no impact on the consolidated balance sheet as of December 31, 2015. In April 2015, the FASB issued ASU No. 2015-03, “Interest-Imputation of Interest (Subtopic 835-30): Simplifiying the Presentation of Debt Issuance Costs”. The updated guidance requires debt issuance costs related to a recognized debt liability, other than those costs related to line of credit arrangements, be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, similar to the presentation for debt discounts and premiums, instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. This guidance became effective for the Company as of January 1, 2016. The Company’s adoption of this guidance was applied retrospectively, and approximately $1.8 million was moved from assets to a direct deduction from the carrying amount of the debt on the Company’s consolidated financial statements. In May 2014, August 2015 and May 2016, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers” , ASU 2015-14, “Revenue from Contracts with Customers, Deferral of the Effective Date”, ASU 2016-12, “Revenue from Contracts with Customers, Narrow-Scope Improvements and Practical Expedients”, and ASU 2016-20, “Revenue from Contracts with Customers, Technical Corrections and Improvements”, respectively, as a new Topic, Accounting Standards Codification Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. It also requires entities to disclose both quantitative and qualitative information that enable financial statements users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. This guidance is effective for annual periods beginning after December 15, 2017 with early adoption permitted on January 1, 2017 and shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. As we are in the process of evaluating the impact of the standard, we have not yet quantified the impact of adoption or determined the method of adoption. During 2017, we will perform the remainder of our implementation process, which will include quantification of impact, selection of adoption method and development of policies. The Company plans to adopt this guidance in the first quarter of 2018. |
Acquisitions and Divestitures
Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2016 | |
Business Combinations [Abstract] | |
Acquisitions and Divestitures | 3. Acquisitions and Divestitures On September 26, 2016, Amadeus Petroleum, Inc. and T-N-T Engineering, Inc. entered into a purchase and sale agreement with AVAD Energy Partners, LLC and Vendera Resources II, LLC to sell their remaining interest in producing wells and related oil and gas leases in its conventional properties located in multiple counties in Texas, effective as of July 1, 2016. The sale price approximated $14,000,000. The transaction closed on October 31, 2016. In the third quarter of 2016, the Company reported an impairment charge of approximately $29.1 million, representing carrying value in excess of fair value, less the cost to sell the properties. On August 2, 2016, Lonestar Resources US Inc. and Eagleford Gas 5, LLC (collectively, “Buyer”) entered into a purchase and sale agreement with Juneau Energy, LLC (“Juneau”) whereby the Company obtained an undivided 50% of Seller’s interest in two producing wells and each well’s respective oil and gas leases covering approximately 1,300 net mineral acres located in Brazos County, Texas. The total consideration paid by the Company was $5,500,000 payable in 500,227 shares of the Company’s Class A common stock. As part of the purchase and sale agreement, the Company entered into a swap of assets of 50% of its interest in the Carter Lake - Wildcat area for 50% of the assets owned by Juneau in the 1,300 net mineral acres. The Company owned 1,110 net mineral acres (“Swap Assets”) in the Carter Lake - Wildcat area on August 1, 2016. As further part of the purchase and sale agreement, the Company agreed to commence operations on drilling one (1) Eagle Ford Shale well by December 31, 2016 on Juneau Energy, LLC’s assets or the Swap Assets; and, another Eagle Ford Shale well on Juneau Energy LLC’s assets or the Swap Assets by December 31, 2017. As of December 31, 2016, the Company had commenced drilling operations of two (2) Eagle Ford Shale wells satisfying the drilling commitment provision under the purchase and sale agreement. On June 15, 2016, Amadeus Petroleum, Inc. and T-N-T Engineering, Inc. sold their entire interest in producing wells and related oil and gas leases in its Morgan’s Bluff property located in Orange County, Texas, effective as of July 1, 2016. Production related to the property was 86 Boe/d during the second quarter of 2016. The sale price approximated $2,200,000 and resulted in a gain of approximately $1,900,000. From January to March 2016 the Company paid approximately $770,000 to acquire approximately 220 net acres in La Salle County, TX surrounding Company developed areas and new undeveloped areas classified by the Company as Burns Ranch. From January to June 2016 the Company paid approximately $1,600,000 to acquire approximately 1,088 net acres in Gonzales County, TX for new well development in the Cyclone area. In January 2015 the Company exchanged its working interest in two non-operated wells and the underlying leasehold acreage for increased working interests in currently owned and operated property. The exchange resulted in a loss of $629,000. Additionally, the Company acquired 159 net acres in the Eagle Ford Shale trend in La Salle County, TX for $500,000 as a further component of the exchange. |
Restricted Certificate of Depos
Restricted Certificate of Deposit | 12 Months Ended |
Dec. 31, 2016 | |
Banking And Thrift [Abstract] | |
Restricted Certificate of Deposit | 4. Restricted Certificate of Deposit The Company is required to maintain a certificate of deposit (“CD”) issued by a municipality in Montana, in which certain of our drilling operations are located. This CD is pledged as collateral for a letter of credit issued by the Company’s bank to the municipality. The CD has a maturity date of March 8, 2018, and bears an interest rate of 0.25%. As this CD is expected to be renewed upon maturity and is not available for use in operations, it is classified as a noncurrent asset. |
Commodity Price Risk Activities
Commodity Price Risk Activities | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Commodity Price Risk Activities | 5. Commodity Price Risk Activities The Company has implemented a strategy to reduce the effects of volatility of oil and natural gas prices on the Company’s results of operations by securing fixed price contracts for a portion of its expected sales volumes. Inherent in the Company’s fixed price contracts, are certain business risks, including market risk and credit risk. Market risk is the risk that the price of oil and natural gas will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not currently require collateral from any of its counterparties nor does its counterparties require collateral from the Company. At December 31, 2016, the Company had no open physical delivery obligations. The Company enters into certain commodity derivative instruments to mitigate commodity price risk associated with a portion of its future oil, NGL and natural gas production and related cash flows. The oil, NGL and natural gas revenues and cash flows are affected by changes in commodity product prices, which are volatile and cannot be accurately predicted. The objective for holding these commodity derivatives is to protect the operating revenues and cash flows related to a portion of the future oil, NGL and natural gas sales from the risk of significant declines in commodity prices, which helps ensure the Company’s ability to fund the capital budget. The Company has not designated any of the commodity derivatives as hedges under the applicable accounting standards. Consequently, all changes in fair value of these derivatives (realized and unrealized) are included in the consolidated statement of operations. As of December 31, 2016, the following derivative transactions were outstanding: Instrument Total Volume Settlement Period Fixed Price Oil – WTI Fixed Price Swap 109,500 Bbl January – December 2017 $ 51.05 Oil – WTI Fixed Price Swap 73,000 Bbl January – December 2017 50.60 Oil – WTI Fixed Price Swap 365,000 Bbl January – December 2017 52.90 Oil – WTI Fixed Price Swap 365,000 Bbl January – December 2018 54.18 Oil – WTI Fixed Price Swap 182,500 Bbl January – December 2018 55.65 Natural Gas – Henry Hub NYMEX Fixed Price Swap 2,555,000 MMBtu January – December 2017 3.36 Instrument Total Volume Settlement Period Puts Calls Oil – 3 Way Collar 365,100 Bbl January – December 2017 $ 40.00 / 60.00 $ 85.00 Oil – 2 Way Collar 182,500 Bbl January – December 2018 50.00 59.45 The above oil derivative contracts aggregate to 912,600 barrels or 2,500 barrels of oil per day for 2017 and 730,000 barrels or 2,000 barrels of oil per day for 2018. The above natural gas derivative contract equates to 7,000 MMBtu per day for 2017. All derivative contracts are carried at their fair value on the balance sheet and all changes in value are recorded in the consolidated statement of operations in gain or loss on derivative financial instruments. As of December 31, 2016 and 2015, all of the Company’s economic derivative hedge positions were with large financial institutions, which are not known to the Company to be in default on their derivative positions. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contain credit-risk related contingent features. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | 6. Fair Value Measurements Non-recurring fair value measurements include certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; impaired oil and natural gas property assessments; warrants issued in equity offerings and the initial recognition of asset retirement obligations for which fair value is used. These 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 estimates as Level 3. The Company periodically reviews for impairment its long-lived assets, including proved oil and natural gas properties accounted for under the successful efforts method of accounting. Based upon the sale of the Company’s conventional oil and natural gas properties located in Texas, the Company reviewed the carrying value of the remaining acreage in this area and recorded an impairment of approximately $29.1 million. During 2016, certain leased acreage was set to expire in Montana as part of the Bakken, Three Forks, and Lower Lodgepole formations (the “Poplar Properties”). Based on our decision to defer drilling on the Poplar Properties, the Company recorded an approximate $1.9 million impairment charge related to leased acreage expiring during 2016. This was calculated through the allocation of our current carrying value of the properties across our proportionate share of the acreage. Certain leased acreage in Wilson County, Texas expired in October 2016. The Company decided to not extend those leases, therefore, the leasehold costs associated with this acreage was impaired as a result of these lease expirations. The Company recorded an impairment charge of approximately $2.8 million. In accordance with ASC 820, Fair Value Measurements and Disclosures Level 1 – Quoted prices for identical assets or liabilities in active markets. Level 2 – Quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs derived principally from or corroborated by observable market data by correlation or other means. Level 3 – Unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement falls in its entirety is determined based on the lowest level input that is significant to the measurement in its entirety. The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2016 and 2015, for each fair value hierarchy level: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total December 31, 2015 (In thousands) Assets: Commodity derivatives $ — $ 36,083 $ — $ 36,083 Liabilities: Commodity derivatives — — — $ — Total $ — $ 36,083 $ — $ 36,083 December 31, 2016 (In thousands) Assets: Commodity derivatives $ — $ 1,730 $ — $ 1,730 Liabilities: Commodity derivatives — (4,110 ) — $ (4,110 ) Equity warrant liability — — (1,565 ) (1,565 ) Equity warrant liability - related parties — — (2,994 ) (2,994 ) Total $ — $ (2,380 ) $ (4,559 ) $ (6,939 ) Level 3 Gains and Losses The table below sets forth a summary of changes in the fair value of the Company’s level 3 liability for the year ended December 31, 2016. December 31, 2016 (In thousands) Balance, beginning of year $ — Purchases, sales, issuances and settlements (net) (5,127 ) Realized gains/(losses) — Unrealized gains/(losses) relating to instruments held at the reporting date 568 Balance, end of year $ (4,559 ) The derivative asset and liability fair values reported in the consolidated balance sheets are as of the balance sheet date and subsequently change as a result of changes in commodity prices, market conditions and other factors. The Company typically has numerous hedge positions that span several time periods and often result in both derivative assets and liabilities with the same counterparty, which positions are all offset to a single derivative asset or liability in the consolidated balance sheets, including the deferred premiums associated with its hedge positions. The Company nets the fair values of its derivative assets and liabilities associated with derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The book values of cash and cash equivalents, receivables for oil, NGL and natural gas sales, joint interest billings, notes and other receivables, accounts payable, and accrued liabilities approximate fair value due to the short-term nature of these instruments. The carrying value of debt approximates fair value since it is subject to a short-term floating interest rate that approximates the rate available to the Company, except for bonds, which are recorded at amortized cost less debt issuance costs. The fair value of the “8.750% Senior Notes” (as defined in Note 10 below) approximates $139.3 million as of December 31, 2016, and the notes are considered a Level 3 liability, as they are based on market transactions that occur infrequently as well as internally generated inputs. The Company’s other Level 3 financial liabilities measured at fair value consist of the warrant liability as of December 31, 2016. Significant unobservable inputs used in the fair value measurement of the warrants include the estimated term. Significant decreases in the estimated remaining period to exercise would result in a significantly lower fair value measurement. |
Oil and Gas Properties
Oil and Gas Properties | 12 Months Ended |
Dec. 31, 2016 | |
Extractive Industries [Abstract] | |
Oil and Gas Properties | 7. Oil and Gas Properties A summary of oil and gas properties follows: December 31, 2016 December 31, 2015 (In thousands) Proved properties and equipment $ 538,695 $ 584,692 Unproved properties 72,584 70,298 Less accumulated depreciation, depletion, amortization, and impairment (172,051 ) (166,890 ) $ 439,228 $ 488,100 |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | 8. Asset Retirement Obligations Pursuant to ASC 410 , Asset Retirement Obligations, The liability has been accreted to its present value as of December 31, 2016. The Company evaluated its wells and has determined a range of abandonment dates through December 2056. The following represents a reconciliation of the asset retirement obligations: Years Ended December 31, 2016 2015 (In thousands) Asset retirement obligations at beginning of period $ 7,488 $ 6,835 Wells drilled during the year 154 331 Wells acquired during the year 28 176 Wells sold during the year (4,780 ) (5 ) Accretion of discount 180 214 Revisions of previous estimates (1) (205 ) 13 Wells plugged and abandoned during the year (182 ) (76 ) Asset retirement obligations at end of period $ 2,683 $ 7,488 |
Accrued Liabilities
Accrued Liabilities | 12 Months Ended |
Dec. 31, 2016 | |
Payables And Accruals [Abstract] | |
Accrued Liabilities | 9. Accrued Liabilities The accrued liabilities consist of the following at December 31: 2016 2015 (In thousands) Bonus payable $ 2,155 $ 1,433 Payroll payable 1 28 Accrued interest - 8.750% Senior Notes 2,924 4,064 Accrued interest - other 523 356 Accrued rent 298 410 Accrued well costs 3,366 1,339 Accrued severance, property and franchise taxes 431 62 Other 249 584 $ 9,947 $ 8,276 |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | 10. Long-Term Debt The long-term debt consists of the following at December 31: 2016 2015 (In thousands) Senior Secured Credit Facility $ 43,500 $ 87,000 Second Lien Notes 11,367 — 8.750% Senior Notes 151,848 220,000 Less unamortized discount on 8.750% Senior Notes (1,708 ) (3,575 ) Less deferred financing costs on 8.750% Senior Notes (851 ) (1,785 ) Less deferred financing costs on Second Lien Notes (316 ) — Other 282 286 $ 204,122 $ 301,926 Senior Secured Credit Facility On July 28, 2015, LRAI closed a new $500,000,000 Senior Secured Credit Facility (the “Senior Secured Credit Facility”) which replaced a $400,000,000 Wells Fargo-led syndicated facility. The new facility was arranged by Citibank, N.A. and featured an expanded borrowing base of $180,000,000 as of December 31, 2015. The new facility provides additional liquidity for the Company and a lower interest rate. The new rate is a 25 basis point improvement over the LIBOR interest rate spread. The new facility provides for an extension in the maturity date to October 16, 2018, which represented a seven month extension over the Wells Fargo-led facility. The financial covenants contained in this new facility are substantially the same as the previous facility. Effective as of May 19, 2016, the borrowing base was reduced from $180,000,000 to $120,000,000. As of December 31, 2016 (giving effect to the amended covenant ratio discussed below) and December 31, 2015, LRAI was in compliance with all covenants including all financial ratios under the Senior Secured Credit Facility. As of December 31, 2016 and 2015, $43,500,000 and $87,000,000 was borrowed, respectively, under the Senior Secured Credit Facility. The Senior Secured Credit Facility may be used for loans and, subject to a $2,500,000 sub-limit, letters of credit. The Senior Secured Credit Facility provides for a commitment fee of 0.375% to 0.5% based on the unused portion of the borrowing base under the Senior Secured Credit Facility. Borrowings under the Senior Secured Credit Facility, at LRAI’s election, bear interest at either: (i) an alternate base rate (“ABR”) equal to the higher of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5% per annum, and (c) the adjusted LIBO rate of a three-month interest period on such day plus 1.0%; or (ii) the adjusted LIBO rate, which is the rate stated on Reuters screen LIBOR01 page, for one, two, three, six or twelve months, as adjusted for statutory reserve requirements for Eurocurrency liabilities, plus, in each of the cases described in clauses (i) and (ii) above, an applicable margin ranging from 0.75% to 1.75% for ABR loans and from 1.75% to 2.75% for adjusted LIBO rate loans (3.64% at December 31, 2016). The Senior Secured Credit Facility requires LRAI to maintain certain financial ratios and limits the amount of indebtedness LRAI can incur. Subject to certain permitted liens, LRAI’s obligations under the Senior Secured Credit Facility have been secured by the grant of a first priority lien on no less than 80% of the value of the proved oil and gas properties of the Company and its subsidiaries. In connection with the Senior Secured Credit Facility, LRAI and certain of its subsidiaries also entered into certain customary ancillary agreements and arrangements, which, among other things, provide that the indebtedness, obligations, and liabilities of the Company arising under or in connection with the Senior Secured Credit Facility are unconditionally guaranteed by such subsidiaries. Effective as of July 27, 2016, LRAI, the several banks and other financial institutions party thereto (collectively, the “Consenting Lenders”) and Citibank, N.A., in its capacity as administrative agent for the lenders (the “Administrative Agent”) entered into the Third Amendment to Credit Agreement and Limited Waiver (the “Amendment”) to that certain Credit Agreement dated as of July 28, 2015, by and among LRAI, the Consenting Lenders (together with the other banks and financial institutions party thereto, the “Lenders”) and the Administrative Agent (as amended, supplemented and modified, the “Credit Agreement”) to (a) permit LRAI to incur the second lien obligations contemplated by the Securities Purchase Agreement with Leucadia National Corporation and others (as described below) and LRAI’s contemplated use of proceeds thereof, (b) increase the applicable margin for Eurodollar and ABR loans and letter of credit fees by 0.75% across all levels of the previously applicable pricing grid, (c) modify the fee payable on the actual daily unused amount of the aggregate commitments to a flat 0.50% across all levels of the pricing grid, (d) increase the minimum percentage of the value of LRAI’s oil and gas properties that must be mortgaged as collateral for the obligations under the Credit Agreement and the other loan documents from 80% to 90%, (e) modify the maximum leverage ratio thresholds from 4.0 to 1.0 to (i) 4.75 to 1.0 for the four quarterly periods ending June 30, 2016, (ii) 4.50 to 1.0 for the four quarterly periods ending September 30, 2016, (iii) 4.25 to 1.0 for the four quarterly periods ending December 31, 2016 and (iv) 4.00 to 1.0 for all periods thereafter, (f) prohibit distributions to the Predecessor for general and administrative expenses after September 30, 2016 and (g) amend certain other provisions of the Credit Agreement as more specifically set forth in the Amendment. 8.750% Senior Notes On April 4, 2014, LRAI issued at par $220,000,000 of 8.750% Senior Unsecured Notes due April 15, 2019 (the “8.750% Senior Notes”) to U.S. based institutional investors. The net proceeds from the offering of approximately $212,000,000 (after deducting purchasers’ discounts and offering expenses) were used to repay LRAI’s Senior Secured Credit Facility and 2nd lien facility both with Wells Fargo at this time, and for general corporate purposes. Under the 2nd lien term loan agreement, LRAI was required to pay a prepayment fee of $1,100,000 in connection with the early prepayment of the facility equal to 2.0% of the principal balance that was prepaid. This facility was terminated upon repayment. On or after April 15, 2016, LRAI may redeem the 8.750% Senior Notes in whole or in part at the redemption prices (expressed as percentages of the principal amount) set forth in the following table plus accrued and unpaid interest, if any, on the 8.750% Senior Notes redeemed, to the applicable date of redemption, if redeemed during the twelve-month period beginning on April 15 of the years indicated below: Year Percentage 2016 106.563 % 2017 104.375 % 2018 and thereafter 100.000 % In addition, upon a change of control of LRAI, holders of the 8.750% Senior Notes will have the right to require LRAI to repurchase all or any part of their 8.750% Senior Notes for cash at a price equal to 101% of the aggregate principal amount of the 8.750% Senior Notes repurchased, plus any accrued and unpaid interest. The 8.750% Senior Notes were issued under and governed by an Indenture dated April 4, 2014, between LRAI, Wells Fargo Bank, National Association, as trustee and LRAI’s subsidiaries named therein as guarantors (the “Indenture”). The Indenture contains covenants that, among other things, limit the ability of LRAI and its subsidiaries to: incur indebtedness; pay dividends or make other distributions on stock; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; refinance certain indebtedness; and merge with or into other companies or transfer substantially all of LRAI’s assets. Debt Issuance Costs The Company capitalizes certain direct costs associated with the issuance of long-term debt and amortizes such costs over the lives of the respective debt. At December 31, 2016 and 2015, the Company had approximately $1,200,000 and $1,100,000, respectively, of debt issuance costs associated with issuance of the Senior Secured Credit Facility remaining that are being amortized over the lives of the respective debt which are recorded as other non-current assets in the consolidated balance sheets. Securities Purchase Agreement and Second Lien Notes On August 2, 2016, the Company entered into a Securities Purchase Agreement with Juneau Energy, LLC, as initial purchaser (“Juneau”), Leucadia National Corporation (“Leucadia”), as guarantor of Juneau’s obligations, the other purchasers party thereto and Jefferies, LLC, in its capacity as the collateral agent for the purchasers, relating to the issuance and sale of (i) up to $49,900,000 aggregate principal amount of LRAI’s 12% senior secured second lien notes due 2021 (the “Second Lien Notes”) and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A common stock at a price equal to $5.00 per share (the “Warrants”).The balance of these notes and warrants is reflected in our long-term debt – related parties and equity warrant liability – related parties on the face of the balance sheet. The Second Lien Notes are secured by second-priority liens on substantially all of LRAI’s and its subsidiaries’ assets to the extent such assets secure obligations under the Senior Secured Credit Facility. During 2016, LRAI issued $38.0 million in aggregate principal amount of Second Lien Notes and the Company issued Warrants to purchase 760,000 shares of its Class A common stock. The Company recorded an equity warrant liability of approximately $5.1 million which was the fair value amount at the date of issuance. The warrants were adjusted to fair value at December 31, 2016 which resulted in an unrealized gain on warrants of approximately $0.6 million. Proceeds from the Second Lien Notes issuance were used to repurchase approximately $68.2 million in aggregate principal amount of the 8.750% Senior Notes in privately negotiated open market repurchases with holders of such notes, and to pay related fees and expenses related to the foregoing. The repurchase amounts paid were approximately $36.2 million in cash. Net of related fees, such repurchases resulted in a gain on debt extinguishment of approximately $28.5 million. In December 2016, LRAI repaid $21.0 million principal of the Second Lien Notes with proceeds from the 2016 Common Stock Offering. Repurchase Facilitation Agreement On October 26, 2016, effective September 29, 2016, Lonestar Resources US, Inc. (the “Company”), by and on behalf of itself and certain of its subsidiaries, entered into an Amended and Restated Repurchase Facilitation Agreement (the “Amended and Restated Agreement”) with Seaport Global Securities LLC, a Delaware limited liability company (“Seaport Global”). Pursuant to the Amended and Restated Agreement, Seaport Global has agreed to provide the Company with financing (“Gap Financing”) from time to time in connection with the repurchase of the 8.750% Senior Notes As of September 30, 2016, the Company recorded $2,063,320 as long-term debt on its balance sheet as a result of this financing. In December 2016, LRAI repaid the Gap Financing with proceeds from the 2016 Common Stock Offering. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | 11. Income Taxes The current and deferred components of income tax expense (benefit) are as follows: Years Ended December 31, 2016 2015 Current income tax expense (In thousands) Federal $ 5,057 $ 288 State 341 74 Total current income tax expense 5,398 362 Deferred tax expense (benefit) Federal 21,909 (15,130 ) Foreign 270 — State (172 ) (353 ) Total deferred income tax expense (benefit) $ 22,007 $ (15,483 ) Total income tax expense (benefit) from continuing operations 27,405 (15,121 ) Total income tax (benefit)/expense differs from the amounts computed by applying the U.S. statutory federal income tax rate to income (loss) before income taxes as a result of state income taxes, certain permanent differences and valuation allowances. The following table provides a reconciliation of the Company’s actual income tax provision amounts from the expected income tax provision amount by applying the U.S. federal statutory corporate income tax rate of 35% for the periods indicated: Years Ended December 31, 2016 2015 (In thousands) Expected income tax provision (benefit) at statutory rate $ (23,416 ) $ (14,859 ) State tax, tax effected 52 11 Other 339 (40 ) Net operating loss write down 49,608 — Rate difference 311 (233 ) Permanent differences 511 — Actual income tax provision $ 27,405 $ (15,121 ) The tax effects of the Company’s temporary differences that give rise to significant portions of the deferred tax assets and liabilities are presented below: December 31, 2016 2015 Deferred tax assets: (In thousands) Net operating loss carryforward $ 20,442 $ 77,508 Organizational expenses 52 57 Stock based compensation 2,593 2,431 Intangibles 682 776 Other 3,812 1,419 27,581 82,191 Deferred tax liabilities: Oil and gas properties and other property and equipment, principally due to intangible drilling costs (66,772 ) (86,790 ) Unrealized hedging loss (gain) 1,371 (11,414 ) Other (200 ) — Net deferred tax liabilities $ (38,020 ) $ (16,013 ) The net operating loss carryforward as of December 31, 2016, approximates $199.9 million and begins to expire in 2030. The deferred tax asset recorded for the net operating losses does not include $2.2 million of deductions for excess stock-based compensation. On December 22, 2016, the Company completed a public offering of 13.8 million of its Class A common stock. A change of ownership, as defined under the provisions of Section 382 of the Internal Revenue Code (“IRC”) occurred on this date. A portion of our net operating loss and tax credit carryforwards will be limited in future periods. IRC Section 382 places limitations on the amount of taxable income which may be offset by tax carryforward attributes, such as net operating losses or tax credits after a change of ownership event. As a result of this ownership change, certain of our accumulated net operating losses will be subject to an annual limitation regarding their utilization against taxable income in future periods. The 2016 change creates an estimated annual utilization limit of approximately $1.0 million on our ability to utilize net operating losses generated prior to the ownership change event. Built-in gains associated with our deferred tax attributes on the date of the ownership change may increase the net operating loss utilization limit in future periods, allowing additional utilization of net operating losses generated prior to the date of the ownership change. Due to the ownership change and the resulting limitation on the utilization of net operating loss generated prior to the change, an estimated $141.7 million of the net operating loss carryforwards have been written off in 2016. The Company files income tax returns in the United States federal jurisdiction and in various state jurisdictions. At December 31, 2016, there are no current examinations of federal or state jurisdictions in progress. The Company’s income tax returns related to fiscal years ended December 31, 2010 through 2015 remain open to possible examination by the tax authorities. The Company has not recorded any interest or penalties associated with uncertain tax positions. |
Stockholders' Equity and Stock
Stockholders' Equity and Stock Based Compensation | 12 Months Ended |
Dec. 31, 2016 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Stockholders' Equity and Stock Based Compensation | 12. Stockholders’ Equity and Stock Based Compensation Common Stock Issuances On December 22, 2016, the Company completed the 2016 Common Stock Offering of 13.8 million shares of its Class A common stock at a price of $5.75 per share, for proceeds of approximately $71.8 million, net of offering costs. The Company used the net proceeds from the stock offering to repay borrowings under its Senior Secured Credit Facility, Second Lien Notes and to repay the debt owed under the Facilitation Agreement with Seaport Global. On August 2, 2016, the Company entered into a purchase and sale agreement with Juneau Energy, LLC (“Juneau”) whereby the Company obtained an undivided 50% of Juneau’s interest in two producing wells and each well’s respective oil and gas leases covering approximately 1,300 net mineral acres located in Brazos County, Texas. The total consideration paid by the Company was $5,500,000 payable in 500,227 shares of the Company’s Class A common stock. In July 2016, the Company issued 2,500 shares of Class B non-voting common stock to Butterfly Flaps, Ltd., a Company in which Dr. Christopher Rowland (a director of the Company) owns an interest. The shares were issued for services to be performed by Butterfly Flaps, Ltd. in 2017. Determining Fair Value of Stock Options In determining the fair value of stock option grants, the Company utilized the following assumptions: Valuation and Amortization Method. The Company estimates the fair value of stock option awards on the date of grant using the Black-Scholes-Merton valuation model. The fair value of all awards is expensed using the “graded-vesting method.” Expected Life. The expected life of stock options granted represents the period of time that stock options are expected, on average, to be outstanding. The Company determined the expected life to be 3.5 years, for all stock options issued with three-year vesting periods and four-year grant expirations. Expected Volatility. Using the Black-Scholes-Merton valuation model, the Company estimates the volatility of Predecessor’s common shares at the beginning of the quarter in which the stock option is granted. The volatility of 58.6% is based on weighted average historical movements of Predecessor’s common share price on the ASX over a period that approximates the expected life. Risk-Free Interest Rate. The Company utilizes a risk-free interest rate equal to the rate of U.S. Treasury zero-coupon issues as of the date of grant with a term equivalent to the stock option’s expected life. Expected Dividend Yield. The Predecessor and the Successor have not paid any cash dividends on its common shares, and the Successor does not anticipate paying any cash dividends in the foreseeable future. Consequently, a dividend yield of zero is utilized in the Black-Scholes-Merton valuation model. Expected Forfeitures. The Company has experienced limited forfeitures and therefore has not discounted expenses for forfeitures at the reporting date. Stock Option Activity For the year ended December 31, 2016, no stock options were exercised. The following tables summarize certain information related to outstanding stock options under the Lonestar Resources Limited 2012 Employee Share Option Plan and the Lonestar Resources US Inc. 2016 Incentive Plan, which replaced the Lonestar Resources Limited 2012 Employee Share Option Plan following the Reorganization: Shares Weighted Average Exercise Price Per Share Weighted Remaining Contractual Term (in years) Outstanding at December 31, 2015 849,936 $ 15.50 1.0 Options vested and exercisable at December 31, 2015 807,686 15.50 1.0 Granted 35,000 15.00 2.0 Exercised — — — Canceled/Expired (693,186 ) 18.00 — Forfeited — — — Outstanding at December 31, 2016 191,750 $ 15.00 0.5 Options vested and exercisable at December 31, 2016 191,750 $ 15.00 0.5 Shares Weighted Average Fair Value per Share Weighted Average Exercise Price per share Weighted Average Remaining Contractual Term (in years) Outstanding non-vested options at December 31, 2015 42,250 $ 9.00 $ 15.50 1.0 Granted 35,000 1.90 15.00 2.0 Vested (77,250 ) 8.00 15.00 1.0 Forfeited — — — — Outstanding non-vested options at December 31, 2016 — $ — $ — — Stock-Based Compensation Expense For the years ended December 31, 2016 and 2015, the Company recorded stock-based compensation expense for stock options granted using the fair-value method of approximately $448,000 and $2,585,000, respectively. As all outstanding options have fully vested, no unrecognized compensation cost existed at December 31, 2016. |
Earnings Per Share
Earnings Per Share | 12 Months Ended |
Dec. 31, 2016 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | 13. Earnings Per Share In accordance with the provisions of current authoritative guidance, basic earnings or loss per share shown on the Consolidated Statements of Operations is computed on the basis of the weighted average number of common shares outstanding during the periods. Diluted earnings or loss per share is computed based upon the weighted average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities. The Company includes the number of stock options in the calculation of diluted weighted average shares outstanding when the grant date or exercise prices are less than the average market prices of the Company’s Class A common stock for the period. When a loss from operations exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding. There is no dilutive effect for the years ended December 31, 2016 and 2015 as the Company reported a loss from operations for those periods. The following table presents unaudited earnings per share of Lonestar Resources US Inc., assuming that the 1 for 2 reverse stock split upon Reorganization had occurred at the beginning of the year ended December 31, 2015: Unaudited Earnings Per Share (After Reorganization) Year Ended December 31, 2016 2015 Net income (loss) per common share: Basic $ (11.64 ) $ (3.63 ) Diluted (11.64 ) (3.63 ) Weighted average common shares outstanding: Basic 8,106,931 7,521,788 Diluted 8,106,931 7,521,788 |
Related Party Activities
Related Party Activities | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
Related Party Activities | 14. Related Party Activities Leucadia On August 2, 2016, LRAI and the Company entered into the Purchase Agreement with Juneau, Leucadia, as guarantor of Juneau’s obligations, the other purchasers party thereto and Jefferies, LLC, in its capacity as the collateral agent for the purchasers, relating to the issuance and sale of (i) up to $49,900,000 aggregate principal amount of Second Lien Notes and (ii) Warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A common stock. Pursuant to the Purchase Agreement Juneau purchased $13,000,000 aggregate principal amount of Second Lien Notes and Warrants to purchase 500,000 shares of Class A common stock. On August 2, 2016, the Company also issued 500,227 shares of Class A common stock to Juneau pursuant in exchange for interests in certain oil and gas assets pursuant to a purchase and sale agreement (the “Purchase and Sale Agreement”). As part of the Purchase and Sale Agreement, the Company entered into a swap of assets of 50% of its interest in the Carter Lake - Wildcat area for 50% of the assets owned by Juneau in the 1,300 net mineral acres. The Company owned 1,110 net mineral acres (“Swap Assets”) in the Carter Lake - Wildcat area on August 1, 2016. As further part of the Purchase and Sale Agreement, the Company agreed to commence operations on drilling one (1) Eagle Ford Shale well by December 31, 2016 on Juneau Energy, LLC’s assets or the Swap Assets; and, another Eagle Ford Shale well on Juneau Energy LLC’s assets or the Swap Assets by December 31, 2017. As of December 31, 2016, the Company had commenced drilling operations of two (2) Eagle Ford Shale wells satisfying the drilling commitment provision under the Purchase and Sale Agreement. Due to Leucadia’s ownership interests in Juneau, Leucadia is considered to be the beneficial owner of shares Juneau owns. As a result of the Warrants and Class A common stock issuances to Juneau in connection with the Purchase Agreement and the Purchase and Sale Agreement, respectively, Leucadia is the beneficial owner of more than 10% of the Company’s Class A common stock. In connection with entering into the Purchase Agreement, the Company also entered into a Registration Rights Agreement and an equity commitment agreement, both dated as of August 2, 2016. Pursuant to the Registration Rights Agreement, the Company has agreed to register for resale certain Class A common stock issued or issuable to Juneau and Leucadia, including those issuable upon exercise of the Warrants. Leucadia has agreed, pursuant to the equity commitment agreement, to purchase a certain number of Class A common stock equal to (a) $20,000,000 (or such lesser amount as the Company requests) divided by (b) the offering price to investors in a registered public offering of securities that is completed on or before December 31, 2016. On December 22, 2016 Leucadia purchased 3,478,261 shares of Class A voting common stock (costing $20,000,000), thus satisfying the equity commitment. In connection with Leucadia’s commitment, the Company agreed to pay Leucadia a fee equal to $1,000,000, payable upon the closing of such offering. This amount was recorded in accounts payable in the consolidated balance sheet at December 31, 2016. This amount was paid on January 3, 2017. EF Realisation On October 26, 2016, the Company entered into a Board Representation Agreement (“Board Representation Agreement”) with EF Realisation. Under the Board Representation Agreement, for as long as EF Realisation owns 15% or more of the issued and outstanding shares of our Class A common stock, it has the right to nominate up to, but no more than, two directors to serve on our Board of Directors and for as long as EF Realisation owns at least 10% but less than 15% of our issued and outstanding shares of Class A common stock, it has the right to nominate up to, but no more than, one director to serve on our Board of Directors. On October 26, 2016, the Company entered into a Registration Rights Agreement with EF Realisation, pursuant to which we agreed to register for resale Class A common stock held by EF Realisation. We have agreed to file a registration statement providing for the resale of Class A common stock held by EF Realisation no later than the earlier of (i) October 26, 2017, and (ii) 30 days after the date we first become eligible to file a registration statement on Form S-3. We have also granted EF Realisation certain piggyback and demand registration rights. Frank D. Bracken III and Thomas H. Olle In April 2014, the Company loaned $539,000 in total to Frank D. Bracken, III and Thomas H. Olle to assist with their tax obligations as a result of stock compensation awarded to them in 2013. The loans were on arms-length commercial terms and were settled in full in January 2016. Dr. Christopher Rowland Butterfly Flaps, Ltd, a company in which Dr. Christopher Rowland (a director of the Company) owns an interest, has performed consultancy work for the Company since 2013 covering various strategic, tax structuring and investor matters at a cost of approximately $25,000 per quarter. In July 2016, the Company issued 2,500 shares of Class B non-voting common stock to Butterfly Flaps, Ltd. The shares were issued for services to be performed by Butterfly Flaps, Ltd. in 2017. Daniel R. Lockwood New Tech Global Ventures, LLC, a company in which Daniel R. Lockwood (a director of the Company) owns a limited partnership interest, has provided field engineering staff and consultancy services for the Company since 2013. The total cost for such services was approximately $665,000 and $938,000 for the years ended December 31, 2016 and 2015, respectively. Mitchell Wells Mitchell Wells, who served as our director since December 2014 until his resignation in January 2017, has provided consultancy services as our Company Secretary since January 2013. These services have been provided through BlueSkye Pty Ltd, for which Mr. Wells is the sole Director and shareholder. BlueSkye Pty Ltd was paid approximately $95,000 and $142,500 for the years ended December 31, 2016 and 2015, respectively. He has not received any additional compensation for his service as a Director. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
Commitments And Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 15. Commitments and Contingencies Employment Agreements Each of the employment agreements to which our executives were a party expired as of December 31, 2015. Currently none of our executive officers are party to any employment agreement or compensatory arrangement, other than customary indemnification agreements. Litigation The Company is subject to certain claims and litigation arising in the normal course of business. In the opinion of management, the outcome of such matters will not have a materially adverse effect on the consolidated results of operations or financial position of the Company. Environmental Remediation Various federal, state, and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the Company’s operations and the costs of its oil and gas exploration, development, and production operations. The Company does not anticipate that it will be required in the near future to expend significant amounts in relation to the consolidated financial statements taken as a whole by reason of environmental laws and regulations, and appropriately no reserves have been recorded. Lease Agreement The Company entered into an operating lease agreement for its primary facility in October 2014. The lease will expire in October 2021. Future minimum annual lease payments are as follows: Amount 2017 $ 464,996 2018 411,768 2019 422,301 2020 432,835 Thereafter 368,011 Total $ 2,099,911 Rent expense was $375,000 and $404,000 for the years ended December 31, 2016 and 2015, respectively. Rig Contract As of December 31, 2016, the Company had one drilling rig under contract. The contract provided for a daily drilling rate of $15,000. The rig contract terminates on July 8, 2017. The early termination fee is equal to 80% of the daily drilling rate times the number of days remaining on the contract term. Using the $15,000 daily rate, as of December 31, 2016 the minimum remaining commitment per the terms of the agreement was approximately $2.7 million. As of December 31, 2015, the Company had one drilling rig under contract. The contract provided for a drilling rate that is indexed on a monthly basis to the West Texas Intermediate (Cushing) average price for that particular month. The current daily drilling rate is $19,000. The rig contract terminated on July 20, 2016. The early termination fee is equal to 75% of the highest month operating rate earned during the 2016 contract period times the number of days remaining on the contract term. Using the $19,000 daily rate, as of December 31, 2015 the minimum remaining commitment per the terms of the agreement was approximately $3.8 million. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental Cash Flow Information | 16. Supplemental Cash Flow Information Supplemental disclosures to the consolidated statements of cash flows are presented below: Years Ended December 31, 2016 2015 (In Thousands) Cash paid for interest expense $ 23,691 $ 21,492 Cash paid for federal income taxes 1,820 257 Non-cash investing and financing activities: Common stock issued for asset acquisition 5,500 — Cost to issue equity included in accounts payable 1,000 — |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2016 | |
Subsequent Events [Abstract] | |
Subsequent Events | 16. Subsequent Events In preparing the consolidated financial statements, management has evaluated all subsequent events and transactions for potential recognition or disclosure through the date the accompanying consolidated financial statements were issued. We are unaware of any material additional disclosures that should be made to these financial statements. |
Nature of Business and Presen24
Nature of Business and Presentation (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Basis of Accounting | Basis of Accounting The accounts are maintained and the consolidated financial statements have been prepared using the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). |
Use of Estimates | Use of Estimates The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect certain reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from these estimates and assumptions. Reserve estimates are inexact and may change as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production and timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Accordingly, there can be no assurance that ultimately, the reserves will be produced, nor can there be assurance that the proved undeveloped reserves will be developed within the period anticipated. |
Principles of Consolidation | Principles of Consolidation The accompanying consolidated financial statements include the accounts of the Company’s wholly owned subsidiaries: Lonestar Resources America, Inc. (“LRAI”), Lonestar Resources, Inc. (“LRI”), Lonestar Resources Intermediate, Inc. (“LRII”) LNR America, Inc. (“LNRA”), Barnett Gas, LLC (“Barnett Gas”), Eagleford Gas, LLC (“Eagleford Gas”), Poplar Energy, LLC (“Poplar”), Eagleford Gas 2, LLC (“Eagleford Gas 2”), Eagleford Gas 3, LLC (“Eagleford Gas 3”), Eagleford Gas 4, LLC (“Eagleford Gas 4”), Eagleford Gas 5, LLC (“Eagleford Gas 5”), Eagleford Gas 6, LLC (“Eagleford Gas 6”), Eagleford Gas 7, LLC (“Eagleford Gas 7”), Eagleford Gas 8, LLC (“Eagleford Gas 8”), Eagleford Gas 9, LLC (“Eagleford Gas 9”) Lonestar Operating, LLC (“LNO”), Lonestar BR Disposal, LLC (“LBRD”) La Salle Eagle Ford Gathering Line, LLC (“LSGL”) Amadeus Petroleum, Inc. (“API”), T-N-T Engineering, Inc. (“TNT”) and Albany Services, LLC (“Albany”). All significant intercompany balances and transactions have been eliminated in consolidation. |
Reclassification | Reclassifications Certain prior year amounts which were determined to be immaterial have been reclassified to conform to current year presentation, with no effect on the previously reported results of operations. |
Cash Equivalents | Cash Equivalents The Company considers all highly liquid investments with original maturities of three months or less when purchased to be cash equivalents. |
Concentrations and Credit Risk | Concentrations and Credit Risk The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents and accounts receivable. The Company places its cash and cash equivalents with reputable financial institutions. At times, the balances deposited may exceed amounts covered by insurance provided by the U.S. Federal Deposit Insurance Corporation (“FDIC”). The Company has not incurred any losses related to amounts in excess of FDIC limits. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, NGL and natural gas or working interest partners in oil and natural gas wells for which a subsidiary of the Company serves as the operator. Generally, operators of oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. The Company’s receivables are generally unsecured. The Company has experienced no material credit losses since its inception, however, an allowance for uncollectible amounts of approximately $196,000 was recorded at December 31, 2016, relating to receivables from joint interest owners of our conventional properties that were sold in the second half of 2016. Oil, NGL and natural gas revenues from Shell Trading (US) Company, Texla Energy Management, Inc., Trafigura AG, and BP Products North America LLC for the year ended December 31, 2016, represented 40%, 21%, 18% and 10%, respectively, of total revenues. Oil, NGL and natural gas revenues from Trafigura AG, BP Products North America LLC, Shell Trading (US) Company and Texla Energy Management, Inc. for the year ended December 31, 2015, represented 38%, 20%, 16% and 11%, respectively, of total revenues. Accounts receivable relating to oil, NGL and natural gas sales from Shell Trading, Trafigura AG and Texla Energy Management, Inc. represented 49%, 30% and 13%, respectively, of total receivables at December 31, 2016. Accounts receivable relating to oil, NGL and natural gas sales from Shell Trading, Trafigura AG and Texla Energy Management, Inc. represented 26%, 25% and 23%, respectively, of total receivables at December 31, 2015. |
Prepaid Expenses | Prepaid Expenses Prepaid expenses generally relate to prepaid drilling and completion costs that will be capitalized into oil and gas properties. |
Oil and Natural Gas Properties | Oil and Natural Gas Properties The Company uses the successful efforts method of accounting to account for its oil and gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The Company’s policy is to expense the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred, whether productive or nonproductive. Capitalized costs attributed to the proved properties are subject to depreciation and depletion. Depreciation and depletion of the cost of oil and gas properties is calculated using the units-of-production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For development costs, the reserve base used to calculate depletion and depreciation is proved developed reserves only. Unproved properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as an impairment of oil and gas properties in the consolidated statement of operations, as applicable. Unproved oil and gas property costs are transferred to proven oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, future plans to develop acreage, and other relevant factors. On the sale or retirement of a complete or partial unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and any gain or loss is recognized. |
Other Property and Equipment | Other Property and Equipment Other property and equipment, consisting primarily of office, transportation and computer equipment, is carried at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 5 years. Major renewals and improvements are capitalized, while expenditures for maintenance and repairs are expensed as incurred. Upon sale or abandonment, the cost of the equipment and related accumulated depreciation are removed from the accounts, and any gain or loss is recognized. |
Impairment of Long-Lived Assets | Impairment of Long-Lived Assets The carrying value of the oil and gas properties and other related property and equipment is periodically evaluated under the provisions of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 360, Property, Plant, and Equipment Under ASC 360, the Company evaluates impairment of proved and unproved oil and gas properties on an area basis. On this basis, certain fields may be impaired because they are not expected to recover their entire carrying value from future net cash flows. As a result of this evaluation, the Company recorded impairment of unproved oil and gas properties of approximately $4.8 million and $8.9 million for the years ended December 31, 2016 and 2015, respectively, and impairment of proven oil and gas properties of $29.1 million and $19.7 million for the years ended December 31, 2016 and 2015, respectively. If pricing declines, it is reasonably likely that the Company may have to record impairment of its oil and gas properties subsequent to December 31, 2016. |
Asset Retirement Obligations | Asset Retirement Obligations The Company accounts for asset retirement obligations under ASC 410, Asset Retirement and Environmental Obligations |
Revenue Recognition | Revenue Recognition Oil, NGL and natural gas revenues are recognized when title to the product transfers to the purchaser. The Company follows the sales method of accounting for its crude oil, NGL and natural gas revenue, whereby revenue is recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. There were no imbalances at December 31, 2016 or 2015. |
Fair Value of Financial Instruments | Fair Value of Financial Instruments In accordance with the reporting requirements of ASC 825, Financial Instruments |
Income Taxes | Income Taxes The Company follows the asset and liability method in accounting for income taxes in accordance with ASC 740, Income Taxes Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which these temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. The Company periodically evaluates the realizable tax benefits of deferred tax assets and records a valuation allowance, if required, based on an estimate of the amount of deferred tax assets the Company believes does not meet the more likely than not criteria of being realized. In certain circumstances, the deferred tax asset may exceed the amount permissible to be used under the tax law, for example, a net operating loss carryforward. In such cases it is appropriate to write-off the excess net operating loss. At December 31, 2016, the Company wrote off $141.7 million of its net operating loss carryforward. The Company evaluates uncertain tax positions, which requires significant judgments and estimates regarding the recoverability of deferred tax assets, the likelihood of the outcome of examinations of tax positions that may or may not be currently under review, and potential scenarios involving settlements of such matters. Changes in these estimates could materially impact the consolidated financial statements. No liability for material uncertain tax positions existed as of December 31, 2016 or 2015. |
Share-Based Payments | Share-Based Payments The Company accounts for equity-based awards in accordance with ASC 718, Compensation-Stock Compensation |
Recently Issued Accounting Pronouncements | In January 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2017-01, "Business Combinations (Topic 805): Clarifying the Definition of a Business" in order to clarify the definition of a business as it relates to whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public entities, this ASU is effective for annual periods beginning after December 15, 2017, and interim periods within those years and early adoption is permitted under certain circumstances. We expect to adopt this guidance in the first quarter of 2018. The impact is not expected to be material. In November 2016, the FASB issued ASU 2016-18, "Statement of Cash Flows (Topic 230): Restricted Cash" require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. For public entities, this ASU is effective for annual periods beginning after December 15, 2017, and interim periods within those years and early adoption is permitted under certain circumstances. We expect to adopt this guidance in the first quarter of 2018. Management is evaluating the provisions of this accounting standards update but considers it to have minimal impact on our consolidated statements of cash flows given the immaterial amount of restricted cash on our balance sheet. In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)" in order, to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The update addresses eight different transaction types and clarifies how to classify each in the statement of cash flows, where previously there was unclear or no specific guidance. For public entities, this ASU is effective for annual periods beginning after December 15, 2017, and interim periods within those years and early adoption is permitted in the year prior to the effective date. We expect to adopt this guidance in the first quarter of 2018. Management is evaluating the provisions of this accounting standards update and assessing the impact it may have on our consolidated statements of cash flows and related disclosures. In June 2016, the FASB issued ASU 2016-13, "Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments", which introduces new guidance for estimating credit losses on certain types of financial instruments based on expected losses and the timing of the recognition of such losses. For public entities, this ASU is effective for annual periods beginning after December 15, 2019, and interim periods within those years and early adoption is permitted in the year prior to the effective date. We expect to adopt this guidance in the first quarter of 2020. Management is evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows. In March 2016, the FASB issued ASU No. 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting” (“Update 2016-09”), which seeks to simplify several aspects of the accounting for share-based payment award transactions, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. For public entities, Update 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We will adopt this standard during the first quarter of 2017; we do not believe it will have a material effect on our consolidated results of operations, financial position or cash flows. In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842)” which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases. This ASU is effective for the annual period ending after December 15, 2018, and for annual interim periods thereafter. Early adoption is permitted. Management is currently evaluating the new guidance to determine the impact it will have on our consolidated results of operations, financial position or cash flows and anticipates adopting the guidance on the effective date of January 1, 2018. In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes” to simplify income tax accounting. The update requires that all deferred tax assets and liabilities be classified as noncurrent on the balance sheet instead of separating deferred taxes into current and noncurrent amounts. This update is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and may be adopted earlier on a voluntary basis. Effective January 1, 2016, the Company early adopted ASU 2015-17 which was applied prospectively and therefore the adoption had no impact on the consolidated balance sheet as of December 31, 2015. In April 2015, the FASB issued ASU No. 2015-03, “Interest-Imputation of Interest (Subtopic 835-30): Simplifiying the Presentation of Debt Issuance Costs”. The updated guidance requires debt issuance costs related to a recognized debt liability, other than those costs related to line of credit arrangements, be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, similar to the presentation for debt discounts and premiums, instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. This guidance became effective for the Company as of January 1, 2016. The Company’s adoption of this guidance was applied retrospectively, and approximately $1.8 million was moved from assets to a direct deduction from the carrying amount of the debt on the Company’s consolidated financial statements. In May 2014, August 2015 and May 2016, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers” , ASU 2015-14, “Revenue from Contracts with Customers, Deferral of the Effective Date”, ASU 2016-12, “Revenue from Contracts with Customers, Narrow-Scope Improvements and Practical Expedients”, and ASU 2016-20, “Revenue from Contracts with Customers, Technical Corrections and Improvements”, respectively, as a new Topic, Accounting Standards Codification Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. It also requires entities to disclose both quantitative and qualitative information that enable financial statements users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. This guidance is effective for annual periods beginning after December 15, 2017 with early adoption permitted on January 1, 2017 and shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. As we are in the process of evaluating the impact of the standard, we have not yet quantified the impact of adoption or determined the method of adoption. During 2017, we will perform the remainder of our implementation process, which will include quantification of impact, selection of adoption method and development of policies. The Company plans to adopt this guidance in the first quarter of 2018. |
Commodity Price Risk Activiti25
Commodity Price Risk Activities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Schedule of Derivative Transactions Outstanding | As of December 31, 2016, the following derivative transactions were outstanding: Instrument Total Volume Settlement Period Fixed Price Oil – WTI Fixed Price Swap 109,500 Bbl January – December 2017 $ 51.05 Oil – WTI Fixed Price Swap 73,000 Bbl January – December 2017 50.60 Oil – WTI Fixed Price Swap 365,000 Bbl January – December 2017 52.90 Oil – WTI Fixed Price Swap 365,000 Bbl January – December 2018 54.18 Oil – WTI Fixed Price Swap 182,500 Bbl January – December 2018 55.65 Natural Gas – Henry Hub NYMEX Fixed Price Swap 2,555,000 MMBtu January – December 2017 3.36 Instrument Total Volume Settlement Period Puts Calls Oil – 3 Way Collar 365,100 Bbl January – December 2017 $ 40.00 / 60.00 $ 85.00 Oil – 2 Way Collar 182,500 Bbl January – December 2018 50.00 59.45 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis | The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2016 and 2015, for each fair value hierarchy level: Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total December 31, 2015 (In thousands) Assets: Commodity derivatives $ — $ 36,083 $ — $ 36,083 Liabilities: Commodity derivatives — — — $ — Total $ — $ 36,083 $ — $ 36,083 December 31, 2016 (In thousands) Assets: Commodity derivatives $ — $ 1,730 $ — $ 1,730 Liabilities: Commodity derivatives — (4,110 ) — $ (4,110 ) Equity warrant liability — — (1,565 ) (1,565 ) Equity warrant liability - related parties — — (2,994 ) (2,994 ) Total $ — $ (2,380 ) $ (4,559 ) $ (6,939 ) |
Summary of Changes in Fair Value for the Level 3 Liability | The table below sets forth a summary of changes in the fair value of the Company’s level 3 liability for the year ended December 31, 2016. December 31, 2016 (In thousands) Balance, beginning of year $ — Purchases, sales, issuances and settlements (net) (5,127 ) Realized gains/(losses) — Unrealized gains/(losses) relating to instruments held at the reporting date 568 Balance, end of year $ (4,559 ) |
Oil and Gas Properties (Tables)
Oil and Gas Properties (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Extractive Industries [Abstract] | |
Summary of Oil and Gas Properties | A summary of oil and gas properties follows: December 31, 2016 December 31, 2015 (In thousands) Proved properties and equipment $ 538,695 $ 584,692 Unproved properties 72,584 70,298 Less accumulated depreciation, depletion, amortization, and impairment (172,051 ) (166,890 ) $ 439,228 $ 488,100 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Change in Asset Retirement Obligations | The following represents a reconciliation of the asset retirement obligations: Years Ended December 31, 2016 2015 (In thousands) Asset retirement obligations at beginning of period $ 7,488 $ 6,835 Wells drilled during the year 154 331 Wells acquired during the year 28 176 Wells sold during the year (4,780 ) (5 ) Accretion of discount 180 214 Revisions of previous estimates (1) (205 ) 13 Wells plugged and abandoned during the year (182 ) (76 ) Asset retirement obligations at end of period $ 2,683 $ 7,488 (1) Revisions of previous estimates during the year ended December 31, 2016 are primarily attributable to changes in estimates of the timing of future costs for oilfield services required to plug and abandon wells. |
Accrued Liabilities (Tables)
Accrued Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Payables And Accruals [Abstract] | |
Schedule of Accrued Liabilities | The accrued liabilities consist of the following at December 31: 2016 2015 (In thousands) Bonus payable $ 2,155 $ 1,433 Payroll payable 1 28 Accrued interest - 8.750% Senior Notes 2,924 4,064 Accrued interest - other 523 356 Accrued rent 298 410 Accrued well costs 3,366 1,339 Accrued severance, property and franchise taxes 431 62 Other 249 584 $ 9,947 $ 8,276 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Schedule of Long-Term Debt | The long-term debt consists of the following at December 31: 2016 2015 (In thousands) Senior Secured Credit Facility $ 43,500 $ 87,000 Second Lien Notes 11,367 — 8.750% Senior Notes 151,848 220,000 Less unamortized discount on 8.750% Senior Notes (1,708 ) (3,575 ) Less deferred financing costs on 8.750% Senior Notes (851 ) (1,785 ) Less deferred financing costs on Second Lien Notes (316 ) — Other 282 286 $ 204,122 $ 301,926 |
LRAI | |
Schedule of Redemption Prices Expressed as Percentages of Principal Amount | On or after April 15, 2016, LRAI may redeem the 8.750% Senior Notes in whole or in part at the redemption prices (expressed as percentages of the principal amount) set forth in the following table plus accrued and unpaid interest, if any, on the 8.750% Senior Notes redeemed, to the applicable date of redemption, if redeemed during the twelve-month period beginning on April 15 of the years indicated below: Year Percentage 2016 106.563 % 2017 104.375 % 2018 and thereafter 100.000 % |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Current and Deferred Components of Income Tax Expense (Benefit) | The current and deferred components of income tax expense (benefit) are as follows: Years Ended December 31, 2016 2015 Current income tax expense (In thousands) Federal $ 5,057 $ 288 State 341 74 Total current income tax expense 5,398 362 Deferred tax expense (benefit) Federal 21,909 (15,130 ) Foreign 270 — State (172 ) (353 ) Total deferred income tax expense (benefit) $ 22,007 $ (15,483 ) Total income tax expense (benefit) from continuing operations 27,405 (15,121 ) |
Difference between Income Taxes Computed at Federal Statutory Rate and Provision for Income Taxes | The following table provides a reconciliation of the Company’s actual income tax provision amounts from the expected income tax provision amount by applying the U.S. federal statutory corporate income tax rate of 35% for the periods indicated: Years Ended December 31, 2016 2015 (In thousands) Expected income tax provision (benefit) at statutory rate $ (23,416 ) $ (14,859 ) State tax, tax effected 52 11 Other 339 (40 ) Net operating loss write down 49,608 — Rate difference 311 (233 ) Permanent differences 511 — Actual income tax provision $ 27,405 $ (15,121 ) |
Deferred Tax Assets and Liabilities | The tax effects of the Company’s temporary differences that give rise to significant portions of the deferred tax assets and liabilities are presented below: December 31, 2016 2015 Deferred tax assets: (In thousands) Net operating loss carryforward $ 20,442 $ 77,508 Organizational expenses 52 57 Stock based compensation 2,593 2,431 Intangibles 682 776 Other 3,812 1,419 27,581 82,191 Deferred tax liabilities: Oil and gas properties and other property and equipment, principally due to intangible drilling costs (66,772 ) (86,790 ) Unrealized hedging loss (gain) 1,371 (11,414 ) Other (200 ) — Net deferred tax liabilities $ (38,020 ) $ (16,013 ) |
Stockholders' Equity and Stoc32
Stockholders' Equity and Stock Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Schedule of Outstanding Stock Options | The following tables summarize certain information related to outstanding stock options under the Lonestar Resources Limited 2012 Employee Share Option Plan and the Lonestar Resources US Inc. 2016 Incentive Plan, which replaced the Lonestar Resources Limited 2012 Employee Share Option Plan following the Reorganization: Shares Weighted Average Exercise Price Per Share Weighted Remaining Contractual Term (in years) Outstanding at December 31, 2015 849,936 $ 15.50 1.0 Options vested and exercisable at December 31, 2015 807,686 15.50 1.0 Granted 35,000 15.00 2.0 Exercised — — — Canceled/Expired (693,186 ) 18.00 — Forfeited — — — Outstanding at December 31, 2016 191,750 $ 15.00 0.5 Options vested and exercisable at December 31, 2016 191,750 $ 15.00 0.5 Shares Weighted Average Fair Value per Share Weighted Average Exercise Price per share Weighted Average Remaining Contractual Term (in years) Outstanding non-vested options at December 31, 2015 42,250 $ 9.00 $ 15.50 1.0 Granted 35,000 1.90 15.00 2.0 Vested (77,250 ) 8.00 15.00 1.0 Forfeited — — — — Outstanding non-vested options at December 31, 2016 — $ — $ — — |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Earnings Per Share [Abstract] | |
Schedule of Unaudited Earnings Per Share (After Reorganization) | The following table presents unaudited earnings per share of Lonestar Resources US Inc., assuming that the 1 for 2 reverse stock split upon Reorganization had occurred at the beginning of the year ended December 31, 2015: Unaudited Earnings Per Share (After Reorganization) Year Ended December 31, 2016 2015 Net income (loss) per common share: Basic $ (11.64 ) $ (3.63 ) Diluted (11.64 ) (3.63 ) Weighted average common shares outstanding: Basic 8,106,931 7,521,788 Diluted 8,106,931 7,521,788 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Commitments And Contingencies Disclosure [Abstract] | |
Schedule of Future Minimum Rental Payments for Operating Leases | The Company entered into an operating lease agreement for its primary facility in October 2014. The lease will expire in October 2021. Future minimum annual lease payments are as follows: Amount 2017 $ 464,996 2018 411,768 2019 422,301 2020 432,835 Thereafter 368,011 Total $ 2,099,911 |
Supplemental Cash Flow Inform35
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental Disclosures to the Consolidated Statements of Cash Flows | Supplemental disclosures to the consolidated statements of cash flows are presented below: Years Ended December 31, 2016 2015 (In Thousands) Cash paid for interest expense $ 23,691 $ 21,492 Cash paid for federal income taxes 1,820 257 Non-cash investing and financing activities: Common stock issued for asset acquisition 5,500 — Cost to issue equity included in accounts payable 1,000 — |
Nature of Business and Presen36
Nature of Business and Presentation - Additional Information (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Nature Of Business And Presentation [Line Items] | ||
Gain (loss) recorded under reorganization | $ 0 | |
Maturity period of highly liquid investments | three months or less | |
Allowance for uncollectible amount | $ 196,000 | |
Material credit loss | 0 | |
Impairment of oil and gas properties | 33,893,000 | $ 28,623,000 |
Net operating loss carryforward, wrote off | 141,700,000 | |
Liability for material uncertain tax positions | $ 0 | 0 |
Option vesting period | 3 years | |
Unproved Oil and Gas Properties | ||
Nature Of Business And Presentation [Line Items] | ||
Impairment of oil and gas properties | $ 4,800,000 | 8,900,000 |
Proven Oil and Gas Properties | ||
Nature Of Business And Presentation [Line Items] | ||
Impairment of oil and gas properties | $ 29,100,000 | $ 19,700,000 |
Minimum | Other Property and Equipment | ||
Nature Of Business And Presentation [Line Items] | ||
Estimated useful lives | 3 years | |
Maximum | Other Property and Equipment | ||
Nature Of Business And Presentation [Line Items] | ||
Estimated useful lives | 5 years | |
Sales Revenue, Net | Customer Concentration Risk | Trafigura AG | ||
Nature Of Business And Presentation [Line Items] | ||
Concentration risk, percentage | 18.00% | 38.00% |
Sales Revenue, Net | Customer Concentration Risk | BP Products North America LLC | ||
Nature Of Business And Presentation [Line Items] | ||
Concentration risk, percentage | 10.00% | 20.00% |
Sales Revenue, Net | Customer Concentration Risk | Shell Trading (US) Company | ||
Nature Of Business And Presentation [Line Items] | ||
Concentration risk, percentage | 40.00% | 16.00% |
Sales Revenue, Net | Customer Concentration Risk | Texla Energy Management, Inc | ||
Nature Of Business And Presentation [Line Items] | ||
Concentration risk, percentage | 21.00% | 11.00% |
Accounts Receivable | Customer Concentration Risk | Trafigura AG | ||
Nature Of Business And Presentation [Line Items] | ||
Concentration risk, percentage | 30.00% | 25.00% |
Accounts Receivable | Customer Concentration Risk | Shell Trading (US) Company | ||
Nature Of Business And Presentation [Line Items] | ||
Concentration risk, percentage | 49.00% | 26.00% |
Accounts Receivable | Customer Concentration Risk | Texla Energy Management, Inc | ||
Nature Of Business And Presentation [Line Items] | ||
Concentration risk, percentage | 13.00% | 23.00% |
Recently Issued Accounting Pr37
Recently Issued Accounting Pronouncements - Additional Information (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Accounting Standards Update 2015-03 | |
New Accounting Pronouncements Or Change In Accounting Principle [Line Items] | |
Moved from assets to a direct deduction from carrying amount of debt | $ 1.8 |
Acquisitions and Divestitures -
Acquisitions and Divestitures - Additional Information (Details) | Sep. 26, 2016USD ($) | Aug. 02, 2016USD ($)aWellshares | Jun. 15, 2016USD ($) | Jan. 31, 2015USD ($)aWell | Jun. 30, 2016aBoe | Mar. 31, 2016USD ($)a | Jun. 30, 2016USD ($)a | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2016USD ($) | Aug. 01, 2016a |
Business Acquisition [Line Items] | |||||||||||
Purchase and sale agreement date | Sep. 26, 2016 | ||||||||||
Business divestitures sale price | $ 14,000,000 | $ 2,200,000 | |||||||||
Business divestiture closing date | Oct. 31, 2016 | ||||||||||
Impairment of oil and gas properties | $ 29,100,000 | ||||||||||
Acquisition of oil and gas properties | $ 4,340,000 | $ 8,723,000 | |||||||||
Gain (loss) on divestitures of business | $ 1,900,000 | $ 74,000 | |||||||||
Business divestiture effective date of divestiture | Jul. 1, 2016 | ||||||||||
Production related to property barrels of oil equivalents per day | Boe | 86 | ||||||||||
Loss on exchange of oil and gas properties | $ (629,000) | ||||||||||
Number of non-operated wells working interest exchanged | Well | 2 | ||||||||||
Carter Lake - Wildcat Area | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Net mineral acres | a | 1,110 | ||||||||||
Percentage of interest through swap | 50.00% | ||||||||||
La Salle | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Payments to acquire land | $ 770,000 | ||||||||||
Area of land acquired | a | 220 | ||||||||||
La Salle | Eagle Ford Shale | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Payments to acquire land | $ 500,000 | ||||||||||
Area of land acquired | a | 159 | ||||||||||
Gonzales | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Payments to acquire land | $ 1,600,000 | ||||||||||
Area of land acquired | a | 1,088 | 1,088 | |||||||||
Juneau Energy, LLC | Brazos County | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Purchase and sale agreement date | Aug. 2, 2016 | ||||||||||
Net mineral acres | a | 1,300 | ||||||||||
Acquisition of oil and gas properties | $ 5,500,000 | ||||||||||
Productive Oil Wells, Number of Wells | Well | 2 | ||||||||||
Undivided interest acquired in producing wells | 50.00% | ||||||||||
Percentage of investment in assets | 50.00% | ||||||||||
Juneau Energy, LLC | Brazos County | Common Class A | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Shares of common stock payable in total purchase | shares | 500,227 |
Restricted Certificate of Dep39
Restricted Certificate of Deposit - Additional Information (Details) - Restricted Certificate of Deposit | 12 Months Ended |
Dec. 31, 2016 | |
Certificates Of Deposit [Line Items] | |
Investment maturity date | Mar. 8, 2018 |
Investment interest rate | 0.25% |
Commodity Price Risk Activiti40
Commodity Price Risk Activities - Additional Information (Details) | 12 Months Ended |
Dec. 31, 2016bbl / dMMBTU / dDeliveryObligationbbl | |
Derivative [Line Items] | |
Number of open physical obligations | DeliveryObligation | 0 |
Oil Derivative Contracts, 2017 | |
Derivative [Line Items] | |
Derivative contracts, aggregate volume | bbl | 912,600 |
Derivative contracts, aggregate volume per day | bbl / d | 2,500 |
Oil Derivative Contracts, 2018 | |
Derivative [Line Items] | |
Derivative contracts, aggregate volume | bbl | 730,000 |
Derivative contracts, aggregate volume per day | bbl / d | 2,000 |
Natural Gas Derivative Contracts, 2017 | |
Derivative [Line Items] | |
Derivative contracts, aggregate volume per day | MMBTU / d | 7,000 |
Commodity Price Risk Activiti41
Commodity Price Risk Activities - Schedule of Derivative Transactions Outstanding (Details) | 12 Months Ended |
Dec. 31, 2016MMBTU$ / bbl$ / MMBTUbbl | |
Oil – WTI Fixed Price Swap - $51.05 - Settlement Period - January - December 2017 | |
Derivative [Line Items] | |
Total Volume | bbl | 109,500 |
Fixed Price | 51.05 |
Oil – WTI Fixed Price Swap - $50.60 - Settlement Period - January - December 2017 | |
Derivative [Line Items] | |
Total Volume | bbl | 73,000 |
Fixed Price | 50.60 |
Oil - WTI Fixed Price Swap - $52.90 - Settlement Period - January - December 2017 | |
Derivative [Line Items] | |
Total Volume | bbl | 365,000 |
Fixed Price | 52.90 |
Oil - WTI Fixed Price Swap - $54.18 - Settlement Period - January - December 2018 | |
Derivative [Line Items] | |
Total Volume | bbl | 365,000 |
Fixed Price | 54.18 |
Oil - WTI Fixed Price Swap - $55.65 - Settlement Period - January - December 2018 | |
Derivative [Line Items] | |
Total Volume | bbl | 182,500 |
Fixed Price | 55.65 |
Natural Gas – Henry Hub NYMEX Fixed Price Swap - $3.36 - Settlement Period - January - December 2017 | |
Derivative [Line Items] | |
Total Energy | MMBTU | 2,555,000 |
Fixed Price | $ / MMBTU | 3.36 |
Oil - 3 Way Collar - Settlement Period - January - December 2017 | |
Derivative [Line Items] | |
Total Volume | bbl | 365,100 |
Oil - 3 Way Collar - Settlement Period - January - December 2017 | Puts | Minimum | |
Derivative [Line Items] | |
Fixed Price | 40 |
Oil - 3 Way Collar - Settlement Period - January - December 2017 | Puts | Maximum | |
Derivative [Line Items] | |
Fixed Price | 60 |
Oil - 3 Way Collar - Settlement Period - January - December 2017 | Calls | |
Derivative [Line Items] | |
Fixed Price | 85 |
Oil - 2 Way Collar - Settlement Period - January - December 2018 | |
Derivative [Line Items] | |
Total Volume | bbl | 182,500 |
Oil - 2 Way Collar - Settlement Period - January - December 2018 | Puts | |
Derivative [Line Items] | |
Fixed Price | 50 |
Oil - 2 Way Collar - Settlement Period - January - December 2018 | Calls | |
Derivative [Line Items] | |
Fixed Price | 59.45 |
Fair Value Measurements - Addit
Fair Value Measurements - Additional Information (Details) - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | |
Oct. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | |||
Impairment of oil and gas properties | $ 33,893 | $ 28,623 | |
8.750% Senior Notes Due April 15, 2019 | |||
Debt Instrument [Line Items] | |||
Fair value of senior notes | $ 139,300 | ||
Debt instrument interest rate | 8.75% | ||
Texas | |||
Debt Instrument [Line Items] | |||
Impairment of oil and gas properties | $ 29,100 | ||
Montana | |||
Debt Instrument [Line Items] | |||
Impairment related to leased acreage | $ 1,900 | ||
Wilson County | |||
Debt Instrument [Line Items] | |||
Impairment related to leased acreage | $ 2,800 | ||
Leased acreage expiration date | Oct. 31, 2016 |
Fair Value Measurements - Sched
Fair Value Measurements - Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Equity warrant liability | $ (1,565) | |
Equity warrant liability - related parties | (2,994) | |
Total | (6,939) | $ 36,083 |
Commodity Derivatives | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets | 1,730 | 36,083 |
Liabilities | (4,110) | |
Significant Other Observable Inputs (Level 2) | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total | (2,380) | 36,083 |
Significant Other Observable Inputs (Level 2) | Commodity Derivatives | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Assets | 1,730 | $ 36,083 |
Liabilities | (4,110) | |
Significant Unobservable Inputs (Level 3) | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Equity warrant liability | (1,565) | |
Equity warrant liability - related parties | (2,994) | |
Total | $ (4,559) |
Fair Value Measurements - Summa
Fair Value Measurements - Summary of Changes in Fair Value for the Level 3 Liability (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Fair Value Disclosures [Abstract] | |
Balance, beginning of year | $ 0 |
Purchases, sales, issuances and settlements (net) | (5,127) |
Unrealized gains/(losses) relating to instruments held at the reporting date | 568 |
Balance, end of year | $ (4,559) |
Oil and Gas Properties - Summar
Oil and Gas Properties - Summary of Oil and Gas Properties (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | ||
Proved properties and equipment | $ 538,695 | $ 584,692 |
Unproved properties | 72,584 | 70,298 |
Less accumulated depreciation, depletion, amortization, and impairment | (172,051) | (166,890) |
Oil and gas property, net | $ 439,228 | $ 488,100 |
Asset Retirement Obligations -
Asset Retirement Obligations - Additional Information (Details) $ in Millions | Dec. 31, 2016USD ($) |
Asset Retirement Obligation [Abstract] | |
Capitalized asset retirement cost | $ 2.5 |
Asset Retirement Obligations 47
Asset Retirement Obligations - Schedule of Change in Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligation [Abstract] | ||
Asset retirement obligations at beginning of period | $ 7,488 | $ 6,835 |
Wells drilled during the year | 154 | 331 |
Wells acquired during the year | 28 | 176 |
Wells sold during the year | (4,780) | (5) |
Accretion of discount | 180 | 214 |
Revisions of previous estimates | (205) | 13 |
Wells plugged and abandoned during the year | (182) | (76) |
Asset retirement obligations at end of period | $ 2,683 | $ 7,488 |
Accrued Liabilities - Schedule
Accrued Liabilities - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Payables And Accruals [Abstract] | ||
Bonus payable | $ 2,155 | $ 1,433 |
Payroll payable | 1 | 28 |
Accrued interest - 8.750% Senior Notes | 2,924 | 4,064 |
Accrued interest - other | 523 | 356 |
Accrued rent | 298 | 410 |
Accrued well costs | 3,366 | 1,339 |
Accrued severance, property and franchise taxes | 431 | 62 |
Other | 249 | 584 |
Accrued liabilities excluding due to related parties | $ 9,947 | $ 8,276 |
Long-Term Debt - Schedule of De
Long-Term Debt - Schedule of Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Debt Instrument [Line Items] | ||
Senior Secured Credit Facility | $ 43,500 | $ 87,000 |
Second Lien Notes | 11,367 | |
8.750% Senior Notes | 151,848 | 220,000 |
Less unamortized discount on 8.750% Senior Notes | (1,708) | (3,575) |
Other | 282 | 286 |
Long-term debt net of deferred financing costs on bonds | 204,122 | 301,926 |
8.750% Senior Notes Due April 15, 2019 | ||
Debt Instrument [Line Items] | ||
Less deferred financing costs | (851) | $ (1,785) |
Second Lien Notes | ||
Debt Instrument [Line Items] | ||
Less deferred financing costs | $ (316) |
Long-Term Debt - Senior Secured
Long-Term Debt - Senior Secured Credit Facility - Additional Information (Details) - USD ($) | Jul. 27, 2016 | Jul. 28, 2015 | Dec. 31, 2016 | May 19, 2016 | Dec. 31, 2015 |
Debt Instrument [Line Items] | |||||
Senior Secured Credit Facility | $ 43,500,000 | $ 87,000,000 | |||
Senior Secured Credit Facility | |||||
Debt Instrument [Line Items] | |||||
Senior secured credit facility sub limit | $ 2,500,000 | ||||
Senior Secured Credit Facility | Minimum | |||||
Debt Instrument [Line Items] | |||||
Commitment fee percentage | 0.375% | ||||
Senior Secured Credit Facility | Maximum | |||||
Debt Instrument [Line Items] | |||||
Commitment fee percentage | 0.50% | ||||
Third Amendment to Credit Agreement and Limited Waiver (the Amendment) | |||||
Debt Instrument [Line Items] | |||||
Line of credit facility commitment fee percentage | 0.50% | ||||
Leverage ratio | 400.00% | ||||
Third Amendment to Credit Agreement and Limited Waiver (the Amendment) | Quarter Period Ending June Thirty Two Thousand Sixteen | |||||
Debt Instrument [Line Items] | |||||
Leverage ratio | 475.00% | ||||
Third Amendment to Credit Agreement and Limited Waiver (the Amendment) | Quarter Period Ending September Thirty Two Thousand Sixteen | |||||
Debt Instrument [Line Items] | |||||
Leverage ratio | 450.00% | ||||
Third Amendment to Credit Agreement and Limited Waiver (the Amendment) | Quarter Period Ending December Thirty One Two Thousand Sixteen | |||||
Debt Instrument [Line Items] | |||||
Leverage ratio | 425.00% | ||||
Third Amendment to Credit Agreement and Limited Waiver (the Amendment) | All Periods After December Thirty One Two Thousand Sixteen | |||||
Debt Instrument [Line Items] | |||||
Leverage ratio | 400.00% | ||||
Third Amendment to Credit Agreement and Limited Waiver (the Amendment) | Letter of Credit | |||||
Debt Instrument [Line Items] | |||||
Increase margin on loans | 0.75% | ||||
Third Amendment to Credit Agreement and Limited Waiver (the Amendment) | ABR | |||||
Debt Instrument [Line Items] | |||||
Increase margin on loans | 0.75% | ||||
Third Amendment to Credit Agreement and Limited Waiver (the Amendment) | Eurodollar | |||||
Debt Instrument [Line Items] | |||||
Increase margin on loans | 0.75% | ||||
Citibank N A | Senior Secured Credit Facility | |||||
Debt Instrument [Line Items] | |||||
Debt instrument expanded borrowing base | $ 120,000,000 | 180,000,000 | |||
Debt instrument maturity date | Oct. 16, 2018 | ||||
Senior Secured Credit Facility | $ 43,500,000 | $ 87,000,000 | |||
Citibank N A | Senior Secured Credit Facility | LIBOR | |||||
Debt Instrument [Line Items] | |||||
Debt instrument basis spread on variable rate | 0.25% | ||||
Wells Fargo Led Facility | |||||
Debt Instrument [Line Items] | |||||
Debt instrument face amount | $ 400,000,000 | ||||
LRAI | Senior Secured Credit Facility | |||||
Debt Instrument [Line Items] | |||||
Debt instrument basis spread on variable rate | 3.64% | ||||
LRAI | Senior Secured Credit Facility | Maximum | |||||
Debt Instrument [Line Items] | |||||
Lien percentage of assets for senior secured credit facility | 80.00% | ||||
LRAI | Senior Secured Credit Facility | LIBOR | |||||
Debt Instrument [Line Items] | |||||
Debt instrument basis spread on variable rate | 1.00% | ||||
Margin of loans, minimum | 1.75% | ||||
Margin of loans, maximum | 2.75% | ||||
LRAI | Senior Secured Credit Facility | Federal Funds Effective Rate | |||||
Debt Instrument [Line Items] | |||||
Debt instrument basis spread on variable rate | 0.50% | ||||
LRAI | Senior Secured Credit Facility | ABR | |||||
Debt Instrument [Line Items] | |||||
Margin of loans, minimum | 0.75% | ||||
Margin of loans, maximum | 1.75% | ||||
LRAI | Third Amendment to Credit Agreement and Limited Waiver (the Amendment) | Minimum | |||||
Debt Instrument [Line Items] | |||||
Percentage of value of oil and gas properties that must be mortgaged as collateral | 90.00% | 80.00% | |||
LRAI | Citibank N A | Senior Secured Credit Facility | |||||
Debt Instrument [Line Items] | |||||
Debt instrument face amount | $ 500,000,000 |
Long-Term Debt - 8.750% Senior
Long-Term Debt - 8.750% Senior Notes - Additional Information (Details) - 8.750% Senior Notes Due April 15, 2019 - USD ($) | Apr. 15, 2016 | Apr. 04, 2014 | Dec. 31, 2016 |
Debt Instrument [Line Items] | |||
Debt instrument interest rate | 8.75% | ||
Debt instrument maturity date | Apr. 15, 2019 | ||
LRAI | |||
Debt Instrument [Line Items] | |||
Debt instrument face amount | $ 220,000,000 | ||
Debt instrument interest rate | 8.75% | ||
Debt instrument maturity date | Apr. 15, 2019 | ||
Net proceeds from offering | $ 212,000,000 | ||
Prepayment fee | $ 1,100,000 | ||
Prepayment fee percentage on principal balance | 2.00% | ||
Redemption price, percentage | 101.00% |
Long-Term Debt - Schedule of Re
Long-Term Debt - Schedule of Redemption Prices Expressed as Percentages of Principal Amount (Details) - LRAI - 8.750% Senior Notes Due April 15, 2019 | Apr. 15, 2016 |
Debt Instrument Redemption [Line Items] | |
Redemption price, percentage | 101.00% |
Unsecured Debt | 2016 | |
Debt Instrument Redemption [Line Items] | |
Redemption price, percentage | 106.563% |
Unsecured Debt | 2017 | |
Debt Instrument Redemption [Line Items] | |
Redemption price, percentage | 104.375% |
Unsecured Debt | 2018 and Thereafter | |
Debt Instrument Redemption [Line Items] | |
Redemption price, percentage | 100.00% |
Long-Term Debt - Debt Issuance
Long-Term Debt - Debt Issuance Costs - Additional Information (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Senior Secured Credit Facility | ||
Debt Instrument [Line Items] | ||
Debt issuance costs | $ 1,200,000 | $ 1,100,000 |
Long-Term Debt - Securities Pur
Long-Term Debt - Securities Purchase Agreement and Second Lien Notes - Additional Information (Details) - USD ($) | Aug. 02, 2016 | Dec. 31, 2016 |
Debt Instrument [Line Items] | ||
Unrealized gain on warrants | $ 568,000 | |
Common Class A | ||
Debt Instrument [Line Items] | ||
Warrants to purchase common stock | 760,000 | |
Warrant liability | $ 5,100,000 | |
Second Lien Notes | ||
Debt Instrument [Line Items] | ||
Debt instrument face amount | 38,000,000 | |
Repayment of principal second lien notes | $ 21,000,000 | |
8.750% Senior Notes Due April 15, 2019 | ||
Debt Instrument [Line Items] | ||
Debt instrument interest rate | 8.75% | |
Debt instrument repurchase amount | $ 68,200,000 | |
Debt instrument maturity date | Apr. 15, 2019 | |
Cash paid for repurchase of debt instrument | $ 36,200,000 | |
Gain on repurchase of debt instrument | $ 28,500,000 | |
Securities Purchase Agreement | 12% Senior Secured Second Lien Notes Due 2021 | ||
Debt Instrument [Line Items] | ||
Debt instrument interest rate | 12.00% | |
Sale of stock, description of transaction | (i) up to $49,900,000 aggregate principal amount of LRAI’s 12% senior secured second lien notes due 2021 (the “Second Lien Notes”) and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A common stock at a price equal to $5.00 per share (the “Warrants”). | |
Common stock price per share | $ 5 | |
Securities Purchase Agreement | 12% Senior Secured Second Lien Notes Due 2021 | Maximum | ||
Debt Instrument [Line Items] | ||
Debt instrument face amount | $ 49,900,000 | |
Number of common shares issued | 998,000 |
Long-Term Debt - Repurchase Fac
Long-Term Debt - Repurchase Facilitation Agreement - Additional Information (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Sep. 30, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | |||
Long-term debt | $ 204,122,000 | $ 301,926,000 | |
Seaport Global Securities LLC | |||
Debt Instrument [Line Items] | |||
Long-term debt | $ 2,063,320 | ||
8.750% Senior Notes Due April 15, 2019 | |||
Debt Instrument [Line Items] | |||
Debt instrument interest rate | 8.75% | ||
Debt instrument maturity date | Apr. 15, 2019 |
Income Taxes - Current and Defe
Income Taxes - Current and Deferred Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Current income tax expense | ||
Federal | $ 5,057 | $ 288 |
State | 341 | 74 |
Total current income tax expense | 5,398 | 362 |
Deferred tax expense (benefit) | ||
Federal | 21,909 | (15,130) |
Foreign | 270 | |
State | (172) | (353) |
Total deferred income tax expense (benefit) | 22,007 | (15,483) |
Total income tax expense (benefit) from continuing operations | $ 27,405 | $ (15,121) |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Details) - USD ($) shares in Millions, $ in Millions | Dec. 22, 2016 | Dec. 31, 2016 |
Income Taxes [Line Items] | ||
Statutory tax rate | 35.00% | |
Net operating loss carryforward | $ 199.9 | |
Deductions for excess stock-based compensation | 2.2 | |
Net operating loss carryforward written off | $ 141.7 | |
Operating loss carryforwards annual installment amount | $ 1 | |
Depletion carryover amount | $ 10 | |
Common Class A | ||
Income Taxes [Line Items] | ||
Sale of common stock, net of offering costs (in shares) | 13.8 |
Income Taxes - Difference betwe
Income Taxes - Difference between Income Taxes Computed at Federal Statutory Rate and Provision for Income Taxes (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | ||
Expected income tax provision (benefit) at statutory rate | $ (23,416) | $ (14,859) |
State tax, tax effected | 52 | 11 |
Other | 339 | (40) |
Net operating loss write down | 49,608 | |
Rate difference | 311 | (233) |
Permanent differences | 511 | |
Total income tax expense (benefit) from continuing operations | $ 27,405 | $ (15,121) |
Income Taxes - Deferred Tax Ass
Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Deferred tax assets: | ||
Net operating loss carryforward | $ 20,442 | $ 77,508 |
Organizational expenses | 52 | 57 |
Stock based compensation | 2,593 | 2,431 |
Intangibles | 682 | 776 |
Other | 3,812 | 1,419 |
Deferred Tax Asset | 27,581 | 82,191 |
Deferred tax liabilities: | ||
Oil and gas properties and other property and equipment, principally due to intangible drilling costs | (66,772) | (86,790) |
Unrealized hedging loss (gain) | 1,371 | (11,414) |
Other | (200) | |
Net deferred tax liabilities | $ (38,020) | $ (16,013) |
Stockholders' Equity and Stoc60
Stockholders' Equity and Stock Based Compensation - Additional Information (Details) | Dec. 22, 2016USD ($)$ / sharesshares | Sep. 26, 2016 | Aug. 02, 2016USD ($)aWellshares | Jul. 31, 2016shares | Jul. 05, 2016USD ($) | Dec. 31, 2016USD ($)shares | Dec. 31, 2015USD ($) |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||
Proceeds from issuance of common stock, net of offering costs | $ 72,807,000 | ||||||
Purchase and sale agreement date | Sep. 26, 2016 | ||||||
Total consideration paid | $ 4,340,000 | $ 8,723,000 | |||||
Expected life of stock options issued | 3 years 6 months | ||||||
Stock options vesting periods | 3 years | ||||||
Stock options grant expirations periods | 4 years | ||||||
Stock options exercised | shares | 0 | ||||||
Compensation expenses for stock options granted using fair-value method | $ 448,000 | $ 2,585,000 | |||||
Unrecognized compensation cost related to stock options | $ 0 | ||||||
Predecessor | |||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||
Weighted average volatility rate of common share price | 58.60% | ||||||
Cash dividend on common shares | $ 0 | ||||||
Juneau Energy, LLC | Brazos County | |||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||
Purchase and sale agreement date | Aug. 2, 2016 | ||||||
Undivided interest acquired in producing wells | 50.00% | ||||||
Productive Oil Wells, Number of Wells | Well | 2 | ||||||
Net mineral acres | a | 1,300 | ||||||
Total consideration paid | $ 5,500,000 | ||||||
Common Class A | |||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||
Common stock shares issued | shares | 13,800,000 | ||||||
Common Class A | Juneau Energy, LLC | Brazos County | |||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||
Shares of common stock payable in total purchase | shares | 500,227 | ||||||
Class B Non-Voting Common Stock | |||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||
Common stock, shares issued | shares | 2,500 | ||||||
2016 Common Stock Offering | Common Class A | |||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||
Common stock shares issued | shares | 13,800,000 | ||||||
Shares issued, price per share | $ / shares | $ 5.75 | ||||||
Proceeds from issuance of common stock, net of offering costs | $ 71,800,000 |
Stockholders' Equity and Stoc61
Stockholders' Equity and Stock Based Compensation - Schedule of Outstanding Stock Options (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Outstanding Shares [Roll Forward] | ||
Exercised, Shares | 0 | |
Outstanding, Weighted Average Remaining Contractual Term (in years) | 3 years 6 months | |
Lonestar Resources Limited 2012 Employee Share Option Plan and Lonestar Resources US Inc 2016 Employee Incentive Plan | ||
Outstanding Shares [Roll Forward] | ||
Outstanding at beginning of period, Shares | 849,936 | |
Granted, Shares | 35,000 | |
Canceled/Expired, Shares | (693,186) | |
Outstanding at end of period, Shares | 191,750 | 849,936 |
Outstanding at beginning of period, Weighted Average Exercise Price Per Share | $ 15.50 | |
Granted, Weighted Average Exercise Price Per Share | 15 | |
Canceled/Expired , Weighted Average Exercise Price Per Share | 18 | |
Outstanding at end of period, Weighted Average Exercise Price Per Share | $ 15 | $ 15.50 |
Outstanding, Weighted Average Remaining Contractual Term (in years) | 6 months | 1 year |
Options vested and exercisable, Weighted Average Remaining Contractual Term (in years) | 6 months | 1 year |
Granted, Weighted Average Remaining Contractual Term (in years) | 2 years | |
Options vested and exercisable, Shares | 191,750 | 807,686 |
Options vested and exercisable, Weighted Average Exercise Price Per Share | $ 15 | $ 15.50 |
Non-vested Shares [Roll Forward] | ||
Outstanding non-vested options at beginning of period, Shares | 42,250 | |
Granted, Shares | 35,000 | |
Vested, Shares | (77,250) | |
Outstanding non-vested options at end of period, Shares | 42,250 | |
Outstanding non-vested options at beginning of period, Weighted Average Fair Value per Share | $ 9 | |
Granted, Weighted Average Fair Value per Share | 1.90 | |
Vested, Weighted Average Fair Value per Share | $ 8 | |
Outstanding non-vested options at ending of period, Weighted Average Fair Value per Share | $ 9 | |
Outstanding non-vested options, Weighted Average Remaining Contractual Term (in years) | 1 year | |
Granted non-vested options, Weighted Average Remaining Contractual Term (in years) | 2 years | |
Vested non-vested options, Weighted Average Remaining Contractual Term (in years) | 1 year | |
Outstanding non-vested options beginning of period, Weighted Average Exercise Price per share | $ 15.50 | |
Granted, Weighted Average Exercise Price per share | 15 | |
Vested, Weighted Average Exercise Price per share | $ 15 | |
Outstanding non-vested options end of period, Weighted Average Exercise Price per share | $ 15.50 | |
Outstanding non-vested options, Weighted Average Remaining Contractual Term (in years) | 1 year |
Earnings Per Share - Additional
Earnings Per Share - Additional Information (Details) | 12 Months Ended | |
Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Earnings Per Share [Abstract] | ||
Dilutive effect of earnings per share | $ 0 | $ 0 |
Reverse stock split, conversion ratio | 2 | 2 |
Earnings Per Share - Schedule o
Earnings Per Share - Schedule of Unaudited Earnings Per Share (After Reorganization) (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Net income (loss) per common share: | ||
Basic | $ (11.64) | $ (3.63) |
Diluted | $ (11.64) | $ (3.63) |
Weighted average common shares outstanding: | ||
Basic | 8,106,931 | 7,521,788 |
Diluted | 8,106,931 | 7,521,788 |
Related Party Activities - Addi
Related Party Activities - Additional Information (Details) | Dec. 22, 2016USD ($)shares | Aug. 02, 2016USD ($)ashares | Jul. 31, 2016shares | Dec. 31, 2016USD ($)shares | Dec. 31, 2016USD ($)shares | Dec. 31, 2015USD ($) | Oct. 26, 2016Director | Aug. 01, 2016a | Apr. 30, 2014USD ($) |
Related Party Transaction [Line Items] | |||||||||
Registration rights agreement description | The Company entered into a Registration Rights Agreement with EF Realisation, pursuant to which we agreed to register for resale Class A common stock held by EF Realisation. We have agreed to file a registration statement providing for the resale of Class A common stock held by EF Realisation no later than the earlier of (i) October 26, 2017, and (ii) 30 days after the date we first become eligible to file a registration statement on Form S-3. We have also granted EF Realisation certain piggyback and demand registration rights. | ||||||||
Common Class A | |||||||||
Related Party Transaction [Line Items] | |||||||||
Warrants to purchase common stock | shares | 760,000 | 760,000 | |||||||
Class B Non-Voting Common Stock | |||||||||
Related Party Transaction [Line Items] | |||||||||
Common stock, shares issued | shares | 2,500 | ||||||||
Securities Purchase Agreement | Common Class A | |||||||||
Related Party Transaction [Line Items] | |||||||||
Shares of common stock for exchange | shares | 500,227 | ||||||||
Carter Lake - Wildcat Area | |||||||||
Related Party Transaction [Line Items] | |||||||||
Percentage of interest through swap | 50.00% | ||||||||
Net mineral acres | a | 1,110 | ||||||||
Leucadia | |||||||||
Related Party Transaction [Line Items] | |||||||||
Equity offering cost | $ 1,000,000 | ||||||||
Leucadia | Class A Voting Common Stock | |||||||||
Related Party Transaction [Line Items] | |||||||||
Number of common shares issued | shares | 3,478,261 | ||||||||
Common shares issued, Value | $ 20,000,000 | ||||||||
Leucadia | Class A Voting Common Stock | Maximum | |||||||||
Related Party Transaction [Line Items] | |||||||||
Commitment amount | $ 20,000,000 | ||||||||
Leucadia | Class A Voting Common Stock | Minimum | |||||||||
Related Party Transaction [Line Items] | |||||||||
Percentage of common stock | 10.00% | ||||||||
Leucadia | Securities Purchase Agreement | Maximum | |||||||||
Related Party Transaction [Line Items] | |||||||||
Debt instrument face amount | $ 49,900,000 | ||||||||
Warrants to purchase common stock | shares | 998,000 | ||||||||
Juneau Energy, LLC | |||||||||
Related Party Transaction [Line Items] | |||||||||
Percentage of investment in assets | 50.00% | ||||||||
Net mineral acres | a | 1,300 | ||||||||
Juneau Energy, LLC | Securities Purchase Agreement | |||||||||
Related Party Transaction [Line Items] | |||||||||
Debt instrument face amount | $ 13,000,000 | ||||||||
Warrants to purchase common stock | shares | 500,000 | ||||||||
Sale of stock, description of transaction | (i) up to $49,900,000 aggregate principal amount of Second Lien Notes and (ii) Warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A common stock. Pursuant to the Purchase Agreement Juneau purchased $13,000,000 aggregate principal amount of Second Lien Notes and Warrants to purchase 500,000 shares of Class A common stock. On August 2, 2016, the Company also issued 500,227 shares of Class A common stock to Juneau pursuant in exchange for interests in certain oil and gas assets pursuant to a purchase and sale agreement (the “Purchase and Sale Agreement”). As part of the Purchase and Sale Agreement, the Company entered into a swap of assets of 50% of its interest in the Carter Lake - Wildcat area for 50% of the assets owned by Juneau in the 1,300 net mineral acres. The Company owned 1,110 net mineral acres (“Swap Assets”) in the Carter Lake - Wildcat area on August 1, 2016. As further part of the Purchase and Sale Agreement, the Company agreed to commence operations on drilling one (1) Eagle Ford Shale well by December 31, 2016 on Juneau Energy, LLC’s assets or the Swap Assets; and, another Eagle Ford Shale well on Juneau Energy LLC’s assets or the Swap Assets by December 31, 2017. As of December 31, 2016, the Company had commenced drilling operations of two (2) Eagle Ford Shale wells satisfying the drilling commitment provision under the Purchase and Sale Agreement. | ||||||||
EF Realisation | Class A Voting Common Stock | Board Representation Agreement | |||||||||
Related Party Transaction [Line Items] | |||||||||
Minimum ownership percentage on common stock issued and outstanding required for nominating two directors | 15.00% | ||||||||
Minimum ownership percentage on common stock issued and outstanding required for nominating one director | 10.00% | ||||||||
EF Realisation | Class A Voting Common Stock | Maximum | |||||||||
Related Party Transaction [Line Items] | |||||||||
Number of directors to be nominated | Director | 2 | ||||||||
EF Realisation | Class A Voting Common Stock | Minimum | |||||||||
Related Party Transaction [Line Items] | |||||||||
Number of directors to be nominated | Director | 1 | ||||||||
Frank D. Bracken, III and Thomas H. Olle | |||||||||
Related Party Transaction [Line Items] | |||||||||
Total loan amount to related parties | $ 539,000 | ||||||||
Butterfly Flaps, Ltd | |||||||||
Related Party Transaction [Line Items] | |||||||||
Cost of consultancy services | $ 25,000 | ||||||||
New Tech Global Ventures, LLC | |||||||||
Related Party Transaction [Line Items] | |||||||||
Cost of consultancy services | $ 665,000 | $ 938,000 | |||||||
BlueSkye Pty Ltd | |||||||||
Related Party Transaction [Line Items] | |||||||||
Cost of consultancy services | $ 95,000 | $ 142,500 |
Commitments and Contingencies -
Commitments and Contingencies - Schedule of Future Minimum Rental Payments for Operating Leases (Details) | Dec. 31, 2016USD ($) |
Operating Leases, Future Minimum Payments Due | |
2,017 | $ 464,996 |
2,018 | 411,768 |
2,019 | 422,301 |
2,020 | 432,835 |
Thereafter | 368,011 |
Total | $ 2,099,911 |
Contingencies and Commitments -
Contingencies and Commitments - Additional Information (Details) | 12 Months Ended | |
Dec. 31, 2016USD ($)Drilling_Rig | Dec. 31, 2015USD ($)Drilling_Rig | |
Loss Contingencies [Line Items] | ||
Operating leases, rent expense | $ 375,000 | $ 404,000 |
Drilling Rig | ||
Loss Contingencies [Line Items] | ||
Number of drilling rigs under contract | Drilling_Rig | 1 | 1 |
Daily drilling rate | $ 15,000 | $ 19,000 |
Leased acreage expiration date | Jul. 8, 2017 | Jul. 20, 2016 |
Early termination fee percentage | 80.00% | 75.00% |
Drilling rig termination fee description | As of December 31, 2016, The early termination fee is equal to 80% of the daily drilling rate times the number of days remaining on the contract term. Using the $15,000 daily rate, as of December 31, 2016 the minimum remaining commitment per the terms of the agreement was approximately $2.7 million. As of December 31, 2015, The early termination fee is equal to 75% of the highest month operating rate earned during the 2016 contract period times the number of days remaining on the contract term. Using the $19,000 daily rate, as of December 31, 2015 the minimum remaining commitment per the terms of the agreement was approximately $3.8 million. | |
Drilling Rig | Minimum | ||
Loss Contingencies [Line Items] | ||
Drilling rig remaining commitment | $ 2,700,000 | $ 3,800,000 |
Supplemental Cash Flow Inform67
Supplemental Cash Flow Information - Supplemental Disclosures to the Consolidated Statements of Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Supplemental Cash Flow Elements [Abstract] | ||
Cash paid for interest expense | $ 23,691 | $ 21,492 |
Cash paid for federal income taxes | 1,820 | $ 257 |
Non-cash investing and financing activities: | ||
Common stock issued for asset acquisition | 5,500 | |
Cost to issue equity included in accounts payable | $ 1,000 |