Document and Entity Information
Document and Entity Information | 9 Months Ended |
Sep. 30, 2016 | |
Document And Entity Information [Abstract] | |
Document Type | S-1/A |
Amendment Flag | false |
Document Period End Date | Sep. 30, 2016 |
Trading Symbol | LONE |
Entity Registrant Name | Lonestar Resources US Inc. |
Entity Central Index Key | 1,661,920 |
Entity Filer Category | Smaller Reporting Company |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) | Sep. 30, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Current assets | |||
Cash and cash equivalents | $ 5,990,000 | $ 4,321,456 | $ 9,992,477 |
Accounts receivable: | |||
Oil, natural gas liquid and natural gas sales | 4,879,000 | 5,043,398 | 8,987,525 |
Joint interest owners and other | 884,000 | 1,305,146 | 7,933,752 |
Related parties | 279,043 | 562,634 | |
Derivative financial instruments | 8,538,000 | 33,218,474 | 31,045,260 |
Prepaid expenses and other | 1,749,000 | 723,988 | 654,880 |
Total current assets | 22,040,000 | 44,891,505 | 59,176,528 |
Oil and gas properties, net, using the successful efforts method of accounting | 432,169,000 | 488,099,597 | 481,079,275 |
Oil and gas properties held for sale | 18,120,000 | ||
Other property and equipment, net | 1,963,000 | 2,223,399 | 2,366,013 |
Derivative financial instruments | 315,000 | 2,864,372 | 12,713,295 |
Other noncurrent assets | 2,185,000 | 1,580,000 | |
Other noncurrent assets including deferred financing costs on bonds | 3,364,621 | 3,608,331 | |
Restricted certificates of deposit | 78,000 | 77,397 | 125,980 |
Total assets | 476,870,000 | 539,736,000 | 559,069,422 |
Current liabilities | |||
Accounts payable | 9,410,000 | 18,027,156 | 30,650,081 |
Accounts payable - related parties | 175,000 | 44,848 | 192,187 |
Oil, natural gas liquid and natural gas sales payable | 3,475,000 | 3,870,464 | 4,961,510 |
Accrued liabilities | 12,450,000 | 8,276,085 | 11,605,120 |
Accrued liabilities - related parties | 356,000 | 125,000 | |
Current income tax payable | 5,581,000 | ||
Derivative financial instruments | 420,000 | ||
Total current liabilities | 31,867,000 | 30,343,553 | 47,408,898 |
Long-term debt net of deferred financing costs on bonds | 277,688,000 | 301,926,000 | |
Long-term debt | 303,710,512 | 264,613,529 | |
Deferred tax liability | 16,013,276 | 31,510,744 | |
Other non-current liabilities | 1,000,000 | 1,000,000 | 1,000,000 |
Equity warrant liability | 5,738,000 | ||
Asset retirement obligations | 2,636,000 | 7,487,501 | 6,834,615 |
Asset retirement obligations - Held for sale | 4,505,000 | ||
Derivative financial instruments | 78,000 | ||
Total liabilities | 323,512,000 | 356,770,000 | 351,367,786 |
Commitments and contingencies | |||
Stockholders' equity | |||
Common stock | 142,637,636 | 142,637,636 | |
Additional paid-in capital | 15,303,000 | 10,270,288 | 7,685,177 |
Accumulated other comprehensive loss | (760,366) | (772,633) | |
Retained (deficit) earnings | (4,583,000) | 30,818,491 | 58,151,456 |
Total stockholders' equity | 153,358,000 | 182,966,049 | 207,701,636 |
Total liabilities and stockholders' equity | 476,870,000 | 539,736,000 | $ 559,069,422 |
Class A Voting Common Stock | |||
Stockholders' equity | |||
Common stock | $ 142,638,000 | 142,637,636 | |
Scenario, Previously Reported | |||
Accounts receivable: | |||
Total assets | 541,520,891 | ||
Current liabilities | |||
Total liabilities | 358,554,842 | ||
Stockholders' equity | |||
Total liabilities and stockholders' equity | $ 541,520,891 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) | Sep. 30, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Other property and equipment, accumulated depreciation | $ 1,067,956 | $ 680,002 | |
Common stock, par value | $ 0.20 | $ 0.20 | |
Common stock, shares authorized | 500,000,000 | 500,000,000 | |
Common stock, shares issued | 15,044,051 | 14,661,004 | |
Common stock, shares outstanding | 15,044,051 | 14,661,004 | |
Class A Voting Common Stock | |||
Common stock, par value | $ 0.001 | $ 0.001 | |
Common stock, shares authorized | 15,000,000 | 15,000,000 | |
Common stock, shares issued | 8,022,015 | 7,521,788 | |
Common stock, shares outstanding | 8,022,015 | 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) Income - USD ($) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenues | ||||||
Oil sales | $ 12,285,000 | $ 18,849,000 | $ 36,404,000 | $ 56,408,000 | $ 70,739,269 | $ 104,233,379 |
Natural gas sales | 2,190,000 | 1,612,000 | 5,448,000 | 4,091,000 | 6,823,019 | 7,589,599 |
Natural gas liquid sales | 1,063,000 | 416,000 | 2,685,000 | 1,538,000 | 1,928,068 | 3,803,582 |
Total revenues | 15,538,000 | 20,877,000 | 44,537,000 | 62,037,000 | 79,490,356 | 115,626,560 |
Costs and expenses | ||||||
Lease operating and gas gathering | 4,006,000 | 4,616,000 | 12,764,000 | 12,666,000 | 17,853,428 | 16,631,611 |
Production, ad valorem, and severance taxes | 907,000 | 1,376,000 | 3,046,000 | 4,203,000 | 4,981,826 | 7,123,332 |
Rig standby expense | 364,000 | 10,000 | 2,261,000 | 10,000 | ||
Depletion, depreciation, and amortization | 10,665,000 | 13,823,000 | 38,301,000 | 39,861,000 | 58,827,705 | 40,521,546 |
Accretion of asset retirement obligations | 53,000 | 53,000 | 160,000 | 160,000 | 214,335 | 201,076 |
Loss (gain) on sale of oil and gas properties | 53,000 | (1,478,000) | 625,000 | |||
Impairment of oil and gas properties | 29,144,000 | 31,082,000 | 28,622,961 | 5,478,264 | ||
Stock-based compensation | 122,000 | 880,000 | 313,000 | 1,746,000 | 2,585,111 | 1,938,400 |
General and administrative | 2,870,000 | 2,399,000 | 8,501,000 | 7,095,000 | 10,824,845 | 8,913,052 |
Other expense | 1,000 | 18,000 | 1,045,000 | 53,000 | ||
Total costs and expenses | 48,185,000 | 23,175,000 | 95,995,000 | 66,419,000 | 123,910,211 | 80,807,281 |
Income (loss) from operations | (32,647,000) | (2,298,000) | (51,458,000) | (4,382,000) | (44,419,855) | 34,819,279 |
Other income (expense) | ||||||
Interest expense | (7,345,000) | (6,666,000) | (19,644,000) | (18,485,000) | (24,576,993) | (19,949,359) |
Gain on disposal of bonds | 29,363,000 | 29,363,000 | ||||
Unrealized loss on warrants | (611,000) | (611,000) | ||||
Gain (loss) on derivative financial instruments | 1,664,000 | 19,481,000 | (3,405,000) | 18,956,000 | 27,608,534 | 43,972,245 |
Other income (expense) | (1,065,539) | 55,187 | ||||
Total other income, net | 23,071,000 | 12,815,000 | 5,703,000 | 471,000 | 1,966,002 | 24,078,073 |
(Loss) income before income taxes | (9,576,000) | 10,517,000 | (45,755,000) | (3,911,000) | (42,453,853) | 58,897,352 |
Income tax (expense) benefit | (1,684,000) | (3,931,000) | 10,354,000 | 1,419,000 | 15,120,888 | (22,431,722) |
Net (loss) income | $ (11,260,000) | $ 6,586,000 | $ (35,401,000) | $ (2,492,000) | $ (27,332,965) | $ 36,465,630 |
Net (loss) income per common share-basic and diluted | $ (1.44) | $ 0.88 | $ (4.64) | $ (0.33) | ||
Net income (loss) per common share-basic | $ (1.44) | $ 0.88 | $ (4.64) | $ (0.33) | $ (1.82) | $ 2.49 |
Weighted average common shares outstanding-basic and diluted | 7,842,586 | 7,522,025 | 7,629,896 | 7,522,025 | ||
Net income (loss) per common share-diluted | $ (1.44) | $ 0.88 | $ (4.64) | $ (0.33) | $ (1.82) | $ 2.42 |
Weighted average common shares outstanding-basic | 7,842,586 | 7,522,025 | 7,629,896 | 7,522,025 | 15,044,051 | 14,661,004 |
Weighted average common shares outstanding-diluted | 7,842,586 | 7,522,025 | 7,629,896 | 7,522,025 | 15,044,051 | 15,069,610 |
Other comprehensive (loss) income: | ||||||
Net (loss) income | $ (11,260,000) | $ 6,586,000 | $ (35,401,000) | $ (2,492,000) | $ (27,332,965) | $ 36,465,630 |
Foreign currency translation adjustments | (13,000) | (30,000) | (29,000) | (29,000) | 12,267 | (404,038) |
Comprehensive (loss) income | $ (11,273,000) | $ 6,556,000 | $ (35,430,000) | $ (2,521,000) | $ (27,320,698) | $ 36,061,592 |
Consolidated Statement of Chang
Consolidated Statement of Changes in Shareholders' Equity - USD ($) | Total | Class A Voting Common Stock | Common Stock | Common StockClass A Voting Common Stock | Additional Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) |
Beginning balance at Dec. 31, 2013 | $ 169,701,644 | $ 142,637,636 | $ 5,746,777 | $ 21,685,826 | $ (368,595) | ||
Beginning balance (in shares) at Dec. 31, 2013 | 13,943,744 | ||||||
Share issuance, (in shares) | 1,100,000 | ||||||
Stock-based compensation | 1,938,400 | 1,938,400 | |||||
Foreign currency translation | (404,038) | (404,038) | |||||
Net income (loss) | 36,465,630 | 36,465,630 | |||||
Ending balance at Dec. 31, 2014 | $ 207,701,636 | $ 142,637,636 | 7,685,177 | 58,151,456 | (772,633) | ||
Ending balance (in shares) at Dec. 31, 2014 | 14,661,004 | 15,043,744 | |||||
Share issuance, (in shares) | 307 | ||||||
Stock-based compensation | $ 2,585,111 | 2,585,111 | |||||
Foreign currency translation | 12,267 | 12,267 | |||||
Net income (loss) | (27,332,965) | (27,332,965) | |||||
Ending balance at Dec. 31, 2015 | $ 182,966,049 | $ 142,637,636 | $ 142,637,636 | 10,270,288 | 30,818,491 | (760,366) | |
Ending balance (in shares) at Dec. 31, 2015 | 15,044,051 | 7,521,788 | 15,044,051 | 7,521,788 | |||
Share issuance | $ 5,509,000 | 5,509,000 | |||||
Share issuance, (in shares) | 500,227 | ||||||
Stock-based compensation | 313,000 | 313,000 | |||||
Foreign currency translation | (29,000) | (789,000) | $ 760,000 | ||||
Net income (loss) | (35,401,000) | (35,401,000) | |||||
Ending balance at Sep. 30, 2016 | $ 153,358,000 | $ 142,638,000 | $ 15,303,000 | $ (4,583,000) | |||
Ending balance (in shares) at Sep. 30, 2016 | 8,022,015 | 8,022,015 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | |
Operating activities | ||||
Net income (loss) | $ (35,401,000) | $ (2,492,000) | $ (27,332,965) | $ 36,465,630 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities | ||||
(Gain) loss on disposal of oil and gas properties | (866,000) | 629,000 | 629,253 | (466,490) |
Accretion of asset retirement obligations | 160,000 | 160,000 | 214,335 | 201,076 |
Depletion, depreciation, and amortization | 38,301,000 | 39,861,000 | 58,827,705 | 40,521,546 |
Stock-based compensation | 313,000 | 1,746,000 | 2,585,111 | 1,938,400 |
Deferred taxes | (10,432,000) | (1,418,000) | (15,497,468) | 22,662,988 |
(Gain) loss on derivative financial instruments | 3,405,000 | (18,956,000) | (27,608,534) | (43,972,245) |
Settlements of derivative financial instruments | 24,322,000 | 26,497,000 | 35,284,243 | (1,503,609) |
Gain on disposal of bonds | (29,363,000) | |||
Impairment of oil and gas properties | 31,082,000 | 28,622,961 | 5,478,264 | |
Non-cash interest expense | 1,677,000 | 825,000 | 1,100,000 | 825,000 |
Changes in operating assets and liabilities: | ||||
Accounts receivable | 865,000 | 8,526,000 | 10,856,325 | (9,408,033) |
Prepaid expenses and other assets | (1,961,000) | (896,000) | 223,186 | (1,856,749) |
Accounts payable and accrued expenses | (4,479,000) | (4,453,000) | (17,065,347) | 31,341,672 |
Net cash provided by operating activities | 17,623,000 | 50,029,000 | 50,838,805 | 82,227,450 |
Investing activities | ||||
Acquisition of oil and gas properties | (3,115,000) | (7,032,000) | (8,723,497) | (70,978,282) |
Development of oil and gas properties | (24,856,000) | (77,735,000) | (85,458,433) | (164,180,576) |
Proceeds from sales of oil and gas properties | 2,720,000 | 3,200,000 | ||
Purchases of other property and equipment | (202,000) | (191,000) | (337,147) | (1,086,073) |
Net cash used in investing activities | (25,453,000) | (84,958,000) | (94,519,077) | (233,044,931) |
Financing activities | ||||
Proceeds from borrowings | 64,325,000 | 123,514,000 | 140,513,602 | 135,000,000 |
Payments on borrowings | (54,789,000) | (93,514,000) | (102,513,602) | (195,000,000) |
Proceeds from bond offering | 214,500,000 | |||
Payments on other note payable | (9,000) | (9,000) | (3,016) | (30,000) |
Net cash provided by (used in) financing activities | 9,527,000 | 29,991,000 | 37,996,984 | 154,470,000 |
Effect of exchange rate changes on cash and cash equivalents | (29,000) | (29,000) | 12,267 | (404,038) |
Increase (decrease) in cash and cash equivalents | 1,668,000 | (4,967,000) | (5,671,021) | 3,248,481 |
Cash and cash equivalents, beginning of the period | 4,321,456 | 9,992,477 | 9,992,477 | 6,743,996 |
Cash and cash equivalents, end of the period | 5,990,000 | 5,025,000 | 4,321,456 | 9,992,477 |
Supplemental information | ||||
Cash paid for federal income taxes | 257,000 | 90,000 | ||
Cash paid for interest expense | 14,095,000 | $ 11,020,000 | $ 21,492,189 | $ 13,400,795 |
Common stock issued for asset acquisition | $ 5,500,000 |
Nature of Business and Presenta
Nature of Business and Presentation | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Accounting Policies [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 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 in this Quarterly Report on Form 10-Q 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 Presentation The accompanying interim consolidated financial statements have not been audited by independent public accountants, but in the opinion of management, reflect all adjustments necessary for a fair presentation of the financial position and results of operations. Any and all adjustments are of a normal and recurring nature. Although management believes the unaudited interim-related disclosures in these consolidated financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission. The results of operations and the cash flows for the nine months ended September 30, 2016 are not necessarily indicative of the results to be expected for the full year. 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”), 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”), Lonestar Operating, LLC (“LNO”), 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. | 1. Nature of Business and Presentation Lonestar Resources Limited (the “Parent”) is a company limited by shares incorporated in Australia, whose shares are publicly traded on the Australian Stock Exchange and the OTCQX. The financial report consists of the consolidated financial statements of Lonestar Resources Limited and its subsidiaries. Lonestar Resources America, Inc., (as combined with the Parent, the “Company”) is a Delaware registered U.S. holding company formed January 31, 2013, which is engaged in the exploration, development, production, acquisition, and sale of oil, natural gas liquid (“NGL”) and natural gas primarily the Eagle Ford Shale Play in South Texas, Conventional properties in North Texas and Bakken properties in Montana through its wholly owned subsidiaries. Its executive offices are located in Fort Worth, Texas. The Company is a wholly owned subsidiary of the Parent. The majority of the activities of the Parent is carried out through Lonestar Resources America, Inc. Lonestar Resources America, Inc. was formed as a U.S. holding company for Lonestar Resources, Inc. and Amadeus Petroleum, Inc., which are subsidiaries previously wholly-owned by the Parent. This formation was effected through an exchange of shares of the Company for those issued by the merged subsidiaries and has been treated as a reorganization of entities under common control. |
Restatement
Restatement | 9 Months Ended |
Sep. 30, 2016 | |
Accounting Changes and Error Corrections [Abstract] | |
Restatement | 2. Restatement On November 21, 2016, the Company determined that there was an error in the proper classification of cash flows related to our gain on disposal of its 8.750% Senior Notes due 2019. As a result of this error, the Company has restated its unaudited Consolidated Statement of Cash Flows for the nine months ended September 30, 2016 in its Quarterly Report on Form 10-Q/A on November 23, 2016. The following table summarizes the restatement changes made to the Consolidated Statement of Cash Flows for the nine months ended September 30, 2016 previously filed in the Company’s Quarterly Report on Form 10-Q on November 10, 2016. Originally Restatement Adjustment As Restated Gain on disposal of bonds — (29,363 ) (29,363 ) Net cash provided by operating activities 46,986 (29,363 ) 17,623 Payments on borrowings (84,152 ) 29,363 (54,789 ) Net cash provided by financing activities (19,836 ) 29,363 9,527 |
Recently Issued Accounting Pron
Recently Issued Accounting Pronouncements | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Accounting Changes and Error Corrections [Abstract] | ||
Recently Issued Accounting Pronouncements | 3. Recently Issued Accounting Pronouncements In August 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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. The impact is not expected to be material. 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. The impact is not expected to be material. 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. Management is currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements. 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 financial statements. In November 2015, the FASB issued ASU No. 2015-17 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. Management is currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements. In April 2015, the FASB issued updated guidance regarding simplification of 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 did not have a material impact on the Company’s consolidated financial statements. In August 2014, the FASB issued ASU No. 2014-15, “Presentation of Financial Statements — Going Concern” (Subtopic 205-40). This ASU provides guidance on management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. This ASU is effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. Management does not expect the adoption of this guidance to have a material impact on our consolidated financial statements. In May 2014, the FASB issued ASU No. 2014-09 that introduces a new five-step revenue recognition model in which an entity 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. This ASU also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. This standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted, but only for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method of adoption. Management is currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements and the method of adoption. | 8. Recently Issued Accounting Pronouncements In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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, 2016, and for annual interim periods thereafter. Early adoption is permitted. We are currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements. In November 2015, the FASB issued ASU No. 2015-17 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. We are currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements. In August 2014, the FASB issued ASU No. 2014-15, “Presentation of Financial Statements—Going Concern” (Subtopic 205-40). This ASU provides guidance on management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. This ASU is effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. We do not expect the adoption of this guidance to have a material impact on our consolidated financial statements. In May 2014, the FASB issued ASU No. 2014-09 that introduces a new five-step revenue recognition model in which an entity 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. This ASU also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. This standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted, but only for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method of adoption. We are currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements and the method of adoption. |
Acquisitions and Divestitures
Acquisitions and Divestitures | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Business Combinations [Abstract] | ||
Acquisitions and Divestitures | 4. 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. Aggregate production related to the properties was 436 Boe/d during the third quarter of 2016. The sale price approximated $14,000,000. The transaction closed on October 31, 2016. As of September 30, 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 the Company 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 purchase paid by the Company was $5,500,000 payable in 500,227 shares of the Company’s Class A voting common stock. 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. | 3. Acquisitions and Divestitures In March 2014 the Company acquired additional working interests in four wells and approximately 1,240 net acres in the Eagle Ford Shale trend. The acquired assets are located in La Salle County. The Company paid approximately $2,385,000 to acquire the acreage. $750,000 was allocated to proved properties, while $1,635,000 was allocated to unproved properties. In March 2014 the Company acquired an additional 15,232 gross / 13,156 net acres in the Eagle Ford Shale trend. The acquired assets are located in La Salle, Frio, Wilson, Brazos and Robertson counties. The Company paid approximately $70,737,000 to acquire the acreage. $58,490,000 of the purchase price was allocated to proved properties, while $12,247,000 was allocated to unproved properties. Virtually all of the properties will be operated by Lonestar. In June 2014, the Company sold its working interest in its non-operated Raccoon Bend property for approximately $3,200,000. The effective date of the sale was June 1, 2014. The gain on the sale approximated $461,000. In September 2014 the Company acquired an additional 720 net acres in the Eagle Ford Shale trend. The acquired assets are located in La Salle County. The Company paid approximately $2,500,000 to acquire the acreage. All of the purchase price was allocated to unproved properties. 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 for $500,000 as a further component of the exchange. |
Restricted Certificate of Depos
Restricted Certificate of Deposit | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Banking and Thrift [Abstract] | ||
Restricted Certificate of Deposit | 5. 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, 2017, 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. | 4. Restricted Certificates of Deposit The Company is required to maintain certain certificates of deposit (“CDs”) by a municipality in which 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, 2016, 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 | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Commodity Price Risk Activities | 6. 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 September 30, 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 September 30, 2016, the following derivative transactions were outstanding: Instrument Total Volume Settlement Period Fixed Price Oil – WTI Fixed Price Swap 48,500 Bbl October – December 2016 $ 84.45 Oil – WTI Fixed Price Swap 70,100 Bbl October – December 2016 90.45 Oil – WTI Fixed Price Swap 28,400 Bbl October – December 2016 63.20 Oil – WTI Fixed Price Swap 36,500 Bbl October – December 2016 56.90 Oil – WTI Fixed Price Swap 49,050 Bbl October – December 2016 42.11 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 Instrument Total Volume Settlement Period Puts Calls Oil – 3 Way Collar 365,100 Bbl January – December 2017 $40.00 / 60.00 $ 85.00 The above derivative contracts aggregate to 232,550 barrels or 2,528 barrels of oil per day for the remainder of 2016 and 547,600 barrels or 1,500 barrels of oil 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 September 30, 2016 and December 31, 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. | 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, 2015, 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 derivative (realized and unrealized) are included in the consolidated statement of operations. As of December 31, 2015, the following derivative transactions were outstanding: Instrument Total Volume Settlement Period Fixed Price Oil – WTI Fixed Price Swap 205,000 BBL January –December 2016 $ 84.45 Oil – WTI Fixed Price Swap 309,000 BBL January – December 2016 90.45 Oil – WTI Fixed Price Swap 135,600 BBL January – December 2016 63.20 Oil – WTI Fixed Price Swap 183,400 BBL January – December 2016 56.90 Instrument Total Volume Settlement Period Puts Calls Oil – 3 Way Collar 365,100 BBL January – December 2017 $40.00 / 60.00 $ 85.00 The above derivative contracts aggregate to 833,000 barrels or 2,276 barrels of oil per day for 2016 and 365,100 barrels or 1,000 barrels of oil 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, 2015 and 2014, 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 contains credit-risk related contingent features. |
Fair Value Measurements
Fair Value Measurements | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | ||
Fair Value Measurements | 7. 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 a purchase and sale agreement for 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 the three months ended September 30, 2016. In accordance with ASC 820, Fair Value Measurements and Disclosures Level 1 Level 2 Level 3 The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2016 and December 31, 2015, for each fair value hierarchy level: Fair Value Measurements Using Quoted (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total September 30, 2016 (unaudited) (In thousands) Assets: Commodity derivatives $ — $ 8,853 $ — $ 8,853 Liabilities: Commodity derivatives — (498 ) — $ (498 ) Warrant liability (5,738 ) $ (5,738 ) Total $ — $ 8,355 $ (5,738 ) $ 2,617 December 31, 2015 (In thousands) Assets: Commodity derivatives $ — $ 36,083 $ — $ 36,083 Liabilities: Commodity derivatives — — — $ — Total $ — $ 36,083 $ — $ 36,083 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 $96.8 million as of September 30, 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 September 30, 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. | 6. Fair Value Measurements In accordance with ASC 820, Fair Value Measurements and Disclosures Level 1— Level 2— Level 3— The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2015 and 2014, 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, 2014 (In thousands) Assets: Commodity derivatives $ — $ 43,759 $ — $ 43,759 Liabilities: Commodity derivatives — — — $ — Total $ — $ 43,759 $ — $ 43,759 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. Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the 2015 and 2014 periods. |
Oil and Gas Properties
Oil and Gas Properties | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Extractive Industries [Abstract] | ||
Oil and Gas Properties | 8. Oil and Gas Properties A summary of oil and gas properties follows: September 30, (unaudited) December 31, (In thousands) Proved properties and equipment $ 525,809 $ 584,692 Proved properties and equipment held for sale 79,537 — Unproved properties 71,658 70,298 Less accumulated depreciation, depletion, and amortization (160,793 ) (166,890 ) Less accumulated depreciation, depletion, amortization, and impairment on properties held for sale (65,922 ) — $ 450,289 $ 488,100 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. Aggregate production related to the properties was 436 Boe/d during the third quarter of 2016. The sale price approximated $14,000,000. The transaction closed on October 31, 2016. As of September 30, 2016, the Company reported an impairment charge of approximately $29.1 million, representing the carrying value in excess of fair value, less the cost to sell the properties. Asset retirement costs of $4 million and the related asset retirement liability of $4.5 million have been included in the carrying value of the properties as well as the impairment charge calculation. The table above provides separate amounts for the carrying value of the assets held for sale and the related accumulated depletion and impairment allowances. 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 during the three months ended June 30, 2016, we 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. If pricing continues to decline, it is reasonably likely that the Company may have to record impairment of its oil and gas properties subsequent to September 30, 2016. | 7. Oil and Gas Properties A summary of oil and gas properties as of December 31, follows: 2015 2014 Proved properties and equipment $ 584,691,945 $ 495,954,566 Unproved properties 70,298,349 65,725,668 Less accumulated depreciation, depletion, and amortization (166,890,697 ) (80,600,959 ) $ 488,099,597 $ 481,079,275 The Company recorded impairment of oil and gas properties of $28,623,000 and $5,478,000 for the years ended December 31, 2015 and 2014, respectively, which is included in accumulated depreciation, depletion, and amortization. During 2015, the sustained deterioration in the long-term outlook for commodity prices was a triggering event that requiring us to perform impairment testing of our assets that are sensitive to commodity prices. The impairment testing of our long-lived assets was based upon a two-step process as prescribed in the accounting standards. Step one was performed on each of our oil and gas producing regions and involved a determination as to whether the property’s net book value is expected to be recovered from the estimated undiscounted future cash flows for each respective region. To compute estimated future cash flows, we used our independent reserve engineers’ estimates of proved and probable reserves. For those regions that failed the impairment test’s first step, we then made a fair market value assessment using discounted cash flow analysis. Based on these results, we recognized $19,696,000 of impairment on those regions where the carrying value exceeded its estimated fair market value. In addition, during 2015, we recorded a $8,927,000 impairment of undeveloped, unproven properties in Gonzales County. Our independent reserve engineers’ estimates for this region did not include any probable or possible reserves, therefore, it was necessary to impair the remaining net book value of undeveloped, unproven properties for this region. |
Accrued Liabilities
Accrued Liabilities | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Payables and Accruals [Abstract] | ||
Accrued Liabilities | 9. Accrued Liabilities The accrued liabilities consist of the following: September 30, (unaudited) December 31, 2015 (In thousands) Bonus payable $ 1,604 $ 1,433 Payroll payable 2 28 Accrued interest 7,286 4,420 Accrued rent 328 410 Accrued expenses 1,928 1,401 Other 1,302 584 $ 12,450 $ 8,276 | 10. Accrued Liabilities The accrued liabilities consist of the following at December 31: 2015 2014 Bonus payable $ 1,432,768 $ 1,848,612 Severance and vacation payable 28,388 283,540 Accrued interest 4,420,317 4,149,105 Accrued rent 409,643 489,191 Accrued expenses 1,401,080 4,592,152 Other 583,890 242,520 $ 8,276,086 $ 11,605,120 |
Long-Term Debt
Long-Term Debt | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Debt Disclosure [Abstract] | ||
Long-Term Debt | 10. Long-Term Debt The Company’s debt consists of the following: September 30, (unaudited) December 31, 2015 (In thousands) Senior Secured Credit Facility $ 94,500 $ 87,000 Second Lien Notes 33,024 — 8.750% Senior Notes 151,848 220,000 Gap Financing 2,063 — Less unamortized discount on 8.750% Senior Notes (1,898 ) (3,575 ) Less deferred financing costs on 8.750% Senior Notes (945 ) (1,785 ) Less deferred financing costs on Second Lien Notes (1,180 ) — Other 276 286 $ 277,688 $ 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 represents 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 September 30, 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 September 30, 2016 and December 31, 2015, $94,500,000 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. 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, 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 September 30, 2016 and December 2015, the Company had approximately $1,300,000 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 voting common stock at a price equal to $5.00 per share (the “Warrants”). 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. As of September 30, 2016, LRAI has issued $38.0 million in aggregate principal amount of Second Lien Notes and the Company has issued Warrants to purchase 760,000 shares of its Class A voting 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 September 30, 2016 which resulted in an unrealized loss 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 $29.4 million. 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, to be acquired by Seaport Global on the Company’s behalf in one or more open market purchases. The Amended and Restated Agreement amends and restates that certain Facilitation Agreement entered into on September 29, 2016 (the “Original Agreement”), between the Company and Seaport Global, which was previously disclosed in a Current Report on Form 8-K filed with the Securities and Exchange Commission (the “Commission”) on October 5, 2016. Other than as provided below, the terms of the Amended and Restated Agreement are substantially the same as those set forth in the Original Agreement. Under the Amended and Restated Agreement, the Company has agreed to repay Seaport Global for Gap Financing, concurrently with the consummation of a public equity offering by the Company of its Class A voting common stock , in an amount of cash (the “Cash Payment Amount”) equal to (i) one hundred five percent (105%) of the amount of the Gap Financing if paid before December 31, 2016 and (ii) one hundred eleven and one tenth percent (111.1%) of the amount of Gap Financing if paid on or after January 1, 2017. To the extent that the Company is unwilling or otherwise unable to consummate such public equity offering, the Company has agreed to issue up to the Share Cap (as defined below) in shares of Class A voting common stock in an amount equal to the purchase price of any 8.750% Senior Notes the repurchase of which is financed by Seaport Global, divided by (i) with respect to any financing prior to the approval of any such issuance by holders of a majority of the issued and outstanding shares of Class A voting common stock (“Stockholder Approval”), 90% of the closing price of the Class A voting common stock on September 28, 2016 and (ii) with respect to any financing subsequent to the Stockholder Approval of shares, 90% of the closing price of the Class A voting common stock on the most recently completed trading date prior to the date that shares of Class A voting common stock are delivered to Seaport Global. The number of shares of Class A voting common stock that the Company may issue to Seaport Global under the Facilitation Agreement (the “Share Cap”) is limited to the lesser of (a) 460,000 shares of Class A voting common stock and (b) a number of shares of Class A voting common stock that would, as a result of the issuance thereof to Seaport Global, cause EFR Guernsey Holding Limited, the Company’s majority stockholder (the “EFR Guernsey”), to hold less than a majority of the issued and outstanding shares of Class A voting common stock. As of September 30, 2016, the Company recorded $2,063,320 as long-term debt on its balance sheet as a result of this Gap Financing. | 12. Long-Term Debt The Company’s debt consists of the following: December 31, 2015 2014 Revolving credit facility $ 87,000,000 $ 49,000,000 8.75% senior notes 220,000,000 220,000,000 Less discount on 8.75% senior notes (3,575,000 ) (4,675,000 ) Other 285,512 288,529 $ 303,710,512 $ 264,613,529 Senior Revolving Credit Facility In March 2013, the Company entered into a $400,000,000 syndicated credit facility agreement (“revolving credit facility”) with Wells Fargo Bank (as Administrative Agent). The initial borrowing base was set at $105,000,000. The borrowing base shall be re-determined semi-annually based on the credit agreement, and such re-determined borrowing base shall become effective and applicable on April 1 and October 1 of each year commencing October 1, 2013. The revolving credit facility matures on March 14, 2018. As of December 31, 2014, $49,000,000 was borrowed under the revolving credit facility. The borrowing base as of December 31, 2014 was $150,000,000. The revolving credit facility may be used for loans and, subject to a $2,500,000 sub-limit, letters of credit. The Company has not drawn any advances on the letter of credit as of December 31, 2014. The revolving credit facility provides for a commitment fee of 0.5% based on the unused portion of the borrowing base under the revolving credit facility. Borrowings under the revolving credit facility, at the Company’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 1.0% to 2.0% for ABR loans and from 2.0 to 3.0% for adjusted LIBO rate loans. The revolving credit facility requires the Company to maintain certain financial ratios and limits the amount of indebtedness the Company can incur. Subject to certain permitted liens, the Company’s obligations under the revolving 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 revolving credit facility, the Company and certain of its subsidiaries also entered into certain customary ancillary agreements and arrangement, which, among other things, provide that the indebtedness, obligations, and liabilities of the Company arising under or in connection with the revolving credit facility are unconditionally guaranteed by such subsidiaries. As of December 31, 2014, the Company was in compliance with all covenants including all financial ratios under the Wells Fargo led facility. In June 2013, the Company entered into a $35,000,000 second lien term loan agreement (“2nd lien facility”) with Wells Fargo Energy Capital, Inc. (as Administrative Agent). The 2nd lien facility provides for a commitment fee of 0.75% based on the unused portion of the commitment amount under the 2nd lien facility. The 2nd lien facility matures on September 14, 2018. In February 2014, the 2nd lien facility was amended increasing the commitment amount to $55,000,000. In April 2014, the 2nd lien facility was fully paid and subsequently terminated. On July 28, 2015, the Company closed a new $500,000,000 Senior Secured Credit Facility which replaced the $400,000,000 Wells Fargo led syndicated facility outlined above. The new facility was arranged by Citibank, N.A. and features an expanded borrowing base of $180,000,000 as of December 31, 2015, which is an increase over the $150,000,000 borrowing base available under the Wells Fargo led facility at December 31, 2014. 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 represents 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. As of December 31, 2015, the Company was in compliance with all covenants including all financial ratios under the Citibank led facility. As of December 31, 2015, $87,000,000 was borrowed under the Citibank led revolving credit facility. 8.75% Senior Notes On April 4, 2014, the Company issued at par $220,000,000 of 8.75% Senior Unsecured Notes due April 15, 2019 (“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 the Company’s revolving credit facility and 2nd lien facility, and for general corporate purposes. Under the 2nd lien term loan agreement, the Company 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, the Company may redeem the 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 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 the Company, holders of the Notes will have the right to require the Company to repurchase all or any part of their Notes for cash at a price equal to 101% of the aggregate principal amount of the Notes repurchased, plus any accrued and unpaid interest. The Notes were issued under and governed by an Indenture dated April 4, 2014, between the Company, Wells Fargo Bank, National Association, as trustee and the Company’s subsidiaries named therein as guarantors (the “Indenture”). The Indenture contains covenants that, among other things, limit the ability of the Company 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 the Company’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. During 2014, the Company capitalized approximately $3.5 million in costs associated with the issuance of the Notes and costs incurred for amendments to the Company’s Senior Revolving Credit Facility. With the payoff and termination of the 2nd lien facility, the Company expensed approximately $700,000 of debt issuance costs. At December 31, 2015 and 2014, the Company had approximately $2,900,000 and $3,300,000, respectively, of debt issuance costs remaining that are being amortized over the lives of the respective debt. |
Stock Options
Stock Options | 9 Months Ended |
Sep. 30, 2016 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock Options | 11. Stock Options 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. Expected Life. Expected Volatility. Risk-Free Interest Rate. Expected Dividend Yield. Expected Forfeitures. Stock Option Activity For the nine months ended September 30, 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 (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 (64,667 ) 18.00 — Forfeited — — — Outstanding at September 30, 2016 820,269 $ 15.00 0.5 Options vested and exercisable at September 30, 2016 778,019 $ 15.00 0.5 Shares Weighted Average Value per 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 2.25 Vested (35,000 ) 1.90 15.00 2.25 Forfeited — — — — Outstanding non-vested options at September 30, 2016 42,250 $ 9.00 $ 15.50 0.25 Stock-Based Compensation Expense For the three and nine month periods ended September 30, 2016, the Company recorded stock-based compensation expense for stock options granted using the fair-value method of $121,986 and $312,638, respectively. |
Earnings Per Share
Earnings Per Share | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Earnings Per Share [Abstract] | ||
Earnings Per Share | 12. 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 voting 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 three and nine months ended September 30, 2016 as the Company reported a loss from operations for those periods. The Company had net income from operations at the three months ended September 30, 2015, however, as the options were considered to be out of the money, the potentially dilutive common shares outstanding are treated as anti-dilutive and therefore, excluded from the calculation of diluted weighted average shares outstanding. 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 three and nine month periods ended September 30, 2016 and 2015: Unaudited Earnings Per Share (After Reorganization) Three months ended Nine months ended 2016 2015 2016 2015 Net income (loss) per common share: Basic $ (1.44 ) $ 0.88 $ (4.64 ) $ (0.33 ) Diluted (1.44 ) 0.88 (4.64 ) (0.33 ) Weighted average common shares outstanding: Basic 7,842,586 7,522,025 7,629,896 7,522,025 Diluted 7,842,586 7,522,025 7,629,896 7,522,025 | 15. 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. Lonestar Resources Limited had outstanding ordinary common shares (prior to the reorganization) of 15,044,051 at December 31, 2015 and 14,661,004 at December 31, 2014. Each share entitles the holder to participate in dividends and the proceeds of winding up of the Company in proportion to the number of, and amounts paid on, the shares held. Each share is also entitled to one vote at a stockholder meeting either in person or by proxy. In connection with a planned reorganization, a new corporate entity was formed, Lonestar Resources US Inc., which immediately prior to the reorganization will acquire the Parent via an Australian Scheme of Arrangement. As a result, certain accounting policies have been adopted in these financial statements as if the Company were a public company. The following table presents unaudited pro forma 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 years ended December 31, 2015 and 2014: UNAUDITED PRO FORMA EARNINGS PER SHARE (AFTER REORGANIZATION) 2015 2014 Net income (loss) per common share: Basic $ (3.63 ) $ 4.97 Diluted (3.63 ) 4.84 Weighted average common shares outstanding: Basic 7,522,025 7,330,602 Diluted 7,522,025 7,534,805 |
Related Party Activities
Related Party Activities | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Related Party Transactions [Abstract] | ||
Related Party Activities | 13. Related Party Activities 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. 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. 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 $78,000 and $149,000 for the three months ended September 30, 2016 and 2015, respectively and approximately $465,000 and $763,000 in the nine months ended September 30, 2016 and 2015, respectively. Mitchell Wells, who has been a director of the Company since December 2014, has provided consultancy services as its 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 $24,000 and $36,000 for the three months ended September 30, 2016 and 2015, respectively and approximately $95,000 and $107,000 for the nine months ended September 30, 2016 and 2015, respectively. He has not received any additional compensation for his service as a Director. | 16. Related Party Activities During the years ended December 31, 2015 and 2014 the Company paid dividends to its Parent of approximately $308,000 and $637,000, respectively. 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. Butterfly Flaps, Ltd, a company in which Dr. Christopher Rowland (a director of Lonestar) owns an interest, has performed consultancy work for Lonestar since 2013 covering various strategic, tax structuring and investor matters at a cost of approximately $25,000 per quarter. New Tech Global Ventures, LLC, a company in which Daniel R. Lockwood (a director of Lonestar) owns a limited partnership interest, has provided field engineering staff and consultancy services for Lonestar since 2013. The total cost for such services was approximately $938,000 and $2,300,000 in 2015 and 2014, respectively. Mitchell Wells, who has been a Director of Lonestar Resources Limited since December 2014, has provided consultancy services as its 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 $143,000 for 2015 and $182,000 for 2014. He has not received any additional compensation for his service as a Director. |
Equity Backstop Commitment
Equity Backstop Commitment | 9 Months Ended |
Sep. 30, 2016 | |
Text Block [Abstract] | |
Equity Backstop Commitment | 14. Equity Backstop Commitment Pursuant to the Securities Purchase Agreement discussed in Note 10 above with Juneau and Leucadia, in the event that the Company elects to pursue an equity offering prior to December 31, 2016, Leucadia has agreed to purchase the number of shares of Class A voting 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. Leucadia’s agreement to purchase the Class A voting common stock is conditioned on, among other things, the Company (i) selecting a lead underwriter approved by Leucadia, (ii) having, together with its subsidiaries, no more than $295,000,000 of long-term debt outstanding (net of cash and cash equivalents), and (iii) the equity order book in such offering is no less than $40,000,000, excluding Leucadia’s commitment. In connection with Leucadia’s commitment, the Company has agreed to pay Leucadia a fee equal to $1,000,000, payable whether such an offering is launched or consummated, upon the earlier of (i) the closing of such offering, (ii) the termination of such offering and (iii) December 31, 2016. This amount is recorded as prepaid expenses and other and accrued liabilities in the consolidated balance sheet. In the event Leucadia purchases not less than their commitment amount, the Company agreed to use commercially reasonable efforts to enter into arrangements to provide Leucadia with the right to appoint one director to the board of directors of the Company, provided that such right will terminate at such time as Leucadia and its affiliates own a number of shares of Class A voting common stock equal to less than 50% of the shares purchased by Leucadia and its affiliates in such offering. |
Subsequent Events
Subsequent Events | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Subsequent Events [Abstract] | ||
Subsequent Events | 15. 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. Board Representation Agreement On October 26, 2016, the Company entered into a Board Representation Agreement (“Board Representation Agreement”) with EF Realisation Company Limited (“EF Realisation”). Under the Board Representation Agreement, as long as EFR Guernsey, a wholly-owned subsidiary of EF Realisation and the direct holder of the majority of the Company’s Class A voting common stock, owns 15% or more of the issued and outstanding shares of Class A voting common stock, it has the right to designate up to, but no more than, two directors (each, a “Designee”) to serve on the board of directors of the Company (the “Board”), and for as long as EFR Guernsey owns at least 10% but less than 15% of the issued and outstanding Class A voting common stock, it has the right to designate up to, but no more than, one Designee to serve on the Board. One Designee, as directed by EF Realisation, must serve on each committee of the Board provided that such appointment would not contravene any applicable rules and regulations of the NASDAQ Stock Market or the Securities and Exchange Commission. Registration Rights Agreement On October 26, 2016, the Company entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with EF Realisation. Pursuant to the Registration Rights Agreement, subject to certain limitations, the Company agreed to register for resale of the Class A voting common stock held by EFR Guernsey (“EF Realisation Stock”). The Company agreed to file a registration statement (the “Registration Statement”) providing for the resale of EF Realisation Stock no later than the earlier of (the “Filing Deadline”): (i) October 26, 2017, and (ii) 30 days after the date the Company first becomes eligible to file a registration statement on Form S-3. The Company agreed to cause the Registration Statement to become effective no later than 120 days after the Filing Deadline. If a Registration Statement is not effective on or prior to the Filing Deadline, EF Realisation will have certain demand registration rights. Subject to certain exceptions, if at any time the Company proposes to register an offering of equity securities or conduct an underwritten offering of its Class A voting common stock, whether or not for its own account, then the Company must notify EF Realisation of such proposal to allow them to include a specified number of their shares of Class A voting common stock in that registration statement or underwritten offering, as applicable. The registration rights provided under the Registration Rights Agreement are subject to certain conditions and limitations. The Company agreed to generally pay all registration expenses in connection with its obligations under the Registration Rights Agreement, regardless of whether a registration statement is filed or becomes effective. Report of Independent Registered Public Accounting Firm Board of Directors and Shareholders Lonestar Resources Limited Fort Worth, Texas We have audited the accompanying consolidated balance sheets of Lonestar Resources Limited and Subsidiaries (the Company) as of December 31, 2015 and 2014, and the related consolidated statements of operations and other comprehensive income (loss), changes in stockholders’ equity, and cash flows for each of the two years in the period ended December 31, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Lonestar Resources Limited and Subsidiaries at December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. | 18. 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. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | 2. Summary of Significant Accounting Policies A summary of the Company’s significant accounting policies, consistently applied in the preparation of the accompanying consolidated financial statements, follows. 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”), 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”), Lonestar Operating, LLC (“LNO”), 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. Currency Translation The consolidated financial statements are presented in U.S. dollars. The functional currency of Parent is the Australian Dollar. At the end of each reporting period, the assets and liabilities of Parent are translated from its functional currency to U.S. dollars using the exchange rate at the end of the month. The monthly results of operations of Parent are generally translated from its functional currency to U.S. dollars using the average exchange rate during the month. Changes in exchange rates result in currency translation gains and losses, which are recorded within other comprehensive income (loss). Parent may also enter into transactions in currencies other than their functional currency. At the end of each reporting period, Parent re-measures the related receivables, payables, and cash to its functional currency using the exchange rate at the end of the period. Changes in exchange rates between the time the transactions were entered into and the end of the reporting period result in currency transaction gains or losses, which are recorded in the consolidated statements of operations. 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 credit losses since its inception and does not carry an allowance for uncollectible amounts at December 31, 2015. 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. Oil, NGL and natural gas revenues from Shell Trading (US) Company, Trafigura AG and BP Products North America LLC for the year ended December 31, 2014, represented 36%, 23% and 16%, 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 26%, 25% and 23%, respectively, of total receivables at December 31, 2015. Accounts receivable relating to oil, NGL and natural gas sales from Shell Trading, Trafigura AG and BP Products North America LLC represented 19%, 27% and 32%, respectively, of total receivables at December 31, 2014. 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 $8,927,000 as of December 31, 2015 and impairment of proven oil and gas properties of $19,696,000 and $5,478,000 for the years ended December 31, 2015 and 2014, respectively. 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, 2015 or 2014. 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 deferred tax assets and recognizes a valuation allowance based on the estimate of the amount of such deferred tax assets which the Company believes does not meet the more-likely-than-not recognition criteria. At December 31, 2015 and 2014, it has been concluded that no deferred tax asset valuation allowance is necessary. 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, 2015 or 2014. Share-Based Payments The Company accounts for equity-based awards in accordance with ASC 718, Compensation-Stock Compensation |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | 9. Asset Retirement Obligations Pursuant to ASC 410 , Asset Retirement Obligations, The liability has been accreted to its present value as of December 31, 2015. The Company evaluated its wells and has determined a range of abandonment dates through December 2069. The following represents a reconciliation of the asset retirement obligations: Amount Asset retirement obligations at December 31, 2013 $ 5,937,118 Wells drilled during the year 543,555 Wells acquired during the year 965,917 Wells sold during the year (482,081 ) Accretion of discount 201,076 Wells plugged and abandoned during the year (330,970 ) Asset retirement obligations at December 31, 2014 6,834,615 Wells drilled during the year 330,969 Wells acquired during the year 176,156 Wells sold during the year (5,421 ) Accretion of discount 214,335 Wells plugged and abandoned during the year (63,153 ) Asset retirement obligations at December 31, 2015 $ 7,487,501 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 2014 Current tax expense (benefit) Federal $ 287,855 $ 112,621 State 74,324 81,936 Deferred tax expense (benefit) Federal (15,130,060 ) 21,592,426 State (353,007 ) 644,739 Income tax expense (benefit) $ (15,120,888 ) $ 22,431,722 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 effective tax rate from the U.S. 35% statutory rate for the periods indicated: Years Ended December 31, 2015 2014 Expected income tax provision (benefit) at statutory rate $ (14,858,849 ) $ 20,614,073 State tax, tax effected 10,536 675,733 Other (39,646 ) 833,016 Rate difference (232,929 ) 308,900 Actual income tax provision $ (15,120,888 ) $ 22,431,722 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, 2015 2014 Deferred tax assets: Net operating loss carryforward $ 77,507,544 $ 64,772,240 Severance costs — 96,679 Organizational expenses 57,439 58,187 Stock based compensation 2,431,147 1,522,325 Intangibles 775,719 869,594 Other 1,418,801 24,207 82,190,650 67,343,232 Deferred tax liabilities: Oil and gas properties and other property and equipment, principally due to intangible drilling costs (86,789,694 ) (84,371,190 ) Unrealized hedging gain (11,414,232 ) (14,482,786 ) Net deferred tax liabilities $ (16,013,276 ) $ (31,510,744 ) The net operating loss carryforward as of December 31, 2015, approximates $222,656,000 and begins to expire in 2030. The deferred tax asset recorded for the net operating losses does not include $2,200,000 of deductions for excess stock-based compensation. In January 2013, the Company experienced an ownership change as defined in Section 382 of the Internal Revenue Code of 1986, as amended. The provisions of Section 382 apply an annual limit to the amount of the net operating loss carryforward that was incurred prior to the ownership change that can be used to offset future taxable income beginning with the 2013 taxable year. Management believes that the Company’s net operating losses will be fully utilized during the loss carryforward period. The Company has approximately $10,810,000 of percentage depletion carryover which has no expiration. The Company files income tax returns in the United States federal jurisdiction and in various state jurisdictions. At December 31, 2015, 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. The Parent files income tax returns in Australia. Management is not aware of a corporate tax implication as a result of the redomiciliation of the Parent to the United States via an Australian Scheme of Arrangement. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 13. 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 2016 $ 478,040 2017 455,600 2018 411,768 2019 422,301 2020 432,835 Thereafter 368,011 Total $ 2,568,555 Rent expense was $404,000 and $337,000 for the years ended December 31, 2015 and 2014, respectively. Included in rent expense for 2014 was $88,000 representing the acceleration of the office rent for our previous Fort Worth corporate office that was subleased in December 2014. Rig Contract As of December 31, 2015, the Company had one drilling rig under contract. The contract provides 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 terminates 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 is approximately $3.8 million. |
Stockholders' Equity
Stockholders' Equity | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Stockholders' Equity | 14. Stockholders’ Equity In January 2013, Amadeus Energy Limited acquired Ecofin Energy Resources Plc (the previous holding company for Lonestar Resources, Inc.) from its controlling shareholder, Ecofin Water & Power Opportunities PLC, and minority shareholders in a reverse merger effected by way of an Australian Scheme of Arrangement. On a pre-reverse merger basis, there were 236,187,211 shares of Amadeus Petroleum, Inc. (“Amadeus”) issued and outstanding. At the time of the reverse merger, 460,000,000 shares of Amadeus were issued. At the annual meeting of stockholders held December 17, 2012, Parent’s stockholders approved the merger and associated stock options to be issued under the 2012 Employee Share Option scheme. All outstanding shares from the previous plan, issued in May 2012, fully vested upon completion of the merger. 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. Expected Life. Expected Volatility. Risk-Free Interest Rate. Expected Dividend Yield. Expected Forfeitures Stock Option Activity For the year ended December 31, 2015, no stock options were exercised. The following tables summarize certain information related to outstanding stock options under the 2012 Plan as of and for the years ended December 31, 2015 and 2014: Shares Weighted Weighted Average Options outstanding at December 31,2013 1,477,685 $ 16.00 3.0 Granted 410,822 18.00 3.0 Exercised — — — Canceled/Expired (24,667 ) 18.00 1.5 Forfeited (249,570 ) 15.00 2.0 Outstanding at December 31, 2014 1,614,270 16.00 2.0 Options vested and exercisable at December 31, 2014 970,155 $ 16.00 2.0 Granted 160,000 10.00 1.0 Exercised — — — Canceled/Expired (50,000 ) 12.00 — Forfeited (24,398 ) 12.00 — Outstanding at December 31, 2015 1,699,872 15.50 1.0 Options vested and exercisable at December 31, 2015 1,615,372 $ 15.50 1.0 Shares Weighted Weighted per share Weighted Average (in years) Outstanding non-vested options at December 31, 2013 882,456 $ 11.50 $ 15.00 3.0 Granted 410,822 4.50 18.00 3.0 Vested (399,593 ) 4.50 16.00 3.0 Forfeited (249,570 ) 4.50 15.00 3.0 Outstanding non-vested options at December 31, 2014 644,115 $ 4.50 $ 16.00 2.0 Granted 160,000 2.40 10.00 1.0 Vested (695,217 ) 4.00 15.50 1.0 Forfeited (24,398 ) 4.50 15.50 — Outstanding non-vested options at December 31, 2015 84,500 $ 4.50 $ 15.50 1.0 Stock-Based Compensation Expense For the years ended December 31, 2014 and 2013, the Company recorded stock-based compensation expense of $2,585,000 and $1,938,000, respectively. As of December 31, 2015, the Company had approximately $380,000 of unrecognized compensation cost related to unvested stock options, which is expected to be amortized over 2016. |
Supplemental Information on Oil
Supplemental Information on Oil and Natural Gas Exploration and Production Activities (Unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Extractive Industries [Abstract] | |
Supplemental Information on Oil and Natural Gas Exploration and Production Activities (Unaudited) | 17. Supplemental Information on Oil and Natural Gas Exploration and Production Activities (unaudited) Capitalized Costs The following table presents the Company’s aggregate capitalized costs relating to oil and gas activities at the end of the periods indicated: December 31, 2015 2014 Oil and natural gas properties: Proved properties and equipment $ 577,764,738 $ 489,472,814 Unproved properties 70,298,349 65,725,668 Capitalized asset retirement cost 6,927,207 6,481,752 Less: Accumulated depletion and amortization (133,080,366 ) (75,122,695 ) Property impairment (33,810,331 ) (5,478,264 ) Total $ 488,099,597 $ 481,079,275 Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Years ended December 31, 2015 2014 Property acquisition costs : Unproved properties $ 7,327,635 $ 12,247,000 Proved properties 1,395,862 58,731,282 Exploration costs — — Development costs 85,458,433 164,180,576 Total costs incurred $ 94,181,930 235,158,858 Results of Operations The following table sets for the results of operations from oil and gas producing activities for the years ended December 31, 2015 and 2014. Years ended December 31, 2015 2014 Oil and gas producing activities: Oil sales $ 70,739,269 $ 104,233,379 Natural gas sales 6,823,019 7,589,599 Natural gas liquids sales 1,928,068 3,803,582 Lease operating and gas gathering (17,860,216 ) (16,631,611 ) Production, ad valorem and severance taxes (4,981,826 ) (7,123,332 ) Accretion of asset retirement obligations (214,335 ) (201,076 ) Depreciation, depletion and amortization (58,827,705 ) (40,521,546 ) Property impairment (28,622,961 ) (5,478,264 ) Results of operations from oil and gas producing activities $ (31,016,687 ) $ 45,670,731 Depletion rate per BOE $ 25.16 $ 24.78 Crude Oil and Natural Gas Reserves Net Proved Reserve Summary The reserve information presented below is based upon estimates of net proved oil and gas reserves that were prepared by the independent petroleum engineering firms of W.D. Von Gonten & Co. for the evaluation of the Company’s Eagle Ford Shale properties and LaRoche Petroleum Consultants, Ltd. for the evaluation of the Company’s conventional assets. All of the Company’s reserves are located in the United States. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and governmental regulations (i.e. prices and costs of the date the estimate is made). The project to extract the hydrocarbons must have commenced or the interest owner must be reasonably certain that it will commence within a reasonable period of time. Reservoir engineering, which is the process of estimating quantities of crude oil and natural gas reserves, is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data for each reservoir. These estimates are dependent upon many variables, and changes occur as knowledge of these variables evolves. Therefore, these estimate are inherently imprecise, and are subject to considerable upward or downward adjustments. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and such variances could be material. In addition, reserve estimates for properties which have not yet been drilled, or properties with a limited production history may be less reliable than estimates for properties with longer production histories. The following information table sets forth changes in estimated net proved developed crude oil and natural gas reserves for the years ended December 31, 2015 and 2014. Oil (BBL) NGLs (BBL) Gas (MCF) BOE(1) Net proved reserves Reserves at December 31, 2013 13,483,483 1,841,457 17,373,143 18,220,463 New discoveries and extensions 2,462,295 321,301 2,528,029 3,204,934 Purchase of reserves in place 9,648,101 484,493 3,655,020 10,741,764 Reserves sold (252,200 ) — (5,632 ) (253,139 ) Revisions of prior year estimates (532,522 ) 551,078 4,106,883 703,038 Production (1,198,279 ) (154,215 ) (1,689,029 ) (1,633,999 ) Reserves at December 31, 2014 23,610,878 3,044,114 25,968,414 30,983,061 New discoveries & extensions 6,575,775 4,281,649 34,155,539 16,550,014 Purchase of reserves in place 1,541,828 297,634 2,344,083 2,230,142 Reserves sold — — — — Revisions of prior year estimates (6,637,821 ) (146,113 ) (2,562,392 ) (7,210,998 ) Production (1,539,505 ) (322,808 ) (2,923,787 ) (2,349,611 ) Reserves at December 31, 2015 23,551,155 7,154,476 56,981,857 40,202,608 Proved Developed Reserves: December 31, 2013 6,195,280 638,632 8,287,574 8,215,173 December 31, 2014 9,184,925 1,211,551 11,990,723 12,394,930 December 31, 2015 8,357,772 2,020,216 17,534,695 13,300,438 Proved Undeveloped Reserves: December 31, 2013 7,288,203 1,202,825 9,085,569 10,005,290 December 31, 2014 14,425,953 1,832,563 13,977,691 18,588,131 December 31, 2015 15,193,383 5,134,260 39,447,162 26,902,170 (1) BOE (barrels of oil equivalent) is calculated by converting 6 MCF of natural gas to 1 BBL of oil. A BBL (barrel) of oil is one stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons. Standardized Measure of Discounted Future Net Cash Flows Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes that such information is essential for a proper understanding and assessment of the data presented. For the years ended December 31, 2015 and 2014, calculations were made using average prices of $50.28 and $94.99 per barrel of crude oil, respectively, and $2.59 and $4.35 per MCF of natural gas, respectively. Prices and costs are held constant for the life of the wells; however, prices are adjusted by well in accordance with sales contracts, energy content quality, transportation, compression and gathering fees, and regional price differentials. These assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC, and do not necessarily reflect the Company’s expectations of the actual net cash flow to be derived from those reserves, nor the present worth of the properties. Further, actual future net cash flows will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, and changes in governmental regulations and tax rates. Sales prices of both crude oil and natural gas have fluctuated significantly in recent years. Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved crude oil and natural gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. A 10% annual discount rate is used to reflect the timing of the future net cash flows relating to proved reserves. The standardized measure of discounted future net cash flows as of December 31, 2015 and 2014 were as follows: December 31, 2015 2014 Future cash flows $ 1,363,349,591 $ 2,389,844,493 Future costs Production (456,088,889 ) (649,398,768 ) Development (289,026,333 ) (320,222,400 ) Future inflows before income tax 618,234,369 1,420,223,325 Future income taxes (66,565,870 ) (353,602,580 ) Future net cash flows 551,668,499 1,066,620,745 10% annual discount for estimated timing of cash flows (283,242,412 ) (517,581,023 ) Standardized measure of discounted future net cash flows $ 268,426,087 $ 549,039,722 Changes in the Standardized Measure of Discounted Future Net Cash flows Relating to Proved Crude Oil and Nature Gas Reserves were as follows for the years indicated: December 31, 2015 2014 Standardized measure at beginning of year $ 549,039,722 $ 302,771,526 Extensions and discoveries and improved recovery net of future production and development costs 74,142,661 88,919,601 Purchase of minerals in place 11,519,608 270,331,369 Accretion of discount 70,582,116 41,871,778 Net change in sales price, net of production costs (501,189,743 ) (38,540,796 ) Changes in estimated future development costs 56,188,859 (9,274,717 ) Changes of production rates (timing) and other 125,681,828 12,731,855 Revisions of quantity estimates (191,356,505 ) 18,066,206 Net change in income taxes 130,906,060 (40,835,170 ) Sales net of production costs (57,088,519 ) (91,571,228 ) Sales of minerals in place — (5,430,702 ) Net increase (decrease) (280,613,635 ) 246,268,196 Standardized measure at end of year $ 268,426,087 $ 549,039,722 |
Reorganization
Reorganization | 12 Months Ended |
Dec. 31, 2015 | |
Reorganizations [Abstract] | |
Reorganization | 19. Reorganization In connection with the planned reorganization, a new corporate entity was formed, Lonestar Resources U.S. Inc., which immediately prior to the reorganization will acquire the Parent via an Australian Scheme of Arrangement. As a result, certain accounting policies have been adopted in these financial statements as if the Company were a public company. These include earnings per share, segment reporting and supplemental oil and gas disclosures. |
Nature of Business and Presen29
Nature of Business and Presentation (Policies) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Accounting Policies [Abstract] | ||
Basis of Presentation | Basis of Presentation The accompanying interim consolidated financial statements have not been audited by independent public accountants, but in the opinion of management, reflect all adjustments necessary for a fair presentation of the financial position and results of operations. Any and all adjustments are of a normal and recurring nature. Although management believes the unaudited interim-related disclosures in these consolidated financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission. The results of operations and the cash flows for the nine months ended September 30, 2016 are not necessarily indicative of the results to be expected for the full year. | 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”). |
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”), 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”), Lonestar Operating, LLC (“LNO”), 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. | 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”), 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”), Lonestar Operating, LLC (“LNO”), 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. |
Recently Issued Accounting Pronouncements | Recently Issued Accounting Pronouncements In August 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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. The impact is not expected to be material. 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. The impact is not expected to be material. 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. Management is currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements. 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 financial statements. In November 2015, the FASB issued ASU No. 2015-17 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. Management is currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements. In April 2015, the FASB issued updated guidance regarding simplification of 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 did not have a material impact on the Company’s consolidated financial statements. In August 2014, the FASB issued ASU No. 2014-15, “Presentation of Financial Statements — Going Concern” (Subtopic 205-40). This ASU provides guidance on management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. This ASU is effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. Management does not expect the adoption of this guidance to have a material impact on our consolidated financial statements. In May 2014, the FASB issued ASU No. 2014-09 that introduces a new five-step revenue recognition model in which an entity 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. This ASU also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. This standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted, but only for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method of adoption. Management is currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements and the method of adoption. | In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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, 2016, and for annual interim periods thereafter. Early adoption is permitted. We are currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements. In November 2015, the FASB issued ASU No. 2015-17 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. We are currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements. In August 2014, the FASB issued ASU No. 2014-15, “Presentation of Financial Statements—Going Concern” (Subtopic 205-40). This ASU provides guidance on management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. This ASU is effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. We do not expect the adoption of this guidance to have a material impact on our consolidated financial statements. In May 2014, the FASB issued ASU No. 2014-09 that introduces a new five-step revenue recognition model in which an entity 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. This ASU also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. This standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted, but only for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method of adoption. We are currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements and the method of adoption. |
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. | |
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. | |
Currency Translation | Currency Translation The consolidated financial statements are presented in U.S. dollars. The functional currency of Parent is the Australian Dollar. At the end of each reporting period, the assets and liabilities of Parent are translated from its functional currency to U.S. dollars using the exchange rate at the end of the month. The monthly results of operations of Parent are generally translated from its functional currency to U.S. dollars using the average exchange rate during the month. Changes in exchange rates result in currency translation gains and losses, which are recorded within other comprehensive income (loss). Parent may also enter into transactions in currencies other than their functional currency. At the end of each reporting period, Parent re-measures the related receivables, payables, and cash to its functional currency using the exchange rate at the end of the period. Changes in exchange rates between the time the transactions were entered into and the end of the reporting period result in currency transaction gains or losses, which are recorded in the consolidated statements of operations. | |
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 credit losses since its inception and does not carry an allowance for uncollectible amounts at December 31, 2015. 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. Oil, NGL and natural gas revenues from Shell Trading (US) Company, Trafigura AG and BP Products North America LLC for the year ended December 31, 2014, represented 36%, 23% and 16%, 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 26%, 25% and 23%, respectively, of total receivables at December 31, 2015. Accounts receivable relating to oil, NGL and natural gas sales from Shell Trading, Trafigura AG and BP Products North America LLC represented 19%, 27% and 32%, respectively, of total receivables at December 31, 2014. | |
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 $8,927,000 as of December 31, 2015 and impairment of proven oil and gas properties of $19,696,000 and $5,478,000 for the years ended December 31, 2015 and 2014, respectively. | |
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, 2015 or 2014. | |
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 deferred tax assets and recognizes a valuation allowance based on the estimate of the amount of such deferred tax assets which the Company believes does not meet the more-likely-than-not recognition criteria. At December 31, 2015 and 2014, it has been concluded that no deferred tax asset valuation allowance is necessary. 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, 2015 or 2014. | |
Share-Based Payments | Share-Based Payments The Company accounts for equity-based awards in accordance with ASC 718, Compensation-Stock Compensation |
Nature of Business and Presen30
Nature of Business and Presentation (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Accounting Policies [Abstract] | |
Restatement Changes Made to Financial Statements Previously Filed | The following table summarizes the restatement changes made to the Consolidated Statement of Cash Flows for the nine months ended September 30, 2016 previously filed in the Company’s Quarterly Report on Form 10-Q on November 10, 2016. Originally Restatement Adjustment As Restated Gain on disposal of bonds — (29,363 ) (29,363 ) Net cash provided by operating activities 46,986 (29,363 ) 17,623 Payments on borrowings (84,152 ) 29,363 (54,789 ) Net cash provided by financing activities (19,836 ) 29,363 9,527 |
Commodity Price Risk Activiti31
Commodity Price Risk Activities (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Schedule of Derivative Transactions Outstanding | As of September 30, 2016, the following derivative transactions were outstanding: Instrument Total Volume Settlement Period Fixed Price Oil – WTI Fixed Price Swap 48,500 Bbl October – December 2016 $ 84.45 Oil – WTI Fixed Price Swap 70,100 Bbl October – December 2016 90.45 Oil – WTI Fixed Price Swap 28,400 Bbl October – December 2016 63.20 Oil – WTI Fixed Price Swap 36,500 Bbl October – December 2016 56.90 Oil – WTI Fixed Price Swap 49,050 Bbl October – December 2016 42.11 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 Instrument Total Volume Settlement Period Puts Calls Oil – 3 Way Collar 365,100 Bbl January – December 2017 $40.00 / 60.00 $ 85.00 | As of December 31, 2015, the following derivative transactions were outstanding: Instrument Total Volume Settlement Period Fixed Price Oil – WTI Fixed Price Swap 205,000 BBL January –December 2016 $ 84.45 Oil – WTI Fixed Price Swap 309,000 BBL January – December 2016 90.45 Oil – WTI Fixed Price Swap 135,600 BBL January – December 2016 63.20 Oil – WTI Fixed Price Swap 183,400 BBL January – December 2016 56.90 Instrument Total Volume Settlement Period Puts Calls Oil – 3 Way Collar 365,100 BBL January – December 2017 $40.00 / 60.00 $ 85.00 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
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 September 30, 2016 and December 31, 2015, for each fair value hierarchy level: Fair Value Measurements Using Quoted (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total September 30, 2016 (unaudited) (In thousands) Assets: Commodity derivatives $ — $ 8,853 $ — $ 8,853 Liabilities: Commodity derivatives — (498 ) — $ (498 ) Warrant liability (5,738 ) $ (5,738 ) Total $ — $ 8,355 $ (5,738 ) $ 2,617 December 31, 2015 (In thousands) Assets: Commodity derivatives $ — $ 36,083 $ — $ 36,083 Liabilities: Commodity derivatives — — — $ — Total $ — $ 36,083 $ — $ 36,083 | The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2015 and 2014, 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, 2014 (In thousands) Assets: Commodity derivatives $ — $ 43,759 $ — $ 43,759 Liabilities: Commodity derivatives — — — $ — Total $ — $ 43,759 $ — $ 43,759 |
Oil and Gas Properties (Tables)
Oil and Gas Properties (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Extractive Industries [Abstract] | ||
Summary of Oil and Gas Properties | A summary of oil and gas properties follows: September 30, (unaudited) December 31, (In thousands) Proved properties and equipment $ 525,809 $ 584,692 Proved properties and equipment held for sale 79,537 — Unproved properties 71,658 70,298 Less accumulated depreciation, depletion, and amortization (160,793 ) (166,890 ) Less accumulated depreciation, depletion, amortization, and impairment on properties held for sale (65,922 ) — $ 450,289 $ 488,100 | A summary of oil and gas properties as of December 31, follows: 2015 2014 Proved properties and equipment $ 584,691,945 $ 495,954,566 Unproved properties 70,298,349 65,725,668 Less accumulated depreciation, depletion, and amortization (166,890,697 ) (80,600,959 ) $ 488,099,597 $ 481,079,275 |
Accrued Liabilities (Tables)
Accrued Liabilities (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Payables and Accruals [Abstract] | ||
Schedule of Accrued Liabilities | The accrued liabilities consist of the following: September 30, (unaudited) December 31, 2015 (In thousands) Bonus payable $ 1,604 $ 1,433 Payroll payable 2 28 Accrued interest 7,286 4,420 Accrued rent 328 410 Accrued expenses 1,928 1,401 Other 1,302 584 $ 12,450 $ 8,276 | The accrued liabilities consist of the following at December 31: 2015 2014 Bonus payable $ 1,432,768 $ 1,848,612 Severance and vacation payable 28,388 283,540 Accrued interest 4,420,317 4,149,105 Accrued rent 409,643 489,191 Accrued expenses 1,401,080 4,592,152 Other 583,890 242,520 $ 8,276,086 $ 11,605,120 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Schedule of Long-Term Debt | The Company’s debt consists of the following: September 30, (unaudited) December 31, 2015 (In thousands) Senior Secured Credit Facility $ 94,500 $ 87,000 Second Lien Notes 33,024 — 8.750% Senior Notes 151,848 220,000 Gap Financing 2,063 — Less unamortized discount on 8.750% Senior Notes (1,898 ) (3,575 ) Less deferred financing costs on 8.750% Senior Notes (945 ) (1,785 ) Less deferred financing costs on Second Lien Notes (1,180 ) — Other 276 286 $ 277,688 $ 301,926 | The Company’s debt consists of the following: December 31, 2015 2014 Revolving credit facility $ 87,000,000 $ 49,000,000 8.75% senior notes 220,000,000 220,000,000 Less discount on 8.75% senior notes (3,575,000 ) (4,675,000 ) Other 285,512 288,529 $ 303,710,512 $ 264,613,529 |
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 % | On or after April 15, 2016, the Company may redeem the 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 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 % |
Stock Options (Tables)
Stock Options (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Disclosure of Compensation Related Costs, Share-based 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 (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 (64,667 ) 18.00 — Forfeited — — — Outstanding at September 30, 2016 820,269 $ 15.00 0.5 Options vested and exercisable at September 30, 2016 778,019 $ 15.00 0.5 Shares Weighted Average Value per 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 2.25 Vested (35,000 ) 1.90 15.00 2.25 Forfeited — — — — Outstanding non-vested options at September 30, 2016 42,250 $ 9.00 $ 15.50 0.25 | The following tables summarize certain information related to outstanding stock options under the 2012 Plan as of and for the years ended December 31, 2015 and 2014: Shares Weighted Weighted Average Options outstanding at December 31,2013 1,477,685 $ 16.00 3.0 Granted 410,822 18.00 3.0 Exercised — — — Canceled/Expired (24,667 ) 18.00 1.5 Forfeited (249,570 ) 15.00 2.0 Outstanding at December 31, 2014 1,614,270 16.00 2.0 Options vested and exercisable at December 31, 2014 970,155 $ 16.00 2.0 Granted 160,000 10.00 1.0 Exercised — — — Canceled/Expired (50,000 ) 12.00 — Forfeited (24,398 ) 12.00 — Outstanding at December 31, 2015 1,699,872 15.50 1.0 Options vested and exercisable at December 31, 2015 1,615,372 $ 15.50 1.0 Shares Weighted Weighted per share Weighted Average (in years) Outstanding non-vested options at December 31, 2013 882,456 $ 11.50 $ 15.00 3.0 Granted 410,822 4.50 18.00 3.0 Vested (399,593 ) 4.50 16.00 3.0 Forfeited (249,570 ) 4.50 15.00 3.0 Outstanding non-vested options at December 31, 2014 644,115 $ 4.50 $ 16.00 2.0 Granted 160,000 2.40 10.00 1.0 Vested (695,217 ) 4.00 15.50 1.0 Forfeited (24,398 ) 4.50 15.50 — Outstanding non-vested options at December 31, 2015 84,500 $ 4.50 $ 15.50 1.0 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
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 three and nine month periods ended September 30, 2016 and 2015: Unaudited Earnings Per Share (After Reorganization) Three months ended Nine months ended 2016 2015 2016 2015 Net income (loss) per common share: Basic $ (1.44 ) $ 0.88 $ (4.64 ) $ (0.33 ) Diluted (1.44 ) 0.88 (4.64 ) (0.33 ) Weighted average common shares outstanding: Basic 7,842,586 7,522,025 7,629,896 7,522,025 Diluted 7,842,586 7,522,025 7,629,896 7,522,025 | |
Schedule of Unaudited Pro Forma Earnings Per Share (After Reorganization) | The following table presents unaudited pro forma 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 years ended December 31, 2015 and 2014: UNAUDITED PRO FORMA EARNINGS PER SHARE (AFTER REORGANIZATION) 2015 2014 Net income (loss) per common share: Basic $ (3.63 ) $ 4.97 Diluted (3.63 ) 4.84 Weighted average common shares outstanding: Basic 7,522,025 7,330,602 Diluted 7,522,025 7,534,805 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Asset Retirement Obligations | The following represents a reconciliation of the asset retirement obligations: Amount Asset retirement obligations at December 31, 2013 $ 5,937,118 Wells drilled during the year 543,555 Wells acquired during the year 965,917 Wells sold during the year (482,081 ) Accretion of discount 201,076 Wells plugged and abandoned during the year (330,970 ) Asset retirement obligations at December 31, 2014 6,834,615 Wells drilled during the year 330,969 Wells acquired during the year 176,156 Wells sold during the year (5,421 ) Accretion of discount 214,335 Wells plugged and abandoned during the year (63,153 ) Asset retirement obligations at December 31, 2015 $ 7,487,501 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 2014 Current tax expense (benefit) Federal $ 287,855 $ 112,621 State 74,324 81,936 Deferred tax expense (benefit) Federal (15,130,060 ) 21,592,426 State (353,007 ) 644,739 Income tax expense (benefit) $ (15,120,888 ) $ 22,431,722 |
Difference between Income Taxes Computed at Federal Statutory Rate and Provision for Income Taxes | The following table provides a reconciliation of the Company’s effective tax rate from the U.S. 35% statutory rate for the periods indicated: Years Ended December 31, 2015 2014 Expected income tax provision (benefit) at statutory rate $ (14,858,849 ) $ 20,614,073 State tax, tax effected 10,536 675,733 Other (39,646 ) 833,016 Rate difference (232,929 ) 308,900 Actual income tax provision $ (15,120,888 ) $ 22,431,722 |
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, 2015 2014 Deferred tax assets: Net operating loss carryforward $ 77,507,544 $ 64,772,240 Severance costs — 96,679 Organizational expenses 57,439 58,187 Stock based compensation 2,431,147 1,522,325 Intangibles 775,719 869,594 Other 1,418,801 24,207 82,190,650 67,343,232 Deferred tax liabilities: Oil and gas properties and other property and equipment, principally due to intangible drilling costs (86,789,694 ) (84,371,190 ) Unrealized hedging gain (11,414,232 ) (14,482,786 ) Net deferred tax liabilities $ (16,013,276 ) $ (31,510,744 ) |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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 2016 $ 478,040 2017 455,600 2018 411,768 2019 422,301 2020 432,835 Thereafter 368,011 Total $ 2,568,555 |
Supplemental Information on O41
Supplemental Information on Oil and Natural Gas Exploration and Production Activities (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Extractive Industries [Abstract] | |
Schedule of Capitalized Costs of Oil and Natural Gas Properties | The following table presents the Company’s aggregate capitalized costs relating to oil and gas activities at the end of the periods indicated: December 31, 2015 2014 Oil and natural gas properties: Proved properties and equipment $ 577,764,738 $ 489,472,814 Unproved properties 70,298,349 65,725,668 Capitalized asset retirement cost 6,927,207 6,481,752 Less: Accumulated depletion and amortization (133,080,366 ) (75,122,695 ) Property impairment (33,810,331 ) (5,478,264 ) Total $ 488,099,597 $ 481,079,275 |
Schedule of Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development | Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Years ended December 31, 2015 2014 Property acquisition costs : Unproved properties $ 7,327,635 $ 12,247,000 Proved properties 1,395,862 58,731,282 Exploration costs — — Development costs 85,458,433 164,180,576 Total costs incurred $ 94,181,930 235,158,858 |
Schedule of Results of Operations for Oil and Natural Gas Producing Activities | The following table sets for the results of operations from oil and gas producing activities for the years ended December 31, 2015 and 2014. Years ended December 31, 2015 2014 Oil and gas producing activities: Oil sales $ 70,739,269 $ 104,233,379 Natural gas sales 6,823,019 7,589,599 Natural gas liquids sales 1,928,068 3,803,582 Lease operating and gas gathering (17,860,216 ) (16,631,611 ) Production, ad valorem and severance taxes (4,981,826 ) (7,123,332 ) Accretion of asset retirement obligations (214,335 ) (201,076 ) Depreciation, depletion and amortization (58,827,705 ) (40,521,546 ) Property impairment (28,622,961 ) (5,478,264 ) Results of operations from oil and gas producing activities $ (31,016,687 ) $ 45,670,731 Depletion rate per BOE $ 25.16 $ 24.78 |
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve | The following information table sets forth changes in estimated net proved developed crude oil and natural gas reserves for the years ended December 31, 2015 and 2014. Oil (BBL) NGLs (BBL) Gas (MCF) BOE(1) Net proved reserves Reserves at December 31, 2013 13,483,483 1,841,457 17,373,143 18,220,463 New discoveries and extensions 2,462,295 321,301 2,528,029 3,204,934 Purchase of reserves in place 9,648,101 484,493 3,655,020 10,741,764 Reserves sold (252,200 ) — (5,632 ) (253,139 ) Revisions of prior year estimates (532,522 ) 551,078 4,106,883 703,038 Production (1,198,279 ) (154,215 ) (1,689,029 ) (1,633,999 ) Reserves at December 31, 2014 23,610,878 3,044,114 25,968,414 30,983,061 New discoveries & extensions 6,575,775 4,281,649 34,155,539 16,550,014 Purchase of reserves in place 1,541,828 297,634 2,344,083 2,230,142 Reserves sold — — — — Revisions of prior year estimates (6,637,821 ) (146,113 ) (2,562,392 ) (7,210,998 ) Production (1,539,505 ) (322,808 ) (2,923,787 ) (2,349,611 ) Reserves at December 31, 2015 23,551,155 7,154,476 56,981,857 40,202,608 Proved Developed Reserves: December 31, 2013 6,195,280 638,632 8,287,574 8,215,173 December 31, 2014 9,184,925 1,211,551 11,990,723 12,394,930 December 31, 2015 8,357,772 2,020,216 17,534,695 13,300,438 Proved Undeveloped Reserves: December 31, 2013 7,288,203 1,202,825 9,085,569 10,005,290 December 31, 2014 14,425,953 1,832,563 13,977,691 18,588,131 December 31, 2015 15,193,383 5,134,260 39,447,162 26,902,170 (1) BOE (barrels of oil equivalent) is calculated by converting 6 MCF of natural gas to 1 BBL of oil. A BBL (barrel) of oil is one stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons. |
Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves | The standardized measure of discounted future net cash flows as of December 31, 2015 and 2014 were as follows: December 31, 2015 2014 Future cash flows $ 1,363,349,591 $ 2,389,844,493 Future costs Production (456,088,889 ) (649,398,768 ) Development (289,026,333 ) (320,222,400 ) Future inflows before income tax 618,234,369 1,420,223,325 Future income taxes (66,565,870 ) (353,602,580 ) Future net cash flows 551,668,499 1,066,620,745 10% annual discount for estimated timing of cash flows (283,242,412 ) (517,581,023 ) Standardized measure of discounted future net cash flows $ 268,426,087 $ 549,039,722 |
Summary of Changes in the Standardized Measure of Discounted Future Net Cash Fows | Changes in the Standardized Measure of Discounted Future Net Cash flows Relating to Proved Crude Oil and Nature Gas Reserves were as follows for the years indicated: December 31, 2015 2014 Standardized measure at beginning of year $ 549,039,722 $ 302,771,526 Extensions and discoveries and improved recovery net of future production and development costs 74,142,661 88,919,601 Purchase of minerals in place 11,519,608 270,331,369 Accretion of discount 70,582,116 41,871,778 Net change in sales price, net of production costs (501,189,743 ) (38,540,796 ) Changes in estimated future development costs 56,188,859 (9,274,717 ) Changes of production rates (timing) and other 125,681,828 12,731,855 Revisions of quantity estimates (191,356,505 ) 18,066,206 Net change in income taxes 130,906,060 (40,835,170 ) Sales net of production costs (57,088,519 ) (91,571,228 ) Sales of minerals in place — (5,430,702 ) Net increase (decrease) (280,613,635 ) 246,268,196 Standardized measure at end of year $ 268,426,087 $ 549,039,722 |
Nature of Business and Presen42
Nature of Business and Presentation - Additional Information (Detail) | 9 Months Ended |
Sep. 30, 2016USD ($) | |
Nature Of Business And Presentation [Abstract] | |
Gain (loss) recorded under reorganization | $ 0 |
Restatement - Additional Inform
Restatement - Additional Information (Detail) | Sep. 30, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
8.750% Senior Notes Due April 15, 2019 | |||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||
Debt instrument interest rate | 8.75% | 8.75% | 8.75% |
Restatement Changes Made to Fin
Restatement Changes Made to Financial Statements Previously Filed (Detail) - USD ($) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | |
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||||
Gain on disposal of bonds | $ (29,363,000) | $ (29,363,000) | |||
Net cash provided by operating activities | 17,623,000 | $ 50,029,000 | $ 50,838,805 | $ 82,227,450 | |
Payments on borrowings | (54,789,000) | (93,514,000) | (102,513,602) | (195,000,000) | |
Net cash provided by financing activities | 9,527,000 | $ 29,991,000 | $ 37,996,984 | $ 154,470,000 | |
Scenario, Previously Reported | |||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||||
Net cash provided by operating activities | 46,986,000 | ||||
Payments on borrowings | (84,152,000) | ||||
Net cash provided by financing activities | (19,836,000) | ||||
Restatement Adjustment | |||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||||
Gain on disposal of bonds | (29,363,000) | ||||
Net cash provided by operating activities | (29,363,000) | ||||
Payments on borrowings | 29,363,000 | ||||
Net cash provided by financing activities | $ 29,363,000 |
Acquisitions and Divestitures -
Acquisitions and Divestitures - Additional Information (Detail) | Sep. 26, 2016USD ($) | Aug. 02, 2016USD ($)aWellshares | Jun. 15, 2016USD ($) | Jan. 31, 2015USD ($)aWell | Sep. 30, 2014USD ($)a | Jun. 30, 2014USD ($) | Mar. 31, 2014USD ($)aWells | Sep. 30, 2016USD ($)Boe | Jun. 30, 2016aBoe | Mar. 31, 2016USD ($)a | Jun. 30, 2016USD ($)a | Sep. 30, 2016USD ($) | Sep. 30, 2015USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) |
Business Acquisition [Line Items] | |||||||||||||||
Production related to property barrels of oil equivalents per day | Boe | 436 | 86 | |||||||||||||
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 | $ 29,100,000 | |||||||||||||
Acquisition of oil and gas properties | 3,115,000 | $ 7,032,000 | $ 8,723,497 | $ 70,978,282 | |||||||||||
Gain (loss) on divestitures of business | $ 1,900,000 | $ 461,000 | |||||||||||||
Business divestiture effective date of divestiture | Jul. 1, 2016 | ||||||||||||||
Number of non-operated wells working interest exchanged | Well | 2 | ||||||||||||||
Loss on exchange of oil and gas properties | $ (629,000) | ||||||||||||||
Proceeds from sales of oil and gas properties | $ 3,200,000 | $ 2,720,000 | $ 3,200,000 | ||||||||||||
La Salle | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Payments to acquire land | $ 770,000 | ||||||||||||||
Area of land acquired | a | 220 | ||||||||||||||
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% | ||||||||||||||
Eagle Ford Shale | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Acquisition of oil and gas properties | $ 70,737,000 | ||||||||||||||
Area of land acquired | a | 15,232 | ||||||||||||||
Area of land acquired, Net | a | 13,156 | ||||||||||||||
Eagle Ford Shale | Proven Oil And Gas Properties | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Acquisition of oil and gas properties | $ 58,490,000 | ||||||||||||||
Eagle Ford Shale | Unproved Oil And Gas Properties | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Acquisition of oil and gas properties | 12,247,000 | ||||||||||||||
Eagle Ford Shale | La Salle | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Acquisition of oil and gas properties | $ 2,500,000 | $ 2,385,000 | |||||||||||||
Payments to acquire land | $ 500,000 | ||||||||||||||
Area of land acquired | a | 159 | 720 | 1,240 | ||||||||||||
Number of wells | Wells | 4 | ||||||||||||||
Eagle Ford Shale | La Salle | Proven Oil And Gas Properties | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Acquisition of oil and gas properties | $ 750,000 | ||||||||||||||
Eagle Ford Shale | La Salle | Unproved Oil And Gas Properties | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Acquisition of oil and gas properties | $ 1,635,000 | ||||||||||||||
Common Class A | Juneau Energy, LLC | Brazos County | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Shares of common stock payable in total purchase | shares | 500,227 |
Restricted Certificate of Dep46
Restricted Certificate of Deposit - Additional Information (Detail) - Restricted Certificate of Deposit | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Certificates Of Deposit [Line Items] | ||
Investment maturity date | Mar. 8, 2017 | Mar. 8, 2016 |
Investment interest rate | 0.25% | 0.25% |
Commodity Price Risk Activiti47
Commodity Price Risk Activities - Additional Information (Detail) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016bbl_per_dayDeliveryObligationbbl | Dec. 31, 2015bbl_per_dayBarrels_per_dayDeliverablesbbl | |
Derivative [Line Items] | ||
Number of open physical obligations | 0 | 0 |
Derivative Contracts, 2016 | ||
Derivative [Line Items] | ||
Derivative contracts, aggregate volume | 833,000 | |
Derivative contracts, aggregate volume per day | Barrels_per_day | 2,276 | |
Derivative Contracts, 2017 | ||
Derivative [Line Items] | ||
Derivative contracts, aggregate volume | 547,600 | 365,100 |
Derivative contracts, aggregate volume per day | bbl_per_day | 1,500 | 1,000 |
Derivative Contracts, remainder of 2016 | ||
Derivative [Line Items] | ||
Derivative contracts, aggregate volume | 232,550 | |
Derivative contracts, aggregate volume per day | bbl_per_day | 2,528 |
Commodity Price Risk Activiti48
Commodity Price Risk Activities - Schedule of Derivative Transactions Outstanding (Detail) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016$ / bblbbl | Dec. 31, 2015$ / bblbbl | |
Oil – WTI Fixed Price Swap - $84.45 - Settlement Period - October - December 2016 | ||
Derivative [Line Items] | ||
Total Volume | bbl | 48,500 | |
Fixed Price | 84.45 | |
Oil – WTI Fixed Price Swap - $90.45 - Settlement Period - October - December 2016 | ||
Derivative [Line Items] | ||
Total Volume | bbl | 70,100 | |
Fixed Price | 90.45 | |
Oil – WTI Fixed Price Swap - $63.20 - Settlement Period - October - December 2016 | ||
Derivative [Line Items] | ||
Total Volume | bbl | 28,400 | |
Fixed Price | 63.20 | |
Oil – WTI Fixed Price Swap - $56.90 - Settlement Period - October - December 2016 | ||
Derivative [Line Items] | ||
Total Volume | bbl | 36,500 | |
Fixed Price | 56.90 | |
Oil – WTI Fixed Price Swap - $42.11 - Settlement Period - October - December 2016 | ||
Derivative [Line Items] | ||
Total Volume | bbl | 49,050 | |
Fixed Price | 42.11 | |
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 - 3 Way Collar - Settlement Period - January - December 2017 | ||
Derivative [Line Items] | ||
Total Volume | bbl | 365,100 | 365,100 |
Oil - 3 Way Collar - Settlement Period - January - December 2017 | Puts | Minimum | ||
Derivative [Line Items] | ||
Fixed Price | 40 | 40 |
Oil - 3 Way Collar - Settlement Period - January - December 2017 | Puts | Maximum | ||
Derivative [Line Items] | ||
Fixed Price | 60 | 60 |
Oil - 3 Way Collar - Settlement Period - January - December 2017 | Calls | ||
Derivative [Line Items] | ||
Fixed Price | 85 | 85 |
Oil - WTI Fixed Price Swap - $84.45 - Settlement Period - January - December 2016 | ||
Derivative [Line Items] | ||
Total Volume | bbl | 205,000 | |
Fixed Price | 84.45 | |
Oil - WTI Fixed Price Swap - $90.45 - Settlement Period - January - December 2016 | ||
Derivative [Line Items] | ||
Total Volume | bbl | 309,000 | |
Fixed Price | 90.45 | |
Oil - WTI Fixed Price Swap - $63.20 - Settlement Period - January - December 2016 | ||
Derivative [Line Items] | ||
Total Volume | bbl | 135,600 | |
Fixed Price | 63.20 | |
Oil - WTI Fixed Price Swap - $56.90 - Settlement Period - January - December 2016 | ||
Derivative [Line Items] | ||
Total Volume | bbl | 183,400 | |
Fixed Price | 56.90 |
Fair Value Measurements - Addit
Fair Value Measurements - Additional Information (Detail) - USD ($) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2016 | Sep. 30, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Debt Instrument [Line Items] | ||||
Impairment of oil and gas properties | $ 29,144,000 | $ 31,082,000 | $ 28,622,961 | $ 5,478,264 |
8.750% Senior Notes Due April 15, 2019 | ||||
Debt Instrument [Line Items] | ||||
Fair value of senior notes | $ 96,800,000 | $ 96,800,000 | ||
Debt instrument interest rate | 8.75% | 8.75% | 8.75% | 8.75% |
Schedule of Assets and Liabilit
Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Warrant liability | $ (5,738) | ||
Total | 2,617 | $ 36,083 | $ 43,759 |
Commodity Derivatives | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Assets | 8,853 | 36,083 | 43,759 |
Liabilities | (498) | ||
Significant Other Observable Inputs (Level 2) | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Total | 8,355 | 36,083 | 43,759 |
Significant Other Observable Inputs (Level 2) | Commodity Derivatives | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Assets | 8,853 | $ 36,083 | $ 43,759 |
Liabilities | (498) | ||
Significant Unobservable Inputs (Level 3) | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Warrant liability | (5,738) | ||
Total | $ (5,738) |
Oil and Gas Properties - Summar
Oil and Gas Properties - Summary of Oil and Gas Properties (Detail) - USD ($) | Sep. 30, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | |||
Proved properties and equipment | $ 525,809,000 | $ 584,691,945 | $ 495,954,566 |
Proved properties and equipment held for sale | 79,537,000 | ||
Unproved properties | 71,658,000 | 70,298,349 | 65,725,668 |
Less accumulated depreciation, depletion, and amortization | (160,793,000) | (166,890,697) | (80,600,959) |
Less accumulated depreciation, depletion, amortization, and impairment on properties held for sale | (65,922,000) | ||
Oil and gas property, net | $ 450,289,000 | $ 488,099,597 | $ 481,079,275 |
Oil and Gas Properties - Additi
Oil and Gas Properties - Additional Information (Detail) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||
Sep. 30, 2016USD ($)Boe | Jun. 30, 2016USD ($)Boe | Sep. 30, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Sep. 26, 2016USD ($) | Jun. 15, 2016USD ($) | |
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | |||||||
Production related to property barrels of oil equivalents per day | Boe | 436 | 86 | |||||
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 | $ 29,100,000 | |||||
Asset retirement costs | 4,000,000 | ||||||
Related asset retirement liability | 4,505,000 | 4,505,000 | |||||
Impairment related to leased acreage | $ 1,900,000 | ||||||
Impairment of oil and gas properties | $ 29,144,000 | $ 31,082,000 | $ 28,622,961 | $ 5,478,264 | |||
Proven Oil And Gas Properties | |||||||
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | |||||||
Impairment of oil and gas properties | 19,696,000 | $ 5,478,000 | |||||
Unproved Oil And Gas Properties | |||||||
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | |||||||
Impairment of oil and gas properties | $ 8,927,000 |
Accrued Liabilities - Schedule
Accrued Liabilities - Schedule of Accrued Liabilities (Detail) - USD ($) | Sep. 30, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Payables And Accruals [Abstract] | |||
Bonus payable | $ 1,604,000 | $ 1,432,768 | $ 1,848,612 |
Payroll payable | 2,000 | 28,000 | |
Severance and vacation payable | 28,388 | 283,540 | |
Accrued interest | 7,286,000 | 4,420,317 | 4,149,105 |
Accrued rent | 328,000 | 409,643 | 489,191 |
Accrued expenses | 1,928,000 | 1,401,080 | 4,592,152 |
Other | 1,302,000 | 583,890 | 242,520 |
Accrued liabilities excluding due to related parties | $ 12,450,000 | $ 8,276,086 | $ 11,605,120 |
Long-Term Debt - Schedule of De
Long-Term Debt - Schedule of Debt (Detail) - USD ($) | Sep. 30, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Debt Instrument [Line Items] | |||
Senior Secured Credit Facility | $ 94,500,000 | $ 87,000,000 | $ 49,000,000 |
Second Lien Notes | 33,024,000 | ||
8.750% Senior Notes | 151,848,000 | 220,000,000 | 220,000,000 |
Less unamortized discount on 8.750% Senior Notes | (1,898,000) | (3,575,000) | (4,675,000) |
Other | 276,000 | 285,512 | 288,529 |
Long-term debt | 303,710,512 | $ 264,613,529 | |
Long-term debt net of deferred financing costs on bonds | 277,688,000 | $ 301,926,000 | |
8.750% Senior Notes Due April 15, 2019 | |||
Debt Instrument [Line Items] | |||
Less deferred financing costs | (945,000) | ||
Gap Financing | |||
Debt Instrument [Line Items] | |||
Long-term debt | 2,063,000 | ||
Second Lien Notes | |||
Debt Instrument [Line Items] | |||
Less deferred financing costs | $ (1,180,000) |
Long-Term Debt - Schedule of 55
Long-Term Debt - Schedule of Debt (Parenthetical) (Detail) | Sep. 30, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
8.750% Senior Notes Due April 15, 2019 | |||
Debt Instrument [Line Items] | |||
Debt instrument interest rate | 8.75% | 8.75% | 8.75% |
Long-Term Debt - Senior Secured
Long-Term Debt - Senior Secured Credit Facility - Additional Information (Detail) - USD ($) | Jul. 27, 2016 | Jul. 28, 2015 | Sep. 30, 2016 | May 19, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Debt Instrument [Line Items] | ||||||
Senior Secured Credit Facility | $ 94,500,000 | $ 87,000,000 | $ 49,000,000 | |||
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) | Letter of Credit | ||||||
Debt Instrument [Line Items] | ||||||
Increase margin on loans | 0.75% | |||||
Third Amendment to Credit Agreement and Limited Waiver (the Amendment) | Quarter Period Ending June 30, 2016 | ||||||
Debt Instrument [Line Items] | ||||||
Leverage ratio | 475.00% | |||||
Third Amendment to Credit Agreement and Limited Waiver (the Amendment) | Quarter Period Ending September 30, 2016 | ||||||
Debt Instrument [Line Items] | ||||||
Leverage ratio | 450.00% | |||||
Third Amendment to Credit Agreement and Limited Waiver (the Amendment) | Quarter Period Ending December 31, 2016 | ||||||
Debt Instrument [Line Items] | ||||||
Leverage ratio | 425.00% | |||||
Third Amendment to Credit Agreement and Limited Waiver (the Amendment) | All Periods Thereafter | ||||||
Debt Instrument [Line Items] | ||||||
Leverage ratio | 400.00% | |||||
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 | $ 94,500,000 | $ 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 | 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 (Detail) - 8.750% Senior Notes Due April 15, 2019 - USD ($) | Apr. 15, 2016 | Apr. 04, 2014 | Sep. 30, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Debt Instrument [Line Items] | |||||
Debt instrument interest rate | 8.75% | 8.75% | 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 (Detail) - 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 (Detail) - USD ($) | 12 Months Ended | ||
Dec. 31, 2014 | Sep. 30, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | |||
Debt issuance costs | $ 3,300,000 | $ 2,900,000 | |
Debt issuance costs capitalized | 3,500,000 | ||
Debt issuance costs, expensed | $ 700,000 | ||
Senior Secured Credit Facility | |||
Debt Instrument [Line Items] | |||
Debt issuance costs | $ 1,300,000 | $ 1,100,000 |
Long-Term Debt - Securities Pur
Long-Term Debt - Securities Purchase Agreement and Second Lien Notes - Additional Information (Detail) - USD ($) | Aug. 02, 2016 | Sep. 30, 2016 | Sep. 30, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Debt Instrument [Line Items] | |||||
Unrealized loss on warrants | $ (611,000) | $ (611,000) | |||
Class A Voting Common Stock | |||||
Debt Instrument [Line Items] | |||||
Warrants to purchase common stock | 760,000 | 760,000 | |||
Warrant liability | $ 5,100,000 | $ 5,100,000 | |||
Second Lien Notes | |||||
Debt Instrument [Line Items] | |||||
Debt instrument face amount | $ 38,000,000 | $ 38,000,000 | |||
8.750% Senior Notes Due April 15, 2019 | |||||
Debt Instrument [Line Items] | |||||
Debt instrument interest rate | 8.75% | 8.75% | 8.75% | 8.75% | |
Debt instrument repurchase amount | $ 68,200,000 | $ 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 | $ 29,400,000 | ||||
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 voting 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 (Detail) - USD ($) | Sep. 29, 2016 | Sep. 30, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Debt Instrument [Line Items] | ||||
Long-term debt | $ 303,710,512 | $ 264,613,529 | ||
8.750% Senior Notes Due April 15, 2019 | ||||
Debt Instrument [Line Items] | ||||
Debt instrument interest rate | 8.75% | 8.75% | 8.75% | |
Debt instrument maturity date | Apr. 15, 2019 | |||
Gap Financing If Paid before December 31, 2016 | Seaport Global Securities LLC | ||||
Debt Instrument [Line Items] | ||||
Gap financing repayment percentage | 105.00% | |||
Gap Financing If Paid on or after January 1, 2017 | Seaport Global Securities LLC | ||||
Debt Instrument [Line Items] | ||||
Gap financing repayment percentage | 111.10% | |||
Gap Financing | Seaport Global Securities LLC | ||||
Debt Instrument [Line Items] | ||||
Long-term debt | $ 2,063,320 | |||
Gap Financing | Seaport Global Securities LLC | Class A Voting Common Stock | ||||
Debt Instrument [Line Items] | ||||
Percentage of closing price of common stock to be taken as denominator on gap financing repayment | 90.00% | |||
Maximum number of shares to be issued on gap financing repayment | 460,000 |
Stock Options - Additional Info
Stock Options - Additional Information (Detail) - USD ($) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2016 | Sep. 30, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Expected life of stock options issued | 3 years 6 months | 3 years 6 months | ||
Stock options vesting periods | 3 years | 3 years | ||
Stock options grant expirations periods | 4 years | 4 years | ||
Weighted average volatility rate of common share price | 58.60% | |||
Cash dividend on common shares | $ 0 | |||
Dividend yield | 0.00% | |||
Stock options exercised | 0 | 0 | ||
Compensation expenses for stock options granted using fair-value method | $ 121,986 | $ 312,638 | $ 2,585,000 | $ 1,938,000 |
Compensation expenses for stock options granted using fair-value method | $ 380,000 | |||
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 | |||
Dividend yield | 0.00% |
Stock Options - Schedule of Out
Stock Options - Schedule of Outstanding Stock Options (Detail) - $ / shares | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Outstanding, Weighted Average Remaining Contractual Term (in years) | 3 years 6 months | 3 years 6 months | ||
Lonestar Resources Limited 2012 Employee Share Option Plan | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Outstanding at beginning of period, Shares | 1,699,872 | 1,614,270 | 1,477,685 | |
Granted, Shares | 160,000 | 410,822 | ||
Canceled/Expired, Shares | (50,000) | (24,667) | ||
Forfeited, Shares | (24,398) | (249,570) | ||
Outstanding at end of period, Shares | 1,699,872 | 1,614,270 | 1,477,685 | |
Options vested and exercisable, Shares | 1,615,372 | 970,155 | ||
Outstanding at beginning of period, Weighted Average Exercise Price Per Share | $ 15.50 | $ 16 | $ 16 | |
Granted, Weighted Average Remaining Contractual Term | 1 year | 3 years | ||
Granted, Weighted Average Exercise Price Per Share | $ 10 | $ 18 | ||
Canceled/Expired, Weighted Average Remaining Contractual Term | 1 year 6 months | |||
Canceled/Expired, Weighted Average Exercise Price Per Share | 12 | $ 18 | ||
Forfeited, Weighted Average Remaining Contractual Term | 2 years | |||
Forfeited, Weighted Average Exercise Price Per Share | $ 12 | $ 15 | ||
Outstanding, Weighted Average Remaining Contractual Term (in years) | 1 year | 2 years | 3 years | |
Outstanding at end of period, Weighted Average Exercise Price Per Share | $ 15.50 | $ 16 | $ 16 | |
Options vested and exercisable, Weighted Average Remaining Contractual Term | 1 year | 2 years | ||
Options vested and exercisable, Weighted Average Exercise Price Per Share | $ 15.50 | $ 16 | ||
Outstanding non-vested options at beginning of period, Shares | 84,500 | 644,115 | 882,456 | |
Granted non-vested options, Shares | 160,000 | 410,822 | ||
Vested non-vested options, Shares | (695,217) | (399,593) | ||
Forfeited non-vested options, Shares | (24,398) | (249,570) | ||
Outstanding non-vested options at end of period, Shares | 84,500 | 644,115 | 882,456 | |
Outstanding non-vested options at beginning of period, Weighted Average Fair Value per Share | $ 4.50 | $ 4.50 | $ 11.50 | |
Granted, Weighted Average Fair Value per Share | 2.40 | 4.50 | ||
Vested, Weighted Average Fair Value per Share | 4 | 4.50 | ||
Forfeited, Weighted Average Fair Value per Share | 4.50 | 4.50 | ||
Outstanding non-vested options at ending of period, Weighted Average Fair Value per Share | 4.50 | 4.50 | $ 11.50 | |
Outstanding non-vested options beginning of period, Weighted Average Exercise Price per share | $ 15.50 | 16 | 15 | |
Granted, Weighted Average Exercise Price per share | 10 | 18 | ||
Vested, Weighted Average Exercise Price per share | 15.50 | 16 | ||
Forfeited, Weighted Average Exercise Price per share | 15.50 | 15 | ||
Outstanding non-vested options end of period, Weighted Average Exercise Price per share | $ 15.50 | $ 16 | $ 15 | |
Granted non-vested options, Weighted Average Remaining Contractual Term (in years) | 1 year | 3 years | ||
Vested non-vested options, Weighted Average Remaining Contractual Term (in years) | 1 year | 3 years | ||
Forfeited non-vested options, Weighted Average Remaining Contractual Term (in years) | 3 years | |||
Outstanding non-vested options, Weighted Average Remaining Contractual Term (in years) | 1 year | 2 years | 3 years | |
Lonestar Resources Limited 2012 Employee Share Option Plan and Lonestar Resources US Inc 2016 Employee Incentive Plan | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Outstanding at beginning of period, Shares | 849,936 | |||
Granted, Shares | 35,000 | |||
Canceled/Expired, Shares | (64,667) | |||
Outstanding at end of period, Shares | 820,269 | 849,936 | ||
Options vested and exercisable, Shares | 778,019 | 807,686 | ||
Outstanding at beginning of period, Weighted Average Exercise Price Per Share | $ 15.50 | |||
Granted, Weighted Average Remaining Contractual Term | 2 years | |||
Granted, Weighted Average Exercise Price Per Share | $ 15 | |||
Canceled/Expired, Weighted Average Remaining Contractual Term | ||||
Canceled/Expired, Weighted Average Exercise Price Per Share | $ 18 | |||
Forfeited, Weighted Average Remaining Contractual Term | ||||
Outstanding, Weighted Average Remaining Contractual Term (in years) | 6 months | 1 year | ||
Outstanding at end of period, Weighted Average Exercise Price Per Share | $ 15 | $ 15.50 | ||
Options vested and exercisable, Weighted Average Remaining Contractual Term | 6 months | 1 year | ||
Options vested and exercisable, Weighted Average Exercise Price Per Share | $ 15 | $ 15.50 | ||
Outstanding non-vested options at beginning of period, Shares | 42,250 | |||
Granted non-vested options, Shares | 35,000 | |||
Vested non-vested options, Shares | (35,000) | |||
Outstanding non-vested options at end of period, Shares | 42,250 | 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 | 1.90 | |||
Outstanding non-vested options at ending of period, Weighted Average Fair Value per Share | 9 | $ 9 | ||
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 | $ 15.50 | ||
Granted non-vested options, Weighted Average Remaining Contractual Term (in years) | 2 years 3 months | |||
Vested non-vested options, Weighted Average Remaining Contractual Term (in years) | 2 years 3 months | |||
Outstanding non-vested options, Weighted Average Remaining Contractual Term (in years) | 3 months | 1 year |
Earnings Per Share (Narrative)
Earnings Per Share (Narrative) (Detail) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||
Sep. 30, 2016USD ($) | Sep. 30, 2015 | Sep. 30, 2016USD ($) | Sep. 30, 2015 | Dec. 31, 2015shares | Dec. 31, 2014shares | Jan. 31, 2013shares | |
Earnings Per Share [Abstract] | |||||||
Reverse stock split | 1 for 2 reverse stock split upon Reorganization had occurred at the beginning of the three and nine month periods ended September 30, 2016 and 2015 | 1 for 2 reverse stock split upon reorganization had occurred at the beginning of years ended December 31, 2015 and 2014 | |||||
Reverse stock split, conversion ratio | 2 | 2 | 2 | 2 | 2 | ||
Dilutive effect of earnings per share | $ | $ 0 | $ 0 | |||||
Outstanding ordinary common shares | shares | 15,044,051 | 14,661,004 | 236,187,211 |
Earnings Per Share - Schedule o
Earnings Per Share - Schedule of Unaudited Earnings Per Share (After Reorganization) (Detail) - $ / shares | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | |
Net income (loss) per common share: | ||||||
Basic | $ (1.44) | $ 0.88 | $ (4.64) | $ (0.33) | $ (1.82) | $ 2.49 |
Diluted | $ (1.44) | $ 0.88 | $ (4.64) | $ (0.33) | $ (1.82) | $ 2.42 |
Weighted average common shares outstanding: | ||||||
Basic | 7,842,586 | 7,522,025 | 7,629,896 | 7,522,025 | 15,044,051 | 14,661,004 |
Diluted | 7,842,586 | 7,522,025 | 7,629,896 | 7,522,025 | 15,044,051 | 15,069,610 |
Related Party Activities - Addi
Related Party Activities - Additional Information (Detail) - USD ($) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Apr. 30, 2014 | |
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 | $ 25,000 | |||||
New Tech Global Ventures, LLC | |||||||
Related Party Transaction [Line Items] | |||||||
Cost of consultancy services | 78,000 | $ 149,000 | $ 465,000 | $ 763,000 | 938,000 | $ 2,300,000 | |
BlueSkye Pty Ltd | |||||||
Related Party Transaction [Line Items] | |||||||
Cost of consultancy services | $ 24,000 | $ 36,000 | $ 95,000 | $ 107,000 | 143,000 | 182,000 | |
Affiliated Entity | Parent Company | |||||||
Related Party Transaction [Line Items] | |||||||
Dividends paid | $ 308,000 | $ 637,000 |
Equity Backstop Commitment - Ad
Equity Backstop Commitment - Additional Information (Detail) | Dec. 31, 2016USD ($) | Aug. 02, 2016USD ($)Director |
Equity Purchase Agreement [Line Items] | ||
No of director | Director | 1 | |
Leucadia | ||
Equity Purchase Agreement [Line Items] | ||
Equity offering cost | $ 1,000,000 | |
Class A Voting Common Stock | Maximum | ||
Equity Purchase Agreement [Line Items] | ||
Percentage of shares purchased in the offering | 50.00% | |
Class A Voting Common Stock | Scenario Forecast | Leucadia | Maximum | ||
Equity Purchase Agreement [Line Items] | ||
Commitment amount | $ 20,000,000 | |
Equity offering threshold amount of long-term debt | 295,000,000 | |
Class A Voting Common Stock | Scenario Forecast | Leucadia | Minimum | ||
Equity Purchase Agreement [Line Items] | ||
Minimum aggregate offering price of equity securities excluding commitment amount | $ 40,000,000 |
Subsequent Events - Additional
Subsequent Events - Additional Information (Detail) - Director | 9 Months Ended | |
Sep. 30, 2016 | Oct. 26, 2016 | |
Subsequent Event [Line Items] | ||
Registration rights agreement description | The Company agreed to file a registration statement (the "Registration Statement") providing for the resale of EF Realisation Stock no later than the earlier of (the "Filing Deadline") (i) October 26, 2017, and (ii) 30 days after the date the Company first becomes eligible to file a registration statement on Form S-3. The Company agreed to cause the Registration Statement to become effective no later than 120 days after the Filing Deadline. | |
Subsequent Event | EF Realisation Company Limited | Maximum | Class A Voting Common Stock | ||
Subsequent Event [Line Items] | ||
Number of directors to be nominated | 2 | |
Subsequent Event | EF Realisation Company Limited | Minimum | Class A Voting Common Stock | ||
Subsequent Event [Line Items] | ||
Number of directors to be nominated | 1 | |
Subsequent Event | EF Realisation Company Limited | Board Representation Agreement | Class A Voting Common Stock | ||
Subsequent Event [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% |
Summary of Significant Accoun69
Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2016 | Sep. 30, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Significant Accounting Policies [Line Items] | ||||
Impairment of oil and gas properties | $ 29,144,000 | $ 31,082,000 | $ 28,622,961 | $ 5,478,264 |
Deferred tax asset valuation allowance | 0 | 0 | ||
Liability for material uncertain tax positions | $ 0 | 0 | ||
Option vesting period | 3 years | 3 years | ||
Employee Stock Option | ||||
Significant Accounting Policies [Line Items] | ||||
Option vesting period | 3 years | |||
Unproved Oil And Gas Properties | ||||
Significant Accounting Policies [Line Items] | ||||
Impairment of oil and gas properties | $ 8,927,000 | |||
Proven Oil And Gas Properties | ||||
Significant Accounting Policies [Line Items] | ||||
Impairment of oil and gas properties | $ 19,696,000 | $ 5,478,000 | ||
Minimum | Other property and equipment | ||||
Significant Accounting Policies [Line Items] | ||||
Estimated useful lives | 3 years | |||
Maximum | Other property and equipment | ||||
Significant Accounting Policies [Line Items] | ||||
Estimated useful lives | 5 years | |||
Sales Revenue, Net | Customer Concentration Risk | Trafigura AG | ||||
Significant Accounting Policies [Line Items] | ||||
Concentration risk, percentage | 38.00% | 23.00% | ||
Sales Revenue, Net | Customer Concentration Risk | BP Products North America LLC | ||||
Significant Accounting Policies [Line Items] | ||||
Concentration risk, percentage | 20.00% | 16.00% | ||
Sales Revenue, Net | Customer Concentration Risk | Shell Trading (US) Company | ||||
Significant Accounting Policies [Line Items] | ||||
Concentration risk, percentage | 16.00% | 36.00% | ||
Sales Revenue, Net | Customer Concentration Risk | Texla Energy Management, Inc | ||||
Significant Accounting Policies [Line Items] | ||||
Concentration risk, percentage | 11.00% | |||
Accounts Receivable | Customer Concentration Risk | Trafigura AG | ||||
Significant Accounting Policies [Line Items] | ||||
Concentration risk, percentage | 25.00% | 27.00% | ||
Accounts Receivable | Customer Concentration Risk | BP Products North America LLC | ||||
Significant Accounting Policies [Line Items] | ||||
Concentration risk, percentage | 32.00% | |||
Accounts Receivable | Customer Concentration Risk | Shell Trading (US) Company | ||||
Significant Accounting Policies [Line Items] | ||||
Concentration risk, percentage | 26.00% | 19.00% | ||
Accounts Receivable | Customer Concentration Risk | Texla Energy Management, Inc | ||||
Significant Accounting Policies [Line Items] | ||||
Concentration risk, percentage | 23.00% |
Asset Retirement Obligations -
Asset Retirement Obligations - Additional Information (Detail) - USD ($) | Dec. 31, 2015 | Dec. 31, 2014 |
Asset Retirement Obligation [Abstract] | ||
Capitalized asset retirement cost | $ 6,927,207 | $ 6,481,752 |
Schedule of Asset Retirement Ob
Schedule of Asset Retirement Obligations (Detail) - USD ($) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | |
Asset Retirement Obligation [Abstract] | ||||||
Asset retirement obligations at the beginning of the year | $ 7,487,501 | $ 6,834,615 | $ 6,834,615 | $ 5,937,118 | ||
Wells drilled during the year | 330,969 | 543,555 | ||||
Wells acquired during the year | 176,156 | 965,917 | ||||
Wells sold during the year | (5,421) | (482,081) | ||||
Accretion of discount | $ 53,000 | $ 53,000 | 160,000 | $ 160,000 | 214,335 | 201,076 |
Wells plugged and abandoned during the year | (63,153) | (330,970) | ||||
Asset retirement obligations at the end of the year | $ 2,636,000 | $ 2,636,000 | $ 7,487,501 | $ 6,834,615 |
Current and Deferred Components
Current and Deferred Components of Income Tax Expense (Benefit) (Detail) - USD ($) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | |
Current tax expense (benefit) | ||||||
Federal | $ 287,855 | $ 112,621 | ||||
State | 74,324 | 81,936 | ||||
Deferred tax expense (benefit) | ||||||
Federal | (15,130,060) | 21,592,426 | ||||
State | (353,007) | 644,739 | ||||
Income tax expense (benefit) | $ 1,684,000 | $ 3,931,000 | $ (10,354,000) | $ (1,419,000) | $ (15,120,888) | $ 22,431,722 |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Detail) | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Income Tax Disclosure [Abstract] | |
Statutory tax rate | 35.00% |
Net operating loss carryforward | $ 222,656,000 |
Deductions for excess stock-based compensation | 2,200,000 |
Depletion carryover amount | $ 10,810,000 |
Difference Between Income Taxes
Difference Between Income Taxes Computed at Federal Statutory Rate and Provision for Income Taxes (Detail) - USD ($) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Tax Disclosure [Abstract] | ||||||
Expected income tax provision (benefit) at statutory rate | $ (14,858,849) | $ 20,614,073 | ||||
State tax, tax effected | 10,536 | 675,733 | ||||
Other | (39,646) | 833,016 | ||||
Rate difference | (232,929) | 308,900 | ||||
Income tax expense (benefit) | $ 1,684,000 | $ 3,931,000 | $ (10,354,000) | $ (1,419,000) | $ (15,120,888) | $ 22,431,722 |
Deferred Tax Assets and Liabili
Deferred Tax Assets and Liabilities (Detail) - USD ($) | Dec. 31, 2015 | Dec. 31, 2014 |
Deferred tax assets: | ||
Net operating loss carryforward | $ 77,507,544 | $ 64,772,240 |
Severance costs | 96,679 | |
Organizational expenses | 57,439 | 58,187 |
Stock based compensation | 2,431,147 | 1,522,325 |
Intangibles | 775,719 | 869,594 |
Other | 1,418,801 | 24,207 |
Deferred Tax Asset | 82,190,650 | 67,343,232 |
Deferred tax liabilities: | ||
Oil and gas properties and other property and equipment, principally due to intangible drilling costs | (86,789,694) | (84,371,190) |
Unrealized hedging gain | (11,414,232) | (14,482,786) |
Net deferred tax liabilities | $ (16,013,276) | $ (31,510,744) |
Long-Term Debt - Senior Revolvi
Long-Term Debt - Senior Revolving Credit Facility - Additional Information (Detail) - USD ($) | Jul. 28, 2015 | Mar. 31, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Sep. 30, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | May 19, 2016 | Feb. 28, 2014 |
Revolving Credit Facility | 2nd lien facility | |||||||||
Debt Instrument [Line Items] | |||||||||
Maximum line of credit borrowing capacity | $ 35,000,000 | $ 55,000,000 | |||||||
Line of credit expiration date | Sep. 14, 2018 | ||||||||
Line of credit facility commitment fee percentage | 0.75% | ||||||||
Senior Secured Credit Facility | |||||||||
Debt Instrument [Line Items] | |||||||||
Current line of credit borrowing capacity | $ 2,500,000 | ||||||||
Senior Secured Credit Facility | Maximum | |||||||||
Debt Instrument [Line Items] | |||||||||
Commitment fee percentage | 0.50% | ||||||||
Citibank N A | Senior Secured Credit Facility | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument expanded borrowing base | $ 180,000,000 | $ 120,000,000 | |||||||
Debt instrument maturity date | Oct. 16, 2018 | ||||||||
Revolving credit facility | $ 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 | ||||||||
Wells Fargo Led Facility | Revolving Credit Facility | |||||||||
Debt Instrument [Line Items] | |||||||||
Maximum line of credit borrowing capacity | $ 400,000,000 | $ 400,000,000 | |||||||
Current line of credit borrowing capacity | $ 105,000,000 | $ 105,000,000 | $ 150,000,000 | ||||||
Line of credit borrowing payment terms | The borrowing base shall be re-determined semi-annually based on the credit agreement, and such re-determined borrowing base shall become effective and applicable on April 1 and October 1 of each year commencing October 1, 2013 | ||||||||
Line of credit expiration date | Mar. 14, 2018 | ||||||||
Revolving credit facility | $ 49,000,000 | ||||||||
Wells Fargo Led Facility | Letter of Credit | Revolving Credit Facility | |||||||||
Debt Instrument [Line Items] | |||||||||
Current line of credit borrowing capacity | $ 2,500,000 | ||||||||
Commitment fee percentage | 0.50% | ||||||||
Wells Fargo Led Facility | Maximum | Letter of Credit | Revolving Credit Facility | |||||||||
Debt Instrument [Line Items] | |||||||||
Lien percentage of assets for credit facility | 80.00% | ||||||||
Wells Fargo Led Facility | LIBOR | Letter of Credit | Revolving Credit Facility | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument basis spread on variable rate | 1.00% | ||||||||
Margin of loans, minimum | 1.00% | ||||||||
Margin of loans, maximum | 2.00% | ||||||||
Wells Fargo Led Facility | Federal Funds Effective Rate | Letter of Credit | Revolving Credit Facility | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument basis spread on variable rate | 0.50% | ||||||||
Wells Fargo Led Facility | ABR | Letter of Credit | Revolving Credit Facility | |||||||||
Debt Instrument [Line Items] | |||||||||
Margin of loans, minimum | 2.00% | ||||||||
Margin of loans, maximum | 3.00% | ||||||||
LRAI | Senior Secured Credit Facility | Maximum | |||||||||
Debt Instrument [Line Items] | |||||||||
Lien percentage of assets for 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 | Citibank N A | Senior Secured Credit Facility | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument face amount | $ 500,000,000 |
Future Minimum Annual Lease Pay
Future Minimum Annual Lease Payments (Detail) | Dec. 31, 2015USD ($) |
Operating Leases, Future Minimum Payments Due | |
2,016 | $ 478,040 |
2,017 | 455,600 |
2,018 | 411,768 |
2,019 | 422,301 |
2,020 | 432,835 |
Thereafter | 368,011 |
Total | $ 2,568,555 |
Contingencies and Commitments -
Contingencies and Commitments - Additional Information (Detail) | 12 Months Ended | |
Dec. 31, 2015USD ($)Drilling_Rig | Dec. 31, 2014USD ($) | |
Loss Contingencies [Line Items] | ||
Operating leases, rent expense | $ 404,000 | $ 337,000 |
Corporate office lease rent expense, sublease | $ 88,000 | |
Drilling Rig | ||
Loss Contingencies [Line Items] | ||
Number of drilling rigs under contract | Drilling_Rig | 1 | |
Daily drilling rate | $ 19,000 | |
Early termination fee percentage | 75.00% | |
Drilling rig termination fee description | 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 is approximately $3.8 million. | |
Drilling Rig | Minimum | ||
Loss Contingencies [Line Items] | ||
Drilling rig remaining commitment | $ 3,800,000 |
Stockholders' Equity - Addition
Stockholders' Equity - Additional Information (Detail) - shares | 1 Months Ended | ||
Jan. 31, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | |
Equity [Abstract] | |||
Common stock, shares issued | 236,187,211 | 15,044,051 | 14,661,004 |
Common stock, shares outstanding | 236,187,211 | 15,044,051 | 14,661,004 |
Stock issued at the time of merger | 460,000,000 |
Earnings Per Share - Schedule80
Earnings Per Share - Schedule of Unaudited Pro Forma Earnings Per Share (After Reorganization) (Detail) - $ / shares | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Net income (loss) per common share: | ||
Basic | $ (3.63) | $ 4.97 |
Diluted | $ (3.63) | $ 4.84 |
Weighted average common shares outstanding: | ||
Basic | 7,522,025 | 7,330,602 |
Diluted | 7,522,025 | 7,534,805 |
Capitalized Costs Relating To O
Capitalized Costs Relating To Oil and Gas Activities (Detail) - USD ($) | Dec. 31, 2015 | Dec. 31, 2014 |
Oil and natural gas properties: | ||
Proved properties and equipment | $ 577,764,738 | $ 489,472,814 |
Unproved properties | 70,298,349 | 65,725,668 |
Capitalized asset retirement cost | 6,927,207 | 6,481,752 |
Accumulated depletion and amortization | (133,080,366) | (75,122,695) |
Property impairment | (33,810,331) | (5,478,264) |
Total | $ 488,099,597 | $ 481,079,275 |
Cost Incurred in Oil and Gas Pr
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development (Detail) - USD ($) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Property acquisition costs: | ||
Unproved properties | $ 7,327,635 | $ 12,247,000 |
Proved properties | 1,395,862 | 58,731,282 |
Exploration costs | 0 | 0 |
Development costs | 85,458,433 | 164,180,576 |
Total costs incurred | $ 94,181,930 | $ 235,158,858 |
Results of Operations for Oil a
Results of Operations for Oil and Gas Producing Activities (Detail) | 12 Months Ended | |
Dec. 31, 2015USD ($)$ / Boe | Dec. 31, 2014USD ($)$ / Boe | |
Oil and gas producing activities: | ||
Lease operating and gas gathering | $ (17,860,216) | $ (16,631,611) |
Production, ad valorem and severance taxes | (4,981,826) | (7,123,332) |
Accretion of asset retirement obligations | (214,335) | (201,076) |
Depreciation, depletion and amortization | (58,827,705) | (40,521,546) |
Property impairment | (28,622,961) | (5,478,264) |
Results of operations from oil and gas producing activities | $ (31,016,687) | $ 45,670,731 |
Depletion rate per BOE | $ / Boe | 25.16 | 24.78 |
Oil | ||
Oil and gas producing activities: | ||
Sales | $ 70,739,269 | $ 104,233,379 |
Natural Gas | ||
Oil and gas producing activities: | ||
Sales | 6,823,019 | 7,589,599 |
Natural Gas Liquids | ||
Oil and gas producing activities: | ||
Sales | $ 1,928,068 | $ 3,803,582 |
Changes in Estimated Net Proved
Changes in Estimated Net Proved Developed Crude Oil and Natural Gas Reserves (Detail) | 12 Months Ended | ||
Dec. 31, 2015BoebblMcf | Dec. 31, 2014BoebblMcf | Dec. 31, 2013BoebblMcf | |
Reserve Quantities [Line Items] | |||
Beginning of the period | Boe | 30,983,061 | 18,220,463 | |
New discoveries & extensions | Boe | 16,550,014 | 3,204,934 | |
Purchase of reserves in place | Boe | 2,230,142 | 10,741,764 | |
Reserves sold | Boe | (253,139) | ||
Revisions of prior year estimates | Boe | (7,210,998) | 703,038 | |
Production | Boe | (2,349,611) | (1,633,999) | |
End of period | Boe | 40,202,608 | 30,983,061 | |
Proved Developed Reserves | Boe | 13,300,438 | 12,394,930 | 8,215,173 |
Proved Undeveloped Reserves | Boe | 26,902,170 | 18,588,131 | 10,005,290 |
Oil | |||
Reserve Quantities [Line Items] | |||
Beginning of the period | 23,610,878 | 13,483,483 | |
New discoveries & extensions | 6,575,775 | 2,462,295 | |
Purchase of reserves in place | 1,541,828 | 9,648,101 | |
Reserves sold | (252,200) | ||
Revisions of prior year estimates | (6,637,821) | (532,522) | |
Production | (1,539,505) | (1,198,279) | |
End of period | 23,551,155 | 23,610,878 | |
Proved Developed Reserves | 8,357,772 | 9,184,925 | 6,195,280 |
Proved Undeveloped Reserves | 15,193,383 | 14,425,953 | 7,288,203 |
Natural Gas Liquids | |||
Reserve Quantities [Line Items] | |||
Beginning of the period | 3,044,114 | 1,841,457 | |
New discoveries & extensions | 4,281,649 | 321,301 | |
Purchase of reserves in place | 297,634 | 484,493 | |
Revisions of prior year estimates | (146,113) | 551,078 | |
Production | (322,808) | (154,215) | |
End of period | 7,154,476 | 3,044,114 | |
Proved Developed Reserves | 2,020,216 | 1,211,551 | 638,632 |
Proved Undeveloped Reserves | 5,134,260 | 1,832,563 | 1,202,825 |
Natural Gas | |||
Reserve Quantities [Line Items] | |||
Beginning of the period | Mcf | 25,968,414 | 17,373,143 | |
New discoveries & extensions | Mcf | 34,155,539 | 2,528,029 | |
Purchase of reserves in place | Mcf | 2,344,083 | 3,655,020 | |
Reserves sold | Mcf | (5,632) | ||
Revisions of prior year estimates | Mcf | (2,562,392) | 4,106,883 | |
Production | Mcf | (2,923,787) | (1,689,029) | |
End of period | Mcf | 56,981,857 | 25,968,414 | |
Proved Developed Reserves | Mcf | 17,534,695 | 11,990,723 | 8,287,574 |
Proved Undeveloped Reserves | Mcf | 39,447,162 | 13,977,691 | 9,085,569 |
Supplemental Information on O85
Supplemental Information on Oil & Natural Gas Exploration and Production Activities (unaudited) - Additional Information (Detail) | 12 Months Ended | |
Dec. 31, 2015$ / Bbls$ / Mcf | Dec. 31, 2014$ / Bbls$ / Mcf | |
Oil | ||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||
Average prices used in calculations | $ / Bbls | 50.28 | 94.99 |
Natural Gas | ||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||
Average prices used in calculations | $ / Mcf | 2.59 | 4.35 |
Standardized Measure of Discoun
Standardized Measure of Discounted Future Cash Flows (Detail) - USD ($) | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Abstract] | |||
Future cash flows | $ 1,363,349,591 | $ 2,389,844,493 | |
Production | (456,088,889) | (649,398,768) | |
Development | (289,026,333) | (320,222,400) | |
Future inflows before income tax | 618,234,369 | 1,420,223,325 | |
Future income taxes | (66,565,870) | (353,602,580) | |
Future net cash flows | 551,668,499 | 1,066,620,745 | |
10% annual discount for estimated timing of cash flows | (283,242,412) | (517,581,023) | |
Standardized measure of discounted future net cash flows | $ 268,426,087 | $ 549,039,722 | $ 302,771,526 |
Standardized Measure of Disco87
Standardized Measure of Discounted Future Net Cash flows Relating to Proved Crude Oil and Nature Gas Reserves (Detail) - USD ($) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract] | ||
Standardized measure at beginning of year | $ 549,039,722 | $ 302,771,526 |
Extensions and discoveries and improved recovery net of future production and development costs | 74,142,661 | 88,919,601 |
Purchase of minerals in place | 11,519,608 | 270,331,369 |
Accretion of discount | 70,582,116 | 41,871,778 |
Net change in sales price, net of production costs | (501,189,743) | (38,540,796) |
Changes in estimated future development costs | 56,188,859 | (9,274,717) |
Changes of production rates (timing) and other | 125,681,828 | 12,731,855 |
Revisions of quantity estimates | (191,356,505) | 18,066,206 |
Net change in income taxes | 130,906,060 | (40,835,170) |
Sales net of production costs | (57,088,519) | (91,571,228) |
Sales of minerals in place | (5,430,702) | |
Net increase (decrease) | (280,613,635) | 246,268,196 |
Standardized measure at end of year | $ 268,426,087 | $ 549,039,722 |