Document and Entity Information
Document and Entity Information - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2017 | Feb. 19, 2018 | Jun. 30, 2017 | |
Document And Entity Information [Abstract] | |||
Entity Registrant Name | SRC Energy Inc. | ||
Entity Central Index Key | 1,413,507 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2017 | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Common Stock, Shares Outstanding | 241,786,159 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 1 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Current assets: | ||
Cash and cash equivalents | $ 48,772 | $ 18,615 |
Accounts receivable: | ||
Oil, natural gas, and NGL sales | 86,013 | 25,728 |
Trade | 18,134 | 6,805 |
Commodity derivative assets | 0 | 297 |
Other current assets | 7,116 | 2,739 |
Total current assets | 160,035 | 54,184 |
Property and equipment: | ||
Proved properties, net of accumulated depletion | 970,584 | 424,082 |
Wells in progress | 106,269 | 81,780 |
Unproved properties and land, not subject to depletion | 793,669 | 398,547 |
Oil and gas properties, net | 1,870,522 | 904,409 |
Other property and equipment, net | 6,054 | 4,327 |
Total property and equipment, net | 1,876,576 | 908,736 |
Cash held in escrow and other deposits | 0 | 18,248 |
Goodwill | 40,711 | 40,711 |
Other assets | 2,242 | 2,234 |
Total assets | 2,079,564 | 1,024,113 |
Current liabilities: | ||
Accounts payable and accrued expenses | 74,672 | 52,453 |
Revenue payable | 64,111 | 16,557 |
Production taxes payable | 52,413 | 17,673 |
Asset retirement obligations | 3,246 | 2,683 |
Commodity derivative liabilities | 7,865 | 2,874 |
Total current liabilities | 202,307 | 92,240 |
Revolving credit facility | 0 | 0 |
Notes payable, net of issuance costs | 538,186 | 75,614 |
Asset retirement obligations | 28,376 | 13,775 |
Other liabilities | 2,261 | 1,745 |
Total liabilities | 771,130 | 183,374 |
Commitments and contingencies (See Note16) | ||
Shareholders' equity: | ||
Preferred stock - $0.01 par value, 10,000,000 shares authorized: no shares issued and outstanding | 0 | 0 |
Common stock - $0.001 par value, 300,000,000 shares authorized: 241,365,522 and 200,647,572 shares issued and outstanding as of December 31, 2017 and 2016, respectively | 241 | 201 |
Additional paid-in capital | 1,474,273 | 1,148,998 |
Retained deficit | (166,080) | (308,460) |
Total shareholders' equity | 1,308,434 | 840,739 |
Total liabilities and shareholders' equity | $ 2,079,564 | $ 1,024,113 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares | Dec. 31, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
Preferred stock, par value per share (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 10,000,000 | 10,000,000 |
Preferred stock, shares issued | 0 | 0 |
Preferred stock, shares outstanding | 0 | |
Common stock, par value per share (in dollars per share) | $ 0.001 | $ 0.001 |
Common stock, shares authorized | 300,000,000 | 300,000,000 |
Common stock, shares issued | 241,365,522 | 200,647,572 |
Common stock, shares outstanding | 241,365,522 | 200,647,572 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | |
Income Statement [Abstract] | ||||
Oil, natural gas, and NGL revenues | $ 34,138 | $ 362,516 | $ 107,149 | $ 124,843 |
Expenses: | ||||
Lease operating expenses | 5,812 | 19,496 | 19,949 | 15,017 |
Transportation and gathering | 0 | 3,226 | 0 | 0 |
Production taxes | 3,104 | 36,266 | 5,732 | 11,340 |
Depreciation, depletion, and accretion | 18,776 | 112,309 | 46,678 | 65,869 |
Full cost ceiling impairment | 125,230 | 0 | 215,223 | 16,000 |
Unused commitment charge | 2,802 | 669 | 597 | 0 |
General and administrative | 17,875 | 32,965 | 30,545 | 18,995 |
Total expenses | 173,599 | 204,931 | 318,724 | 127,221 |
Operating income (loss) | (139,461) | 157,585 | (211,575) | (2,378) |
Other income (expense): | ||||
Commodity derivative gain (loss) | 6,482 | (4,226) | (7,750) | 32,256 |
Interest expense, net of amounts capitalized | 0 | (11,842) | 0 | (245) |
Interest income | 40 | 363 | 192 | 86 |
Other income | 0 | 503 | 50 | 0 |
Total other income (expense) | 6,522 | (15,202) | (7,508) | 32,097 |
Income (Loss) before income taxes | (132,939) | 142,383 | (219,083) | 29,719 |
Income tax expense (benefit) | (10,007) | (99) | 106 | 11,677 |
Net income (loss) | $ (122,932) | $ 142,482 | $ (219,189) | $ 18,042 |
Net income (loss) per common share: | ||||
Basic (in dollars per share) | $ (1.14) | $ 0.69 | $ (1.26) | $ 0.19 |
Diluted (in dollars per share) | $ (1.14) | $ 0.69 | $ (1.26) | $ 0.19 |
Weighted-average shares outstanding: | ||||
Basic (in shares) | 107,789,554 | 206,167,506 | 173,774,035 | 94,628,665 |
Diluted (in shares) | 107,789,554 | 206,743,551 | 173,774,035 | 95,319,269 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY - USD ($) $ in Thousands | Total | Common stock | Additional Paid - In Capital | Accumulated Earnings (Deficit) |
Balance at Aug. 31, 2014 | $ 281,490 | $ 78 | $ 265,793 | $ 15,619 |
Balance, shares at Aug. 31, 2014 | 77,999,082 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Shares issued in equity offering | $ 190,845 | $ 19 | 190,826 | |
Shares issued in equity offering, shares | 18,613,952 | 18,613,952 | ||
Shares issued for acquisition | $ 48,434 | $ 5 | 48,429 | |
Shares issued for acquisition, shares | 4,648,136 | 4,648,136 | ||
Shares issued in exchange for mineral assets | $ 11,787 | $ 1 | 11,786 | |
Shares issued in exchange for mineral assets, shares | 995,672 | 995,672 | ||
Shares issued for exercise of warrants | $ 15,370 | $ 2 | 15,368 | |
Shares issued for exercise of warrants, shares | 2,562,473 | |||
Shares issued under stock bonus and equity incentive plans | 2,950 | 2,950 | ||
Shares issued under stock bonus and equity incentive plans, shares | 161,755 | |||
Shares issued for exercise of stock options | $ 0 | |||
Shares issued for exercise of stock options, shares | 258,000 | 118,272 | ||
Stock-based compensation for options | $ 4,741 | 4,741 | ||
Stock based compensation for options, shares | 0 | |||
Payment of tax withholdings using withheld shares | (1,262) | (1,262) | ||
Net income (loss) | 18,042 | 18,042 | ||
Balance at Aug. 31, 2015 | $ 572,397 | $ 105 | 538,631 | 33,661 |
Balance, shares at Aug. 31, 2015 | 105,099,342 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Shares issued in equity offering, shares | 0 | |||
Shares issued for acquisition | $ 49,839 | $ 4 | 49,835 | |
Shares issued for acquisition, shares | 4,418,413 | 4,418,413 | ||
Shares issued in exchange for mineral assets | $ 426 | $ 0 | 426 | |
Shares issued in exchange for mineral assets, shares | 37,051 | 37,051 | ||
Shares issued under stock bonus and equity incentive plans | $ 7,163 | $ 1 | 7,162 | |
Shares issued under stock bonus and equity incentive plans, shares | 422,035 | |||
Shares issued for exercise of stock options | $ 0 | |||
Shares issued for exercise of stock options, shares | 188,000 | 56,760 | ||
Stock-based compensation for options | $ 2,161 | 2,161 | ||
Stock based compensation for options, shares | 0 | |||
Payment of tax withholdings using withheld shares | (2,544) | (2,544) | ||
Net income (loss) | (122,932) | (122,932) | ||
Balance at Dec. 31, 2015 | 506,510 | $ 110 | 595,671 | (89,271) |
Balance, shares at Dec. 31, 2015 | 110,033,601 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Shares issued in equity offering | $ 543,411 | $ 90 | 543,321 | |
Shares issued in equity offering, shares | 90,275,000 | 90,275,000 | ||
Shares issued for acquisition, shares | 0 | |||
Shares issued in exchange for mineral assets, shares | 0 | |||
Shares issued under stock bonus and equity incentive plans | $ 4,232 | $ 1 | 4,231 | |
Shares issued under stock bonus and equity incentive plans, shares | 321,101 | |||
Shares issued for exercise of stock options | $ 68 | $ 0 | 68 | |
Shares issued for exercise of stock options, shares | 20,000 | 17,870 | ||
Stock-based compensation for options | $ 5,417 | 5,417 | ||
Stock-based compensation for performance-vested stock units | 1,047 | 1,047 | ||
Payment of tax withholdings using withheld shares | (757) | (757) | ||
Net income (loss) | (219,189) | (219,189) | ||
Balance at Dec. 31, 2016 | $ 840,739 | $ 201 | 1,148,998 | (308,460) |
Balance, shares at Dec. 31, 2016 | 200,647,572 | 200,647,572 | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Shares issued in equity offering | $ 312,171 | $ 40 | 312,131 | |
Shares issued in equity offering, shares | 40,250,000 | 40,250,000 | ||
Shares issued for acquisition, shares | 0 | |||
Shares issued in exchange for mineral assets, shares | 0 | |||
Shares issued under stock bonus and equity incentive plans | $ 4,976 | $ 0 | 4,976 | |
Shares issued under stock bonus and equity incentive plans, shares | 280,284 | |||
Shares issued for exercise of stock options | $ 740 | $ 0 | 740 | |
Shares issued for exercise of stock options, shares | 187,666 | 187,666 | ||
Stock-based compensation for options | $ 5,076 | 5,076 | ||
Stock-based compensation for performance-vested stock units | 2,938 | 2,938 | ||
Payment of tax withholdings using withheld shares | (688) | (688) | ||
Net income (loss) | 142,482 | 142,482 | ||
Balance at Dec. 31, 2017 | $ 1,308,434 | $ 241 | 1,474,273 | (166,080) |
Balance, shares at Dec. 31, 2017 | 241,365,522 | 241,365,522 | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Adoption of ASU 2016-09 | $ 102 | $ (102) |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | |
Cash flows from operating activities: | ||||
Net income (loss) | $ (122,932) | $ 142,482 | $ (219,189) | $ 18,042 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||
Depletion, depreciation, and accretion | 18,776 | 112,309 | 46,678 | 65,869 |
Full cost ceiling impairment | 125,230 | 0 | 215,223 | 16,000 |
Settlements of asset retirement obligations | (745) | (4,541) | (228) | 0 |
Loss on extinguishment of debt | 0 | 11,842 | 0 | 0 |
Provision for deferred taxes | (10,007) | 0 | 0 | 11,679 |
Stock-based compensation expense | 8,431 | 11,225 | 9,491 | 7,691 |
Total (gain) loss on commodity derivative contracts | (6,482) | 4,226 | 7,750 | (32,256) |
Cash settlements on commodity derivative contracts | 1,954 | 942 | 5,374 | 31,721 |
Cash premiums paid for commodity derivative contracts | (956) | 0 | 0 | (4,117) |
Changes in operating assets and liabilities | 6,803 | 12,830 | (16,411) | 10,458 |
Net cash provided by operating activities | 20,072 | 291,315 | 48,688 | 125,087 |
Cash flows from investing activities: | ||||
Acquisitions of oil and gas properties and leaseholds | (37,150) | (661,468) | (511,173) | (82,584) |
Capital expenditures for drilling and completion activities | (41,581) | (450,384) | (119,571) | (186,135) |
Other capital expenditures | (5,811) | (17,841) | (7,044) | (6,375) |
Acquisition of land and other property and equipment | (395) | (4,186) | (5,478) | (714) |
Proceeds from sales of oil and gas properties and other | 0 | 93,573 | 25,350 | 6,239 |
Net cash used in investing activities | (84,937) | (1,040,306) | (617,916) | (269,569) |
Cash flows from financing activities: | ||||
Proceeds from the sale of stock | 0 | 322,000 | 565,398 | 200,100 |
Offering costs | 0 | (9,745) | (21,987) | (9,255) |
Proceeds from the employee exercise of stock options | 0 | 741 | 68 | 15,370 |
Payment of employee payroll taxes in connection with shares withheld | (2,544) | (688) | (757) | (1,262) |
Proceeds from revolving credit facility | 0 | 250,000 | 55,000 | 186,000 |
Principal repayments on revolving credit facility | 0 | (250,000) | (133,000) | (145,000) |
Proceeds from issuance of notes payable | 0 | 550,000 | 80,000 | 0 |
Repayment of notes payable | 0 | (88,234) | 0 | 0 |
Financing fees on issuance of notes payable and amendments to revolving credit facility | 0 | (13,145) | (5,159) | (2,316) |
Net cash provided by (used in) financing activities | (2,544) | 760,929 | 539,563 | 243,637 |
Net increase (decrease) in cash, cash equivalents, and restricted cash | (67,409) | 11,938 | (29,665) | 99,155 |
Cash, cash equivalents, and restricted cash at beginning of period | 133,908 | 36,834 | 66,499 | 34,753 |
Cash, cash equivalents, and restricted cash at end of period | $ 66,499 | $ 48,772 | $ 36,834 | $ 133,908 |
Organization and Summary of Sig
Organization and Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Summary of Significant Accounting Policies | Organization and Summary of Significant Accounting Policies Organization : SRC Energy Inc. is an independent oil and natural gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and NGLs, primarily in the D-J Basin of Colorado. On June 15, 2017, our shareholders approved an amendment to the Amended and Restated Articles of Incorporation of the Company to change the name of the Company from Synergy Resources Corporation to SRC Energy Inc. The Company had been using the new name on a "doing business as" basis since March 6, 2017. In addition to using the new name, the Company’s common stock, which is listed and traded on the NYSE American, changed to the new symbol "SRCI." Basis of Presentation: The Company operates in one business segment, and all of its operations are located in the United States of America. At the directive of the Securities and Exchange Commission ("SEC") to use "plain English" in public filings, the Company will use such terms as "we," "our," "us," or the "Company" in place of SRC Energy Inc . When such terms are used in this manner throughout this document, they are in reference only to the corporation, SRC Energy Inc., and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees. The consolidated financial statements include the accounts of the Company, including its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. The Company prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”). Change of Year-End: On February 25, 2016, the Company's Board of Directors approved a change in fiscal year end from August 31 to December 31. Unless otherwise noted, all references to "years" in this report refer to the twelve-month fiscal year, which prior to September 1, 2015 ended on August 31, and beginning with December 31, 2015 ends on the December 31 of each year. Use of Estimates: The preparation of consolidated financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and natural gas reserves, goodwill, business combinations, derivatives, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain. Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions are revised periodically, and the effects of revisions are reflected in the c onsolidated financial statements in the period that it is determined to be necessary. Actual results could differ from these estimates. Cash and Cash Equivalents: The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents. Cash Held in Escrow: Cash held in escrow includes deposits for purchases of certain oil and gas properties as required under the related purchase and sale agreements. As of December 31, 2016, the Company had placed $18.2 million in escrow, which was released upon the second closing of the GC Acquisition. Please refer to Note 3 , Acquisitions and Divestitures, for further information. The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets to the consolidated statements of cash flows: As of December 31, As of August 31, 2015 2017 2016 2015 Cash and cash equivalents $ 48,772 $ 18,615 $ 66,499 $ 133,908 Restricted cash included in cash held in escrow and other deposits — 18,219 — — $ 48,772 $ 36,834 $ 66,499 $ 133,908 Oil and Gas Properties: The Company uses the full cost method of accounting for costs related to its oil and gas properties. Accordingly, all costs associated with acquisition, exploration, and development of oil and natural gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, and overhead charges directly related to acquisition, exploration, and development activities. Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves. Capitalized costs of oil and gas properties are depleted using the unit-of-production method based upon estimates of proved reserves. For depletion purposes, the volume of proved oil and natural gas reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of oil. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is the impairment test prescribed by SEC regulations. The ceiling test determines a limit on the net book value of oil and gas properties. The ceiling is calculated as the sum of the present value of estimated future net revenues from proved oil and natural gas reserves, plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized, less the income tax effects related to differences between the book and tax basis of the properties. The present value of estimated future net revenues is computed by applying current prices of oil and natural gas reserves to estimated future production of proved oil and natural gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves; the result is discounted at 10% and assumes continuation of current economic conditions. Future cash outflows associated with settling accrued asset retirement obligations that have been accrued on the balance are excluded from the calculation of the present value of future net revenues. The calculation of income tax effects takes into account the tax basis of oil and gas properties, net operating loss carryforwards, and the impact of statutory depletion. If the capitalized costs of proved and unproved oil and gas properties, net of accumulated depletion and prior impairments, and the related deferred income taxes exceed the ceiling limit, the excess is charged to expense. Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount. During the year ended December 31, 2017 , the Company did not recognize any ceiling test impairments. During the year ended December 31, 2016, the four months ended December 31, 2015, and the year ended August 31, 2015, the Company recognized ceiling test impairments of $215.2 million , $125.2 million , and $16.0 million , respectively. The oil and natural gas prices used to calculate the full cost ceiling limitation are based upon a 12-month rolling average, calculated as the unweighted arithmetic average of the first day of the month price for each month within the preceding 12-month period unless prices are defined by contractual arrangements. Prices are adjusted for basis or location differentials and are held constant for the productive life of each well. Oil and Natural Gas Reserves: Oil and natural gas reserves represent theoretical, estimated quantities of oil and natural gas which, using geological and engineering data, are estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values including many factors beyond the Company’s control. Accordingly, reserve estimates are different from the future quantities of oil and natural gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves. The determination of depletion expense, as well as the ceiling test calculation related to the recorded value of the Company’s oil and gas properties, is highly dependent on estimates of proved oil and natural gas reserves. Capitalized Interest: The Company capitalizes interest on expenditures made in connection with acquisitions of mineral interests that are currently not subject to depletion and exploration and development projects that are in progress. Interest is capitalized during the period that activities are in progress to bring the projects to their intended use. See Note 10 for additional information. Capitalized Overhead: A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities. Under the full cost method of accounting, these expenses are capitalized in the full cost pool. See Note 2 for additional information. Other Property and Equipment: Support equipment (including such items as vehicles, computer equipment, and software), office leasehold improvements, office furniture and equipment, and buildings are stated at historical cost. Expenditures for support equipment relating to new assets or improvements are capitalized, provided the expenditure extends the useful life of an asset or extends the asset’s functionality. Support equipment, office leasehold improvements, and office furniture and equipment are depreciated under the straight-line method using estimated useful lives ranging from three to five years. Buildings are also depreciated under the straight-line method using estimated useful lives of thirty-nine years. No depreciation is taken on assets classified as construction in progress until the asset is placed into service. Gains and losses are recorded upon retirement, sale, or disposal of assets. Maintenance and repair costs are recognized as period costs when incurred. The Company evaluates its other property and equipment for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable. Accounts Payable and Accrued Expenses: Accounts payable and accrued expenses consist of the following (in thousands): As of December 31, 2017 2016 Trade accounts payable $ 624 $ 786 Accrued well costs 56,348 42,779 Accrued G&A 6,017 4,292 Accrued LOE 5,249 3,140 Accrued interest 3,125 320 Accrued other 3,309 1,136 74,672 52,453 Revenue Payable: Revenue payable represents amounts collected from purchasers for oil and natural gas sales which are revenues due to other working or royalty interest owners. Generally, the Company is required to remit amounts due under these liabilities within 30 days of the end of the month in which the related proceeds from the production are received. Asset Retirement Obligations: The Company’s activities are subject to various laws and regulations, including legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service. Calculation of an asset retirement obligation ("ARO") requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors. The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using the Company’s credit-adjusted risk-free rate. Estimates are periodically reviewed and adjusted to reflect changes. The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made. When the ARO is initially recorded, the Company capitalizes the cost by increasing the carrying value of the related asset. Asset retirement costs ("ARCs") related to wells are capitalized to the full cost pool and subject to depletion. Over time, the liability increases for the change in its present value, while the net capitalized cost decreases over the useful life of the asset as depletion expense is recognized. In addition, ARCs are included in the ceiling test calculation when assessing the full cost pool for impairment. Business Combinations: The Company accounts for its acquisitions that qualify as businesses using the acquisition method under FASB Accounting Standards Codification ("ASC") 805, Business Combinations . Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values. The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable. The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain. Goodwill: The Company’s goodwill represents the excess of the purchase price over the fair value of net identifiable assets acquired in a business combination. Goodwill is not amortized and is tested for impairment annually or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. We have historically performed the annual impairment assessment as of August 31 st . During 2016, we changed the date of our annual goodwill impairment assessment to October 1 st . With respect to its annual goodwill testing date, management believes that this voluntary change in accounting method is preferable as it better aligns the annual impairment testing date with the Company’s new fiscal year end, which was also changed in 2016. This change in assessment date was applied prospectively and did not delay, accelerate, or avoid a potential impairment charge. When evaluating goodwill for impairment, the Company may first perform an assessment of qualitative factors to determine if the fair value of the reporting unit is more-likely-than-not greater than its carrying amount. If, based on the review of the qualitative factors, the Company determines it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying value, the required impairment test can be bypassed. If the Company does not perform a qualitative assessment or if the fair value of the reporting unit is not more-likely-than-not greater than its carrying value, the Company must calculate the estimated fair value of the reporting unit. If the carrying value of the reporting unit exceeds the estimated fair value, the Company should recognize an impairment charge. The amount of impairment for goodwill is measured as the amount by which the carrying amount of the reporting unit exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill. For purposes of assessing goodwill, the Company only has one reporting unit. We performed our annual goodwill impairment test as of October 1, 2017. This test did not result in an impairment. The Company utilized a market approach in estimating the fair value of the reporting unit. The primary assumptions used in the Company's impairment evaluations are based on the best available market information at the time. Changes in these assumptions or future economic conditions could impact the Company's conclusion regarding an impairment of goodwill and potentially result in a non-cash impairment loss in a future period. Oil, Natural Gas, and NGL Revenues: The Company derives revenue primarily from the sale of oil, natural gas, and NGLs produced on its properties. Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's pro-rata interest. Revenues are reported on a net revenue interest basis, which excludes revenues that are attributable to other parties' working or royalty interests. Revenue is recorded and receivables are accrued in the month production is delivered to the purchaser, at which time ownership of the product is transferred to the purchaser. Payment is generally received between thirty and ninety days after the date of production. Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement. Major Customers: The Company sells production to a small number of customers as is customary in the industry. Customers representing 10% or more of its oil, natural gas, and NGL revenue (“major customers”) for each of the periods presented are shown in the following table: Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Company A 33% * * * Company B 24% 20% 15% 11% Company C 17% 20% * * Company D * 16% * * Company E * 13% * * Company F * * 57% 65% Company G * * 12% * * less than 10% Based on the current demand for oil and natural gas, the availability of other buyers, the multiple contracts for sales of our products, and the Company having the option to sell to other buyers if conditions warrant, the Company believes that the loss of our existing customers or individual contract would not have a material adverse effect on us. Our oil and natural gas production is a commodity with a readily available market, and we sell our products under many distinct contracts. In addition, there are several oil and natural gas purchasers and processors within our area of operations to whom our production could be sold. Accounts receivable consist primarily of receivables from oil, natural gas, and NGL sales and amounts due from other working interest owners who are liable for their proportionate share of well costs. The Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings on outstanding receivables from joint interest owners. Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table (these companies do not necessarily correspond to those presented above): As of December 31, 2017 2016 Company A 26% 23% Company B 23% * Company C 16% * Company D 11% 43% Company E * 10% * less than 10% The Company operates exclusively within the United States of America, and except for cash and cash equivalents, all of the Company’s assets are employed in, and all of its revenues are derived from, the oil and gas industry. Lease Operating Expenses: Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred. Lease operating expenses (also referred to as production or lifting costs) include the costs of labor to operate the wells and related equipment and facilities, repairs and maintenance, materials, fuel consumed, supplies utilized in operating the wells and related equipment and facilities, property taxes, and insurance applicable to proved properties and wells and related equipment and facilities. Stock-Based Compensation: The Company recognizes all equity-based compensation as stock-based compensation expense based on the fair value of the compensation measured at the grant date. For stock options, fair value is calculated using the Black-Scholes-Merton option pricing model. For stock bonus awards and restricted stock units, fair value is the closing stock price for the Company's common stock on the grant date. For performance-vested stock units, fair value is calculated using a Monte Carlo simulation. The compensation is recognized over the vesting period of the grant. See Note 13 for additional information. Income Tax: Income taxes are computed using the asset and liability method. Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases as well as the effect of net operating losses, tax credits, and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. No significant uncertain tax positions were identified as of any date on or before December 31, 2017 . The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of December 31, 2017 , the Company has not recognized any interest or penalties related to uncertain tax benefits. See Note 15 for further information. Financial Instruments : Financial instruments, whether measured on a recurring or non-recurring basis, are recorded at fair value. A fair value hierarchy, established by the Financial Accounting Standards Board (“FASB”), prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). Commodity Derivative Instruments: The Company has entered into commodity derivative instruments, primarily utilizing swaps, puts, or collars, to reduce the effect of price changes on a portion of its future oil and natural gas production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative gain (loss) line on the consolidated statement of operations. The Company values its derivative instruments by obtaining independent market quotes as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors as well as other relevant economic measures. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. For additional discussion, please refer to Note 8 . Transportation Commitment Charge: The Company has entered into several agreements that require us to deliver minimum amounts of oil to a third party marketer and/or other counterparties that transport oil via pipelines. See Note 16 for additional information. Pursuant to these agreements, we must deliver specific amounts, either from our own production or from oil that we acquire. If we are unable to fulfill all of our contractual delivery obligations from our own production, we may be required to pay penalties or damages pursuant to these agreements, or we may have to purchase oil from third parties to fulfill our delivery obligations. When we incur penalties of this type, we recognize the expense as a transportation commitment charge in the consolidated statement of operations. Recently Adopted Accounting Pronouncements: In November 2016, the FASB issued Accounting Standards Update ("ASU") 2016-18, "Restricted Cash" ("ASU 2016-18"), which amends ASC 230 to add or clarify guidance on the classification and presentation of restricted cash in the statement of cash flows. Key requirements of ASU 2016-18 are as follows: 1) An entity should include in its cash and cash equivalent balances in the statement of cash flows those amounts that are deemed to be restricted cash and restricted cash equivalents. ASU 2016-18 does not define the terms “restricted cash” and “restricted cash equivalents” but states that an entity should continue to provide appropriate disclosures about its accounting policies pertaining to restricted cash in accordance with other GAAP. ASU 2016-18 also states that any change in accounting policy will need to be assessed under ASC 250; 2) A reconciliation between the statement of financial position and the statement of cash flows must be disclosed when the statement of financial position includes more than one line item for cash, cash equivalents, restricted cash, and restricted cash equivalents; 3) Changes in restricted cash and restricted cash equivalents that result from transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows; and 4) An entity with a material balance of amounts generally described as restricted cash and restricted cash equivalents must disclose information about the nature of the restrictions. We adopted this pronouncement effective October 1, 2017 and have applied it retrospectively. Upon adoption, we removed cash held in escrow of $18.2 million from the statement of cash flows for the year ended December 31, 2016. This change resulted in a decrease to net cash used in investing activities of $18.2 million . Additionally, we removed cash held in escrow of $18.2 million from the statement of cash flows for the year ended December 31, 2017. This change resulted in an increase to net cash used in investing activities of $18.2 million . The adoption of this standard did not impact cash flows for the 4-months ended December 31, 2015 nor the year ended August 31, 2015. We have included a tabular reconciliation of cash, cash equivalents, and restricted cash in the discussion of " Cash Held in Escrow" above . In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting” (“ASU 2016-09”), which intends to improve the accounting for share-based payment transactions. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions, including: (1) Accounting and Cash Flow Classification for Excess Tax Benefits and Deficiencies, (2) Forfeitures, and (3) Tax Withholding Requirements and Cash Flow Classification. ASU 2016-09 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We adopted this pronouncement effective January 1, 2017. Upon adoption of this standard, we no longer estimate the total number of awards for which the requisite service period will not be rendered, and effective January 1, 2017, we began accounting for forfeitures when they occur. We applied this accounting change on a modified retrospective basis with a cumulative-effect adjustment of $0.1 million to retained earnings as of the date of adoption. The adoption of the other provisions did not materially impact the consolidated financial statements. In January 2017, the FASB issued ASU 2017-04, "Simplifying the Test for Goodwill Impairment" ("ASU 2017-04"), which removes the requirement to compare the implied fair value of goodwill with its carrying amount as part of step 2 of the goodwill impairment test. We adopted ASU 2017-04 on January 1, 2017, and it will be applied for any interim or annual goodwill impairment tests subsequent to that date. The adoption of this guidance did not impact the consolidated financial statements. Recently Issued Accounting Pronouncements: We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new accounting pronouncements on us. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" ("ASU 2016-02"), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous US GAAP. ASU 2016-02 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the impact of the adoption of this standard on our consolidated financial statements. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The objective of this update is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The FASB subsequently issued various ASUs, which deferred the effective date of ASU 2014-09 and provided additional implementation guidance. ASU 2014-09 and its amendments are effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. The Company will adopt these ASUs with an effective date of January 1, 2018, using the modified retrospective method. While we have not yet completed all aspects of the adoption of the standard, based on our current assessment of contracts with customers, we do not believe there will be any impact to the timing of our revenue recognition or our operating income (loss), net income (loss), and cash flows. The Company is in the process of evaluating changes, if any, to accounting policies and internal control procedures along with continuing to assess additional disclosures which may be required upon implementation of these ASUs. There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows. |
Property and Equipment
Property and Equipment | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Property and Equipment | Property and Equipment The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands): As of December 31, 2017 2016 Oil and gas properties, full cost method: Costs of proved properties: Producing and non-producing $ 1,629,789 $ 969,239 Less, accumulated depletion and full cost ceiling impairments (659,205 ) (545,157 ) Subtotal, proved properties, net 970,584 424,082 Costs of wells in progress 106,269 81,780 Costs of unproved properties and land, not subject to depletion: Lease acquisition and other costs 786,469 392,561 Land 7,200 5,986 Subtotal, unproved properties and land 793,669 398,547 Costs of other property and equipment: Other property and equipment 8,134 5,063 Less, accumulated depreciation (2,080 ) (736 ) Subtotal, other property and equipment, net 6,054 4,327 Total property and equipment, net $ 1,876,576 $ 908,736 The Company periodically reviews its oil and gas properties to determine if the carrying value of such assets exceeds estimated fair value. For proved producing and non-producing properties, the Company performs a ceiling test each quarter to determine whether there has been an impairment to its capitalized costs. At December 31, 2017 , the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary. During the year ended December 31, 2016 , the four months ended December 31, 2015, and the year ended August 31, 2015, the Company's ceiling tests resulted in total impairments of $215.2 million , $125.2 million , and $16.0 million , respectively. No impairments were recognized for the comparable 2017 period. The costs of unproved properties are withheld from the depletion base until such time as the properties are either developed or abandoned. Unproved properties are reviewed on an annual basis, or more frequently if necessary, for impairment and, if impaired, are reclassified to proved properties and included in the depletion base. During the year ended December 31, 2017 , these reviews indicated that the estimated fair value of such assets exceeded the carrying values. Therefore, no impairment was necessary as December 31, 2017. However, during the years ended December 31, 2016 and August 31, 2015, the Company recorded impairments of $18.9 million and $15.4 million , respectively, related to the fair value of its unproved properties. No such impairments were recognized during the four months ended December 31, 2015. Capitalized Overhead: A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities. Under the full cost method of accounting, these expenditures, in the amounts shown in the table below, were capitalized in the full cost pool (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Capitalized overhead $ 10,293 $ 7,074 $ 1,091 $ 2,049 Costs Incurred: Costs incurred in oil and gas property acquisition, exploration, and development activities for the periods presented were (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Acquisition of property: Unproved $ 538,489 $ 365,548 $ 38,779 $ 32,701 Proved 139,154 152,363 51,085 51,400 Exploration costs — 43,154 23,697 146,892 Development costs 460,875 87,782 17,742 4,957 Other property and equipment, and land 4,397 7,506 395 741 Capitalized interest, capitalized G&A, and other 26,677 18,744 4,415 7,051 Total costs incurred $ 1,169,592 $ 675,097 $ 136,113 $ 243,742 Capitalized Costs Excluded from Depletion: The following table summarizes costs related to unproved properties that have been excluded from amounts subject to depletion at December 31, 2017 (in thousands): Period Incurred Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, Total as of December 31, 2017 2017 2016 2015 2014 and Prior Unproved leasehold acquisition costs $ 537,470 $ 223,907 $ 23,068 $ 456 $ 1,568 $ 786,469 Unproved development costs 26,056 — — — — 26,056 Total unevaluated costs $ 563,526 $ 223,907 $ 23,068 $ 456 $ 1,568 $ 812,525 There were no individually significant properties or significant development projects included in the Company’s unproved property balance. The Company regularly evaluates these costs to determine whether impairment has occurred or proved reserves have been established. The majority of these costs are expected to be evaluated and included in the depletion base within three years . |
Acquisitions and Divestitures
Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
Acquisitions and Divestitures | Acquisitions and Divestitures The Company seeks to acquire developed and undeveloped oil and gas properties in the core Wattenberg Field to provide additional mineral acres upon which the Company can drill wells and produce hydrocarbons. December 2017 Acquisition In November 2017, the Company entered into an agreement ("GCII Agreement") to purchase a total of approximately 30,200 net acres located in an area known as the Greeley-Crescent development area in Weld County Colorado, primarily south of the city of Greeley, for $568 million ("GCII Acquisition"). Estimated net daily production from the acquired non-operated properties was approximately 2,500 BOE at the time we entered into the agreement. On December 15, 2017, the Company closed on the portion of the assets comprised of the undeveloped lands and non-operated production. The effective date of this part of the transaction was November 1, 2017, and the purchase price was $569.5 million , comprised of $568.1 million in cash and the assumption of certain liabilities. The purchase price has preliminarily been allocated as $59.9 million to proved oil and gas properties and $509.6 million to unproved oil and gas properties, pending the final closing. The second closing will cover the operated producing properties and is expected to be completed in 2018. For the second closing, the effective date will be the first day of the calendar month in which the closing for such properties occurs. The second closing is subject to certain closing conditions including the receipt of regulatory approval. Accordingly, the second closing of the transaction may not close in the expected time frame or at all. The first closing was accounted for as an asset acquisition under ASC 805, Business Combinations , which requires the acquired assets and liabilities to be recorded at cost on the acquisition date of December 15, 2017. September 2017 Acquisition In September 2017, we completed the second closing of the GC Acquisition (as defined in " -June 2016 Acquisition " below). At the second closing, we acquired 335 operated vertical wells and 7 operated horizontal wells. The effective date of the second closing was April 1, 2016 for the horizontal wells acquired and September 1, 2017 for the vertical wells acquired. At the second closing, the escrow balance of $18.2 million was released and $11.4 million of that amount was returned to the Company. The total purchase price for the second closing was $30.3 million , composed of cash of $6.3 million and assumed liabilities of $24.0 million . The assumed liabilities included $20.9 million for asset retirement obligations. The entire purchase price has been allocated to proved oil and gas properties. August 2017 Acquisition and Swap In August 2017, we also entered into an agreement with another party to trade approximately 3,200 net acres of the Company's non-contiguous acreage for approximately 3,200 net acres within the Company's core operating area. This transaction closed in the fourth quarter of 2017. We also acquired approximately 1,000 net acres of developed and undeveloped leasehold and mineral interests, along with the associated production, for a total purchase price of $22.6 million , composed of cash and assumed liabilities. The purchase price for the acquisition has preliminarily been allocated as $6.7 million to proved oil and gas properties and $15.9 million to unproved oil and gas properties, pending the final closing. March 2017 Acquisition In March 2017, we closed an acquisition comprised primarily of developed and undeveloped oil and gas leasehold interests for a total purchase price of $25.1 million , composed of cash and assumed liabilities. The purchase price has been allocated as $15.3 million to proved oil and gas properties, $9.4 million to unproved oil and gas properties, and $0.4 million to other assets and land. Acquisitions in the Second Half of 2016 In August and October 2016, the Company completed four acquisitions of certain assets for a total purchase price of $13.5 million composed of cash, forgiven receivables, and assumed liabilities. The acquired properties were comprised primarily of undeveloped oil and gas leasehold interests and additional interests in developed properties operated by the Company. June 2016 Acquisition In May 2016, we entered into a purchase and sale agreement pursuant to which we agreed to acquire a total of approximately 72,000 gross ( 33,100 net) acres in an area referred to as the Greeley-Crescent project in the Wattenberg Field for $505 million (the "GC Acquisition"). In June 2016, the Company closed on the portion of the assets comprised of undeveloped oil and gas leasehold interests and non-operated production. The effective date of this part of the transaction was April 1, 2016. As discussed above in "- September 2017 Acquisition" above, we closed on the second part of this transaction covering the operated producing properties in September 2017. The first closing on June 14, 2016 was for a total purchase price of $486.4 million , net of customary closing adjustments. The purchase price was composed of $485.1 million in cash plus the assumption of certain liabilities. The first closing encompassed approximately 33,100 net acres of oil and gas leasehold interests and related assets and net production of approximately 800 BOED at the time of entering into the GC Agreement. The first closing was accounted for using the acquisition method under ASC 805, Business Combinations , which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of June 14, 2016. Transaction costs of $0.5 million r elated to the acquisition were expensed as incurred. The following table summarizes the purchase price and final fair values of assets acquired and liabilities assumed (in thousands): Purchase Price June 14, 2016 Consideration given: Cash $ 485,141 Net liabilities assumed, including asset retirement obligations 1,273 Total consideration given $ 486,414 Allocation of Purchase Price (1) Proved oil and gas properties $ 132,903 Unproved oil and gas properties 353,511 Total fair value of assets acquired $ 486,414 (1) Oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rat e of 11.5% , a nd assumptions regarding the timing and amount of future development and operating costs. For th e year ended December 31, 2017 , the results of operations of the acquired assets, representing approximately $5.4 million of revenue and $4.7 million of operating income, have been included in the Company's consolidated statements of operations. The following table presents the unaudited pro forma combined results of operations for the year ended December 31, 2016 as if the first closing had occurred on September 1, 2014. The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through cash, additional depreciation expense, costs directly attributable to the acquisition, and operating costs incurred as a result of the assets acquired. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results. (in thousands) Year Ended December 31, 2016 Oil, natural gas, and NGL revenues $ 110,635 Net loss $ (218,578 ) Net loss per common share Basic $ (1.10 ) Diluted $ (1.10 ) February 2016 Acquisition In February 2016, the Company completed the acquisition of undeveloped oil and gas leasehold interests for a total purchase price of $10.0 million . The purchase price has been allocated as $8.6 million to proved oil and gas properties and $1.4 million to unproved oil and gas properties. See Note 9 for further details as to the preparation of these significant estimates. Divestitures During the year ended December 31, 2017 , we completed divestitures of approximately 16,000 net undeveloped acres, along with associated production, outside of the Company's core development area for approximately $91.6 million in cash and the assumption by the buyers of $5.2 million in asset retirement obligations and $22.2 million in other liabilities. During the year ended December 31, 2016, the Company completed divestitures of approximately 3,700 net undeveloped acres and 107 vertical wells primarily in Adams County, Colorado for total consideration of approximately $24.7 million in cash and the assumption by the buyers of $0.5 million in liabilities. The divested assets had associated production of approximately 200 BOED. In accordance with full cost accounting guidelines, the net proceeds from these divestitures were credited to the full cost pool. |
Depletion, depreciation and acc
Depletion, depreciation and accretion ("DD&A") | 12 Months Ended |
Dec. 31, 2017 | |
Other Costs and Disclosures [Abstract] | |
Depletion, depreciation and accretion (DD&A) | Depletion, depreciation, and accretion ("DD&A") DD&A consisted of the following (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Depletion of oil and gas properties $ 109,287 $ 45,193 $ 18,371 $ 65,158 Depreciation and accretion 3,022 1,485 405 711 Total DD&A Expense $ 112,309 $ 46,678 $ 18,776 $ 65,869 Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total reserves at the beginning of the quarter. For the year ended December 31, 2017 , production of 12,481 MBOE represented 5.2% of estimated total proved reverses. For the year ended December 31, 2016 , production of 4,271 MBOE represented 4.4% of estimated total proved reserves. For the four months ended December 31, 2015, production of 1,320 MBOE represented 2.0% of estimated total proved reserves. For the year ended August 31, 2015, production of 3,194 MBOE represented 5.3% of estimated total proved reserves. DD&A expense was $9.00 per BOE and $10.93 per BOE for the years ended December 31, 2017 and 2016 , respectively. DD&A expense was $14.22 per BOE and $20.62 per BOE for the four months ended December 31, 2015 and the year ended August 31, 2015, respectively. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations Upon completion or acquisition of a well, the Company recognizes obligations for its oil and natural gas operations for anticipated costs to remove and dispose of surface equipment, plug and abandon the wells, and restore the drilling site to its original use. The estimated present value of such obligations is determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in regulations. Changes in estimates are reflected in the obligations as they occur. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the capitalized asset retirement cost. The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands): Year Ended December 31, 2017 2016 Beginning asset retirement obligation $ 16,458 $ 13,400 Obligations incurred with development activities 3,398 773 Obligations assumed with acquisitions 24,696 2,230 Accretion expense 1,554 1,046 Obligations discharged with asset retirements and divestitures (14,332 ) (4,739 ) Revisions in previous estimates (152 ) 3,748 Ending asset retirement obligation $ 31,622 $ 16,458 Less, current portion (3,246 ) (2,683 ) Non-current portion $ 28,376 $ 13,775 During the year ended December 31, 2017 , the Company decreased its asset retirement obligation by $0.2 million due to a revision to the expected timing of the future cash flows. During the year ended December 31, 2016 , the Company increased its asset retirement obligation by $3.7 million due primarily to a revision to its assumption of the average cost to plug and abandon each well. |
Revolving Credit Facility
Revolving Credit Facility | 12 Months Ended |
Dec. 31, 2017 | |
Line of Credit Facility [Abstract] | |
Revolving Credit Facility | Revolving Credit Facility The Company maintains a revolving credit facility (sometimes referred to as the "Revolver") with a bank syndicate with a maturity date of December 15, 2019 . The Revolver is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes, and to support letters of credit. As of December 31, 2017 , the terms of the Revolver provide for up to $500 million in borrowings, subject to a borrowing base limitation of $400 million . As of December 31, 2017 and 2016, there was no outstanding principal balance. The Company has an outstanding letter of credit of approximately $0.5 million . In September 2017, the lenders under the Revolver completed their regular semi-annual redetermination of our borrowing base. The borrowing base was increased from $225 million to $400 million . The next semi-annual redetermination is scheduled for April 2018 . Interest under the Revolver accrues monthly at a variable rate. For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin or LIBOR plus a margin. The interest rate margin, as well as other bank fees, varies with utilization of the Revolver. The average annual interest rate for borrowings during the years ended December 31, 2017 and 2016 , was 3.4% , and 2.6% , respectively. Certain of the Company’s assets, including substantially all of the producing wells and developed oil and gas leases, have been designated as collateral under the Revolver. The borrowing commitment is subject to scheduled redeterminations on a semi-annual basis. If certain events occur, or if the bank syndicate or the Company so elects, an unscheduled redetermination could be undertaken. The Revolver contains covenants that, among other things, restrict the payment of dividends and limit our overall commodity derivative position to a maximum position that varies over 5 years as a percentage of estimated proved developed producing or total proved reserves as projected in the semi-annual reserve report. Furthermore, the Revolver requires the Company to maintain compliance with certain financial and liquidity ratio covenants. In particular, the Company must not (a) permit its ratio of total funded debt to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0 as of the end of any fiscal quarter; or (b) as of the last day o f any fiscal quarter permit its current ratio, as defined in the agreement, to be less than 1.0 to 1.0. As of December 31, 2017 , the most recent compliance date, the C ompany was in compliance with these loan covenants and expects to remain in compliance throughout the next 12-month period. |
Notes Payable
Notes Payable | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Notes Payable | Notes Payable 2025 Senior Notes In November 2017, the Company issued $550 million aggregate principal amount of 6.25% Senior Notes (the "2025 Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is December 1, 2025. Interest on the 2025 Senior Notes accrues at 6.25% and began accruing on November 29, 2017. Interest is payable on June 1 and December 1 of each year, beginning on June 1, 2018. The 2025 Senior Notes were issued pursuant to an indenture dated as of November 29, 2017 and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the Revolver. The net proceeds from the sale of the 2025 Senior Notes were $538.1 million after deductions of $11.9 million for expenses and underwriting discounts and commissions. The associated expenses and underwriting discounts and commissions are amortized using the interest method at an effective interest rate of 6.6% . The net proceeds were used to fund the GCII Acquisition as discussed further in Note 3 , repay the 2021 Senior Notes, and pay off the outstanding Revolver balance . At any time prior to December 1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at a redemption price equal to 100% of the principal amount plus an Applicable Premium (as defined in the Indenture) plus accrued and unpai d interest. On and after December 1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at a redemption price equal to a specified percentage of the principal amount of the redeemed notes ( 104.688% for 2020, 103.125% for 2021, 101.563% for 2022, and 100% for 2023 and thereafter, during the twelve-month period beginning on December 1 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 1, 2020, the Company can, on one or more occasions, redeem up to 35% of the principal amount of the 2025 Senior Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to 106.25% of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions. The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge, or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities. These covenants are subject to a number of exceptions and qualifications. As of December 31, 2017 , the most recent compliance date, the C ompany was in compliance with these loan covenants and expects to remain in compliance throughout the next 12-month period. 2021 Senior Notes In June 2016, the Company issued $80 million aggregate principal amount of 9% Senior Notes due 2021 (the "2021 Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal was June 13, 2021. Interest on the 2021 Senior Notes accrued at 9% and began accruing on June 14, 2016. Interest was payable on June 15 and December 15 of each year, beginning on December 15, 2016. The 2021 Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility. The net proceeds from the sale of the 2021 Senior Notes were $75.2 million after deductions of $4.8 million for expenses and underwriting discounts and commissions. In December 2017, the Company repurchased all $80 million aggregate principal amount of the 2021 Senior Notes. At the time of repurchase, the Company made a required make whole payment of $8.2 million and wrote-off deferred issuance costs of $3.6 million . |
Commodity Derivative Instrument
Commodity Derivative Instruments | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Commodity Derivative Instruments | Commodity Derivative Instruments The Company has entered into commodity derivative instruments, as described below. Our commodity derivative instruments may include but are not limited to "collars," "swaps," and "put" positions. Our derivative strategy, including the volumes and commodities covered and the relevant strike prices, is based in part on our view of expected future market conditions and our analysis of well-level economic return potential. In addition, our use of derivative contracts is subject to stipulations set forth in the Revolver. A "put" option gives the owner the right, but not the obligation, to sell the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may at times purchase put options, which require us to pay premiums at the time we purchase the contracts. These premiums represent the fair value of the purchased put as of the date of purchase. A "call" option gives the owner the right, but not the obligation, to purchase the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, sell call options in conjunction with the purchase of put options to create "collars." We regularly utilize "no premium" (a.k.a. zero cost) collars where the cost of the put is offset by the proceeds of the call. At settlement, we receive the difference between the published index price and a floor price if the index price is below the floor. We pay the difference between the ceiling price and the index price if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the floor and the ceiling price. Additionally, at times, we may enter into swaps. Swaps are derivative contracts which obligate two counterparties to effectively trade the underlying commodity at a set price over a specified term. The Company may, from time to time, add incremental derivatives to cover additional production, restructure existing derivative contracts, or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes. The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with five counterparties and an exchange. Three of the counterparties are lenders in the Revolver. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets or liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses are recorded in the consolidated statements of operations. The Company’s cash flow is only impacted when the actual settlements under commodity derivative contracts result in it making or receiving a payment to or from the counterparty. Actual cash settlements can occur at either the scheduled maturity date of the contract or at an earlier date if the contract is liquidated prior to its scheduled maturity. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows. The Company’s commodity derivative contracts as of December 31, 2017 are summarized below: Settlement Period Derivative Instrument Average Volumes (Bbls per day) Floor Price Ceiling Price Crude Oil - NYMEX WTI Jan 1, 2018 - Dec 31, 2018 Collar 1,000 $ 40.00 $ 57.50 Jan 1, 2018 - Dec 31, 2018 Collar 1,000 $ 40.00 $ 57.75 Jan 1, 2018 - Dec 31, 2018 Collar 500 $ 40.00 $ 57.50 Jan 1, 2018 - Dec 31, 2018 Collar 2,500 $ 45.00 $ 58.00 Jan 1, 2018 - Dec 31, 2018 Collar 2,500 $ 45.00 $ 64.55 Jan 1, 2018 - Dec 31, 2018 Collar 1,000 $ 44.50 $ 65.00 Jan 1, 2018 - Dec 31, 2018 Collar 1,500 $ 44.50 $ 65.00 Settlement Period Derivative Average Volumes Floor Ceiling Natural Gas - CIG Rocky Mountain Jan 1, 2018 - Dec 31, 2018 Collar 10,000 $ 2.25 $ 2.82 Jan 1, 2018 - Dec 31, 2018 Collar 5,000 $ 2.25 $ 2.81 Subsequent to December 31, 2017 , the Company added the following positions: Settlement Period Derivative Instrument Average Volumes Average Fixed Price Propane - Mont Belvieu Feb 1, 2018 - Dec 31, 2018 Swap 1,000 $ 0.80 Offsetting of Derivative Assets and Liabilities As of December 31, 2017 and 2016 , all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of either party, for transactions that occur on the same date and in the same currency. The Company’s agreements also provide that, in the event of an early termination, each party has the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in its consolidated balance sheets. The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying consolidated balance sheets and the potential effect of master netting arrangements on the fair value of the Company’s derivative contracts (in thousands): As of December 31, 2017 Underlying Commodity Balance Sheet Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offset in the Net Amounts of Assets and Liabilities Presented in the Commodity derivative contracts Current assets $ 1,960 $ (1,960 ) $ — Commodity derivative contracts Non-current assets $ — $ — $ — Commodity derivative contracts Current liabilities $ 9,825 $ (1,960 ) $ 7,865 Commodity derivative contracts Non-current liabilities $ — $ — $ — As of December 31, 2016 Underlying Commodity Balance Sheet Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offset in the Net Amounts of Assets and Liabilities Presented in the Commodity derivative contracts Current assets $ 2,045 $ (1,748 ) $ 297 Commodity derivative contracts Non-current assets $ — $ — $ — Commodity derivative contracts Current liabilities $ 4,622 $ (1,748 ) $ 2,874 Commodity derivative contracts Non-current liabilities $ — $ — $ — The amount of gain (loss) recognized in the consolidated statements of operations related to derivative financial instruments was as follows (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Realized gain (loss) on commodity derivatives $ 39 $ 2,355 $ 1,577 $ 30,466 Unrealized gain (loss) on commodity derivatives (4,265 ) (10,105 ) 4,905 1,790 Total gain (loss) $ (4,226 ) $ (7,750 ) $ 6,482 $ 32,256 Realized gains and losses include cash received from the monthly settlement of derivative contracts at their scheduled maturity date net of the previously incurred premiums attributable to settled commodity contracts. During the year ended August 31, 2015, the Company liquidated oil derivatives with an average price of $82.79 and covering 372,500 barrels and received cash settlements of approximately $20.5 million . The following table summarizes derivative realized gains and losses during the periods presented (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Monthly settlement $ 1,062 $ 4,396 $ 2,331 $ 11,212 Previously incurred premiums attributable to settled commodity contracts (1,023 ) (2,041 ) (754 ) (1,255 ) Early liquidation — — — 20,509 Total realized gain (loss) $ 39 $ 2,355 $ 1,577 $ 30,466 Credit Related Contingent Features As of December 31, 2017 , three of the six counterparties to the Company's derivative instruments were members of the Company’s credit facility syndicate. The Company’s obligations under the credit facility and its derivative contracts are secured by liens on substantially all of the Company’s producing oil and gas properties. The agreement with the fourth counterparty, which is not a lender under the credit facility, is unsecured and does not require the posting of collateral. The agreement with the fifth counterparty, which is not a lender under the credit facility, may require the posting of collateral if in a liability position. The agreement with the sixth counterparty is subject to an inter-creditor agreement between the counterparty and the Company’s lenders under the credit facility. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements ASC 820, Fair Value Measurements and Disclosure , establishes a hierarchy for inputs used in measuring fair value for financial assets and liabilities that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows: • Level 1: Quoted prices available in active markets for identical assets or liabilities; • Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; and • Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash or valuation models. The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The Company’s non-recurring fair value measurements include unproved properties, asset retirement obligations, and purchase price allocations for the fair value of assets and liabilities acquired through business combinations and certain asset acquisitions. Please refer to Notes 2 , 3 , and 5 for further discussion of unproved properties, business combinations and asset acquisitions, and asset retirement obligations, respectively. The Company determines the estimated fair value of its unproved properties using market comparables which are deemed to be a Level 3 input. See Note 2 for additional information. The acquisition of a group of assets in a business combination transaction and certain asset acquisitions requires fair value estimates for assets acquired and liabilities assumed. The fair value of assets and liabilities acquired is calculated using a net discounted cash flow approach for the proved producing, proved undeveloped, probable, and possible properties. The discounted cash flows are developed using the income approach and are based on management’s expectations for the future. Unobservable inputs include estimates of future oil and natural gas production from the Company’s reserve reports, commodity prices based on the NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), estimated operating and development costs, and a risk-adjusted discount rate (all of which are designated as Level 3 inputs within the fair value hierarchy). For unproved properties, the fair value is determined using market comparables. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit-adjusted risk-free rate, inflation rate, and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period, and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method. See Notes 3 and 5 for additional information. The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis by level within the fair value hierarchy (in thousands): Fair Value Measurements at December 31, 2017 Level 1 Level 2 Level 3 Total Financial assets and liabilities: Commodity derivative asset $ — $ — $ — $ — Commodity derivative liability $ — $ 7,865 $ — $ 7,865 Fair Value Measurements at December 31, 2016 Level 1 Level 2 Level 3 Total Financial assets and liabilities: Commodity derivative asset $ — $ 297 $ — $ 297 Commodity derivative liability $ — $ 2,874 $ — $ 2,874 Commodity Derivative Instruments The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparties to its derivative contracts would default by failing to make any contractually required payments. The Company considers the counterparties to be of substantial credit quality and believes that they have the financial resources and willingness to meet their potential repayment obligations associated with the derivative transactions. At December 31, 2017 , derivative instruments utilized by the Company consist of collars. The oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are based on several factors including public indices, the instruments themselves are traded with third-party counterparties. As such, the Company has classified these instruments as Level 2. Fair Value of Financial Instruments The Company’s financial instruments consist primarily of cash and cash equivalents, cash held in escrow, accounts receivable, accounts payable, commodity derivative instruments (discussed above), notes payable, and credit facility borrowings. The carrying values of cash and cash equivalents, cash held in escrow, accounts receivable, and accounts payable are representative of their fair values due to their short-term maturities. Due to the variable interest rate paid on the credit facility borrowings, the carrying value is representative of its fair value. The fair value of the notes payable is estimated to be $564.1 million at December 31, 2017 . The Company determined the fair value of its notes payable at December 31, 2017 by using observable market based information for debt instruments of similar amounts and duration. The Company has classified the notes payable as Level 2. |
Interest Expense
Interest Expense | 12 Months Ended |
Dec. 31, 2017 | |
Interest and Debt Expense [Abstract] | |
Interest Expense | Interest Expense The components of interest expense are (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Revolving credit facility $ 2,004 $ 154 $ 661 $ 2,776 Notes payable 10,036 3,940 — — Amortization of debt issuance costs 3,084 1,638 431 853 Debt extinguishment costs 11,842 — — — Less: interest capitalized (15,124 ) (5,732 ) (1,092 ) (3,384 ) Interest expense, net $ 11,842 $ — $ — $ 245 |
Shareholders' Equity
Shareholders' Equity | 12 Months Ended |
Dec. 31, 2017 | |
Stockholders' Equity Note [Abstract] | |
Shareholders' Equity | Shareholders’ Equity The Company's classes of stock are summarized as follows: As of December 31, 2017 2016 Preferred stock, shares authorized 10,000,000 10,000,000 Preferred stock, par value $ 0.01 $ 0.01 Preferred stock, shares issued and outstanding nil nil Common stock, shares authorized 300,000,000 300,000,000 Common stock, par value $ 0.001 $ 0.001 Common stock, shares issued and outstanding 241,365,522 200,647,572 Preferred Stock may be issued in series with such rights and preferences as may be determined by the Board of Directors. Since inception, the Company has not issued any preferred shares. Shares of the Company’s common stock were issued during the years ended December 31, 2017 and 2016 , the four months ended December 31, 2015, and the year ended August 31, 2015, as described further below. Sales of common stock A summary of the transactions is shown in the following table. Net proceeds represent amounts received by the Company after deductions for underwriting discounts, commissions, and expenses of the offering. Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Number of common shares sold 40,250,000 90,275,000 — 18,613,952 Offering price per common share $ 7.76 $ 6.02 $ — $ 10.75 Net proceeds (in thousands) $ 312,170 $ 543,400 $ — $ 190,845 In November 2017, the Company, in connection with a registered underwritten public offering of its common stock (the “Offering”), entered into an underwriting agreement (the “Underwriting Agreement”) with the several underwriters named therein (the “Underwriters”) and pursuant to which the Company agreed to sell 35,000,000 shares of its common stock to the Underwriters at a price of $7.76 per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within 30 days, to purchase up to an additional 5,250,000 shares of common stock on the same terms and condition s. The option was exercised in full on November 10, 2017, bringing the total number of shares issued in the Offering to 40,250,000 . Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $312.2 million . The Company used the proceeds of the Offering to pay a portion of the purchase price of the GCII Acquisition, to repay a portion of the 2021 Senior Notes, and to repay amounts borrowed under the Revolver. Common stock issued for acquisition of mineral property interests During the periods presented, the Company issued shares of common stock in exchange for mineral property interests. The value of each transaction was determined using the market price of the Company’s common stock on the date of each transaction. Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Number of common shares issued for mineral property leases — — 37,051 995,672 Number of common shares issued for acquisitions — — 4,418,413 4,648,136 Total common shares issued — — 4,455,464 5,643,808 Average price per common share $ — $ — $ 11.28 $ 10.67 Aggregate value of shares issues (in thousands) $ — $ — $ 50,265 $ 60,221 |
Weighted-Average Shares Outstan
Weighted-Average Shares Outstanding | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Weighted-Average Shares Outstanding | Weighted-Average Shares Outstanding The following table sets forth the Company's outstanding equity grants which have a dilutive effect on earnings per share: Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31,2015 2017 2016 Weighted-average shares outstanding - basic 206,167,506 173,774,035 107,789,554 94,628,665 Potentially dilutive common shares from: Stock options 417,809 — — 672,493 Restricted stock units and stock bonus shares 158,236 — — 18,111 Weighted-average shares outstanding - diluted 206,743,551 173,774,035 107,789,554 95,319,269 The following potentially dilutive securities outstanding for the periods presented were not included in the respective weighted-average shares outstanding-diluted calculation above as such securities had an anti-dilutive effect on earnings per share: Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Potentially dilutive common shares from: Stock options 4,657,834 6,001,500 5,056,000 2,785,500 Performance-vested stock units 1 951,884 478,510 — — Restricted stock units and stock bonus shares 285,448 890,336 915,867 145,000 Total 5,895,166 7,370,346 5,971,867 2,930,500 1 The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the vesting condition. |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock-Based Compensation | Stock-Based Compensation In addition to cash compensation, the Company may compensate employees and directors with equity-based compensation in the form of stock options, performance-vested stock units, restricted stock units, stock bonus shares, and other equity awards. The Company records its equity compensation by pro-rating the estimated grant-date fair value of each grant over the period of time that the recipient is required to provide services to the Company (the "vesting period"). The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock. Indirect valuations are calculated using the Black-Scholes-Merton option pricing model or a Monte Carlo Model. For the periods presented, all stock-based compensation was either classified as a component within general and administrative expense in the Company's consolidated statements of operations or, for that portion which is directly attributable to individuals performing acquisition, exploration, and development activities, was capitalized to the full cost pool. As of December 31, 2017 , there were 4,500,000 common shares authorized for grant under the 2015 Equity Incentive Plan, of which 110,158 shares were available for future grants. The shares available for future grant exclude 951,884 shares which have been reserved for future vesting of performance-vested stock units in the event that these awards met the criterion to vest at their maximum multiplier. The amount of stock-based compensation was as follows (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Stock options $ 5,076 $ 5,417 $ 2,161 $ 4,741 Performance-vested stock units 2,938 1,047 — — Restricted stock units and stock bonus shares 4,977 4,232 7,162 2,950 Total stock-based compensation 12,991 10,696 9,323 7,691 Less: stock-based compensation capitalized (1,766 ) (1,205 ) (892 ) (778 ) Total stock-based compensation expense $ 11,225 $ 9,491 $ 8,431 $ 6,913 Stock options No stock options were granted during the year ended December 31, 2017 . During the periods presented, the Company granted the following stock options: Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 Number of options to purchase common shares 1,067,500 1,142,500 2,377,500 Weighted-average exercise price $ 7.19 $ 10.84 $ 11.55 Term (in years) 10 years 10 years 10 years Vesting Period (in years) 3 - 5 years 3.7-5 years 3-5 years Fair Value (in thousands) $ 3,860 $ 6,591 $ 13,266 The assumptions used in valuing stock options granted during each of the periods presented were as follows: Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 Expected term 6.4 years 6.5 years 6.5 years Expected volatility 55 % 53 % 47 % Risk-free rate 1.25 - 2.00% 1.8 - 2.0% 1.4 - 2.0% Expected dividend yield — % — % — % The following table summarizes activity for stock options for the periods presented: Number of Weighted-Average Weighted-Average Aggregate Intrinsic Value Outstanding, August 31, 2014 2,167,000 $ 5.94 8.0 years $ 16,287 Granted 2,377,500 11.55 Exercised (258,000 ) 3.81 2,103 Forfeited (110,000 ) 4.97 Outstanding, August 31, 2015 4,176,500 9.29 8.6 years 8,187 Granted 1,142,500 10.84 Exercised (188,000 ) 6.56 981 Expired (60,000 ) 11.74 Forfeited (15,000 ) 11.68 Outstanding, December 31, 2015 5,056,000 9.71 8.7 years 4,351 Granted 1,067,500 7.19 Exercised (20,000 ) 3.19 117 Expired — — Forfeited (102,000 ) 10.40 Outstanding, December 31, 2016 6,001,500 9.27 8.0 years 6,515 Granted — — Exercised (187,666 ) 3.95 976 Expired (41,000 ) 11.98 Forfeited (136,000 ) 10.97 Outstanding, December 31, 2017 5,636,834 $ 9.38 7.0 years $ 4,806 Outstanding, Exercisable at December 31, 2017 3,203,045 $ 9.08 6.5 years $ 3,587 The following table summarizes information about issued and outstanding stock options as of December 31, 2017 : Outstanding Options Exercisable Options Range of Exercise Prices Options Weighted-Average Exercise Price per Share Weighted-Average Remaining Contractual Life Options Weighted-Average Exercise Price per Share Weighted-Average Remaining Contractual Life Under $5.00 454,000 $ 3.45 3.5 years 454,000 $ 3.45 3.5 years $5.00 - $6.99 1,012,000 6.38 6.9 years 558,400 6.45 5.8 years $7.00 - $10.99 1,548,834 9.36 7.4 years 708,245 9.53 7.0 years $11.00 - $13.46 2,622,000 11.58 7.4 years 1,482,400 11.59 7.4 years Total 5,636,834 $ 9.38 7.0 years 3,203,045 $ 9.08 6.5 years The estimated unrecognized compensation cost from stock options not vested as of December 31, 2017 , which will be recognized ratably over the remaining vesting period, is as follows: Unrecognized compensation (in thousands) $ 9,697 Remaining vesting period 2.3 years Restricted stock units and stock bonus awards The Company grants restricted stock units and stock bonus awards to directors, eligible employees, and officers as a part of its equity incentive plan. Restrictions and vesting periods for the awards are determined by the Compensation Committee of the Board of Directors and are set forth in the award agreements. Each restricted stock unit or stock bonus award represents one share of the Company’s common stock to be released from restrictions upon completion of the vesting period. The awards typically vest in equal increments over three to five years . Restricted stock units and stock bonus awards are valued at the closing price of the Company’s common stock on the grant date and are recognized over the vesting period of the award. The following table summarizes activity for restricted stock units and stock bonus awards for the periods presented: Number of Weighted-Average Not vested, August 31, 2014 293,333 $ 10.60 Granted 547,699 11.17 Vested (208,532 ) 11.09 Forfeited — — Not vested, August 31, 2015 632,500 10.93 Granted 919,604 10.08 Vested (636,237 ) 10.13 Forfeited — — Not vested, December 31, 2015 915,867 10.63 Granted 464,533 7.66 Vested (424,483 ) 9.92 Forfeited (65,581 ) 8.99 Not vested, December 31, 2016 890,336 9.55 Granted 681,568 8.29 Vested (455,772 ) 9.21 Forfeited (28,746 ) 9.74 Not vested, December 31, 2017 1,087,386 $ 8.89 The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of December 31, 2017 , which will be recognized ratably over the remaining vesting period, is as follows: Unrecognized compensation (in thousands) $ 7,113 Remaining vesting period 2.2 years Performance-vested stock units The Company grants performance-vested stock units ("PSUs") to certain executives under its long-term incentive plan. The number of shares of the Company’s common stock that may be issued to settle PSUs ranges from zero to two times the number of PSUs awarded. The shares issued for PSUs are determined based on the Company’s performance over a three -year measurement period and vest in their entirety at the end of the measurement period. The PSUs will be settled in shares of the Company’s common stock following the end of the three -year performance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited. The vesting criterion for the PSUs is based on a comparison of the Company’s total shareholder return ("TSR") for the measurement period compared with the TSRs of a group of peer companies for the same measurement period. As the vesting criterion is linked to the Company's share price, it is considered a market condition for purposes of calculating the grant-date fair value of the awards. The fair value of the PSUs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period, and the volatilities for each of the Company’s peers. The assumptions used in valuing the PSUs granted were as follows: Year Ended December 31, 2017 2016 Weighted-average expected term 2.9 years 2.7 years Weighted-average expected volatility 59 % 58 % Weighted-average risk-free rate 1.34 % 0.87 % The fair value of the PSUs granted during the years ended December 31, 2017 and 2016 was $5.1 million and $4.0 million , respectively. As of December 31, 2017 , unrecognized compensation for PSUs was $5.0 million and will be amortized through 2019. A summary of the status and activity of PSUs is presented in the following table: Number of Units 1 Weighted-Average Grant-Date Fair Value Not vested, December 31, 2015 — $ — Granted 490,713 8.10 Vested — — Forfeited (12,203 ) 8.22 Not vested, December 31, 2016 478,510 8.09 Granted 473,374 10.79 Vested — — Forfeited — — Not vested, December 31, 2017 951,884 $ 9.44 1 The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two , depending on the level of satisfaction of the vesting condition. |
Defined Contribution Plan
Defined Contribution Plan | 12 Months Ended |
Dec. 31, 2017 | |
Retirement Benefits [Abstract] | |
Defined Contribution Plan | Defined Contribution Plan The Company sponsors a 401(k) defined contribution plan (the "plan") for eligible employees. Effective January 1, 2017, the Company modified the plan to include a discretionary matching contribution equal to 100% of compensation deferrals not to exceed 6% of eligible compensation. The Company contributed approximately $0.7 million for year ended December 31, 2017 , $0.4 million for the year ended December 31, 2016 , $0.1 million for the four months ended December 31, 2015, and $0.1 million during the year ended August 31, 2015 to the plan. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes The income tax provision is comprised of the following (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Current: Federal $ (99 ) $ 106 $ — $ (4 ) State — — — (111 ) Total current income tax expense (benefit) (99 ) 106 — (115 ) Deferred: Federal 48,631 (74,099 ) (45,332 ) 10,820 State 4,371 (6,651 ) (4,074 ) 972 Total deferred income tax (benefit) expense 53,002 (80,750 ) (49,406 ) 11,792 Valuation allowance (53,002 ) 80,750 39,399 — Income tax expense (benefit) $ (99 ) $ 106 $ (10,007 ) $ 11,677 A reconciliation of expected federal income taxes on income from continuing operations at statutory rates with the expense (benefit) for income taxes is presented in the following table (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Federal income tax at statutory rate $ 48,410 $ (74,489 ) $ (45,200 ) $ 10,105 State income taxes, net of federal tax 4,371 (6,685 ) (4,062 ) 908 Statutory depletion (159 ) (287 ) (150 ) (451 ) Stock-based compensation 50 383 — 92 Non-deductible compensation — — — 850 Impact of tax reform, net of valuation allowance (99 ) Valuation allowance (53,002 ) 80,750 39,399 — Other 330 434 6 173 Income tax expense (benefit) $ (99 ) $ 106 $ (10,007 ) $ 11,677 Effective rate expressed as a percentage — % — % 8 % 39 % On December 22, 2017, Congress signed Public Law No. 115-97, commonly referred to as the Tax Cut and Jobs Act of 2017 (“TCJA”). The passage of this legislation resulted in the change in the U.S. statutory rate from 35% to 21% beginning in January of 2018, the elimination of the corporate alternative minimum tax (“AMT”), the acceleration of depreciation for US tax purposes, limitations on deductibility of interest expense, the elimination of net operating loss carrybacks, and limitations on the use of future losses. In accordance with ASC 740, Income Taxes , the impact of a change in tax law is recorded in the period of enactment. Consequently, the Company has recorded a decrease to its net deferred tax assets of $24.0 million with a corresponding net adjustment to the valuation allowance for the year ended December 31, 2017. The Company also eliminated the $0.1 million deferred tax asset for its AMT credits and recorded a non-current tax receivable with a corresponding benefit to current income taxes. Based on the Company's current interpretation and subject to the release of the related regulations and any future interpretive guidance, the Company believes the effects of the change in tax law incorporated herein are substantially complete. As a result of other changes introduced by the TCJA, starting with compensation paid in 2018, Section 162(m) may limit us from deducting compensation, including performance-based compensation, in excess of $1 million paid to anyone who, starting in 2018, serves as the Chief Executive Officer or Chief Financial Officer, or who is among the three most highly compensated executive officers for any fiscal year. The only exception to this rule is for compensation that is paid pursuant to a binding contract in effect on November 2, 2017 that would have otherwise been deductible under the prior Section 162(m) rules. Accordingly, any compensation paid in the future pursuant to new compensation arrangements entered into after November 2, 2017, even if performance-based, will count towards the $1 million fiscal year deduction limit if paid to a covered executive. Additional information that may affect our income tax accounts and disclosures would include further clarification and guidance on how the Internal Revenue Service will implement tax reform, including guidance with respect to 100% bonus depreciation on self-constructed assets and Section 162(m), further clarification and guidance on how state taxing authorities will implement tax reform and the related effect on our state income tax returns, completion of our 2017 tax return filings, and the potential for additional guidance from the SEC or the FASB related to tax reform. In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income, and tax planning strategies in making this assessment. Judgment is required in considering the relative weight of negative and positive evidence. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits, and other deferred tax assets will be utilized prior to their expiration. As a result, it may be determined that a deferred tax asset valuation allowance should be established or released. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense. The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at each of the period ends is presented in the following table (in thousands): As of December 31, 2017 2016 Deferred tax assets (liabilities): Net operating loss carryforward $ 43,283 $ 47,462 Stock-based compensation 5,237 5,576 Basis of oil and gas properties (5,011 ) 62,707 Statutory depletion 2,795 4,028 Unrealized loss on commodity derivative 1,939 1,334 Other (615 ) (958 ) 47,628 120,149 Valuation allowance on tax assets (47,628 ) (120,149 ) Deferred tax asset (liability), net $ — $ — In connection with ASU 2016-09, deferred tax assets were increased by $4.5 million related to excess benefit net operating loss carryforwards along with a $4.5 million offsetting increase in the Company's valuation allowance. The impact of the adjustments netted to zero within retained earnings. At December 31, 2017 , the Company has U.S. Federal and state net operating loss carryforward of approximately $175.5 million that could be utilized to offset taxable income of future years. These net operating loss carryforwards will expire in various years beginning in 2025 with substantially all of the carryforwards expiring beginning in 2031 . At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income, and tax planning strategies in making an assessment as to the future utilization of deferred tax assets. During the year ended December 31, 2017 , the Company recognized a full valuation allowance on its net deferred tax assets. This decision was based on the fact that for the preceding three-year period, the Company has reported cumulative net losses. The ability of the Company to utilize its NOL carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of a Company’s taxable income that can be offset by these carryforwards. The Company underwent an ownership change as defined in Section 382 of the Internal Revenue Code on December 31, 2016, as a result of our issuance of common stock. The amount of our taxable income for tax years ending after our ownership change, which may be offset by NOL carryovers from pre-change years, will be subject to an annual limitation, known as a Section 382 limitation. The Section 382 limitation is based on the value of our stock immediately before the ownership change multiplied by the long-term tax exempt rate in effect at the time of the ownership change, increased by built in gains recognized during the 5-year period beginning on the ownership change date. The identified change of ownership is not anticipated to restrict the Company's ability to utilize its NOLs. As of December 31, 2017 , the Company had no unrecognized tax benefits. The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company’s tax position. Given the substantial NOL carryforwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carryforwards, and would not result in significant interest expense or penalties. The Company's federal and state tax returns filed since August 31, 2014 and August 31, 2013, respectively, remain subject to examination by tax authorities. |
Other Commitments and Contingen
Other Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Other Commitments and Contingencies | Other Commitments and Contingencies Volume Commitments The Company entered into firm sales agreements for its oil production with three counterparties during 2014 and entered into an additional firm sales agreement for its oil production in the third quarter 2017. Deliveries under two of the sales agreements commenced during 2015. Deliveries under the third agreement commenced in 2016. Deliveries under the fourth agreement are expected to commence in the fourth quarter of 2018. Pursuant to these agreements, we must deliver specific amounts of oil either from our own production or from oil that we acquire from third parties. If we are unable to fulfill all of our contractual obligations, we may be required to pay penalties or damages pursuant to these agreements. Our commitments over the next five years, excluding the contingent commitment described below, are as follows: Year ending December 31, Oil (MBbls) 2018 4,485 2019 5,167 2020 4,003 2021 1,672 2022 — Thereafter — Total 15,327 During the years ended December 31, 2017 and 2016 , and four months ended December 31, 2015, the Company incurred transportation deficiency charges of $0.7 million , $0.6 million , and $2.8 million , respectively, as we were unable to meet all of the obligations during the period. No such charges were incurred during the year ended August 31, 2015. In collaboration with several other producers and DCP Midstream, LP ("DCP Midstream"), we have agreed to participate in the expansion of natural gas gathering and processing capacity in the D-J Basin. The first agreement includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system. Both are currently expected to be completed during the third quarter of 2018, although the start-up date is undetermined at this time. Our share of the commitment will require 46.4 MMcf per day to be delivered after the plant in-service date for a period of 7 years. The second agreement also includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system. Both are currently expected to be completed in mid-2019, although the start-up date is undetermined at this time. Our share of the commitment will require 43.8 MMcf per day to be delivered after the plant in-service date for a period of 7 years. These contractual obligations can be reduced by the collective volumes delivered to the plants by other producers in the D-J Basin that are in excess of such producers' total commitment. We expect that our development plan will support the utilization of this capacity. Litigation From time to time, the Company is a party to various commercial and regulatory claims, pending or threatened legal action, and other proceedings that arise in the ordinary course of business. It is the opinion of management that none of the current proceedings are reasonably likely to have a material adverse impact on its business, financial position, results of operations, or cash flows. Office Leases In September 2016, the Company entered into a new 65 -month lease for the Company’s principal office space located in Denver, which commenced in the first quarter of 2017. Rent under the new lease is approximately $62,000 per month. In July 2016, the Company entered into a field office lease in Greeley which requires monthly payments of $7,500 through October 2021. Rent expense for office leases was $1.1 million for the year ended December 31, 2017 , $1.0 million for year ended December 31, 2016, $0.3 million for the four months ended December 31, 2015, and $0.3 million for the year ended August 31, 2015. Vehicle Leases In December 2017, the Company entered into a leasing arrangement for its vehicles used in our normal operations. These leases expire after four years and are classified as capital leases. The assets associated with these capital leases are recorded within "Other property and equipment, net." A schedule of the minimum lease payments under non-cancelable capital and operating leases as of December 31, 2017 follows (in thousands): Year ending December 31: Vehicles Leases Office Leases 2018 $ 76 $ 840 2019 37 859 2020 37 878 2021 63 875 2022 — 477 Thereafter — — Total minimum lease payments $ 213 $ 3,929 Less: Amount representing estimated executory cost (16 ) Net minimum lease payments 197 Less: Amount representing interest (24 ) Present value of net minimum lease payments * $ 173 * Reflected in the balance sheet as current and non-current obligations of $63 thousand and $110 thousand , respectively, within "Accounts payable and accrued expenses" and "Other liabilities," respectively. |
Supplemental Schedule of Inform
Supplemental Schedule of Information to the Statements of Cash Flows | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Schedule of Information to the Statements of Cash Flows | Supplemental Schedule of Information to the Consolidated Statements of Cash Flows The following table supplements the cash flow information presented in the consolidated financial statements for the periods presented (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 Supplemental cash flow information: 2017 2016 Interest paid $ 9,235 $ 3,779 $ 683 $ 2,817 Income taxes paid $ — $ 106 $ (150 ) $ 202 Non-cash investing and financing activities: Accrued well costs as of period end $ 56,348 $ 42,779 $ 31,414 $ 33,071 Assets acquired in exchange for common stock — — 50,265 60,221 Asset retirement obligations incurred with development activities 3,398 773 1,819 7,051 Asset retirement obligations assumed with acquisitions 24,696 2,230 — — Obligations discharged with asset retirements and divestitures $ (14,332 ) $ (4,739 ) $ — $ — Net changes in operating assets and liabilities: Accounts receivable $ (72,518 ) $ (13,063 ) $ 5,696 $ 3,446 Accounts payable and accrued expenses 5,823 2,283 3,954 (2,307 ) Revenue payable 47,345 2,254 (5,441 ) 4,557 Production taxes payable 33,311 (7,095 ) 3,631 5,121 Other (1,131 ) (790 ) (1,037 ) (359 ) Changes in operating assets and liabilities $ 12,830 $ (16,411 ) $ 6,803 $ 10,458 |
Unaudited Oil and Gas Reserves
Unaudited Oil and Gas Reserves Information | 12 Months Ended |
Dec. 31, 2017 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Unaudited Oil and Gas Reserves Information | Unaudited Oil and Natural Gas Reserves Information Oil and Natural Gas Reserve Information: Proved reserves are the estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (prices and costs held constant as of the date the estimate is made). Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved oil and natural gas reserve information as of the period ends presented and the related discounted future net cash flows before income taxes are based on estimates prepared by Ryder Scott. Reserve information for the properties was prepared in accordance with guidelines established by the SEC. The reserve estimates prepared as of each of the period ends presented were prepared in accordance with applicable SEC rules. Proved oil and natural gas reserves are calculated based on the prices for oil and natural gas during the twelve-month period before the determination date, determined as the unweighted arithmetic average of the first day of the month price for each month within such period. This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows. Undrilled locations can generally be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years of initial booking. The following table sets forth information regarding the Company’s net ownership interests in estimated quantities of proved developed and undeveloped oil and natural gas reserve quantities and changes therein for each of the periods presented: Oil (MBbl) Natural Gas (MMcf) NGL (MBbl) MBOE Balance, August 31, 2014 16,324 95,179 — 32,188 Revision of previous estimates (1,699 ) (4,889 ) — (2,513 ) Purchase of reserves in place 4,201 21,957 — 7,860 Extensions, discoveries, and other additions 11,465 73,392 — 23,696 Sale of reserves in place (629 ) (4,337 ) — (1,352 ) Production (1,970 ) (7,344 ) — (3,194 ) Balance, August 31, 2015 27,692 173,958 — 56,685 Revision of previous estimates (10,917 ) (38,931 ) — (17,407 ) Purchase of reserves in place 4,380 58,959 — 14,207 Extensions, discoveries, and other additions 8,263 62,301 — 18,647 Sale of reserves in place (2,297 ) (14,149 ) — (4,655 ) Production (742 ) (3,468 ) — (1,320 ) Balance, December 31, 2015 26,379 238,670 — 66,157 Revision of previous estimates (7,788 ) (80,549 ) — (21,213 ) Purchase of reserves in place 23,141 197,103 — 55,991 Extensions, discoveries, and other additions 1,457 13,018 — 3,627 Sale of reserves in place (2,900 ) (24,235 ) — (6,939 ) Production (2,257 ) (12,086 ) — (4,271 ) Balance, December 31, 2016 38,032 331,921 — 93,352 Revision of previous estimates (3,038 ) (66,413 ) 28,689 14,581 Purchase of reserves in place 12,150 117,167 13,424 45,103 Extensions, discoveries, and other additions 28,736 206,644 24,358 87,535 Sale of reserves in place (660 ) (4,592 ) — (1,425 ) Production (5,824 ) (24,834 ) (2,518 ) (12,481 ) Balance, December 31, 2017 69,396 559,893 63,953 226,665 Proved developed and undeveloped reserves: Developed at August 31, 2015 7,393 46,026 — 15,064 Undeveloped at August 31, 2015 20,299 127,932 — 41,621 Balance, August 31, 2015 27,692 173,958 — 56,685 Developed at December 31, 2015 8,410 56,751 — 17,868 Undeveloped at December 31, 2015 17,969 181,919 — 48,289 Balance, December 31, 2015 26,379 238,670 — 66,157 Developed at December 31, 2016 7,435 62,570 — 17,863 Undeveloped at December 31, 2016 30,597 269,351 — 75,489 Balance, December 31, 2016 38,032 331,921 — 93,352 Developed at December 31, 2017 26,552 219,279 24,251 87,350 Undeveloped at December 31, 2017 42,844 340,614 39,702 139,315 Balance, December 31, 2017 69,396 559,893 63,953 226,665 Notable changes in proved reserves for the year ended December 31, 2017 included: • Purchases of reserves in place. For the year ended December 31, 2017 , purchases of reserves in place of 45,103 MBOE were primarily attributable to the acquisition of proved reserves in the GCII Acquisition. Please see Note 3 for further information. • Revision of previous estimates. For the year ended December 31, 2017, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 14,581 MBOE primarily as a result of updated pricing as well as shifting from reporting reserves on a 2-stream to a 3-stream basis. • Extensions and discoveries. For the year ended December 31, 2017 , total extensions and discoveries of 87,535 MBOE were primarily attributable to extending our development plan by a year due to the passage of time, the addition of a third rig for the second and third years of our development plan, and the drilling and completion of wells not previously proved. Notable changes in proved reserves for the year ended December 31, 2016 included: • Purchases of reserves in place. For the year ended December 31, 2016 , purchases of reserves in place of 55,991 MBOE were primarily attributable to the acquisition of proved reserves in the GC Acquisition. Please see Note 3 for further information. • Revision of previous estimates. For the year ended December 31, 2016 , revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 21,213 MBOE primarily as a result of the GC Acquisition and related changes to our development plan that resulted in the removal of certain legacy PUD locations from the three-year drilling plan. • Extensions and discoveries. For the year ended December 31, 2016 , total extensions and discoveries of 3,627 MBOE were primarily attributable to successful drilling in the Wattenberg Field. In addition, successful drilling by other operators in adjacent acreage allowed us to increase our proved undeveloped locations. Notable changes in proved reserves for the four months ended December 31, 2015 included: • Purchases of reserves in place. For the four months ended December 31, 2015, purchases of reserves in place of 14,207 MBO E were attributable to the acquisition of proved reserves. Please see Note 3 for further information. • Revision of previous estimates. For the four months ended December 31, 2015, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 17,407 MBOE. As the Company continued to revise its drilling plans, the development plan was changed to remove undeveloped reserves that were not projected to be drilled in the subsequent three years and reflected the lower development costs anticipated from transitioning to a monobore wellbore design and longer horizontal wells; in addition, we high-graded our inventory of wells to be drilled. • Extensions and discoveries. For the four months ended December 31, 2015, total extensions and discoveries of 18,647 MBOE were primarily attributable to successful drilling in the Wattenberg Field. In addition, successful drilling by other operators in adjacent acreage allowed us to increase our proved undeveloped locations. Notable changes in proved reserves for the year ended August 31, 2015 included: • Purchases of reserves in place. For the year ended August 31, 2015, purchases of reserves in place of 7,860 MBOE were attributable to the acquisition of proved reserves. • Revision of previous estimates. For the year ended August 31, 2015, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 2,513 MBOE. As the Company continued to revise its drilling plans toward horizontal drilling, the vertical proved undeveloped and vertical developed non-producing locations were removed from its development plan. • Extensions and discoveries. For the year ended August 31, 2015, total extensions and discoveries of 23,696 MBOE were primarily attributable to successful drilling in the Wattenberg Field. The Company drilled 67 vertical exploratory wells. In addition, successful drilling by other operators in adjacent acreage allowed us to increase our proved undeveloped locations. Standardized Measure of Discounted Future Net Cash Flows: The following discussion relates to the standardized measure of future net cash flows from our proved reserves and changes therein related to estimated proved reserves. Future oil and natural gas sales have been computed by applying average prices of oil and natural gas as discussed below. Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at the end of the period based on period-end costs. The calculation assumes the continuation of existing economic conditions, including the use of constant prices and costs. Future income tax expenses were calculated by applying period-end statutory tax rates, with consideration of future tax rates already legislated, to future pretax cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carryforwards relating to oil and natural gas producing activities. All cash flow amounts are discounted at 10% annually to derive the standardized measure of discounted future cash flows. Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s oil and natural gas reserves. Actual future net cash flows from oil and gas properties will also be affected by factors such as actual prices the Company receives for oil and natural gas, the amount and timing of actual production, supply of and demand for oil and natural gas, and changes in governmental regulations or taxation. The following table sets forth the Company’s future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by the SEC (in thousands): As of December 31, As of August 31, 2015 2017 2016 2015 Future cash inflow $ 5,493,507 $ 2,180,673 $ 1,710,610 $ 2,046,615 Future production costs (1,291,369 ) (644,093 ) (462,097 ) (653,009 ) Future development costs (1,048,856 ) (584,537 ) (340,449 ) (510,720 ) Future income tax expense (285,349 ) (90,195 ) (108,172 ) (144,399 ) Future net cash flows 2,867,933 861,848 799,892 738,487 10% annual discount for estimated timing of cash flows (1,267,258 ) (427,587 ) (408,939 ) (372,658 ) Standardized measure of discounted future net cash flows $ 1,600,675 $ 434,261 $ 390,953 $ 365,829 There have been significant fluctuations in the posted prices of oil and natural gas during the last three years. Prices actually received from purchasers of the Company’s oil and natural gas are adjusted from posted prices for location differentials, quality differentials, and Btu content. Estimates of the Company’s reserves are based on realized prices. The following table presents the prices used to prepare the reserve estimates based upon the unweighted arithmetic average of the first day of the month price for each month within the twelve-month period prior to the end of the respective reporting period presented as adjusted for our differentials: Oil (Bbl) Natural Gas (Mcf) NGL (Bbl) December 31, 2017 (Average) $ 46.57 $ 2.21 $ 16.06 December 31, 2016 (Average) $ 36.07 $ 2.44 $ — December 31, 2015 (Average) $ 41.33 $ 2.60 $ — August 31, 2015 (Average) $ 53.27 $ 3.28 $ — The prices for the December 31, 2017 oil and natural gas reserves are based on the twelve-month arithmetic average for the first of month prices as adjusted for our differentials from January 1, 2017 through December 31, 2017 . The December 31, 2017 oil price of $46.57 per barrel (West Texas Intermediate Cushing) was $10.50 higher than the December 31, 2016 oil price of $36.07 per barrel. The December 31, 2017 natural gas price of $2.21 per Mcf (Henry Hub) was $0.23 lower than the December 31, 2016 price of $2.44 per Mcf. Changes in the Standardized Measure of Discounted Future Net Cash Flows: The principle sources of change in the standardized measure of discounted future net cash flows are (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Standardized measure, beginning of period $ 434,261 $ 390,953 $ 365,829 $ 402,699 Sale and transfers, net of production costs (306,754 ) (81,468 ) (25,222 ) (98,486 ) Net changes in prices and production costs 135,525 (64,387 ) (81,968 ) (233,051 ) Extensions, discoveries, and improved recovery 811,564 18,795 116,343 173,918 Changes in estimated future development costs (25,969 ) (6,016 ) (7,195 ) 10,002 Previously estimated development costs incurred during the period 170,296 62,502 5,923 4,957 Revision of quantity estimates 165,267 (110,306 ) (36,820 ) (38,340 ) Accretion of discount 47,635 44,703 14,610 57,629 Net change in income taxes (113,523 ) 5,104 25,263 58,547 Divestitures of reserves (7,157 ) (26,839 ) (43,754 ) (19,234 ) Purchase of reserves in place 260,999 228,855 77,024 56,795 Changes in timing and other 28,531 (27,635 ) (19,080 ) (9,607 ) Standardized measure, end of period $ 1,600,675 $ 434,261 $ 390,953 $ 365,829 |
Unaudited Financial Data
Unaudited Financial Data | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Unaudited Financial Data | Unaudited Financial Data The Company’s unaudited quarterly financial information is as follows (in thousands, except share data): Year Ended December 31, 2017 First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 43,790 $ 75,036 $ 103,593 $ 140,097 Expenses 27,536 48,514 57,461 71,420 Operating income 16,254 26,522 46,132 68,677 Other income (expense) 3,626 1,414 (2,284 ) (17,958 ) Income before income taxes 19,880 27,936 43,848 50,719 Income tax benefit — — — (99 ) Net income $ 19,880 $ 27,936 $ 43,848 $ 50,818 Net income per common share: (1) Basic $ 0.10 $ 0.14 $ 0.22 $ 0.23 Diluted (2) $ 0.10 $ 0.14 $ 0.22 $ 0.23 Weighted-average shares outstanding: Basic 200,707,891 200,831,063 200,881,447 222,072,930 Diluted 201,309,251 201,224,172 201,460,915 222,917,611 Year Ended December 31, 2016 First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 18,273 $ 23,947 $ 26,234 $ 38,695 Expenses 71,356 172,157 45,887 29,324 Operating income (loss) (53,083 ) (148,210 ) (19,653 ) 9,371 Other income (expense) 1,682 (5,537 ) 417 (4,070 ) Income (loss) before income taxes (51,401 ) (153,747 ) (19,236 ) 5,301 Income tax expense — 101 5 — Net income (loss) $ (51,401 ) $ (153,848 ) $ (19,241 ) $ 5,301 Net income (loss) per common share: (1) Basic $ (0.42 ) $ (0.89 ) $ (0.10 ) $ 0.03 Diluted (2) $ (0.42 ) $ (0.89 ) $ (0.10 ) $ 0.03 Weighted-average shares outstanding: Basic 121,392,736 172,013,551 200,515,555 200,585,800 Diluted 121,392,736 172,013,551 200,515,555 201,254,678 1 The sum of net income (loss) per common share for the four quarters may not agree with the annual amount reported because the number used as the denominator for each quarterly computation is based on the weighted-average number of shares outstanding during that quarter whereas the annual computation is based upon an average for the entire year. 2 Common share equivalents were excluded from the calculation of net income (loss) per share as the inclusion of the common share equivalents was anti-dilutive. |
Organization and Summary of S26
Organization and Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation | Basis of Presentation: The Company operates in one business segment, and all of its operations are located in the United States of America. At the directive of the Securities and Exchange Commission ("SEC") to use "plain English" in public filings, the Company will use such terms as "we," "our," "us," or the "Company" in place of SRC Energy Inc . When such terms are used in this manner throughout this document, they are in reference only to the corporation, SRC Energy Inc., and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees. The consolidated financial statements include the accounts of the Company, including its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. The Company prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”). |
Change of Year-End | Change of Year-End: On February 25, 2016, the Company's Board of Directors approved a change in fiscal year end from August 31 to December 31. Unless otherwise noted, all references to "years" in this report refer to the twelve-month fiscal year, which prior to September 1, 2015 ended on August 31, and beginning with December 31, 2015 ends on the December 31 of each year. |
Use of Estimates | Use of Estimates: The preparation of consolidated financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and natural gas reserves, goodwill, business combinations, derivatives, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain. Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions are revised periodically, and the effects of revisions are reflected in the c onsolidated financial statements in the period that it is determined to be necessary. Actual results could differ from these estimates. |
Cash and Cash Equivalents | Cash and Cash Equivalents: The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents. Cash Held in Escrow: Cash held in escrow includes deposits for purchases of certain oil and gas properties as required under the related purchase and sale agreements. |
Oil and Gas Properties | Oil and Gas Properties: The Company uses the full cost method of accounting for costs related to its oil and gas properties. Accordingly, all costs associated with acquisition, exploration, and development of oil and natural gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, and overhead charges directly related to acquisition, exploration, and development activities. Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves. Capitalized costs of oil and gas properties are depleted using the unit-of-production method based upon estimates of proved reserves. For depletion purposes, the volume of proved oil and natural gas reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of oil. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is the impairment test prescribed by SEC regulations. The ceiling test determines a limit on the net book value of oil and gas properties. The ceiling is calculated as the sum of the present value of estimated future net revenues from proved oil and natural gas reserves, plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized, less the income tax effects related to differences between the book and tax basis of the properties. The present value of estimated future net revenues is computed by applying current prices of oil and natural gas reserves to estimated future production of proved oil and natural gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves; the result is discounted at 10% and assumes continuation of current economic conditions. Future cash outflows associated with settling accrued asset retirement obligations that have been accrued on the balance are excluded from the calculation of the present value of future net revenues. The calculation of income tax effects takes into account the tax basis of oil and gas properties, net operating loss carryforwards, and the impact of statutory depletion. If the capitalized costs of proved and unproved oil and gas properties, net of accumulated depletion and prior impairments, and the related deferred income taxes exceed the ceiling limit, the excess is charged to expense. Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount. During the year ended December 31, 2017 , the Company did not recognize any ceiling test impairments. During the year ended December 31, 2016, the four months ended December 31, 2015, and the year ended August 31, 2015, the Company recognized ceiling test impairments of $215.2 million , $125.2 million , and $16.0 million , respectively. The oil and natural gas prices used to calculate the full cost ceiling limitation are based upon a 12-month rolling average, calculated as the unweighted arithmetic average of the first day of the month price for each month within the preceding 12-month period unless prices are defined by contractual arrangements. Prices are adjusted for basis or location differentials and are held constant for the productive life of each well. |
Oil and Natural Gas Reserves | Oil and Natural Gas Reserves: Oil and natural gas reserves represent theoretical, estimated quantities of oil and natural gas which, using geological and engineering data, are estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values including many factors beyond the Company’s control. Accordingly, reserve estimates are different from the future quantities of oil and natural gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves. The determination of depletion expense, as well as the ceiling test calculation related to the recorded value of the Company’s oil and gas properties, is highly dependent on estimates of proved oil and natural gas reserves. |
Capitalized Interest | Capitalized Interest: The Company capitalizes interest on expenditures made in connection with acquisitions of mineral interests that are currently not subject to depletion and exploration and development projects that are in progress. Interest is capitalized during the period that activities are in progress to bring the projects to their intended use. See Note 10 for additional information. |
Capitalized Overhead | Capitalized Overhead: A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities. Under the full cost method of accounting, these expenses are capitalized in the full cost pool. See Note 2 for additional information. |
Other Property and Equipment | Other Property and Equipment: Support equipment (including such items as vehicles, computer equipment, and software), office leasehold improvements, office furniture and equipment, and buildings are stated at historical cost. Expenditures for support equipment relating to new assets or improvements are capitalized, provided the expenditure extends the useful life of an asset or extends the asset’s functionality. Support equipment, office leasehold improvements, and office furniture and equipment are depreciated under the straight-line method using estimated useful lives ranging from three to five years. Buildings are also depreciated under the straight-line method using estimated useful lives of thirty-nine years. No depreciation is taken on assets classified as construction in progress until the asset is placed into service. Gains and losses are recorded upon retirement, sale, or disposal of assets. Maintenance and repair costs are recognized as period costs when incurred. The Company evaluates its other property and equipment for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable. |
Revenue Payable | Revenue Payable: Revenue payable represents amounts collected from purchasers for oil and natural gas sales which are revenues due to other working or royalty interest owners. Generally, the Company is required to remit amounts due under these liabilities within 30 days of the end of the month in which the related proceeds from the production are received. |
Asset Retirement Obligations | Asset Retirement Obligations: The Company’s activities are subject to various laws and regulations, including legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service. Calculation of an asset retirement obligation ("ARO") requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors. The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using the Company’s credit-adjusted risk-free rate. Estimates are periodically reviewed and adjusted to reflect changes. The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made. When the ARO is initially recorded, the Company capitalizes the cost by increasing the carrying value of the related asset. Asset retirement costs ("ARCs") related to wells are capitalized to the full cost pool and subject to depletion. Over time, the liability increases for the change in its present value, while the net capitalized cost decreases over the useful life of the asset as depletion expense is recognized. In addition, ARCs are included in the ceiling test calculation when assessing the full cost pool for impairment. |
Business Combinations | Business Combinations: The Company accounts for its acquisitions that qualify as businesses using the acquisition method under FASB Accounting Standards Codification ("ASC") 805, Business Combinations . Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values. The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable. The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain. |
Goodwill | Goodwill: The Company’s goodwill represents the excess of the purchase price over the fair value of net identifiable assets acquired in a business combination. Goodwill is not amortized and is tested for impairment annually or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. We have historically performed the annual impairment assessment as of August 31 st . During 2016, we changed the date of our annual goodwill impairment assessment to October 1 st . With respect to its annual goodwill testing date, management believes that this voluntary change in accounting method is preferable as it better aligns the annual impairment testing date with the Company’s new fiscal year end, which was also changed in 2016. This change in assessment date was applied prospectively and did not delay, accelerate, or avoid a potential impairment charge. When evaluating goodwill for impairment, the Company may first perform an assessment of qualitative factors to determine if the fair value of the reporting unit is more-likely-than-not greater than its carrying amount. If, based on the review of the qualitative factors, the Company determines it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying value, the required impairment test can be bypassed. If the Company does not perform a qualitative assessment or if the fair value of the reporting unit is not more-likely-than-not greater than its carrying value, the Company must calculate the estimated fair value of the reporting unit. If the carrying value of the reporting unit exceeds the estimated fair value, the Company should recognize an impairment charge. The amount of impairment for goodwill is measured as the amount by which the carrying amount of the reporting unit exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill. For purposes of assessing goodwill, the Company only has one reporting unit. We performed our annual goodwill impairment test as of October 1, 2017. This test did not result in an impairment. The Company utilized a market approach in estimating the fair value of the reporting unit. The primary assumptions used in the Company's impairment evaluations are based on the best available market information at the time. Changes in these assumptions or future economic conditions could impact the Company's conclusion regarding an impairment of goodwill and potentially result in a non-cash impairment loss in a future period. |
Oil and Natural Gas Sales | Oil, Natural Gas, and NGL Revenues: The Company derives revenue primarily from the sale of oil, natural gas, and NGLs produced on its properties. Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's pro-rata interest. Revenues are reported on a net revenue interest basis, which excludes revenues that are attributable to other parties' working or royalty interests. Revenue is recorded and receivables are accrued in the month production is delivered to the purchaser, at which time ownership of the product is transferred to the purchaser. Payment is generally received between thirty and ninety days after the date of production. Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement. |
Major Customers | Major Customers: The Company sells production to a small number of customers as is customary in the industry. |
Lease Operating Expenses | Lease Operating Expenses: Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred. Lease operating expenses (also referred to as production or lifting costs) include the costs of labor to operate the wells and related equipment and facilities, repairs and maintenance, materials, fuel consumed, supplies utilized in operating the wells and related equipment and facilities, property taxes, and insurance applicable to proved properties and wells and related equipment and facilities. |
Stock-Based Compensation | Stock-Based Compensation: The Company recognizes all equity-based compensation as stock-based compensation expense based on the fair value of the compensation measured at the grant date. For stock options, fair value is calculated using the Black-Scholes-Merton option pricing model. For stock bonus awards and restricted stock units, fair value is the closing stock price for the Company's common stock on the grant date. For performance-vested stock units, fair value is calculated using a Monte Carlo simulation. The compensation is recognized over the vesting period of the grant. |
Income Tax | Income Tax: Income taxes are computed using the asset and liability method. Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases as well as the effect of net operating losses, tax credits, and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. No significant uncertain tax positions were identified as of any date on or before December 31, 2017 . The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of December 31, 2017 , the Company has not recognized any interest or penalties related to uncertain tax benefits. |
Financial Instruments | Financial Instruments : Financial instruments, whether measured on a recurring or non-recurring basis, are recorded at fair value. A fair value hierarchy, established by the Financial Accounting Standards Board (“FASB”), prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). |
Commodity Derivative Instruments | Commodity Derivative Instruments: The Company has entered into commodity derivative instruments, primarily utilizing swaps, puts, or collars, to reduce the effect of price changes on a portion of its future oil and natural gas production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative gain (loss) line on the consolidated statement of operations. The Company values its derivative instruments by obtaining independent market quotes as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors as well as other relevant economic measures. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. |
Transportation Commitment Charge | Transportation Commitment Charge: The Company has entered into several agreements that require us to deliver minimum amounts of oil to a third party marketer and/or other counterparties that transport oil via pipelines. See Note 16 for additional information. Pursuant to these agreements, we must deliver specific amounts, either from our own production or from oil that we acquire. If we are unable to fulfill all of our contractual delivery obligations from our own production, we may be required to pay penalties or damages pursuant to these agreements, or we may have to purchase oil from third parties to fulfill our delivery obligations. When we incur penalties of this type, we recognize the expense as a transportation commitment charge in the consolidated statement of operations. |
Recent Accounting Pronouncements | Recently Adopted Accounting Pronouncements: In November 2016, the FASB issued Accounting Standards Update ("ASU") 2016-18, "Restricted Cash" ("ASU 2016-18"), which amends ASC 230 to add or clarify guidance on the classification and presentation of restricted cash in the statement of cash flows. Key requirements of ASU 2016-18 are as follows: 1) An entity should include in its cash and cash equivalent balances in the statement of cash flows those amounts that are deemed to be restricted cash and restricted cash equivalents. ASU 2016-18 does not define the terms “restricted cash” and “restricted cash equivalents” but states that an entity should continue to provide appropriate disclosures about its accounting policies pertaining to restricted cash in accordance with other GAAP. ASU 2016-18 also states that any change in accounting policy will need to be assessed under ASC 250; 2) A reconciliation between the statement of financial position and the statement of cash flows must be disclosed when the statement of financial position includes more than one line item for cash, cash equivalents, restricted cash, and restricted cash equivalents; 3) Changes in restricted cash and restricted cash equivalents that result from transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows; and 4) An entity with a material balance of amounts generally described as restricted cash and restricted cash equivalents must disclose information about the nature of the restrictions. We adopted this pronouncement effective October 1, 2017 and have applied it retrospectively. Upon adoption, we removed cash held in escrow of $18.2 million from the statement of cash flows for the year ended December 31, 2016. This change resulted in a decrease to net cash used in investing activities of $18.2 million . Additionally, we removed cash held in escrow of $18.2 million from the statement of cash flows for the year ended December 31, 2017. This change resulted in an increase to net cash used in investing activities of $18.2 million . The adoption of this standard did not impact cash flows for the 4-months ended December 31, 2015 nor the year ended August 31, 2015. We have included a tabular reconciliation of cash, cash equivalents, and restricted cash in the discussion of " Cash Held in Escrow" above . In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting” (“ASU 2016-09”), which intends to improve the accounting for share-based payment transactions. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions, including: (1) Accounting and Cash Flow Classification for Excess Tax Benefits and Deficiencies, (2) Forfeitures, and (3) Tax Withholding Requirements and Cash Flow Classification. ASU 2016-09 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We adopted this pronouncement effective January 1, 2017. Upon adoption of this standard, we no longer estimate the total number of awards for which the requisite service period will not be rendered, and effective January 1, 2017, we began accounting for forfeitures when they occur. We applied this accounting change on a modified retrospective basis with a cumulative-effect adjustment of $0.1 million to retained earnings as of the date of adoption. The adoption of the other provisions did not materially impact the consolidated financial statements. In January 2017, the FASB issued ASU 2017-04, "Simplifying the Test for Goodwill Impairment" ("ASU 2017-04"), which removes the requirement to compare the implied fair value of goodwill with its carrying amount as part of step 2 of the goodwill impairment test. We adopted ASU 2017-04 on January 1, 2017, and it will be applied for any interim or annual goodwill impairment tests subsequent to that date. The adoption of this guidance did not impact the consolidated financial statements. Recently Issued Accounting Pronouncements: We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new accounting pronouncements on us. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" ("ASU 2016-02"), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous US GAAP. ASU 2016-02 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the impact of the adoption of this standard on our consolidated financial statements. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The objective of this update is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The FASB subsequently issued various ASUs, which deferred the effective date of ASU 2014-09 and provided additional implementation guidance. ASU 2014-09 and its amendments are effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. The Company will adopt these ASUs with an effective date of January 1, 2018, using the modified retrospective method. While we have not yet completed all aspects of the adoption of the standard, based on our current assessment of contracts with customers, we do not believe there will be any impact to the timing of our revenue recognition or our operating income (loss), net income (loss), and cash flows. The Company is in the process of evaluating changes, if any, to accounting policies and internal control procedures along with continuing to assess additional disclosures which may be required upon implementation of these ASUs. There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows. |
Organization and Summary of S27
Organization and Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Cash and Cash Equivalents | The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets to the consolidated statements of cash flows: As of December 31, As of August 31, 2015 2017 2016 2015 Cash and cash equivalents $ 48,772 $ 18,615 $ 66,499 $ 133,908 Restricted cash included in cash held in escrow and other deposits — 18,219 — — $ 48,772 $ 36,834 $ 66,499 $ 133,908 |
Restrictions on Cash and Cash Equivalents | The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets to the consolidated statements of cash flows: As of December 31, As of August 31, 2015 2017 2016 2015 Cash and cash equivalents $ 48,772 $ 18,615 $ 66,499 $ 133,908 Restricted cash included in cash held in escrow and other deposits — 18,219 — — $ 48,772 $ 36,834 $ 66,499 $ 133,908 |
Schedule of Accounts Payable and Accrued Expenses | Accounts payable and accrued expenses consist of the following (in thousands): As of December 31, 2017 2016 Trade accounts payable $ 624 $ 786 Accrued well costs 56,348 42,779 Accrued G&A 6,017 4,292 Accrued LOE 5,249 3,140 Accrued interest 3,125 320 Accrued other 3,309 1,136 74,672 52,453 |
Schedule of Customers With Balances Greater Than 10% of Total Receivables | The Company sells production to a small number of customers as is customary in the industry. Customers representing 10% or more of its oil, natural gas, and NGL revenue (“major customers”) for each of the periods presented are shown in the following table: Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Company A 33% * * * Company B 24% 20% 15% 11% Company C 17% 20% * * Company D * 16% * * Company E * 13% * * Company F * * 57% 65% Company G * * 12% * * less than 10% Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table (these companies do not necessarily correspond to those presented above): As of December 31, 2017 2016 Company A 26% 23% Company B 23% * Company C 16% * Company D 11% 43% Company E * 10% * less than 10% |
Property and Equipment (Tables)
Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Schedule of Capitalized Costs | The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands): As of December 31, 2017 2016 Oil and gas properties, full cost method: Costs of proved properties: Producing and non-producing $ 1,629,789 $ 969,239 Less, accumulated depletion and full cost ceiling impairments (659,205 ) (545,157 ) Subtotal, proved properties, net 970,584 424,082 Costs of wells in progress 106,269 81,780 Costs of unproved properties and land, not subject to depletion: Lease acquisition and other costs 786,469 392,561 Land 7,200 5,986 Subtotal, unproved properties and land 793,669 398,547 Costs of other property and equipment: Other property and equipment 8,134 5,063 Less, accumulated depreciation (2,080 ) (736 ) Subtotal, other property and equipment, net 6,054 4,327 Total property and equipment, net $ 1,876,576 $ 908,736 |
Schedule of Costs Incurred | Under the full cost method of accounting, these expenditures, in the amounts shown in the table below, were capitalized in the full cost pool (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Capitalized overhead $ 10,293 $ 7,074 $ 1,091 $ 2,049 Costs Incurred: Costs incurred in oil and gas property acquisition, exploration, and development activities for the periods presented were (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Acquisition of property: Unproved $ 538,489 $ 365,548 $ 38,779 $ 32,701 Proved 139,154 152,363 51,085 51,400 Exploration costs — 43,154 23,697 146,892 Development costs 460,875 87,782 17,742 4,957 Other property and equipment, and land 4,397 7,506 395 741 Capitalized interest, capitalized G&A, and other 26,677 18,744 4,415 7,051 Total costs incurred $ 1,169,592 $ 675,097 $ 136,113 $ 243,742 |
Schedule of Capitalized Costs Excluded from Amortization | The following table summarizes costs related to unproved properties that have been excluded from amounts subject to depletion at December 31, 2017 (in thousands): Period Incurred Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, Total as of December 31, 2017 2017 2016 2015 2014 and Prior Unproved leasehold acquisition costs $ 537,470 $ 223,907 $ 23,068 $ 456 $ 1,568 $ 786,469 Unproved development costs 26,056 — — — — 26,056 Total unevaluated costs $ 563,526 $ 223,907 $ 23,068 $ 456 $ 1,568 $ 812,525 |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Tables) - Greeley-Crescent Agreement | 12 Months Ended |
Dec. 31, 2017 | |
Business Acquisition [Line Items] | |
Schedule of Fair Value of Acquisition | The following table summarizes the purchase price and final fair values of assets acquired and liabilities assumed (in thousands): Purchase Price June 14, 2016 Consideration given: Cash $ 485,141 Net liabilities assumed, including asset retirement obligations 1,273 Total consideration given $ 486,414 Allocation of Purchase Price (1) Proved oil and gas properties $ 132,903 Unproved oil and gas properties 353,511 Total fair value of assets acquired $ 486,414 (1) Oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rat e of 11.5% , a nd assumptions regarding the timing and amount of future development and operating costs. |
Schedule of Pro Forma Results | The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results. (in thousands) Year Ended December 31, 2016 Oil, natural gas, and NGL revenues $ 110,635 Net loss $ (218,578 ) Net loss per common share Basic $ (1.10 ) Diluted $ (1.10 ) |
Depletion, depreciation and a30
Depletion, depreciation and accretion ("DD&A") (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Other Costs and Disclosures [Abstract] | |
Schedule of Depletion, Depreciation and Amortization | DD&A consisted of the following (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Depletion of oil and gas properties $ 109,287 $ 45,193 $ 18,371 $ 65,158 Depreciation and accretion 3,022 1,485 405 711 Total DD&A Expense $ 112,309 $ 46,678 $ 18,776 $ 65,869 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Asset Retirement Obligations | The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands): Year Ended December 31, 2017 2016 Beginning asset retirement obligation $ 16,458 $ 13,400 Obligations incurred with development activities 3,398 773 Obligations assumed with acquisitions 24,696 2,230 Accretion expense 1,554 1,046 Obligations discharged with asset retirements and divestitures (14,332 ) (4,739 ) Revisions in previous estimates (152 ) 3,748 Ending asset retirement obligation $ 31,622 $ 16,458 Less, current portion (3,246 ) (2,683 ) Non-current portion $ 28,376 $ 13,775 |
Commodity Derivative Instrume32
Commodity Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Commodity Derivative Contracts | The Company’s commodity derivative contracts as of December 31, 2017 are summarized below: Settlement Period Derivative Instrument Average Volumes (Bbls per day) Floor Price Ceiling Price Crude Oil - NYMEX WTI Jan 1, 2018 - Dec 31, 2018 Collar 1,000 $ 40.00 $ 57.50 Jan 1, 2018 - Dec 31, 2018 Collar 1,000 $ 40.00 $ 57.75 Jan 1, 2018 - Dec 31, 2018 Collar 500 $ 40.00 $ 57.50 Jan 1, 2018 - Dec 31, 2018 Collar 2,500 $ 45.00 $ 58.00 Jan 1, 2018 - Dec 31, 2018 Collar 2,500 $ 45.00 $ 64.55 Jan 1, 2018 - Dec 31, 2018 Collar 1,000 $ 44.50 $ 65.00 Jan 1, 2018 - Dec 31, 2018 Collar 1,500 $ 44.50 $ 65.00 Settlement Period Derivative Average Volumes Floor Ceiling Natural Gas - CIG Rocky Mountain Jan 1, 2018 - Dec 31, 2018 Collar 10,000 $ 2.25 $ 2.82 Jan 1, 2018 - Dec 31, 2018 Collar 5,000 $ 2.25 $ 2.81 Subsequent to December 31, 2017 , the Company added the following positions: Settlement Period Derivative Instrument Average Volumes Average Fixed Price Propane - Mont Belvieu Feb 1, 2018 - Dec 31, 2018 Swap 1,000 $ 0.80 |
Schedule of Fair Value of Derivatives | The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying consolidated balance sheets and the potential effect of master netting arrangements on the fair value of the Company’s derivative contracts (in thousands): As of December 31, 2017 Underlying Commodity Balance Sheet Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offset in the Net Amounts of Assets and Liabilities Presented in the Commodity derivative contracts Current assets $ 1,960 $ (1,960 ) $ — Commodity derivative contracts Non-current assets $ — $ — $ — Commodity derivative contracts Current liabilities $ 9,825 $ (1,960 ) $ 7,865 Commodity derivative contracts Non-current liabilities $ — $ — $ — As of December 31, 2016 Underlying Commodity Balance Sheet Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offset in the Net Amounts of Assets and Liabilities Presented in the Commodity derivative contracts Current assets $ 2,045 $ (1,748 ) $ 297 Commodity derivative contracts Non-current assets $ — $ — $ — Commodity derivative contracts Current liabilities $ 4,622 $ (1,748 ) $ 2,874 Commodity derivative contracts Non-current liabilities $ — $ — $ — |
Schedule of Loss Recognized in Statements of Operations | The amount of gain (loss) recognized in the consolidated statements of operations related to derivative financial instruments was as follows (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Realized gain (loss) on commodity derivatives $ 39 $ 2,355 $ 1,577 $ 30,466 Unrealized gain (loss) on commodity derivatives (4,265 ) (10,105 ) 4,905 1,790 Total gain (loss) $ (4,226 ) $ (7,750 ) $ 6,482 $ 32,256 |
Schedule of Hedge Realized Gains (Losses) | The following table summarizes derivative realized gains and losses during the periods presented (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Monthly settlement $ 1,062 $ 4,396 $ 2,331 $ 11,212 Previously incurred premiums attributable to settled commodity contracts (1,023 ) (2,041 ) (754 ) (1,255 ) Early liquidation — — — 20,509 Total realized gain (loss) $ 39 $ 2,355 $ 1,577 $ 30,466 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Schedule of Assets and Liabilities Measured on a Recurring Basis | The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis by level within the fair value hierarchy (in thousands): Fair Value Measurements at December 31, 2017 Level 1 Level 2 Level 3 Total Financial assets and liabilities: Commodity derivative asset $ — $ — $ — $ — Commodity derivative liability $ — $ 7,865 $ — $ 7,865 Fair Value Measurements at December 31, 2016 Level 1 Level 2 Level 3 Total Financial assets and liabilities: Commodity derivative asset $ — $ 297 $ — $ 297 Commodity derivative liability $ — $ 2,874 $ — $ 2,874 |
Interest Expense (Tables)
Interest Expense (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Interest and Debt Expense [Abstract] | |
Schedule of the Components of Interest Expense | The components of interest expense are (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Revolving credit facility $ 2,004 $ 154 $ 661 $ 2,776 Notes payable 10,036 3,940 — — Amortization of debt issuance costs 3,084 1,638 431 853 Debt extinguishment costs 11,842 — — — Less: interest capitalized (15,124 ) (5,732 ) (1,092 ) (3,384 ) Interest expense, net $ 11,842 $ — $ — $ 245 |
Shareholders' Equity (Tables)
Shareholders' Equity (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Stockholders' Equity Note [Abstract] | |
Schedule of Classes of Stock | The Company's classes of stock are summarized as follows: As of December 31, 2017 2016 Preferred stock, shares authorized 10,000,000 10,000,000 Preferred stock, par value $ 0.01 $ 0.01 Preferred stock, shares issued and outstanding nil nil Common stock, shares authorized 300,000,000 300,000,000 Common stock, par value $ 0.001 $ 0.001 Common stock, shares issued and outstanding 241,365,522 200,647,572 |
Schedule of Common Stock Sold in Public Offering | A summary of the transactions is shown in the following table. Net proceeds represent amounts received by the Company after deductions for underwriting discounts, commissions, and expenses of the offering. Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Number of common shares sold 40,250,000 90,275,000 — 18,613,952 Offering price per common share $ 7.76 $ 6.02 $ — $ 10.75 Net proceeds (in thousands) $ 312,170 $ 543,400 $ — $ 190,845 |
Schedule of Common Stock Issued For Acquisition of Mineral Interests and Services | The value of each transaction was determined using the market price of the Company’s common stock on the date of each transaction. Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Number of common shares issued for mineral property leases — — 37,051 995,672 Number of common shares issued for acquisitions — — 4,418,413 4,648,136 Total common shares issued — — 4,455,464 5,643,808 Average price per common share $ — $ — $ 11.28 $ 10.67 Aggregate value of shares issues (in thousands) $ — $ — $ 50,265 $ 60,221 |
Weighted-Average Shares Outst36
Weighted-Average Shares Outstanding (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Reconciliation of Weighted-average Shares Outstanding Basic and Diluted | The following table sets forth the Company's outstanding equity grants which have a dilutive effect on earnings per share: Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31,2015 2017 2016 Weighted-average shares outstanding - basic 206,167,506 173,774,035 107,789,554 94,628,665 Potentially dilutive common shares from: Stock options 417,809 — — 672,493 Restricted stock units and stock bonus shares 158,236 — — 18,111 Weighted-average shares outstanding - diluted 206,743,551 173,774,035 107,789,554 95,319,269 |
Schedule of Potentially Dilutive Securities | The following potentially dilutive securities outstanding for the periods presented were not included in the respective weighted-average shares outstanding-diluted calculation above as such securities had an anti-dilutive effect on earnings per share: Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Potentially dilutive common shares from: Stock options 4,657,834 6,001,500 5,056,000 2,785,500 Performance-vested stock units 1 951,884 478,510 — — Restricted stock units and stock bonus shares 285,448 890,336 915,867 145,000 Total 5,895,166 7,370,346 5,971,867 2,930,500 1 The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the vesting condition. |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of Stock-based Compensation Expense Recognized | he amount of stock-based compensation was as follows (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Stock options $ 5,076 $ 5,417 $ 2,161 $ 4,741 Performance-vested stock units 2,938 1,047 — — Restricted stock units and stock bonus shares 4,977 4,232 7,162 2,950 Total stock-based compensation 12,991 10,696 9,323 7,691 Less: stock-based compensation capitalized (1,766 ) (1,205 ) (892 ) (778 ) Total stock-based compensation expense $ 11,225 $ 9,491 $ 8,431 $ 6,913 |
Schedule of Employee Stock Options Granted During the Period | No stock options were granted during the year ended December 31, 2017 . During the periods presented, the Company granted the following stock options: Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 Number of options to purchase common shares 1,067,500 1,142,500 2,377,500 Weighted-average exercise price $ 7.19 $ 10.84 $ 11.55 Term (in years) 10 years 10 years 10 years Vesting Period (in years) 3 - 5 years 3.7-5 years 3-5 years Fair Value (in thousands) $ 3,860 $ 6,591 $ 13,266 |
Schedule of Assumptions Used In Valuing Stock Options | The assumptions used in valuing the PSUs granted were as follows: Year Ended December 31, 2017 2016 Weighted-average expected term 2.9 years 2.7 years Weighted-average expected volatility 59 % 58 % Weighted-average risk-free rate 1.34 % 0.87 % The assumptions used in valuing stock options granted during each of the periods presented were as follows: Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 Expected term 6.4 years 6.5 years 6.5 years Expected volatility 55 % 53 % 47 % Risk-free rate 1.25 - 2.00% 1.8 - 2.0% 1.4 - 2.0% Expected dividend yield — % — % — % |
Summary of Stock Option Activity Under Stock Option | The following table summarizes activity for stock options for the periods presented: Number of Weighted-Average Weighted-Average Aggregate Intrinsic Value Outstanding, August 31, 2014 2,167,000 $ 5.94 8.0 years $ 16,287 Granted 2,377,500 11.55 Exercised (258,000 ) 3.81 2,103 Forfeited (110,000 ) 4.97 Outstanding, August 31, 2015 4,176,500 9.29 8.6 years 8,187 Granted 1,142,500 10.84 Exercised (188,000 ) 6.56 981 Expired (60,000 ) 11.74 Forfeited (15,000 ) 11.68 Outstanding, December 31, 2015 5,056,000 9.71 8.7 years 4,351 Granted 1,067,500 7.19 Exercised (20,000 ) 3.19 117 Expired — — Forfeited (102,000 ) 10.40 Outstanding, December 31, 2016 6,001,500 9.27 8.0 years 6,515 Granted — — Exercised (187,666 ) 3.95 976 Expired (41,000 ) 11.98 Forfeited (136,000 ) 10.97 Outstanding, December 31, 2017 5,636,834 $ 9.38 7.0 years $ 4,806 Outstanding, Exercisable at December 31, 2017 3,203,045 $ 9.08 6.5 years $ 3,587 |
Schedule of Issued and Outstanding Stock Options | The following table summarizes information about issued and outstanding stock options as of December 31, 2017 : Outstanding Options Exercisable Options Range of Exercise Prices Options Weighted-Average Exercise Price per Share Weighted-Average Remaining Contractual Life Options Weighted-Average Exercise Price per Share Weighted-Average Remaining Contractual Life Under $5.00 454,000 $ 3.45 3.5 years 454,000 $ 3.45 3.5 years $5.00 - $6.99 1,012,000 6.38 6.9 years 558,400 6.45 5.8 years $7.00 - $10.99 1,548,834 9.36 7.4 years 708,245 9.53 7.0 years $11.00 - $13.46 2,622,000 11.58 7.4 years 1,482,400 11.59 7.4 years Total 5,636,834 $ 9.38 7.0 years 3,203,045 $ 9.08 6.5 years |
Schedule of Unrecognized Compensation Cost | The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of December 31, 2017 , which will be recognized ratably over the remaining vesting period, is as follows: Unrecognized compensation (in thousands) $ 7,113 Remaining vesting period 2.2 years The estimated unrecognized compensation cost from stock options not vested as of December 31, 2017 , which will be recognized ratably over the remaining vesting period, is as follows: Unrecognized compensation (in thousands) $ 9,697 Remaining vesting period 2.3 years |
Summary of Restricted Stock Awards | The following table summarizes activity for restricted stock units and stock bonus awards for the periods presented: Number of Weighted-Average Not vested, August 31, 2014 293,333 $ 10.60 Granted 547,699 11.17 Vested (208,532 ) 11.09 Forfeited — — Not vested, August 31, 2015 632,500 10.93 Granted 919,604 10.08 Vested (636,237 ) 10.13 Forfeited — — Not vested, December 31, 2015 915,867 10.63 Granted 464,533 7.66 Vested (424,483 ) 9.92 Forfeited (65,581 ) 8.99 Not vested, December 31, 2016 890,336 9.55 Granted 681,568 8.29 Vested (455,772 ) 9.21 Forfeited (28,746 ) 9.74 Not vested, December 31, 2017 1,087,386 $ 8.89 |
Schedule of Nonvested Share Activity | A summary of the status and activity of PSUs is presented in the following table: Number of Units 1 Weighted-Average Grant-Date Fair Value Not vested, December 31, 2015 — $ — Granted 490,713 8.10 Vested — — Forfeited (12,203 ) 8.22 Not vested, December 31, 2016 478,510 8.09 Granted 473,374 10.79 Vested — — Forfeited — — Not vested, December 31, 2017 951,884 $ 9.44 1 The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two , depending on the level of satisfaction of the vesting condition. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Taxes | The income tax provision is comprised of the following (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Current: Federal $ (99 ) $ 106 $ — $ (4 ) State — — — (111 ) Total current income tax expense (benefit) (99 ) 106 — (115 ) Deferred: Federal 48,631 (74,099 ) (45,332 ) 10,820 State 4,371 (6,651 ) (4,074 ) 972 Total deferred income tax (benefit) expense 53,002 (80,750 ) (49,406 ) 11,792 Valuation allowance (53,002 ) 80,750 39,399 — Income tax expense (benefit) $ (99 ) $ 106 $ (10,007 ) $ 11,677 |
Schedule of Reconciliation of Income Taxes | A reconciliation of expected federal income taxes on income from continuing operations at statutory rates with the expense (benefit) for income taxes is presented in the following table (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Federal income tax at statutory rate $ 48,410 $ (74,489 ) $ (45,200 ) $ 10,105 State income taxes, net of federal tax 4,371 (6,685 ) (4,062 ) 908 Statutory depletion (159 ) (287 ) (150 ) (451 ) Stock-based compensation 50 383 — 92 Non-deductible compensation — — — 850 Impact of tax reform, net of valuation allowance (99 ) Valuation allowance (53,002 ) 80,750 39,399 — Other 330 434 6 173 Income tax expense (benefit) $ (99 ) $ 106 $ (10,007 ) $ 11,677 Effective rate expressed as a percentage — % — % 8 % 39 % |
Schedule of Deferred Tax Assets and Liabilities | The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at each of the period ends is presented in the following table (in thousands): As of December 31, 2017 2016 Deferred tax assets (liabilities): Net operating loss carryforward $ 43,283 $ 47,462 Stock-based compensation 5,237 5,576 Basis of oil and gas properties (5,011 ) 62,707 Statutory depletion 2,795 4,028 Unrealized loss on commodity derivative 1,939 1,334 Other (615 ) (958 ) 47,628 120,149 Valuation allowance on tax assets (47,628 ) (120,149 ) Deferred tax asset (liability), net $ — $ — |
Other Commitments and Conting39
Other Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Contractual Commitment Over the Next Five Years | Our commitments over the next five years, excluding the contingent commitment described below, are as follows: Year ending December 31, Oil (MBbls) 2018 4,485 2019 5,167 2020 4,003 2021 1,672 2022 — Thereafter — Total 15,327 |
Operating Leases of Lessee Disclosure | A schedule of the minimum lease payments under non-cancelable capital and operating leases as of December 31, 2017 follows (in thousands): Year ending December 31: Vehicles Leases Office Leases 2018 $ 76 $ 840 2019 37 859 2020 37 878 2021 63 875 2022 — 477 Thereafter — — Total minimum lease payments $ 213 $ 3,929 Less: Amount representing estimated executory cost (16 ) Net minimum lease payments 197 Less: Amount representing interest (24 ) Present value of net minimum lease payments * $ 173 * Reflected in the balance sheet as current and non-current obligations of $63 thousand and $110 thousand , respectively, within "Accounts payable and accrued expenses" and "Other liabilities," respectively. |
Supplemental Schedule of Info40
Supplemental Schedule of Information to the Statements of Cash Flows (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of Supplemental Information to the Statements of Cash Flows | The following table supplements the cash flow information presented in the consolidated financial statements for the periods presented (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 Supplemental cash flow information: 2017 2016 Interest paid $ 9,235 $ 3,779 $ 683 $ 2,817 Income taxes paid $ — $ 106 $ (150 ) $ 202 Non-cash investing and financing activities: Accrued well costs as of period end $ 56,348 $ 42,779 $ 31,414 $ 33,071 Assets acquired in exchange for common stock — — 50,265 60,221 Asset retirement obligations incurred with development activities 3,398 773 1,819 7,051 Asset retirement obligations assumed with acquisitions 24,696 2,230 — — Obligations discharged with asset retirements and divestitures $ (14,332 ) $ (4,739 ) $ — $ — Net changes in operating assets and liabilities: Accounts receivable $ (72,518 ) $ (13,063 ) $ 5,696 $ 3,446 Accounts payable and accrued expenses 5,823 2,283 3,954 (2,307 ) Revenue payable 47,345 2,254 (5,441 ) 4,557 Production taxes payable 33,311 (7,095 ) 3,631 5,121 Other (1,131 ) (790 ) (1,037 ) (359 ) Changes in operating assets and liabilities $ 12,830 $ (16,411 ) $ 6,803 $ 10,458 |
Unaudited Oil and Gas Reserve41
Unaudited Oil and Gas Reserves Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Schedule of Net Ownership Interests in Estimated Quantities of Proved Developed and Undeveloped Oil and Gas Reserve Quantities and Changes During Fiscal Year | The following table sets forth information regarding the Company’s net ownership interests in estimated quantities of proved developed and undeveloped oil and natural gas reserve quantities and changes therein for each of the periods presented: Oil (MBbl) Natural Gas (MMcf) NGL (MBbl) MBOE Balance, August 31, 2014 16,324 95,179 — 32,188 Revision of previous estimates (1,699 ) (4,889 ) — (2,513 ) Purchase of reserves in place 4,201 21,957 — 7,860 Extensions, discoveries, and other additions 11,465 73,392 — 23,696 Sale of reserves in place (629 ) (4,337 ) — (1,352 ) Production (1,970 ) (7,344 ) — (3,194 ) Balance, August 31, 2015 27,692 173,958 — 56,685 Revision of previous estimates (10,917 ) (38,931 ) — (17,407 ) Purchase of reserves in place 4,380 58,959 — 14,207 Extensions, discoveries, and other additions 8,263 62,301 — 18,647 Sale of reserves in place (2,297 ) (14,149 ) — (4,655 ) Production (742 ) (3,468 ) — (1,320 ) Balance, December 31, 2015 26,379 238,670 — 66,157 Revision of previous estimates (7,788 ) (80,549 ) — (21,213 ) Purchase of reserves in place 23,141 197,103 — 55,991 Extensions, discoveries, and other additions 1,457 13,018 — 3,627 Sale of reserves in place (2,900 ) (24,235 ) — (6,939 ) Production (2,257 ) (12,086 ) — (4,271 ) Balance, December 31, 2016 38,032 331,921 — 93,352 Revision of previous estimates (3,038 ) (66,413 ) 28,689 14,581 Purchase of reserves in place 12,150 117,167 13,424 45,103 Extensions, discoveries, and other additions 28,736 206,644 24,358 87,535 Sale of reserves in place (660 ) (4,592 ) — (1,425 ) Production (5,824 ) (24,834 ) (2,518 ) (12,481 ) Balance, December 31, 2017 69,396 559,893 63,953 226,665 Proved developed and undeveloped reserves: Developed at August 31, 2015 7,393 46,026 — 15,064 Undeveloped at August 31, 2015 20,299 127,932 — 41,621 Balance, August 31, 2015 27,692 173,958 — 56,685 Developed at December 31, 2015 8,410 56,751 — 17,868 Undeveloped at December 31, 2015 17,969 181,919 — 48,289 Balance, December 31, 2015 26,379 238,670 — 66,157 Developed at December 31, 2016 7,435 62,570 — 17,863 Undeveloped at December 31, 2016 30,597 269,351 — 75,489 Balance, December 31, 2016 38,032 331,921 — 93,352 Developed at December 31, 2017 26,552 219,279 24,251 87,350 Undeveloped at December 31, 2017 42,844 340,614 39,702 139,315 Balance, December 31, 2017 69,396 559,893 63,953 226,665 |
Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves | The following table sets forth the Company’s future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by the SEC (in thousands): As of December 31, As of August 31, 2015 2017 2016 2015 Future cash inflow $ 5,493,507 $ 2,180,673 $ 1,710,610 $ 2,046,615 Future production costs (1,291,369 ) (644,093 ) (462,097 ) (653,009 ) Future development costs (1,048,856 ) (584,537 ) (340,449 ) (510,720 ) Future income tax expense (285,349 ) (90,195 ) (108,172 ) (144,399 ) Future net cash flows 2,867,933 861,848 799,892 738,487 10% annual discount for estimated timing of cash flows (1,267,258 ) (427,587 ) (408,939 ) (372,658 ) Standardized measure of discounted future net cash flows $ 1,600,675 $ 434,261 $ 390,953 $ 365,829 |
Schedule of Prices Used to Prepare Estimates of Oil and Gas Reserves | The following table presents the prices used to prepare the reserve estimates based upon the unweighted arithmetic average of the first day of the month price for each month within the twelve-month period prior to the end of the respective reporting period presented as adjusted for our differentials: Oil (Bbl) Natural Gas (Mcf) NGL (Bbl) December 31, 2017 (Average) $ 46.57 $ 2.21 $ 16.06 December 31, 2016 (Average) $ 36.07 $ 2.44 $ — December 31, 2015 (Average) $ 41.33 $ 2.60 $ — August 31, 2015 (Average) $ 53.27 $ 3.28 $ — |
Schedule of Changes in the Standardized Measure for Discounted Cash Flows | The principle sources of change in the standardized measure of discounted future net cash flows are (in thousands): Year Ended December 31, Four Months Ended December 31, 2015 Year Ended August 31, 2015 2017 2016 Standardized measure, beginning of period $ 434,261 $ 390,953 $ 365,829 $ 402,699 Sale and transfers, net of production costs (306,754 ) (81,468 ) (25,222 ) (98,486 ) Net changes in prices and production costs 135,525 (64,387 ) (81,968 ) (233,051 ) Extensions, discoveries, and improved recovery 811,564 18,795 116,343 173,918 Changes in estimated future development costs (25,969 ) (6,016 ) (7,195 ) 10,002 Previously estimated development costs incurred during the period 170,296 62,502 5,923 4,957 Revision of quantity estimates 165,267 (110,306 ) (36,820 ) (38,340 ) Accretion of discount 47,635 44,703 14,610 57,629 Net change in income taxes (113,523 ) 5,104 25,263 58,547 Divestitures of reserves (7,157 ) (26,839 ) (43,754 ) (19,234 ) Purchase of reserves in place 260,999 228,855 77,024 56,795 Changes in timing and other 28,531 (27,635 ) (19,080 ) (9,607 ) Standardized measure, end of period $ 1,600,675 $ 434,261 $ 390,953 $ 365,829 |
Unaudited Financial Data (Table
Unaudited Financial Data (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Unaudited Quarterly Financial Data | The Company’s unaudited quarterly financial information is as follows (in thousands, except share data): Year Ended December 31, 2017 First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 43,790 $ 75,036 $ 103,593 $ 140,097 Expenses 27,536 48,514 57,461 71,420 Operating income 16,254 26,522 46,132 68,677 Other income (expense) 3,626 1,414 (2,284 ) (17,958 ) Income before income taxes 19,880 27,936 43,848 50,719 Income tax benefit — — — (99 ) Net income $ 19,880 $ 27,936 $ 43,848 $ 50,818 Net income per common share: (1) Basic $ 0.10 $ 0.14 $ 0.22 $ 0.23 Diluted (2) $ 0.10 $ 0.14 $ 0.22 $ 0.23 Weighted-average shares outstanding: Basic 200,707,891 200,831,063 200,881,447 222,072,930 Diluted 201,309,251 201,224,172 201,460,915 222,917,611 Year Ended December 31, 2016 First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 18,273 $ 23,947 $ 26,234 $ 38,695 Expenses 71,356 172,157 45,887 29,324 Operating income (loss) (53,083 ) (148,210 ) (19,653 ) 9,371 Other income (expense) 1,682 (5,537 ) 417 (4,070 ) Income (loss) before income taxes (51,401 ) (153,747 ) (19,236 ) 5,301 Income tax expense — 101 5 — Net income (loss) $ (51,401 ) $ (153,848 ) $ (19,241 ) $ 5,301 Net income (loss) per common share: (1) Basic $ (0.42 ) $ (0.89 ) $ (0.10 ) $ 0.03 Diluted (2) $ (0.42 ) $ (0.89 ) $ (0.10 ) $ 0.03 Weighted-average shares outstanding: Basic 121,392,736 172,013,551 200,515,555 200,585,800 Diluted 121,392,736 172,013,551 200,515,555 201,254,678 1 The sum of net income (loss) per common share for the four quarters may not agree with the annual amount reported because the number used as the denominator for each quarterly computation is based on the weighted-average number of shares outstanding during that quarter whereas the annual computation is based upon an average for the entire year. 2 Common share equivalents were excluded from the calculation of net income (loss) per share as the inclusion of the common share equivalents was anti-dilutive. |
Organization and Summary of S43
Organization and Summary of Significant Accounting Policies (Details) $ in Thousands | 4 Months Ended | 9 Months Ended | 12 Months Ended | |||||
Dec. 31, 2015USD ($) | Sep. 30, 2017USD ($) | Dec. 31, 2017USD ($)segment | Dec. 31, 2016USD ($) | Aug. 31, 2015USD ($) | Jan. 01, 2017USD ($) | Jun. 14, 2016 | Aug. 31, 2014USD ($) | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||||||||
Number of operating segments | segment | 1 | |||||||
Cash and cash equivalents | $ 66,499 | $ 48,772 | $ 18,615 | $ 133,908 | ||||
Restricted cash included in cash held in escrow and other deposits | 0 | 0 | 18,219 | 0 | ||||
Cash, cash equivalents, restricted cash and cash held in escrow and other deposits | 66,499 | $ 48,772 | 36,834 | $ 133,908 | $ 34,753 | |||
Net cash flows, discount rate (percent) | 10.00% | 10.00% | ||||||
Remittance period | 30 days | |||||||
Cash held in escrow | $ (18,200) | (18,200) | ||||||
Accounts Payable, Current [Abstract] | ||||||||
Trade accounts payable | 624 | 786 | ||||||
Accrued well costs | 56,348 | 42,779 | ||||||
Accrued G&A | 6,017 | 4,292 | ||||||
Accrued LOE | 5,249 | 3,140 | ||||||
Accrued interest | 3,125 | 320 | ||||||
Accrued other | 3,309 | 1,136 | ||||||
Accounts payable and accrued expenses | 74,672 | 52,453 | ||||||
Concentration Risk [Line Items] | ||||||||
Cash held in escrow and other deposits | 0 | 18,248 | ||||||
Net cash used in investing activities | (84,937) | (1,040,306) | (617,916) | $ (269,569) | ||||
Full cost ceiling impairment | $ 125,230 | 0 | 215,223 | $ 16,000 | ||||
Accounting Standards Update 2016-18 | ||||||||
Concentration Risk [Line Items] | ||||||||
Net cash used in investing activities | $ 18,200 | $ (18,200) | ||||||
Accumulated Earnings (Deficit) | ||||||||
Concentration Risk [Line Items] | ||||||||
Adoption of ASU 2016-09 | $ (102) | |||||||
Accumulated Earnings (Deficit) | Accounting Standards Update 2016-09 | ||||||||
Concentration Risk [Line Items] | ||||||||
Adoption of ASU 2016-09 | $ 100 | |||||||
Customer concentration risk | Oil and Gas revenues | Company A | ||||||||
Concentration Risk [Line Items] | ||||||||
Risk percentage | 33.00% | |||||||
Customer concentration risk | Oil and Gas revenues | Company B | ||||||||
Concentration Risk [Line Items] | ||||||||
Risk percentage | 15.00% | 24.00% | 20.00% | 11.00% | ||||
Customer concentration risk | Oil and Gas revenues | Company C | ||||||||
Concentration Risk [Line Items] | ||||||||
Risk percentage | 17.00% | 20.00% | ||||||
Customer concentration risk | Oil and Gas revenues | Company D | ||||||||
Concentration Risk [Line Items] | ||||||||
Risk percentage | 16.00% | |||||||
Customer concentration risk | Oil and Gas revenues | Company E | ||||||||
Concentration Risk [Line Items] | ||||||||
Risk percentage | 13.00% | |||||||
Customer concentration risk | Oil and Gas revenues | Company F | ||||||||
Concentration Risk [Line Items] | ||||||||
Risk percentage | 57.00% | 65.00% | ||||||
Customer concentration risk | Oil and Gas revenues | Company G | ||||||||
Concentration Risk [Line Items] | ||||||||
Risk percentage | 12.00% | |||||||
Customer concentration risk | Accounts receivable | Company A | ||||||||
Concentration Risk [Line Items] | ||||||||
Risk percentage | 26.00% | 23.00% | ||||||
Customer concentration risk | Accounts receivable | Company B | ||||||||
Concentration Risk [Line Items] | ||||||||
Risk percentage | 23.00% | |||||||
Customer concentration risk | Accounts receivable | Company C | ||||||||
Concentration Risk [Line Items] | ||||||||
Risk percentage | 16.00% | |||||||
Customer concentration risk | Accounts receivable | Company D | ||||||||
Concentration Risk [Line Items] | ||||||||
Risk percentage | 11.00% | 43.00% | ||||||
Customer concentration risk | Accounts receivable | Company E | ||||||||
Concentration Risk [Line Items] | ||||||||
Risk percentage | 10.00% | |||||||
D-J Basin, Colorado | Greeley-Crescent Agreement | ||||||||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||||||||
Net cash flows, discount rate (percent) | 11.50% | |||||||
Concentration Risk [Line Items] | ||||||||
Cash held in escrow and other deposits | $ 18,200 | $ 18,200 |
Property and Equipment (Schedul
Property and Equipment (Schedule of Capitalized Costs) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Costs of proved properties: | ||
Producing and non-producing | $ 1,629,789 | $ 969,239 |
Less, accumulated depletion and full cost ceiling impairments | (659,205) | (545,157) |
Subtotal, proved properties, net | 970,584 | 424,082 |
Costs of wells in progress | 106,269 | 81,780 |
Costs of unproved properties and land, not subject to depletion: | ||
Unproved properties and land | 793,669 | 398,547 |
Costs of other property and equipment: | ||
Other property and equipment | 8,134 | 5,063 |
Less, accumulated depreciation | (2,080) | (736) |
Subtotal, other property and equipment, net | 6,054 | 4,327 |
Total property and equipment, net | 1,876,576 | 908,736 |
Unproved leasehold acquisition costs | ||
Costs of unproved properties and land, not subject to depletion: | ||
Unproved properties and land | 786,469 | 392,561 |
Unproved development costs | Land | ||
Costs of unproved properties and land, not subject to depletion: | ||
Unproved properties and land | $ 7,200 | $ 5,986 |
Property and Equipment (Narrati
Property and Equipment (Narrative) (Details) - USD ($) | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | |
Reserve Quantities [Line Items] | ||||
Full cost ceiling impairment | $ 125,230,000 | $ 0 | $ 215,223,000 | $ 16,000,000 |
Unproved properties impairment | 125,230,000 | 0 | 215,223,000 | 16,000,000 |
Unproved properties | ||||
Reserve Quantities [Line Items] | ||||
Unproved properties impairment | $ 0 | $ 0 | $ 18,900,000 | $ 15,400,000 |
Property and Equipment (Sched46
Property and Equipment (Schedule of Capitalized Overhead) (Details) - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | |
Property, Plant and Equipment [Abstract] | ||||
Capitalized overhead | $ 1,091 | $ 10,293 | $ 7,074 | $ 2,049 |
Property and Equipment (Sched47
Property and Equipment (Schedule of Costs Incurred) (Details) - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | |
Acquisition of property: | ||||
Unproved | $ 38,779 | $ 538,489 | $ 365,548 | $ 32,701 |
Proved | 51,085 | 139,154 | 152,363 | 51,400 |
Exploration costs | 23,697 | 0 | 43,154 | 146,892 |
Development costs | 17,742 | 460,875 | 87,782 | 4,957 |
Other property and equipment, and land | 395 | 4,397 | 7,506 | 741 |
Capitalized interest, capitalized G&A, and other | 4,415 | 26,677 | 18,744 | 7,051 |
Total costs Incurred | $ 136,113 | $ 1,169,592 | $ 675,097 | $ 243,742 |
Property and Equipment (Sched48
Property and Equipment (Schedule of Capitalized Costs Excluded from Amortization) (Details) - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | |
Property, Plant and Equipment [Line Items] | |||||
Total unevaluated costs | $ 23,068 | $ 563,526 | $ 223,907 | $ 456 | $ 1,568 |
Unevaluated costs, not subject to amortization | 812,525 | ||||
Unproved leasehold acquisition costs | |||||
Property, Plant and Equipment [Line Items] | |||||
Total unevaluated costs | 23,068 | 537,470 | 223,907 | 456 | 1,568 |
Unevaluated costs, not subject to amortization | 786,469 | ||||
Unproved development costs | |||||
Property, Plant and Equipment [Line Items] | |||||
Total unevaluated costs | $ 0 | 26,056 | $ 0 | $ 0 | $ 0 |
Unevaluated costs, not subject to amortization | $ 26,056 |
Acquisitions and Divestitures49
Acquisitions and Divestitures (Narrative) (Details) $ in Thousands | Nov. 01, 2017USD ($) | Sep. 30, 2017USD ($)well | Jun. 14, 2016USD ($)abbl / d | May 02, 2016USD ($)a | Feb. 04, 2016USD ($) | Nov. 30, 2017USD ($)abbl / d | Aug. 31, 2017USD ($)a | Mar. 31, 2017USD ($) | Oct. 31, 2016USD ($) | Apr. 30, 2016USD ($)aBoewell | Oct. 31, 2016acquisition | Dec. 31, 2015USD ($)Boe | Dec. 31, 2017USD ($)aBoe | Dec. 31, 2016USD ($)Boe | Aug. 31, 2015USD ($)Boe |
Business Acquisition [Line Items] | |||||||||||||||
Mineral acres, net | a | 30,200 | ||||||||||||||
Cash held in escrow and other deposits | $ 0 | $ 18,248 | |||||||||||||
Proceeds from sales of oil and gas properties and other | $ 0 | $ 93,573 | $ 25,350 | $ 6,239 | |||||||||||
Production of BOE (in Boe's) | Boe | 1,320,000 | 12,481,000 | 4,271,000 | 3,194,000 | |||||||||||
Disposal Group, disposed of by sale, not discontinued operations | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Mineral acres, net | a | 16,000 | ||||||||||||||
Proceeds from sales of oil and gas properties and other | $ 91,600 | ||||||||||||||
Assumption of liabilities | 22,200 | ||||||||||||||
Asset retirement obligations | 5,200 | ||||||||||||||
Disposal Group, disposed of by sale, not discontinued operations | Adams County, Colorado | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Mineral acres, net | a | 3,700 | ||||||||||||||
Number of vertical wells | well | 107 | ||||||||||||||
Cash held in escrow and other deposits | $ 500 | ||||||||||||||
Proceeds from sales of oil and gas properties and other | $ 24,700 | ||||||||||||||
Production of BOE (in Boe's) | Boe | 200 | ||||||||||||||
Greeley-Crescent Agreement II | D-J Basin, Colorado | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Total purchase price | $ 569,500 | $ 568,000 | |||||||||||||
Production of barrels of oil equivalent per day | bbl / d | 2,500 | ||||||||||||||
Cash | 568,100 | ||||||||||||||
Series of individually immaterial business acquisitions | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Total purchase price | $ 10,000 | $ 25,100 | $ 13,500 | ||||||||||||
Acquisitions of certain assets | acquisition | 4 | ||||||||||||||
Proved oil and gas properties | 8,600 | ||||||||||||||
Unproved oil and gas properties | $ 1,400 | ||||||||||||||
Greeley-Crescent Agreement | Wattenberg Field | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Mineral acres, net | a | 33,100 | ||||||||||||||
Total purchase price | $ 505,000 | ||||||||||||||
Mineral acres, gross | a | 72,000 | ||||||||||||||
Greeley-Crescent Agreement | D-J Basin, Colorado | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Mineral acres, net | a | 33,100 | ||||||||||||||
Total purchase price | $ 30,300 | $ 486,414 | |||||||||||||
Production of barrels of oil equivalent per day | bbl / d | 800 | ||||||||||||||
Cash | $ 6,300 | $ 485,141 | |||||||||||||
Number of vertical wells | well | 335 | ||||||||||||||
Number of horizontal wells | well | 7 | ||||||||||||||
Cash held in escrow and other deposits | $ 18,200 | $ 18,200 | |||||||||||||
Escrow balance returned to company | 11,400 | ||||||||||||||
Assumed liabilities | 24,000 | ||||||||||||||
Assumed asset retirement obligations | $ 20,900 | ||||||||||||||
Transaction costs | 500 | ||||||||||||||
Proved oil and gas properties | 132,903 | ||||||||||||||
Unproved oil and gas properties | $ 353,511 | ||||||||||||||
Pro forma revenue since acquisition date | 5,400 | ||||||||||||||
Pro forma net income since acquisition date | $ 4,700 | ||||||||||||||
Private party August 2017 | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Total purchase price | $ 22,600 | ||||||||||||||
Acres expected to be traded | a | 3,200 | ||||||||||||||
Mineral acres, gross | a | 1,000 | ||||||||||||||
Proved oil and gas properties | Greeley-Crescent Agreement II | D-J Basin, Colorado | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Total purchase price | 59,900 | ||||||||||||||
Proved oil and gas properties | Series of individually immaterial business acquisitions | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Total purchase price | 15,300 | ||||||||||||||
Proved oil and gas properties | Private party August 2017 | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Total purchase price | $ 6,700 | ||||||||||||||
Unproved properties | Greeley-Crescent Agreement II | D-J Basin, Colorado | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Total purchase price | $ 509,600 | ||||||||||||||
Unproved properties | Series of individually immaterial business acquisitions | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Total purchase price | 9,400 | ||||||||||||||
Unproved properties | Private party August 2017 | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Total purchase price | $ 15,900 | ||||||||||||||
Other assets and land | Series of individually immaterial business acquisitions | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Total purchase price | $ 400 |
Acquisitions and Divestitures50
Acquisitions and Divestitures (Schedule of Fair Value of Acquisition) (Details) - USD ($) $ in Thousands | Sep. 30, 2017 | Jun. 14, 2016 | Dec. 31, 2017 | Aug. 31, 2015 |
Business Acquisition [Line Items] | ||||
Net cash flows, discount rate (percent) | 10.00% | 10.00% | ||
D-J Basin, Colorado | Greeley-Crescent Agreement | ||||
Business Acquisition [Line Items] | ||||
Cash | $ 6,300 | $ 485,141 | ||
Net liabilities assumed, including asset retirement obligations | 1,273 | |||
Total consideration given | $ 30,300 | 486,414 | ||
Proved oil and gas properties | 132,903 | |||
Unproved oil and gas properties | 353,511 | |||
Total fair value of assets acquired | $ 486,414 | |||
Net cash flows, discount rate (percent) | 11.50% |
Acquisitions and Divestitures51
Acquisitions and Divestitures (Schedule of Pro Forma Results) (Details) - D-J Basin, Colorado - Greeley-Crescent Agreement $ / shares in Units, $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($)$ / shares | |
Business Acquisition [Line Items] | |
Oil and gas revenues | $ | $ 110,635 |
Net income | $ | $ (218,578) |
Net (loss) income per common share | |
Basic (in dollars per share) | $ / shares | $ (1.10) |
Diluted (in dollars per share) | $ / shares | $ (1.10) |
Depletion, depreciation and a52
Depletion, depreciation and accretion ("DD&A") (Details) Boe in Thousands, $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015USD ($)Boe$ / Boe | Dec. 31, 2017USD ($)Boe$ / Boe | Dec. 31, 2016USD ($)Boe$ / Boe | Aug. 31, 2015USD ($)Boe$ / Boe | |
Other Costs and Disclosures [Abstract] | ||||
Depletion of oil and gas properties | $ 18,371 | $ 109,287 | $ 45,193 | $ 65,158 |
Depreciation and accretion | 405 | 3,022 | 1,485 | 711 |
Total DDA Expense | $ 18,776 | $ 112,309 | $ 46,678 | $ 65,869 |
Production of BOE (in Boe's) | Boe | 1,320 | 12,481 | 4,271 | 3,194 |
Percentage of total reserves | 2.00% | 5.20% | 4.40% | 5.30% |
DDA expense per BOE (in dollars per BOE) | $ / Boe | 14.22 | 9 | 10.93 | 20.62 |
Asset Retirement Obligations (S
Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning asset retirement obligation | $ 16,458 | $ 13,400 |
Obligations incurred with development activities | 3,398 | 773 |
Obligations assumed with acquisitions | 24,696 | 2,230 |
Accretion expense | 1,554 | 1,046 |
Obligations discharged with asset retirements and divestitures | (14,332) | (4,739) |
Revisions in previous estimates | (152) | 3,748 |
Ending asset retirement obligation | 31,622 | 16,458 |
Less, current portion | (3,246) | (2,683) |
Non-current portion | $ 28,376 | $ 13,775 |
Revolving Credit Facility (Deta
Revolving Credit Facility (Details) | 12 Months Ended | ||
Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Sep. 01, 2017USD ($) | |
Line of Credit Facility [Line Items] | |||
Amount outstanding | $ 0 | $ 0 | |
Line of credit | Revolving credit facility | |||
Line of Credit Facility [Line Items] | |||
Total borrowing commitment | 500,000,000 | ||
Borrowing base | 400,000,000 | $ 225,000,000 | |
Amount outstanding | $ 0 | $ 0 | |
Average interest rate | 3.40% | 2.60% | |
Term of covenants | 5 years | ||
Maximum funded debt to EBITDAX | 4 | ||
Current ratio covenant | 1 | ||
Line of credit | Letter of credit | |||
Line of Credit Facility [Line Items] | |||
Amount outstanding | $ 500,000 |
Notes Payable (Details)
Notes Payable (Details) - USD ($) | Jun. 14, 2016 | Dec. 31, 2017 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | Nov. 30, 2017 |
Debt Instrument [Line Items] | |||||||||
Payments of Debt Issuance Costs | $ 0 | $ 13,145,000 | $ 5,159,000 | $ 2,316,000 | |||||
Senior notes | Six Point Two Five Percent Senior Notes Due 2025 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Face value of promissory note | $ 550,000,000 | ||||||||
Debt instrument stated interest rate (percent) | 6.25% | ||||||||
Debt instrument effective interest rate (percent) | 6.60% | ||||||||
Senior notes | 9% Senior notes due 2021 | |||||||||
Debt Instrument [Line Items] | |||||||||
Face value of promissory note | $ 80,000,000 | $ 80,000,000 | $ 80,000,000 | 80,000,000 | |||||
Debt instrument stated interest rate (percent) | 9.00% | ||||||||
Proceeds from sale of Senior Notes | $ 75,200,000 | $ 538,100,000 | |||||||
Payments of Debt Issuance Costs | $ 11,900,000 | ||||||||
Redemption price (percent) | 100.00% | ||||||||
Debt issuance costs | $ 4,800,000 | ||||||||
Required makewhole payment | 8,200,000 | $ 8,200,000 | $ 8,200,000 | ||||||
Write off of deferred debt issuance cost | $ 3,600,000 | ||||||||
Senior notes | 9% Senior notes due 2021 | 2020 | |||||||||
Debt Instrument [Line Items] | |||||||||
Redemption price (percent) | 104.688% | ||||||||
Senior notes | 9% Senior notes due 2021 | 2021 | |||||||||
Debt Instrument [Line Items] | |||||||||
Redemption price (percent) | 103.125% | ||||||||
Senior notes | 9% Senior notes due 2021 | 2022 | |||||||||
Debt Instrument [Line Items] | |||||||||
Redemption price (percent) | 101.563% | ||||||||
Senior notes | 9% Senior notes due 2021 | 2023 | |||||||||
Debt Instrument [Line Items] | |||||||||
Redemption price (percent) | 100.00% | ||||||||
Senior notes | 9% Senior notes due 2021 | Prior to December 1, 2020 | |||||||||
Debt Instrument [Line Items] | |||||||||
Redemption price (percent) | 106.25% | ||||||||
Amount of principal that can be redeemed (percent) | 35.00% |
Commodity Derivative Instrume56
Commodity Derivative Instruments (Schedule of Commodity Derivative Contracts) (Details) | 2 Months Ended | 12 Months Ended |
Feb. 21, 2018bbl / d$ / bbl | Dec. 31, 2017MMBTU / dbbl / d$ / bbl$ / MMBTU | |
Crude Oil | Jan 1, 2018 - Dec 31, 2018 | Collar | ||
Derivatives, Fair Value [Line Items] | ||
Average Volume (BBl's per day) | bbl / d | 1,000 | |
Floor Price | 40 | |
Ceiling Price | 57.50 | |
Crude Oil | Jan 1, 2018 - Dec 31, 2018 | Collar | ||
Derivatives, Fair Value [Line Items] | ||
Average Volume (BBl's per day) | bbl / d | 1,000 | |
Floor Price | 40 | |
Ceiling Price | 57.75 | |
Crude Oil | Jan 1, 2018 - Dec 31, 2018 | Collar | ||
Derivatives, Fair Value [Line Items] | ||
Average Volume (BBl's per day) | bbl / d | 500 | |
Floor Price | 40 | |
Ceiling Price | 57.50 | |
Crude Oil | Jan 1, 2018 - Dec 31, 2018 | Collar | ||
Derivatives, Fair Value [Line Items] | ||
Average Volume (BBl's per day) | bbl / d | 2,500 | |
Floor Price | 45 | |
Ceiling Price | 58 | |
Crude Oil | Jan 1, 2018 - Dec 31, 2018 | Collar | ||
Derivatives, Fair Value [Line Items] | ||
Average Volume (BBl's per day) | bbl / d | 2,500 | |
Floor Price | 45 | |
Ceiling Price | 64.55 | |
Crude Oil | Jan 1, 2018 - Dec 31, 2018 | Collar | ||
Derivatives, Fair Value [Line Items] | ||
Average Volume (BBl's per day) | bbl / d | 1,000 | |
Floor Price | 44.50 | |
Ceiling Price | 65 | |
Crude Oil | Jan 1, 2018 - Dec 31, 2018 | Collar | ||
Derivatives, Fair Value [Line Items] | ||
Average Volume (BBl's per day) | bbl / d | 1,500 | |
Floor Price | 44.50 | |
Ceiling Price | 65 | |
Natural Gas | Jan 1, 2018 - Dec 31, 2018 | Collar | ||
Derivatives, Fair Value [Line Items] | ||
Average Volumes (MMBtu per day) | MMBTU / d | 10,000 | |
Floor Price | $ / MMBTU | 2.25 | |
Ceiling Price | $ / MMBTU | 2.82 | |
Natural Gas | Jan 1, 2018 - Dec 31, 2018 | Collar | ||
Derivatives, Fair Value [Line Items] | ||
Average Volumes (MMBtu per day) | MMBTU / d | 5,000 | |
Floor Price | $ / MMBTU | 2.25 | |
Ceiling Price | $ / MMBTU | 2.81 | |
Subsequent event | Propane | Feb 1, 2018 - Dec 31, 2018 | Swap | ||
Derivatives, Fair Value [Line Items] | ||
Average Volume (BBl's per day) | bbl / d | 1,000 | |
Average fixed price (in dollars per gallon) | 0.8 |
Commodity Derivative Instrume57
Commodity Derivative Instruments (Schedule of Fair Value of Derivatives) (Details) - Commodity derivative contracts - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Current assets | ||
Derivatives, Fair Value [Line Items] | ||
Derivative asset, Gross Amount Recognized | $ 1,960 | $ 2,045 |
Derivative asset, Gross Amounts Offset in the Balance Sheet | (1,960) | (1,748) |
Derivative asset, Net | 0 | 297 |
Non-current assets | ||
Derivatives, Fair Value [Line Items] | ||
Derivative asset, Gross Amount Recognized | 0 | 0 |
Derivative asset, Gross Amounts Offset in the Balance Sheet | 0 | 0 |
Derivative asset, Net | 0 | 0 |
Current liabilities | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liability, Gross Amount Recognized | 9,825 | 4,622 |
Derivative liability, Gross Amounts Offset in the Balance Sheet | (1,960) | (1,748) |
Derivative liability, Net | 7,865 | 2,874 |
Non-current liabilities | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liability, Gross Amount Recognized | 0 | 0 |
Derivative liability, Gross Amounts Offset in the Balance Sheet | 0 | 0 |
Derivative liability, Net | $ 0 | $ 0 |
Commodity Derivative Instrume58
Commodity Derivative Instruments (Schedule of Gain (Loss) Recognized in Statements of Operations) (Details) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Aug. 31, 2015USD ($)$ / bblbbl | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||
Realized gain (loss) on commodity derivatives | $ 1,577 | $ 39 | $ 2,355 | $ 30,466 |
Unrealized gain (loss) on commodity derivatives | 4,905 | (4,265) | (10,105) | 1,790 |
Total gain (loss) | $ 6,482 | $ (4,226) | $ (7,750) | $ 32,256 |
Average price of liquidated swaps (in dollars per share) | $ / bbl | 82.79 | |||
Number of barrels liquidated (in bbl) | bbl | 372,500 | |||
Early liquidation | $ 20,500 |
Commodity Derivative Instrume59
Commodity Derivative Instruments (Schedule of Hedge Realized Gains (Losses)) (Details) - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||
Monthly settlement | $ 2,331 | $ 1,062 | $ 4,396 | $ 11,212 |
Previously incurred premiums attributable to settled commodity contracts | (754) | (1,023) | (2,041) | (1,255) |
Early liquidation | 0 | 0 | 0 | 20,509 |
Total realized gain (loss) | $ 1,577 | $ 39 | $ 2,355 | $ 30,466 |
Commodity Derivative Instrume60
Commodity Derivative Instruments (Narrative) (Details) | Dec. 31, 2017counterparty |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |
Number of counterparties | 6 |
Credit facility syndicate | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |
Number of counterparties | 3 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Level 2 | Estimate of Fair Value Measurement | ||
Financial Liabilities: | ||
Notes payable | $ 564,100 | |
Recurring | ||
Financial Assets: | ||
Commodity derivative asset | 0 | $ 297 |
Financial Liabilities: | ||
Commodity derivative liability | 7,865 | 2,874 |
Recurring | Level 1 | ||
Financial Assets: | ||
Commodity derivative asset | 0 | 0 |
Financial Liabilities: | ||
Commodity derivative liability | 0 | 0 |
Recurring | Level 2 | ||
Financial Assets: | ||
Commodity derivative asset | 0 | 297 |
Financial Liabilities: | ||
Commodity derivative liability | 7,865 | 2,874 |
Recurring | Level 3 | ||
Financial Assets: | ||
Commodity derivative asset | 0 | 0 |
Financial Liabilities: | ||
Commodity derivative liability | $ 0 | $ 0 |
Interest Expense (Details)
Interest Expense (Details) - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | |
Debt Instrument [Line Items] | ||||
Amortization of debt issuance costs | $ 431 | $ 3,084 | $ 1,638 | $ 853 |
Debt extinguishment costs | 0 | 11,842 | 0 | 0 |
Less: interest capitalized | (1,092) | (15,124) | (5,732) | (3,384) |
Interest expense, net | 0 | 11,842 | 0 | 245 |
Revolving credit facility | Revolving credit facility | ||||
Debt Instrument [Line Items] | ||||
Interest from debt | 661 | 2,004 | 154 | 2,776 |
Notes payable | ||||
Debt Instrument [Line Items] | ||||
Interest from debt | $ 0 | $ 10,036 | $ 3,940 | $ 0 |
Shareholders' Equity (Common St
Shareholders' Equity (Common Stock Transactions) (Details) - USD ($) $ / shares in Units, $ in Thousands | 1 Months Ended | 4 Months Ended | 12 Months Ended | ||
Nov. 30, 2017 | Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | |
Classes of stock | |||||
Preferred stock, shares authorized | 10,000,000 | 10,000,000 | |||
Preferred stock, par value (in dollars per share) | $ 0.01 | $ 0.01 | |||
Preferred stock, shares issued | 0 | 0 | |||
Preferred stock, shares outstanding | 0 | ||||
Common stock, shares authorized | 300,000,000 | 300,000,000 | |||
Common stock, par value (in dollars per share) | $ 0.001 | $ 0.001 | |||
Common stock, shares issued | 241,365,522 | 200,647,572 | |||
Common stock, shares outstanding | 241,365,522 | 200,647,572 | |||
Sale of common stock | |||||
Number of common shares sold (in shares) | 35,000,000 | 0 | 40,250,000 | 90,275,000 | 18,613,952 |
Offering price per common share (in dollars per share) | $ 0 | $ 6.0193852119 | $ 10.75 | ||
Net proceeds | $ 0 | $ 312,170 | $ 543,400 | $ 190,845 | |
Common stock issued for acquisition of mineral interests | |||||
Number of common shares issued for mineral property leases (in shares) | 37,051 | 0 | 0 | 995,672 | |
Business acquisition, shares issued (in shares) | 4,418,413 | 0 | 0 | 4,648,136 | |
Number of common shares sold (in shares) | 4,455,464 | 0 | 0 | 5,643,808 | |
Average price per common share (in dollars per share) | $ 11.28 | $ 0 | $ 0 | $ 10.67 | |
Aggregate value of shares issued | $ 50,265 | $ 0 | $ 0 | $ 60,221 | |
IPO | |||||
Sale of common stock | |||||
Offering price per common share (in dollars per share) | $ 7.76 | ||||
Over-Allotment option | |||||
Sale of common stock | |||||
Number of common shares sold (in shares) | 5,250,000 | ||||
Over-allotment option, exercise period | 30 days |
Weighted-Average Shares Outst64
Weighted-Average Shares Outstanding (Details) - shares | 3 Months Ended | 4 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||||||||||
Weighted-average shares outstanding - basic (in shares) | 222,072,930 | 200,881,447 | 200,831,063 | 200,707,891 | 200,585,800 | 200,515,555 | 172,013,551 | 121,392,736 | 107,789,554 | 206,167,506 | 173,774,035 | 94,628,665 |
Potentially dilutive common shares from: | ||||||||||||
Stock options (in shares) | 0 | 417,809 | 0 | 672,493 | ||||||||
Restricted stock units and stock bonus shares (in shares) | 0 | 158,236 | 18,111 | |||||||||
Performance-vested stock units (in shares) | 0 | |||||||||||
Weighted-average shares outstanding - diluted (in shares) | 222,917,611 | 201,460,915 | 201,224,172 | 201,309,251 | 201,254,678 | 200,515,555 | 172,013,551 | 121,392,736 | 107,789,554 | 206,743,551 | 173,774,035 | 95,319,269 |
Potentially dilutive common shares having anti-dilutive effect on earnings per share (in shares) | 5,971,867 | 5,895,166 | 7,370,346 | 2,930,500 | ||||||||
Stock options | ||||||||||||
Potentially dilutive common shares from: | ||||||||||||
Potentially dilutive common shares having anti-dilutive effect on earnings per share (in shares) | 5,056,000 | 4,657,834 | 6,001,500 | 2,785,500 | ||||||||
Performance stock units | ||||||||||||
Potentially dilutive common shares from: | ||||||||||||
Potentially dilutive common shares having anti-dilutive effect on earnings per share (in shares) | 0 | 285,448 | 890,336 | 0 | ||||||||
Restricted stock units and stock bonus shares | ||||||||||||
Potentially dilutive common shares from: | ||||||||||||
Potentially dilutive common shares having anti-dilutive effect on earnings per share (in shares) | 915,867 | 951,884 | 478,510 | 145,000 |
Stock-Based Compensation (Narra
Stock-Based Compensation (Narrative) (Details) - USD ($) $ in Thousands | 1 Months Ended | 4 Months Ended | 12 Months Ended | ||
Mar. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Remaining vesting phase | 2 years 3 months 29 days | ||||
Unrecognized compensation expense | $ 9,697 | ||||
Minimum | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period | 3 years 8 months 12 days | 3 years | 3 years | ||
Maximum | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period | 5 years | 5 years | 5 years | ||
2015 Equity Incentive Plan | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Number of shares authorized | 4,500,000 | ||||
Number of shares available for grant | 110,158 | ||||
Number of shares reserved for future vestings | 951,884 | ||||
Stock bonus plan | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Number of shares authorized | 2,000,000 | ||||
Restricted stock | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Remaining vesting phase | 2 years 2 months 29 days | ||||
Granted (shares) | 919,604 | 681,568 | 464,533 | 547,699 | |
Unrecognized compensation expense | $ 7,113 | ||||
Restricted stock | Minimum | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period | 3 years | ||||
Restricted stock | Maximum | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period | 5 years | ||||
Performance stock units | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period | 3 years | ||||
Granted (shares) | 473,374 | 490,713 | |||
Fair value of stock granted | $ 5,100 | $ 4,000 | |||
Unrecognized compensation expense | $ 5,000 | ||||
Performance stock units | Minimum | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Performance multiplier (percent) | 0.00% | ||||
Performance stock units | Maximum | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Performance multiplier (percent) | 200.00% |
Stock-Based Compensation (Stock
Stock-Based Compensation (Stock Based Compensation Expense) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||
Total stock-based compensation | $ 12,991 | $ 10,696 |
Less: stock-based compensation capitalized | (1,766) | (1,205) |
Total stock-based compensation expense | 11,225 | 9,491 |
Stock options | ||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||
Total stock-based compensation | 5,076 | 5,417 |
Performance stock units | ||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||
Total stock-based compensation | 2,938 | 1,047 |
Restricted stock units and stock bonus shares | ||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||
Total stock-based compensation | $ 4,977 | $ 4,232 |
Stock-Based Compensation (Non-Q
Stock-Based Compensation (Non-Qualified Stock Options Granted) (Details) - USD ($) $ / shares in Units, $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Number of options to purchase common shares | 1,142,500 | 0 | 1,067,500 | 2,377,500 |
Weighted-average exercise price (in dollars per share) | $ 10.84 | $ 0 | $ 7.19 | $ 11.55 |
Term | 10 years | 10 years | 10 years | |
Fair Value | $ 6,591 | $ 3,860 | $ 13,266 | |
Minimum | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting Period | 3 years 8 months 12 days | 3 years | 3 years | |
Maximum | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting Period | 5 years | 5 years | 5 years |
Stock-Based Compensation (Sto68
Stock-Based Compensation (Stock Option Assumptions) (Details) | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Expected term | 6 years 6 months | 6 years 4 months 23 days | 6 years 6 months | |
Expected volatility (percent) | 53.00% | 55.00% | 47.00% | |
Risk-free rate, minimum (percent) | 1.80% | 0.00% | 1.25% | 1.40% |
Risk-free rate, maximum (percent) | 2.00% | 0.00% | 2.00% | 2.00% |
Expected dividend yield (percent) | 0.00% | 0.00% | 0.00% | |
Performance stock units | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Expected term | 2 years 10 months 7 days | 2 years 8 months 12 days | ||
Expected volatility (percent) | 59.00% | 58.00% | ||
Weighted-average risk free rate (percent) | 1.34% | 0.87% |
Stock-Based Compensation (Sto69
Stock-Based Compensation (Stock Option Activity) (Details) - USD ($) $ / shares in Units, $ in Thousands | 4 Months Ended | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | |
Summary of activity for stock options (in shares): | |||||
Outstanding, Beginning balance (shares) | 4,176,500 | 6,001,500 | 5,056,000 | 2,167,000 | |
Granted (shares) | 1,142,500 | 0 | 1,067,500 | 2,377,500 | |
Exercised (shares) | (188,000) | (187,666) | (20,000) | (258,000) | |
Forfeited (shares) | (15,000) | (136,000) | (102,000) | (110,000) | |
Expired (shares) | (60,000) | (41,000) | 0 | ||
Outstanding, Ending balance (shares) | 5,056,000 | 5,636,834 | 6,001,500 | 4,176,500 | 2,167,000 |
Outstanding, Exercisable at end of period (shares) | 3,203,045 | ||||
Weighted Average Exercise Price (in dollars per share): | |||||
Beginning balance, Weighted average exercise price (in dollars per share) | $ 9.29 | $ 9.27 | $ 9.71 | $ 5.94 | |
Granted, weighted average exercise price (in dollars per share) | 10.84 | 0 | 7.19 | 11.55 | |
Exercised, weighted average exercise price (in dollars per share) | 6.56 | 3.95 | 3.19 | 3.81 | |
Forfeited, weighted average exercise price (in dollars per share) | 11.68 | 10.97 | 10.40 | 4.97 | |
Expired, weighted average exercise price (in dollars per share) | 11.74 | 11.98 | 0 | ||
Ending balance, Weighted average exercise price (in dollars per share) | $ 9.71 | 9.38 | $ 9.27 | $ 9.29 | $ 5.94 |
Outstanding, exercisable, weighted average exercise price (in dollars per share) | $ 9.08 | ||||
Weighted-Average Remaining Contractual Life | |||||
Weighted average remaining contractual life | 8 years 7 months 25 days | 7 years 4 days | 8 years | 8 years 7 months 6 days | 8 years |
Outstanding, Exercisable | 6 years 5 months 23 days | ||||
Aggregate Intrinsic Value: | |||||
Beginning balance, aggregate intrinsic value | $ 4,351 | $ 4,806 | $ 6,515 | $ 8,187 | $ 16,287 |
Exercised, aggregate intrinsic value | 981 | 976 | 117 | 2,103 | |
Ending balance, aggregate intrinsic value | $ 4,351 | 4,806 | $ 6,515 | $ 8,187 | $ 16,287 |
Outstanding, Exercisable at end of period | $ 3,587 |
Stock-Based Compensation (Issue
Stock-Based Compensation (Issued and Outstanding Option Details) (Details) - $ / shares | 4 Months Ended | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Outstanding options (in shares) | 5,636,834 | ||||
Weighted average exercise price (in dollars per share) | $ 9.71 | $ 9.38 | $ 9.27 | $ 9.29 | $ 5.94 |
Weighted-Average Remaining Contractual Life, Outstanding Options | 8 years 7 months 25 days | 7 years 4 days | 8 years | 8 years 7 months 6 days | 8 years |
Exercisable options (in shares) | 3,203,045 | ||||
Exercisable options, weighted average exercise price (in dollars per share) | $ 9.08 | ||||
Weighted-Average Remaining Contractual Life, Exercisable Options | 6 years 5 months 23 days | ||||
$5.00 | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Exercise price range maximum (in dollars per share) | $ 5 | ||||
Outstanding options (in shares) | 454,000 | ||||
Weighted average exercise price (in dollars per share) | $ 3.45 | ||||
Weighted-Average Remaining Contractual Life, Outstanding Options | 3 years 6 months 7 days | ||||
Exercisable options (in shares) | 454,000 | ||||
Exercisable options, weighted average exercise price (in dollars per share) | $ 3.45 | ||||
Weighted-Average Remaining Contractual Life, Exercisable Options | 3 years 6 months 7 days | ||||
$5.00 - $6.99 | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Exercise price range minimum (in dollars per share) | $ 5 | ||||
Exercise price range maximum (in dollars per share) | $ 6.99 | ||||
Outstanding options (in shares) | 1,012,000 | ||||
Weighted average exercise price (in dollars per share) | $ 6.38 | ||||
Weighted-Average Remaining Contractual Life, Outstanding Options | 6 years 11 months 1 day | ||||
Exercisable options (in shares) | 558,400 | ||||
Exercisable options, weighted average exercise price (in dollars per share) | $ 6.45 | ||||
Weighted-Average Remaining Contractual Life, Exercisable Options | 5 years 9 months 15 days | ||||
$7.00 - $10.99 | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Exercise price range minimum (in dollars per share) | $ 7 | ||||
Exercise price range maximum (in dollars per share) | $ 10.99 | ||||
Outstanding options (in shares) | 1,548,834 | ||||
Weighted average exercise price (in dollars per share) | $ 9.36 | ||||
Weighted-Average Remaining Contractual Life, Outstanding Options | 7 years 5 months 1 day | ||||
Exercisable options (in shares) | 708,245 | ||||
Exercisable options, weighted average exercise price (in dollars per share) | $ 9.53 | ||||
Weighted-Average Remaining Contractual Life, Exercisable Options | 7 years 4 days | ||||
$11.00 - $13.46 | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Exercise price range minimum (in dollars per share) | $ 11 | ||||
Exercise price range maximum (in dollars per share) | $ 13.46 | ||||
Outstanding options (in shares) | 2,622,000 | ||||
Weighted average exercise price (in dollars per share) | $ 11.58 | ||||
Weighted-Average Remaining Contractual Life, Outstanding Options | 7 years 4 months 28 days | ||||
Exercisable options (in shares) | 1,482,400 | ||||
Exercisable options, weighted average exercise price (in dollars per share) | $ 11.59 | ||||
Weighted-Average Remaining Contractual Life, Exercisable Options | 7 years 4 months 21 days |
Stock-Based Compensation (Restr
Stock-Based Compensation (Restricted Stock and Performance-vested Stock Units Activity) (Details) - $ / shares | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | |
Restricted stock | ||||
Number of Shares | ||||
Nonvested, Beginning balance (shares) | 632,500 | 890,336 | 915,867 | 293,333 |
Granted (shares) | 919,604 | 681,568 | 464,533 | 547,699 |
Vested (shares) | (636,237) | (455,772) | (424,483) | (208,532) |
Forfeited (shares) | 0 | (28,746) | (65,581) | 0 |
Nonvested, Ending balance (shares) | 915,867 | 1,087,386 | 890,336 | 632,500 |
Weighted Average Grant Date Fair Value (in dollars per share) | ||||
Nonvested, beginning balance (in dollars per share) | $ 10.93 | $ 9.55 | $ 10.63 | $ 10.60 |
Granted (in dollars per share) | 10.08 | 8.29 | 7.66 | 11.17 |
Vested (in dollars per share) | 10.13 | 9.21 | 9.92 | 11.09 |
Forfeited (in dollars per share) | 0 | 9.74 | 8.99 | 0 |
Nonvested, ending balance (in dollars per share) | $ 10.63 | $ 8.89 | $ 9.55 | $ 10.93 |
Performance stock units | ||||
Number of Shares | ||||
Nonvested, Beginning balance (shares) | 478,510 | 0 | ||
Granted (shares) | 473,374 | 490,713 | ||
Vested (shares) | 0 | 0 | ||
Forfeited (shares) | 0 | (12,203) | ||
Nonvested, Ending balance (shares) | 0 | 951,884 | 478,510 | |
Weighted Average Grant Date Fair Value (in dollars per share) | ||||
Nonvested, beginning balance (in dollars per share) | $ 8.09 | $ 0 | ||
Granted (in dollars per share) | 10.79 | 8.10 | ||
Vested (in dollars per share) | 0 | 0 | ||
Forfeited (in dollars per share) | 0 | 8.22 | ||
Nonvested, ending balance (in dollars per share) | $ 0 | $ 9.44 | $ 8.09 |
Defined Contribution Plan (Deta
Defined Contribution Plan (Details) - USD ($) $ in Millions | Jan. 01, 2017 | Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 |
Retirement Benefits [Abstract] | |||||
Employer matching contribution percent of employees' gross pay | 100.00% | ||||
Percent of employer matching contribution | 6.00% | ||||
Contribution cost recognized | $ 0.1 | $ 0.7 | $ 0.4 | $ 0.1 |
Income Taxes (Schedule of Compo
Income Taxes (Schedule of Components of Income Taxes) (Details) - USD ($) $ in Thousands | 3 Months Ended | 4 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | |
Current: | ||||||||||||
Federal | $ 0 | $ (99) | $ 106 | $ (4) | ||||||||
State | 0 | 0 | 0 | (111) | ||||||||
Total current income tax expense (benefit) | 0 | (99) | 106 | (115) | ||||||||
Deferred: | ||||||||||||
Federal | (45,332) | 48,631 | (74,099) | 10,820 | ||||||||
State | (4,074) | 4,371 | (6,651) | 972 | ||||||||
Total deferred income tax (benefit) expense | (49,406) | 53,002 | (80,750) | 11,792 | ||||||||
Valuation allowance | 39,399 | (53,002) | 80,750 | 0 | ||||||||
Income tax expense (benefit) | $ (99) | $ 0 | $ 0 | $ 0 | $ 0 | $ 5 | $ 101 | $ 0 | $ (10,007) | $ (99) | $ 106 | $ 11,677 |
Income Taxes (Schedule of Recon
Income Taxes (Schedule of Reconciliation of Income Taxes) (Details) - USD ($) $ in Thousands | 3 Months Ended | 4 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | |
Income Tax Disclosure [Abstract] | ||||||||||||
Federal income tax at statutory rate | $ (45,200) | $ 48,410 | $ (74,489) | $ 10,105 | ||||||||
State income taxes, net of federal tax | (4,062) | 4,371 | (6,685) | 908 | ||||||||
Statutory depletion | (150) | (159) | (287) | (451) | ||||||||
Stock-based compensation | 0 | 50 | 383 | 92 | ||||||||
Non-deductible compensation | 0 | 0 | 0 | 850 | ||||||||
Impact of tax reform, net of valuation allowance | (99) | |||||||||||
Valuation allowance | 39,399 | (53,002) | 80,750 | 0 | ||||||||
Other | 6 | 330 | 434 | 173 | ||||||||
Income tax expense (benefit) | $ (99) | $ 0 | $ 0 | $ 0 | $ 0 | $ 5 | $ 101 | $ 0 | $ (10,007) | $ (99) | $ 106 | $ 11,677 |
Effective rate expressed as a percentage | 8.00% | 0.00% | 0.00% | 39.00% |
Income Taxes (Schedule of Defer
Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Income Tax Disclosure [Abstract] | ||
Net operating loss carryforward | $ 43,283 | $ 47,462 |
Stock-based compensation | 5,237 | 5,576 |
Basis of oil and gas properties | (5,011) | |
Basis of oil and gas properties | 62,707 | |
Statutory depletion | 2,795 | 4,028 |
Unrealized loss on commodity derivative | 1,939 | 1,334 |
Other | (615) | (958) |
Deferred tax assets, gross | 47,628 | 120,149 |
Valuation allowance on tax assets | (47,628) | (120,149) |
Deferred tax asset (liability), net | $ 0 | $ 0 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Operating Loss Carryforwards [Line Items] | |
Deferred tax assets expense (benefit) | $ 24 |
Decrease in AMT deferred tax assets | 0.1 |
Domestic tax authority | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carryforward | 175.5 |
Valuation Allowance | Accounting Standard Update 2016-09 | |
Operating Loss Carryforwards [Line Items] | |
Deferred tax assets expense (benefit) | (4.5) |
NOL | Accounting Standard Update 2016-09 | |
Operating Loss Carryforwards [Line Items] | |
Deferred tax assets expense (benefit) | $ (4.5) |
Other Commitments and Conting77
Other Commitments and Contingencies (Narrative) (Details) | 1 Months Ended | 4 Months Ended | 12 Months Ended | |||
Sep. 30, 2016 | Jul. 31, 2016USD ($) | Dec. 31, 2015USD ($)counterparty | Dec. 31, 2017USD ($)MMcfe | Dec. 31, 2016USD ($) | Aug. 31, 2015USD ($)counterparty | |
Long-term Purchase Commitment [Line Items] | ||||||
Transport agreement number of counterparties | counterparty | 2 | 3 | ||||
Unused commitment charge | $ | $ 2,802,000 | $ 669,000 | $ 597,000 | $ 0 | ||
Rent expense | $ | $ 300,000 | $ 1,100,000 | $ 1,000,000 | $ 300,000 | ||
Agreement One | ||||||
Long-term Purchase Commitment [Line Items] | ||||||
Processing plant capacity (in MMcfe) | MMcfe | 200 | |||||
Share of the commitment (in MMcfe) | MMcfe | 46.4 | |||||
Commitment term | 7 years | |||||
Agreement Two | ||||||
Long-term Purchase Commitment [Line Items] | ||||||
Processing plant capacity (in MMcfe) | MMcfe | 200 | |||||
Share of the commitment (in MMcfe) | MMcfe | 43.8 | |||||
Commitment term | 7 years | |||||
Denver | ||||||
Long-term Purchase Commitment [Line Items] | ||||||
Lease term | 65 months | |||||
Monthly rent expense | $ | $ 62,000 | |||||
Greeley, Colorado | ||||||
Long-term Purchase Commitment [Line Items] | ||||||
Monthly rent expense | $ | $ 7,500 |
Other Commitments and Conting78
Other Commitments and Contingencies (Volume Commitments) (Details) bbl / yr in Thousands | Dec. 31, 2017bbl / yr |
Commitments and Contingencies Disclosure [Abstract] | |
2,018 | 4,485 |
2,019 | 5,167 |
2,020 | 4,003 |
2,021 | 1,672 |
2,022 | 0 |
Thereafter | 0 |
Total | 15,327 |
Other Commitments and Conting79
Other Commitments and Contingencies (Minimum Lease Payments Under Non-Cancelable Operating Leases) (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Vehicles Leases | |
Operating Leased Assets [Line Items] | |
Capital lease, 2018 | $ 76 |
Capital lease, 2019 | 37 |
Capital lease, 2020 | 37 |
Capital lease 2021 | 63 |
Capital lease 2022 | 0 |
Capital lease, thereafter | 0 |
Total minimum capital lease payments | 213 |
Less: Amount representing estimated executory cost | (16) |
Net minimum lease payments | 197 |
Less: Amount representing interest | (24) |
Present value of net minimum lease payments | 173 |
Vehicles Leases | Accounts payable and accrued expenses | |
Operating Leased Assets [Line Items] | |
Present value of net minimum lease payments | 63 |
Vehicles Leases | Other liabilities | |
Operating Leased Assets [Line Items] | |
Present value of net minimum lease payments | 110 |
Office Leases | |
Operating Leased Assets [Line Items] | |
Operating lease, 2018 | 840 |
Operating lease, 2019 | 859 |
Operating lease, 2020 | 878 |
Operating lease, 2021 | 875 |
Operating lease, 2022 | 477 |
Operating lease, thereafter | 0 |
Total minimum operating lease payments | $ 3,929 |
Supplemental Schedule of Info80
Supplemental Schedule of Information to the Statements of Cash Flows (Details) - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | |
Supplemental cash flow information: | ||||
Interest paid | $ 683 | $ 9,235 | $ 3,779 | $ 2,817 |
Income taxes paid | (150) | 0 | 106 | 202 |
Non-cash investing and financing activities: | ||||
Accrued well costs as of period end | 31,414 | 56,348 | 42,779 | 33,071 |
Assets acquired in exchange for common stock | 50,265 | 0 | 0 | 60,221 |
Asset retirement obligations incurred with development activities | 1,819 | 3,398 | 773 | 7,051 |
Asset retirement obligations assumed with acquisitions | 0 | 24,696 | 2,230 | 0 |
Obligations discharged with asset retirements and divestitures | 0 | (14,332) | (4,739) | 0 |
Net changes in operating assets and liabilities: | ||||
Accounts receivable | 5,696 | (72,518) | (13,063) | 3,446 |
Accounts payable and accrued expenses | 3,954 | 5,823 | 2,283 | (2,307) |
Revenue payable | (5,441) | 47,345 | 2,254 | 4,557 |
Production taxes payable | 3,631 | 33,311 | (7,095) | 5,121 |
Other | (1,037) | (1,131) | (790) | (359) |
Changes in operating assets and liabilities | $ 6,803 | $ 12,830 | $ (16,411) | $ 10,458 |
Unaudited Oil and Gas Reserve81
Unaudited Oil and Gas Reserves Information (Schedule of Net Ownership Interests in Estimated Quantities of Proved Developed and Undeveloped Oil and Gas Reserve Quantities and Changes During Fiscal Year) (Details) bbl in Thousands, Mcf in Thousands, Boe in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015BoeMcfbbl | Dec. 31, 2017BoeMcfbbl | Dec. 31, 2016BoeMcfbbl | Aug. 31, 2015BoeMcfbbl | |
Oil (MBbl) | ||||
Proved developed and undeveloped reserves: | ||||
Beginning Balance | 27,692 | 38,032 | 26,379 | 16,324 |
Revision of previous estimates | (10,917) | (3,038) | (7,788) | (1,699) |
Purchase of reserves in place | 4,380 | 12,150 | 23,141 | 4,201 |
Extensions, discoveries, and other additions | 8,263 | 28,736 | 1,457 | 11,465 |
Sale of reserves in place | (2,297) | (660) | (2,900) | (629) |
Production | (742) | (5,824) | (2,257) | (1,970) |
Ending Balance | 26,379 | 69,396 | 38,032 | 27,692 |
Proved developed reserves: | ||||
Proved developed reserves | 8,410 | 26,552 | 7,435 | 7,393 |
Proved undeveloped reserves: | ||||
Proved undeveloped reserves | 17,969 | 42,844 | 30,597 | 20,299 |
Natural Gas (MMcf) | ||||
Proved developed and undeveloped reserves: | ||||
Beginning Balance | Mcf | 173,958 | 331,921 | 238,670 | 95,179 |
Revision of previous estimates | Mcf | (38,931) | (66,413) | (80,549) | (4,889) |
Purchase of reserves in place | Mcf | 58,959 | 117,167 | 197,103 | 21,957 |
Extensions, discoveries, and other additions | Mcf | 62,301 | 206,644 | 13,018 | 73,392 |
Sale of reserves in place | Mcf | (14,149) | (4,592) | (24,235) | (4,337) |
Production | Mcf | (3,468) | (24,834) | (12,086) | (7,344) |
Ending Balance | Mcf | 238,670 | 559,893 | 331,921 | 173,958 |
Proved developed reserves: | ||||
Proved developed reserves | Mcf | 56,751 | 219,279 | 62,570 | 46,026 |
Proved undeveloped reserves: | ||||
Proved undeveloped reserves | Mcf | 181,919 | 340,614 | 269,351 | 127,932 |
NGL (MBbl) | ||||
Proved developed and undeveloped reserves: | ||||
Beginning Balance | 0 | 0 | 0 | 0 |
Revision of previous estimates | 0 | 28,689 | 0 | 0 |
Purchase of reserves in place | 0 | 13,424 | 0 | 0 |
Extensions, discoveries, and other additions | 0 | 24,358 | 0 | 0 |
Sale of reserves in place | 0 | 0 | 0 | 0 |
Production | 0 | (2,518) | 0 | 0 |
Ending Balance | 0 | 63,953 | 0 | 0 |
Proved developed reserves: | ||||
Proved developed reserves | 0 | 24,251 | 0 | 0 |
Proved undeveloped reserves: | ||||
Proved undeveloped reserves | 0 | 39,702 | 0 | 0 |
MBOE | ||||
Proved developed and undeveloped reserves: | ||||
Balance (Boe) | Boe | 56,685 | 93,352 | 66,157 | 32,188 |
Revisions of previous estimates (Boe) | Boe | (17,407) | 14,581 | (21,213) | (2,513) |
Purchase of reserves in place (Boe) | Boe | 14,207 | 45,103 | 55,991 | 7,860 |
Extensions, discoveries, and other additions (Boe) | Boe | 18,647 | 87,535 | 3,627 | 23,696 |
Sales of reserves in place (Boe) | Boe | (4,655) | (1,425) | (6,939) | (1,352) |
Production (Boe) | Boe | (1,320) | (12,481) | (4,271) | (3,194) |
Balance (Boe) | Boe | 66,157 | 226,665 | 93,352 | 56,685 |
Proved developed reserves: | ||||
Proved developed reserves (Boe) | Boe | 17,868 | 87,350 | 17,863 | 15,064 |
Proved undeveloped reserves: | ||||
Proved undeveloped reserves (Boe) | Boe | 48,289 | 139,315 | 75,489 | 41,621 |
Unaudited Oil and Gas Reserve82
Unaudited Oil and Gas Reserves Information (Narrative) (Details) Boe in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015Boe$ / bbl$ / Mcf | Dec. 31, 2017Boe$ / bbl$ / Mcf | Dec. 31, 2016Boe$ / bbl$ / Mcf | Aug. 31, 2015Boewell$ / bbl$ / Mcf | |
Reserve Quantities [Line Items] | ||||
Exploratory wells | well | 67 | |||
Net cash flows, discount rate (percent) | 10.00% | 10.00% | ||
MBOE | ||||
Reserve Quantities [Line Items] | ||||
Purchase of reserves in place (Boe) | 14,207 | 45,103 | 55,991 | 7,860 |
Revisions of previous estimates (Boe) | (17,407) | 14,581 | (21,213) | (2,513) |
Extensions, discoveries, and other additions (Boe) | 18,647 | 87,535 | 3,627 | 23,696 |
Oil (MBbl) | ||||
Reserve Quantities [Line Items] | ||||
Price per unit used to prepare reserve estimates, based upon average prices | $ / bbl | 41.33 | 46.57 | 36.07 | 53.27 |
Increase (decrease) in price per unit used to prepare reserve estimates, based upon average prices | $ / bbl | 10.50 | |||
Natural Gas (MMcf) | ||||
Reserve Quantities [Line Items] | ||||
Price per unit used to prepare reserve estimates, based upon average prices | $ / Mcf | 2.60 | 2.21 | 2.44 | 3.28 |
Increase (decrease) in price per unit used to prepare reserve estimates, based upon average prices | $ / Mcf | (0.23) | |||
Wattenberg Field | MBOE | ||||
Reserve Quantities [Line Items] | ||||
Extensions, discoveries, and other additions (Boe) | 23,696 |
Unaudited Oil and Gas Reserve83
Unaudited Oil and Gas Reserves Information (Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Aug. 31, 2015 | Aug. 31, 2014 |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||||
Future cash inflows | $ 5,493,507 | $ 2,180,673 | $ 1,710,610 | $ 2,046,615 | |
Future production costs | (1,291,369) | (644,093) | (462,097) | (653,009) | |
Future development costs | (1,048,856) | (584,537) | (340,449) | (510,720) | |
Future income tax expense | (285,349) | (90,195) | (108,172) | (144,399) | |
Future net cash flows | 2,867,933 | 861,848 | 799,892 | 738,487 | |
10% annual discount for estimated timing of cash flows | (1,267,258) | (427,587) | (408,939) | (372,658) | |
Standardized measure of discounted future net cash flows | $ 1,600,675 | $ 434,261 | $ 390,953 | $ 365,829 | $ 402,699 |
Unaudited Oil and Gas Reserve84
Unaudited Oil and Gas Reserves Information (Schedule of Prices Used to Prepare Estimates of Oil and Gas Reserves) (Details) | Dec. 31, 2017$ / bbl$ / Mcf | Dec. 31, 2016$ / bbl$ / Mcf | Dec. 31, 2015$ / bbl$ / Mcf | Aug. 31, 2015$ / bbl$ / Mcf |
Oil (MBbl) | ||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Price per unit used to prepare reserve estimates, based upon average prices | 46.57 | 36.07 | 41.33 | 53.27 |
Natural Gas (MMcf) | ||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Price per unit used to prepare reserve estimates, based upon average prices | $ / Mcf | 2.21 | 2.44 | 2.60 | 3.28 |
NGL (MBbl) | ||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Price per unit used to prepare reserve estimates, based upon average prices | 16.06 | 0 | 0 | 0 |
Unaudited Oil and Gas Reserve85
Unaudited Oil and Gas Reserves Information (Schedule of Changes in the Standardized Measure for Discounted Cash Flows) (Details) - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward] | ||||
Standardized measure, beginning of year | $ 365,829 | $ 434,261 | $ 390,953 | $ 402,699 |
Sale and transfers, net of production costs | (25,222) | (306,754) | (81,468) | (98,486) |
Net changes in prices and production costs | (81,968) | 135,525 | (64,387) | (233,051) |
Extensions, discoveries, and improved recovery | 116,343 | 811,564 | 18,795 | 173,918 |
Changes in estimated future development costs | (7,195) | (25,969) | (6,016) | 10,002 |
Development costs incurred during the period | 5,923 | 170,296 | 62,502 | 4,957 |
Revision of quantity estimates | (36,820) | 165,267 | (110,306) | (38,340) |
Accretion of discount | 14,610 | 47,635 | 44,703 | 57,629 |
Net change in income taxes | 25,263 | (113,523) | 5,104 | 58,547 |
Divestitures of reserves | (43,754) | (7,157) | (26,839) | (19,234) |
Purchase of reserves in place | 77,024 | 260,999 | 228,855 | 56,795 |
Changes in timing and other | (19,080) | 28,531 | (27,635) | (9,607) |
Standardized measure, end of year | $ 390,953 | $ 1,600,675 | $ 434,261 | $ 365,829 |
Unaudited Financial Data (Detai
Unaudited Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 4 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | ||||||||||||
Revenues | $ 140,097 | $ 103,593 | $ 75,036 | $ 43,790 | $ 38,695 | $ 26,234 | $ 23,947 | $ 18,273 | ||||
Expenses | 71,420 | 57,461 | 48,514 | 27,536 | 29,324 | 45,887 | 172,157 | 71,356 | $ 173,599 | $ 204,931 | $ 318,724 | $ 127,221 |
Operating income (loss) | 68,677 | 46,132 | 26,522 | 16,254 | 9,371 | (19,653) | (148,210) | (53,083) | (139,461) | 157,585 | (211,575) | (2,378) |
Other income (expense) | (17,958) | (2,284) | 1,414 | 3,626 | (4,070) | 417 | (5,537) | 1,682 | 6,522 | (15,202) | (7,508) | 32,097 |
Income (Loss) before income taxes | 50,719 | 43,848 | 27,936 | 19,880 | 5,301 | (19,236) | (153,747) | (51,401) | (132,939) | 142,383 | (219,083) | 29,719 |
Income tax expense (benefit) | (99) | 0 | 0 | 0 | 0 | 5 | 101 | 0 | (10,007) | (99) | 106 | 11,677 |
Net income (loss) | $ 50,818 | $ 43,848 | $ 27,936 | $ 19,880 | $ 5,301 | $ (19,241) | $ (153,848) | $ (51,401) | $ (122,932) | $ 142,482 | $ (219,189) | $ 18,042 |
Net income (loss) per common share: | ||||||||||||
Basic (in dollars per share) | $ 0.23 | $ 0.22 | $ 0.14 | $ 0.10 | $ 0.03 | $ (0.10) | $ (0.89) | $ (0.42) | $ (1.14) | $ 0.69 | $ (1.26) | $ 0.19 |
Diluted (in dollars per share) | $ 0.23 | $ 0.22 | $ 0.14 | $ 0.10 | $ 0.03 | $ (0.10) | $ (0.89) | $ (0.42) | $ (1.14) | $ 0.69 | $ (1.26) | $ 0.19 |
Weighted-average shares outstanding: | ||||||||||||
Basic (in shares) | 222,072,930 | 200,881,447 | 200,831,063 | 200,707,891 | 200,585,800 | 200,515,555 | 172,013,551 | 121,392,736 | 107,789,554 | 206,167,506 | 173,774,035 | 94,628,665 |
Diluted (in shares) | 222,917,611 | 201,460,915 | 201,224,172 | 201,309,251 | 201,254,678 | 200,515,555 | 172,013,551 | 121,392,736 | 107,789,554 | 206,743,551 | 173,774,035 | 95,319,269 |