Document and Entity Information
Document and Entity Information - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2018 | Feb. 14, 2019 | Jun. 30, 2018 | |
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 | ||
Entity Emerging Growth Company | false | ||
Entity Small Business | false | ||
Entity Shell Company | false | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2018 | ||
Document Fiscal Year Focus | 2,018 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Common Stock, Shares Outstanding | 243,256,234 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 2 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 49,609 | $ 48,772 |
Accounts receivable: | ||
Oil, natural gas, and NGL sales | 100,973 | 86,013 |
Trade | 39,415 | 18,134 |
Commodity derivative assets | 34,906 | 0 |
Other current assets | 7,537 | 7,116 |
Total current assets | 232,440 | 160,035 |
Property and equipment: | ||
Proved properties, net of accumulated depletion | 1,545,445 | 970,584 |
Wells in progress | 227,262 | 106,269 |
Unproved properties and land, not subject to depletion | 740,453 | 793,669 |
Oil and gas properties, net | 2,513,160 | 1,870,522 |
Other property and equipment, net | 5,540 | 6,054 |
Total property and equipment, net | 2,518,700 | 1,876,576 |
Goodwill | 0 | 40,711 |
Other assets | 3,574 | 2,242 |
Total assets | 2,754,714 | 2,079,564 |
Current liabilities: | ||
Accounts payable and accrued expenses | 150,010 | 74,672 |
Revenue payable | 97,030 | 64,111 |
Production taxes payable | 95,099 | 52,413 |
Asset retirement obligations | 11,694 | 3,246 |
Commodity derivative liabilities | 0 | 7,865 |
Total current liabilities | 353,833 | 202,307 |
Revolving credit facility | 195,000 | 0 |
Notes payable, net of issuance costs | 539,360 | 538,186 |
Deferred taxes | 37,967 | 0 |
Asset retirement obligations | 40,052 | 28,376 |
Other liabilities | 2,210 | 2,261 |
Total liabilities | 1,168,422 | 771,130 |
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, 400,000,000 and 300,000,000 shares authorized: 242,608,284 and 241,365,522 shares issued and outstanding as of December 31, 2018 and 2017, respectively | 243 | 241 |
Additional paid-in capital | 1,492,107 | 1,474,273 |
Retained earnings (deficit) | 93,942 | (166,080) |
Total shareholders' equity | 1,586,292 | 1,308,434 |
Total liabilities and shareholders' equity | $ 2,754,714 | $ 2,079,564 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares | Dec. 31, 2018 | Dec. 31, 2017 |
Statement of Financial Position [Abstract] | ||
Preferred stock, shares authorized | 10,000,000 | 10,000,000 |
Preferred stock, par value per share (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock, shares issued | 0 | 0 |
Preferred stock, shares outstanding | 0 | 0 |
Common stock, shares authorized | 400,000,000 | 300,000,000 |
Common stock, par value per share (in dollars per share) | $ 0.001 | $ 0.001 |
Common stock, shares issued | 242,608,284 | 241,365,522 |
Common stock, shares outstanding | 242,608,284 | 241,365,522 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Statement [Abstract] | |||
Oil, natural gas, and NGL revenues | $ 645,641 | $ 362,516 | $ 107,149 |
Expenses: | |||
Lease operating expenses | 43,291 | 19,496 | 19,949 |
Transportation and gathering | 9,135 | 3,226 | 0 |
Production taxes | 59,830 | 36,266 | 5,732 |
Depreciation, depletion, and accretion | 179,773 | 112,309 | 46,678 |
Full cost ceiling impairment | 0 | 0 | 215,223 |
Goodwill impairment | 40,711 | 0 | 0 |
Unused commitment charge | 0 | 669 | 597 |
General and administrative | 38,618 | 32,965 | 30,545 |
Total expenses | 371,358 | 204,931 | 318,724 |
Operating income (loss) | 274,283 | 157,585 | (211,575) |
Other income (expense): | |||
Commodity derivative gain (loss) | 23,413 | (4,226) | (7,750) |
Interest expense, net of amounts capitalized | 0 | (11,842) | 0 |
Interest income | 99 | 363 | 192 |
Other income | 194 | 503 | 50 |
Total other income (expense) | 23,706 | (15,202) | (7,508) |
Income (Loss) before income taxes | 297,989 | 142,383 | (219,083) |
Income tax expense (benefit) | 37,967 | (99) | 106 |
Net income (loss) | $ 260,022 | $ 142,482 | $ (219,189) |
Net income (loss) per common share: | |||
Basic (in dollars per share) | $ 1.07 | $ 0.69 | $ (1.26) |
Diluted (in dollars per share) | $ 1.07 | $ 0.69 | $ (1.26) |
Weighted-average shares outstanding: | |||
Basic (in shares) | 242,308,893 | 206,167,506 | 173,774,035 |
Diluted (in shares) | 243,021,002 | 206,743,551 | 173,774,035 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY - USD ($) $ in Thousands | Total | Common stock | Additional Paid-In Capital | Retained Earnings (Deficit) |
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 offerings | 543,411 | $ 90 | 543,321 | |
Shares issued in equity offering, shares | 90,275,000 | |||
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 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Shares issued in equity offerings | 312,171 | $ 40 | 312,131 | |
Shares issued in equity offering, shares | 40,250,000 | |||
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) | ||
Adjustments to Additional Paid in Capital, Other | 102 | (102) | ||
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] | ||||
Shares issued under stock bonus and equity incentive plans | $ 5,973 | $ 1 | 5,972 | |
Shares issued under stock bonus and equity incentive plans, shares | 432,700 | |||
Shares issued for exercise of stock options | $ 4,302 | $ 1 | 4,301 | |
Shares issued for exercise of stock options, shares | 823,883 | 810,062 | ||
Stock-based compensation for options | $ 4,543 | 4,543 | ||
Stock-based compensation for performance-vested stock units | 4,212 | 4,212 | ||
Payment of tax withholdings using withheld shares | (1,121) | (1,121) | ||
Adjustments to Additional Paid in Capital, Other | (73) | (73) | ||
Net income (loss) | 260,022 | 260,022 | ||
Balance at Dec. 31, 2018 | $ 1,586,292 | $ 243 | $ 1,492,107 | $ 93,942 |
Balance, shares at Dec. 31, 2018 | 242,608,284 | 242,608,284 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Cash flows from operating activities: | |||
Net income (loss) | $ 260,022 | $ 142,482 | $ (219,189) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depletion, depreciation, and accretion | 179,773 | 112,309 | 46,678 |
Full cost ceiling impairment | 0 | 0 | 215,223 |
Goodwill impairment | 40,711 | 0 | 0 |
Settlements of asset retirement obligations | (6,388) | (4,541) | (228) |
Loss on extinguishment of debt | 0 | 11,842 | 0 |
Provision for deferred taxes | 37,967 | 0 | 0 |
Stock-based compensation expense | 12,287 | 11,225 | 9,491 |
Total (gain) loss on commodity derivative contracts | (23,413) | 4,226 | 7,750 |
Cash settlements on commodity derivative contracts | (19,359) | 942 | 5,374 |
Changes in operating assets and liabilities | 39,543 | 12,830 | (16,411) |
Net cash provided by operating activities | 521,143 | 291,315 | 48,688 |
Cash flows from investing activities: | |||
Acquisitions of oil and gas properties and leaseholds | (149,658) | (661,468) | (511,173) |
Capital expenditures for drilling and completion activities | (516,480) | (450,384) | (119,571) |
Other capital expenditures | (47,916) | (17,841) | (7,044) |
Acquisition of land and other property and equipment | (3,039) | (4,186) | (5,478) |
Proceeds from sales of oil and gas properties and other | 1,627 | 93,573 | 25,350 |
Net cash used in investing activities | (715,466) | (1,040,306) | (617,916) |
Cash flows from financing activities: | |||
Proceeds from the sale of stock | 0 | 322,000 | 565,398 |
Offering costs | (157) | (9,745) | (21,987) |
Proceeds from the employee exercise of stock options | 4,302 | 741 | 68 |
Payment of employee payroll taxes in connection with shares withheld | (1,121) | (688) | (757) |
Proceeds from revolving credit facility | 195,000 | 250,000 | 55,000 |
Principal repayments on revolving credit facility | 0 | (250,000) | (133,000) |
Proceeds from issuance of notes payable | 0 | 550,000 | 80,000 |
Repayment of notes payable | 0 | (88,234) | 0 |
Financing fees on issuance of notes payable and amendments to revolving credit facility | (2,588) | (13,145) | (5,159) |
Capital lease payments | (276) | 0 | 0 |
Net cash provided by financing activities | 195,160 | 760,929 | 539,563 |
Net increase (decrease) in cash, cash equivalents, and restricted cash | 837 | 11,938 | (29,665) |
Cash, cash equivalents, and restricted cash at beginning of period | 48,772 | 36,834 | 66,499 |
Cash, cash equivalents, and restricted cash at end of period | $ 49,609 | $ 48,772 | $ 36,834 |
Organization and Summary of Sig
Organization and Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2018 | |
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. 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"). 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. 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 lease 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 retirement 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 in 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 years ended December 31, 2018 and 2017 , the Company did not recognize any ceiling test impairments. During the year ended December 31, 2016, the Company recognized ceiling test impairments of $215.2 million . 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, 2018 2017 Trade accounts payable $ 2,029 $ 624 Accrued well costs 130,784 56,348 Accrued G&A 4,913 6,017 Accrued LOE 8,366 5,249 Accrued interest 3,574 3,125 Accrued other 344 3,309 $ 150,010 $ 74,672 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 retired. Calculation of an asset retirement obligation ("ARO") requires estimates about several future events, including the life of the asset, the costs to retire the asset, 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: 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 perform the annual impairment assessment as of October 1. 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. The Company performed its annual goodwill impairment test as of October 1, 2018 and determined that no impairment had occurred. However, as a result of a sustained decrease in the price of our common stock during the fourth quarter of 2018 caused by a significant decline in oil prices over the same period, the Company performed another goodwill impairment test as of December 31, 2018. The impairment test performed by the Company indicated that the carrying value of its reporting unit exceeded its fair value and that an impairment loss should be recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to the reporting unit . Based on these results, the Company recorded a non-cash impairment charge of $40.7 million , reducing the carrying value of goodwill to zero. 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 and contain considerable management judgments. 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, 2018 2017 2016 Company A 22% 33% * Company B 20% 24% 20% Company C 17% * * Company D 13% 17% 20% Company E 13% * * Company F * * 16% Company G * * 13% * 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, 2018 2017 Company A 15% 26% Company B 13% 16% Company C 12% 23% Company D 12% * Company E * 11% * 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. Once a grant date has been established, the compensation is recognized over the remaining vesting period of the grant. See Note 11 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, 2018 . The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of December 31, 2018 , the Company has not recognized any interest or penalties related to uncertain tax benefits. See Note 14 for further information. 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 in 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, 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 May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update ("ASU") 2014-09, "Revenue from Contracts with Customers (Topic 606)" ("ASU 2014-09"), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 (collectively with ASU 2014-09, the "Revenue ASUs") to clarify principal versus agent considerations. The Revenue ASUs allow for the use of either the full or modified retrospective transition method, and the standard became effective for annual reporting periods beginning after December 15, 2017 including interim periods within that period. The Company adopted the guidance using the modified retrospective method with the effective date of January 1, 2018. The Company did not record a cumulative-effect adjustment to the opening balance of retained earnings as no adjustment was necessary. The adoption of the Revenue ASUs did not impact net income or cash flows. See Note 15 for the new disclosures required by the Revenue ASUs. 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 in the balance sheet and disclosing key information about leasing arrangements. For leases with terms of more than 12 months, ASU 2016-02 requires lessees to recognize a right-of-use asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. Both the lease asset and liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, including the presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. In January 2018, the FASB issued "Update No. 2018-01 Leases (Topic 842) - Land Easement Practical Expedient for Transition to Topic 842", which permits an entity to elect an optional transition practical expedient to not evaluate land easements existing or expiring before the entity’s adoption of ASU 2016-02 and not previously accounted for as leases. Furthermore, in July 2018, the FASB issued "Update No. 2018-11 Leases (Topic 842): Targeted Improvements", which provides for an additional transition method that allows an entity to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings (deficit) in the period of adoption. For example, comparative periods presented in the financial statements will continue to be in accordance with current guidance, Topic 840, Leases. Collectively, ASU 2016-02 and the subsequent updates will be referred to as "ASU 2016-02, as amended". The guidance is effective for fiscal years beginning after December 15, 2018 and interim periods within those years, with early adoption permitted. ASU 2016-02, as amended does not apply to leases of mineral rights to explore for or use crude oil and natural gas. In the normal course of business, we enter into contracts to support our exploration and development operations including contracts for drilling rigs, field services, well equipment, pipeline capacity, office space, and other assets. Although we are continuing to assess the full effect the guidance will have on our existing accounting policies and our consolidated financial statements, we expect that there will be an increase in disclosures and an increase in assets and liabilities in our consolidated balance sheets upon adoption due to the recording of right-of-use assets and corresponding lease liabilities . We are reviewing contracts, have contracted for lease accounting software, and are researching pertinent matters to accommodate adoption of this guidance. 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, 2018 | |
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, 2018 2017 Oil and gas properties, full cost method: Costs of proved properties: Producing and non-producing $ 2,385,958 $ 1,629,789 Less, accumulated depletion and full cost ceiling impairments (840,513 ) (659,205 ) Subtotal, proved properties, net 1,545,445 970,584 Costs of wells in progress 227,262 106,269 Costs of unproved properties and land, not subject to depletion: Lease acquisition and other costs 731,058 786,469 Land 9,395 7,200 Subtotal, unproved properties and land 740,453 793,669 Costs of other property and equipment: Other property and equipment 9,642 8,134 Less, accumulated depreciation (4,102 ) (2,080 ) Subtotal, other property and equipment, net 5,540 6,054 Total property and equipment, net $ 2,518,700 $ 1,876,576 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, 2018 and 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 Company's ceiling tests resulted in total impairments of $215.2 million . 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, this review indicated that the carrying values had not been impaired. Therefore, no impairment was necessary as December 31, 2017. However, during the years ended December 31, 2018 and December 31, 2016, the Company recorded impairments of $1.2 million and $18.9 million , respectively, to the carrying value of its unproved properties. Capitalized Overhead: A portion of the Company’s overhead expenditures 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, 2018 2017 2016 Capitalized overhead $ 12,775 $ 10,293 $ 7,074 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, 2018 2017 2016 Acquisition of property: Unproved $ 46,039 $ 538,489 $ 365,548 Proved 136,652 139,154 152,363 Exploration costs — — 43,154 Development costs 583,660 460,875 87,782 Other property and equipment and land 3,039 4,397 7,506 Capitalized interest, capitalized G&A, and other 57,039 26,677 18,744 Total costs incurred $ 826,429 $ 1,169,592 $ 675,097 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, 2018 (in thousands): Period Incurred Year Ended December 31, Prior to January 1, 2016 Total as of December 31, 2018 2018 2017 2016 Unproved leasehold acquisition costs $ 78,743 $ 460,627 $ 175,666 $ 16,022 $ 731,058 Unproved development costs 50,083 — — — 50,083 Total unevaluated costs $ 128,826 $ 460,627 $ 175,666 $ 16,022 $ 781,141 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, 2018 | |
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. Acquisitions In September 2018, the Company completed the second closing contemplated by the purchase and sale agreement relating to our 2017 acquisition of approximately 30,200 net acres in the Greeley-Crescent development area discussed below. At the second closing, we acquired the operated vertical and horizontal wells. The effective date for this second closing was September 1, 2018. The purchase and sale agreement for the GCII Acquisition was signed in November 2017, and the first closing was completed in December 2017. The total purchase price for the second closing was $96.9 million , composed of cash of $64.2 million and assumed liabilities of $32.7 million . The assumed liabilities included $25.8 million for asset retirement obligations. The entire purchase price has been allocated to proved oil and gas properties. In August 2018, the Company completed the purchase of leasehold acreage and associated non-operated production for $37.2 million in cash and the assumption of certain liabilities for a total purchase price of $37.5 million . The acreage increased our working interest in existing operations and planned wells. The purchase price for the acquisition was allocated as $23.9 million to proved oil and gas properties and $13.6 million to unproved oil and gas properties. In November 2018, 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 ("GCII Acquisition"). In December 2017, the Company closed on the portion of the assets comprising the approximately 30,200 net acres and the associated non-operated production for $576.4 million in cash and the assumption of certain liabilities for a total purchase price of $577.5 million . The purchase price for the first closing was allocated as $60.8 million to proved oil and gas properties and $516.7 million to unproved oil and gas properties. The effective date of this part of the transaction was November 1, 2017. As discussed above, we closed on the second part of this transaction covering the operated properties in September 2018. In September 2017, we completed the purchase of the operated vertical and horizontal wells in the Greeley-Crescent development area in Weld County, Colorado. This purchase was contemplated in May 2016 when 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 (the "GC Acquisition"). The first closing for this agreement occurred in June 2016. The effective date of this second closing was April 1, 2016 for the horizontal wells acquired and September 1, 2017 for the vertical wells acquired. At the second closing, an escrow balance of $18.2 million was released, and $11.4 million of that amount was returned to the Company. The total purchase price 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. In August 2017, we 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 been allocated as $6.7 million to proved oil and gas properties and $15.9 million to unproved oil and gas properties. 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. All of these transactions were accounted for as asset acquisitions, which requires the acquired assets and liabilities to be recorded at cost on the acquisition date. 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. 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, 2018 | |
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, 2018 2017 2016 Depletion of oil and gas properties $ 175,441 $ 109,287 $ 45,193 Depreciation and accretion 4,332 3,022 1,485 Total DD&A Expense $ 179,773 $ 112,309 $ 46,678 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 proved reserves at the beginning of the quarter. For the year ended December 31, 2018 , production of 18,448 MBOE represented 5.7% of estimated total proved reverses. For the year ended December 31, 2017 , production of 12,481 MBOE represented 5.2% of estimated total proved reserves. For the year ended December 31, 2016 , production of 4,271 MBOE represented 4.4% of estimated total proved reserves. DD&A expense was $9.74 per BOE, $9.00 per BOE, and $10.93 per BOE for the years ended December 31, 2018 , 2017 , and 2016 , respectively. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2018 | |
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 reclaim 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, 2018 2017 Beginning asset retirement obligation $ 31,622 $ 16,458 Obligations incurred with development activities 4,174 3,398 Obligations assumed with acquisitions 26,150 24,696 Accretion expense 2,310 1,554 Obligations discharged with asset retirements and divestitures (12,267 ) (14,332 ) Revisions in previous estimates (243 ) (152 ) Ending asset retirement obligation $ 51,746 $ 31,622 Less, current portion (11,694 ) (3,246 ) Non-current portion $ 40,052 $ 28,376 |
Revolving Credit Facility
Revolving Credit Facility | 12 Months Ended |
Dec. 31, 2018 | |
Line of Credit Facility [Abstract] | |
Revolving Credit Facility | Revolving Credit Facility On April 2, 2018, the Company entered into a second amended and restated credit agreement (the "Restated Credit Agreement") with certain banks and other lenders. The Restated Credit Agreement provides a revolving credit facility (sometimes referred to as the "Revolver") and a $25 million swingline facility with a maturity date of April 2, 2023 . The Revolver is available for working capital for exploration and production operations, acquisitions of oil and gas properties, and general corporate purposes and to support letters of credit. At December 31, 2018 , the terms of the Revolver provided for up to $1.5 billion in borrowings, an aggregate elected commitment of $500 million , and a borrowing base limitation of $650 million . As of December 31, 2018 and December 31, 2017 , the outstanding principal balance was $195.0 million and nil , respectively. At December 31, 2018 , the Company had no letters of credit issued. 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 year ended December 31, 2018 and 2017 was 4.2% and 3.4% , respectively. Certain of the Company’s assets, including substantially all of its producing wells and developed oil and gas leases, have been designated as collateral under the Restated Credit Agreement. The amount available to be borrowed is subject to scheduled redeterminations on a semi-annual basis. If certain events occur or if the bank syndicate or the Company so elects in certain circumstances, an unscheduled redetermination could be undertaken. The Restated Credit Agreement 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 the projected production from proved developed producing or total proved reserves as reflected in the most recently completed reserve report. Furthermore, the Restated Credit Agreement 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 last day of any fiscal quarter or (b) permit its ratio of current assets to current liabilities, each as defined in the agreement, to be less than 1.0 to 1.0 as of the last day of any fiscal quarter. As of December 31, 2018 , the most recent compliance date, the Company 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, 2018 | |
Debt Disclosure [Abstract] | |
Notes Payable | Notes Payable 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 (the "Indenture") 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 , to repay our previously outstanding senior notes due 2021, and to pay off the then-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. The Indenture provides that, in certain circumstances, the 2025 Senior Notes will be guaranteed by one or more subsidiaries of the Company, in which case such guarantee would be made on a full and unconditional and joint and several senior unsecured basis. As of December 31, 2018 , none of the Company's subsidiaries met the criteria outlined within the Indenture to be considered a guarantors of the 2025 Senior Notes. As of December 31, 2018 , 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. |
Commodity Derivative Instrument
Commodity Derivative Instruments | 12 Months Ended |
Dec. 31, 2018 | |
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 or price differential 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. In conjunction with certain derivative contracts, the Company deferred the payment of certain put premiums. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month. The Company amortizes the deferred put premium liabilities as they become payable. As of December 31, 2018, the deferred put premium liability was $1.9 million and netted against current commodity derivative assets. 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 six counterparties. Five 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, 2018 are summarized below: Settlement Period Derivative Instrument Volumes (Bbls per day) Weighted Average Floor Price Weighted Average Ceiling Price Crude Oil - NYMEX WTI Jan 1, 2019 - Dec 31, 2019 Collar 6,000 $ 55.00 $ 74.31 Settlement Period Derivative Volumes (MMBtu per day) Weighted Average Floor Price Weighted Average Ceiling Price Natural Gas - NYMEX Henry Hub Jan 1, 2019 - Mar 31, 2019 Collar 30,000 $ 3.00 $ 4.50 Apr 1, 2019 - Dec 31, 2019 Collar 30,000 $ 3.00 $ 3.50 Settlement Period Derivative Instrument Volumes Weighted-Average Fixed Basis Difference Natural Gas - CIG Rocky Mountain Jan 1, 2019 - Dec 31, 2019 Swap 30,000 $ (0.75 ) Jan 1, 2019 - Mar 31, 2019 Swap 30,000 $ (0.56 ) Settlement Period Derivative Volumes Weighted-Average Fixed Price Natural Gas - NYMEX Henry Hub (MMBtu per day) Jan 1, 2019 - Mar 31, 2019 Swap 60,000 $ 4.00 Propane - Mont Belvieu (Bbls per day) Jan 1, 2019 - Dec 31, 2019 Swap 2,000 $ 37.52 Offsetting of Derivative Assets and Liabilities As of December 31, 2018 and 2017 , 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 in 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, 2018 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 $ 39,485 $ (4,579 ) $ 34,906 Commodity derivative contracts Non-current assets $ — $ — $ — Commodity derivative contracts Current liabilities $ 4,579 $ (4,579 ) $ — Commodity derivative contracts Non-current liabilities $ — $ — $ — 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 $ — $ — $ — 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, 2018 2017 2016 Realized gain (loss) on commodity derivatives $ (19,359 ) $ 39 $ 2,355 Unrealized gain (loss) on commodity derivatives 42,772 (4,265 ) (10,105 ) Total gain (loss) $ 23,413 $ (4,226 ) $ (7,750 ) 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. The following table summarizes derivative realized gains and losses during the periods presented (in thousands): Year Ended December 31, 2018 2017 2016 Monthly settlements $ (19,359 ) $ 1,062 $ 4,396 Previously incurred premiums attributable to settled commodity contracts — (1,023 ) (2,041 ) Total realized gain (loss) $ (19,359 ) $ 39 $ 2,355 Credit Related Contingent Features As of December 31, 2018 , five 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 sixth counterparty, which is not a lender under the credit facility, is unsecured and does not require the posting of collateral. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2018 | |
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 goodwill, 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. Refer to Notes 1, 2 , 3 , and 5 for further discussion of goodwill, unproved properties, business combinations and asset acquisitions, and asset retirement obligations, respectively. The Company determines the estimated fair value of its goodwill using a quoted market price for the Company as adjusted for a control premium. As the control premium is an unobservable pricing input, this input is deemed to be a Level 3 input. See Note 1 for additional information. 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 reclamation 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 retirement. 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, 2018 Level 1 Level 2 Level 3 Total Financial assets and liabilities: Commodity derivative asset $ — $ 34,906 $ — $ 34,906 Commodity derivative liability $ — $ — $ — $ — 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 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, 2018 , derivative instruments utilized by the Company consist of collars and swaps. The oil, natural gas, and propane 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, 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 $462.0 million at December 31, 2018 . The Company determined the fair value of its notes payable at December 31, 2018 by using observable market-based information for debt instruments of similar terms and duration. The Company has classified the notes payable as Level 2. |
Interest Expense
Interest Expense | 12 Months Ended |
Dec. 31, 2018 | |
Interest and Debt Expense [Abstract] | |
Interest Expense | Interest Expense The components of interest expense are (in thousands): Year Ended December 31, 2018 2017 2016 Revolving credit facility $ 2,209 $ 2,004 $ 154 Notes payable 34,375 10,036 3,940 Amortization of debt issuance costs and other 3,926 3,084 1,638 Debt extinguishment costs — 11,842 — Less: interest capitalized (40,510 ) (15,124 ) (5,732 ) Interest expense, net $ — $ 11,842 $ — |
Equity and Stock-Based Compensa
Equity and Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Equity and Stock-Based Compensation | Stock-Based Compensation Equity At the 2018 annual meeting of shareholders of the Company held on May 18, 2018, the shareholders approved the Third Amended and Restated Articles of Incorporation of the Company to increase the number of authorized shares of common stock of the Company from 300,000,000 to 400,000,000 . 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, 2018 , there were 10,500,000 common shares authorized for grant under the 2015 Equity Incentive Plan, of which 4,446,904 shares were available for future grants. The shares available for future grant exclude 1,054,926 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, 2018 2017 2016 Stock options $ 4,543 $ 5,076 $ 5,417 Performance-vested stock units 4,212 2,938 1,047 Restricted stock units and stock bonus shares 5,972 4,977 4,232 Total stock-based compensation 14,727 12,991 10,696 Less: stock-based compensation capitalized (2,440 ) (1,766 ) (1,205 ) Total stock-based compensation expense $ 12,287 $ 11,225 $ 9,491 Stock options No stock options were granted during the years ended December 31, 2018 and 2017 . During the period presented, the Company granted the following stock options: Year Ended December 31, 2016 Number of options to purchase common shares 1,067,500 Weighted-average exercise price $ 7.19 Term (in years) 10 years Vesting Period (in years) 3 - 5 years Fair Value (in thousands) $ 3,860 The assumptions used in valuing stock options granted during the period presented were as follows: Year Ended December 31, 2016 Expected term 6.4 years Expected volatility 55 % Risk-free rate 1.25 - 2.00% 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, 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 Granted — — Exercised (823,883 ) 5.36 4,611 Expired (37,400 ) 11.22 Forfeited (122,917 ) 9.93 Outstanding, December 31, 2018 4,652,634 $ 10.06 6.4 years $ 49 Outstanding, Exercisable at December 31, 2018 3,278,330 $ 10.28 6.2 years $ 49 The following table summarizes information about issued and outstanding stock options as of December 31, 2018 : 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 35,000 $ 3.31 3.5 years 35,000 $ 3.31 3.5 years $5.00 - $6.99 723,800 6.30 6.5 years 398,600 6.28 5.7 years $7.00 - $10.99 1,360,334 9.42 6.4 years 897,630 9.50 6.2 years $11.00 - $13.46 2,533,500 11.57 6.4 years 1,947,100 11.58 6.4 years Total 4,652,634 $ 10.06 6.4 years 3,278,330 $ 10.28 6.2 years The estimated unrecognized compensation cost from stock options not vested as of December 31, 2018 , which will be recognized ratably over the remaining vesting period, is as follows: Unrecognized compensation (in thousands) $ 4,504 Remaining vesting period 1.7 years Restricted stock units and stock bonus awards The Company grants restricted stock units and stock bonus awards to directors, eligible employees, and officers under 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, 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 Granted 1,130,388 7.76 Vested (478,517 ) 8.96 Forfeited (99,339 ) 9.28 Not vested, December 31, 2018 1,639,918 $ 8.07 The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of December 31, 2018 , which will be recognized ratably over the remaining vesting period, is as follows: Unrecognized compensation (in thousands) $ 8,992 Remaining vesting period 2.1 years Performance-vested stock units The Company grants two types of 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. Goal-Based PSUs - These PSUs are earned and vested after 2020 based on a discretionary assessment by the Compensation Committee. This assessment is anticipated to measure the performance of the Company and the executives over the defined vesting period. As vesting is based on the discretion of the Compensation Committee, we have not yet met the requirements of establishing an accounting grant date for them. This will occur when the Compensation Committee determines and communicates the vesting percentage to the award recipients, which will then trigger the service inception date, the fair value of the awards, and the associated expense recognition period. As of December 31, 2018 , 274,898 Goal-Based PSUs remained outstanding. Total Shareholder Return ("TSR") PSUs - The vesting criterion for the TSR PSUs is based on a comparison of the Company’s 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 TSR 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 TSR 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 TSR 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 TSR PSUs granted were as follows: Year Ended December 31, 2018 2017 2016 Weighted-average expected term 2.8 years 2.9 years 2.7 years Weighted-average expected volatility 52 % 59 % 58 % Weighted-average risk-free rate 2.41 % 1.34 % 0.87 % As of December 31, 2018 , unrecognized compensation for TSR PSUs was $4.7 million and will be amortized through 2020. A summary of the status and activity of TSR 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 Granted 321,507 13.11 Vested (465,188 ) 8.09 Forfeited (28,175 ) 10.15 Not vested, December 31, 2018 780,028 $ 11.73 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. |
Weighted-Average Shares Outstan
Weighted-Average Shares Outstanding | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 2017 2016 Weighted-average shares outstanding - basic 242,308,893 206,167,506 173,774,035 Potentially dilutive common shares from: Stock options 229,946 417,809 — TSR PSUs 1 175,412 — — Restricted stock units and stock bonus shares 306,751 158,236 — Weighted-average shares outstanding - diluted 243,021,002 206,743,551 173,774,035 1 The number of awards assumes that the associated vesting condition is met at the respective period end based on market prices as of the respective period end. 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. 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, 2018 2017 2016 Potentially dilutive common shares from: Stock options 1 3,747,634 4,657,834 6,001,500 TSR PSUs 1,2 314,533 951,884 478,510 Goal-Based PSUs 2,3 274,898 — — Restricted stock units and stock bonus shares 1 49,907 285,448 890,336 Total 4,386,972 5,895,166 7,370,346 1 Potential common shares excluded from the weighted-average shares outstanding-diluted calculation as the securities had an anti-dilutive effect on earnings per share. 2 The number of awards reflects the target amount of shares granted. 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. 3 Potential common shares excluded from the weighted-average shares outstanding-diluted calculation as the securities are considered contingently issuable, and the performance criteria are not considered met as of period end. |
Defined Contribution Plan
Defined Contribution Plan | 12 Months Ended |
Dec. 31, 2018 | |
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 $0.9 million , $0.7 million , and $0.4 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively, to the plan. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes The income tax provision is comprised of the following (in thousands): Year Ended December 31, 2018 2017 2016 Current: Federal $ — $ (99 ) $ 106 State — — — Total current income tax expense (benefit) — (99 ) 106 Deferred: Federal 72,898 48,631 (74,099 ) State 12,697 4,371 (6,651 ) Total deferred income tax (benefit) expense 85,595 53,002 (80,750 ) Valuation allowance (47,628 ) (53,002 ) 80,750 Income tax expense (benefit) $ 37,967 $ (99 ) $ 106 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, 2018 2017 2016 Federal income tax at statutory rate $ 62,578 $ 48,410 $ (74,489 ) State income taxes, net of federal tax 12,697 4,371 (6,685 ) Statutory depletion (113 ) (159 ) (287 ) Stock-based compensation (296 ) 50 383 Non-deductible compensation 598 — — Impact of tax reform, net of valuation allowance — (99 ) Valuation allowance (47,628 ) (53,002 ) 80,750 Goodwill impairment 8,549 — — Other 1,582 330 434 Income tax expense (benefit) $ 37,967 $ (99 ) $ 106 Effective rate expressed as a percentage 13 % — % — % The change in the Federal tax rate in 2017 was due to the passage of Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act ("TCJA"). The passage of this legislation resulted in the change in the U.S. statutory rate from 35% to 21% . 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 have been incorporated herein, and no substantial changes were identified compared to December 31, 2017. 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, 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, 2018 2017 Deferred tax assets (liabilities): Net operating loss carryforward $ 111,587 $ 43,283 Stock-based compensation 6,984 5,237 Basis of oil and gas properties (150,080 ) (5,011 ) Statutory depletion 2,434 2,795 Unrealized loss on commodity derivative (8,607 ) 1,939 Other (285 ) (615 ) (37,967 ) 47,628 Valuation allowance on tax assets — (47,628 ) Deferred tax liability, net $ (37,967 ) $ — During the three months ended March 31, 2018, the Company concluded it is more likely than not it will realize the benefits of its net deferred tax assets by the end of 2018 as a result of current year ordinary income. This conclusion was based upon the Company’s cumulative positive net income for the three-year period ended December 31, 2018. In addition to the cumulative positive net income, the temporary deferred tax liabilities exceed the deferred tax assets resulting in the ability to utilize all deferred tax assets to offset future taxable income resulting from the reversal of the deferred tax liabilities. At December 31, 2018 , the Company has U.S. Federal and state net operating loss carryforward of approximately $452.5 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 . As of December 31, 2018 , 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 December 31, 2015 and December 31, 2014, respectively, remain subject to examination by tax authorities. |
Revenue from Contract with Cust
Revenue from Contract with Customer | 12 Months Ended |
Dec. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenue from Contract with Customer | Revenue from Contracts with Customers Sales of oil, natural gas, and NGLs are recognized at the point control of the product is transferred to the customer and collectability is reasonably assured. All of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies. Year Ended December 31, Revenues (in thousands): 2018 2017 2016 Oil $ 494,052 $ 261,505 $ 77,699 Natural Gas and NGLs 151,589 101,011 29,450 $ 645,641 $ 362,516 $ 107,149 Natural Gas and NGLs Sales Under our natural gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to us for the resulting sales of NGLs and residue gas. For these contracts, we have concluded that the midstream processing entity is our customer. We recognize natural gas and NGL revenues based on the net amount of the proceeds received from the midstream processing. Oil Sales Our oil sales contracts are generally structured in one of the following ways: • We sell oil production at the wellhead and collect an agreed-upon index price, net of pricing differentials. In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead at the net price received. • We deliver oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title, and risk of loss of the product. Under this arrangement, we pay a third party to transport the product and receive a specified index price from the purchaser, net of pricing differentials. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as transportation and gathering in our consolidated statements of operations. Transaction Price Allocated to Remaining Performance Obligations A significant number of our product sales are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606-10-50-14(a) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Contract Balances Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not typically give rise to contract assets or liabilities under ASC 606. As of December 31, 2018 , we had contract assets recorded within other current assets of $1.4 million representing cash advances to customers which are expected to be realized within a year. Prior-Period Performance Obligations We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain sales may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales when that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2018 , revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. |
Other Commitments and Contingen
Other Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Other Commitments and Contingencies | Other Commitments and Contingencies Oil Commitments The Company entered into firm sales agreements for its oil production with four counterparties. Deliveries under three of the sales agreements have commenced. Deliveries under the fourth agreement are expected to commence in the first quarter of 2019. 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) 2019 5,090 2020 4,003 2021 1,672 2022 — 2023 — Thereafter — Total 10,765 During the years ended December 31, 2018 , 2017 , and 2016 , the Company incurred transportation deficiency charges of nil , $0.7 million , and $0.6 million , respectively. During 2018 , we were able to meet all of our delivery obligations, and we anticipate that our current gross operated production will continue to meet our future delivery obligations, although this cannot be guaranteed. Natural Gas Commitments In collaboration with several other producers and 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 ("Mewbourn 3") as well as the expansion of a related gathering system. Starting in August 2018, Mewbourn 3 was complete and in service. Our share of the commitment requires 46.4 MMcf per day to be delivered after the plant in-service date for a period of 7 years. • The second agreement includes an additional 200 MMcf per day processing plant ("O'Connor 2") as well as an incremental 100 MMcf per day of bypass and the expansion of a related gathering system. Construction of the plant is underway and it is expected to be placed into service in the second quarter of 2019. Our share of the commitment will require an additional 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. If we are unable to fulfill all of our contractual obligations and our obligations are not sufficiently reduced by the collective volumes delivered by other producers, we may be required to pay penalties or damages pursuant to these agreements. During 2018 , we were able to meet all of our delivery obligations and we anticipate that our current gross operated production will continue to meet our future delivery obligations. However, this cannot be guaranteed. 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 the Company's business, financial position, results of operations, or cash flows. Office Leases The Company’s principal office space located in Denver is under lease through July 2022. Current rent under the lease is approximately $66,000 per month. The Company also has a field office lease in Greeley which requires monthly payments of $7,500 through October 2021. Rent expense for office leases was $1.0 million , $1.1 million , and $1.0 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively. Vehicle Leases The Company has entered into a leasing arrangement for its vehicles used in our operations. These leases terminate 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-cancellable capital and operating leases as of December 31, 2018 follows (in thousands): Year ending December 31: Vehicles Leases Office Leases 2019 $ 183 $ 896 2020 183 916 2021 204 913 2022 167 500 2023 — Thereafter — — Total minimum lease payments $ 737 $ 3,225 Less: Amount representing estimated executory cost (60 ) Net minimum lease payments 677 Less: Amount representing interest (96 ) Present value of net minimum lease payments * $ 581 * Reflected in the balance sheet as current and non-current obligations of $0.1 million and $0.5 million , 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, 2018 | |
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, Supplemental cash flow information: 2018 2017 2016 Interest paid $ 36,134 $ 9,235 $ 3,779 Income taxes paid $ — $ — $ 106 Non-cash investing and financing activities: Accrued well costs as of period end $ 130,784 $ 54,877 $ 42,779 Asset retirement obligations incurred with development activities 4,174 3,398 773 Asset retirement obligations assumed with acquisitions 26,150 24,696 2,230 Obligations discharged with asset retirements and divestitures $ (12,267 ) $ (14,332 ) $ (4,739 ) Net changes in operating assets and liabilities: Accounts receivable $ (29,521 ) $ (72,518 ) $ (13,063 ) Accounts payable and accrued expenses 697 5,823 2,283 Revenue payable 30,219 47,345 2,254 Production taxes payable 38,489 33,311 (7,095 ) Other (341 ) (1,131 ) (790 ) Changes in operating assets and liabilities $ 39,543 $ 12,830 $ (16,411 ) |
Unaudited Oil and Gas Reserves
Unaudited Oil and Gas Reserves Information | 12 Months Ended |
Dec. 31, 2018 | |
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, 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 Revision of previous estimates 1,718 41,393 5,589 14,205 Purchase of reserves in place 5,398 63,367 6,474 22,433 Extensions, discoveries, and other additions 19,892 144,337 16,946 60,894 Sale of reserves in place — — — — Production (8,392 ) (37,123 ) (3,869 ) (18,448 ) Balance, December 31, 2018 88,012 771,867 89,093 305,749 Proved developed and undeveloped reserves: 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 Developed at December 31, 2018 37,102 324,169 36,427 127,557 Undeveloped at December 31, 2018 50,910 447,698 52,666 178,192 Balance, December 31, 2018 88,012 771,867 89,093 305,749 Notable changes in proved reserves for the year ended December 31, 2018 included: • Purchases of reserves in place. For the year ended December 31, 2018 , purchases of reserves in place of 22,433 MBOE were attributable to the various acquisitions and swaps executed during the year. 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 14,205 MBOE primarily as a result of increasing our density of proved undeveloped reserves. • Extensions and discoveries. For the year ended December 31, 2018, total extensions and discoveries of 60,894 MBOE were primarily attributable to extending our development plan by a year due to the passage of time and the drilling and completion of wells not previously proved. 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. 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. 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. 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, 2018 2017 2016 Future cash inflow $ 8,831,319 $ 5,493,507 $ 2,180,673 Future production costs (2,082,036 ) (1,291,369 ) (644,093 ) Future development costs (1,372,511 ) (1,048,856 ) (584,537 ) Future income tax expense (759,280 ) (285,349 ) (90,195 ) Future net cash flows 4,617,492 2,867,933 861,848 10% annual discount for estimated timing of cash flows (1,941,844 ) (1,267,258 ) (427,587 ) Standardized measure of discounted future net cash flows $ 2,675,648 $ 1,600,675 $ 434,261 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, 2018 (Average) $ 61.23 $ 2.07 $ 20.74 December 31, 2017 (Average) $ 46.57 $ 2.21 $ 16.06 December 31, 2016 (Average) $ 36.07 $ 2.44 $ — The prices for the December 31, 2018 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, 2018 through December 31, 2018 . The December 31, 2018 oil price of $61.23 per barrel (West Texas Intermediate Cushing) was $14.66 higher than the December 31, 2017 oil price of $46.57 per barrel. The December 31, 2018 natural gas price of $2.07 per Mcf (Henry Hub) was $0.14 lower than the December 31, 2017 price of $2.21 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, 2018 2017 2016 Standardized measure, beginning of period $ 1,600,675 $ 434,261 $ 390,953 Sale and transfers, net of production costs (533,385 ) (306,754 ) (81,468 ) Net changes in prices and production costs 538,404 135,525 (64,387 ) Extensions, discoveries, and improved recovery 760,575 811,564 18,795 Changes in estimated future development costs (23,712 ) (25,969 ) (6,016 ) Previously estimated development costs incurred during the period 248,739 170,296 62,502 Revision of quantity estimates 176,264 165,267 (110,306 ) Accretion of discount 175,628 47,635 44,703 Net change in income taxes (329,894 ) (113,523 ) 5,104 Divestitures of reserves — (7,157 ) (26,839 ) Purchase of reserves in place 176,707 260,999 228,855 Changes in timing and other (114,353 ) 28,531 (27,635 ) Standardized measure, end of period $ 2,675,648 $ 1,600,675 $ 434,261 |
Unaudited Financial Data
Unaudited Financial Data | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 147,233 $ 147,087 $ 160,978 $ 190,343 Expenses 69,875 79,833 81,051 140,599 Operating income 77,358 67,254 79,927 49,744 Other income (expense) (5,751 ) (14,283 ) (8,381 ) 52,121 Income before income taxes 71,607 52,971 71,546 101,865 Income tax expense 5,811 3,347 8,918 19,891 Net income $ 65,796 $ 49,624 $ 62,628 $ 81,974 Net income per common share: (1) Basic $ 0.27 $ 0.20 $ 0.26 $ 0.34 Diluted (2) $ 0.27 $ 0.20 $ 0.26 $ 0.34 Weighted-average shares outstanding: Basic 241,751,915 242,255,724 242,536,781 242,678,465 Diluted 243,166,897 244,464,776 243,560,046 243,032,793 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 1 The sum of net income 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 per share as the inclusion of the common share equivalents was anti-dilutive. |
Organization and Summary of S_2
Organization and Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
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"). |
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. |
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 lease 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 retirement 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 in 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 years ended December 31, 2018 and 2017 , the Company did not recognize any ceiling test impairments. During the year ended December 31, 2016, the Company recognized ceiling test impairments of $215.2 million . 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. |
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 retired. Calculation of an asset retirement obligation ("ARO") requires estimates about several future events, including the life of the asset, the costs to retire the asset, 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: 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 perform the annual impairment assessment as of October 1. 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. The Company performed its annual goodwill impairment test as of October 1, 2018 and determined that no impairment had occurred. However, as a result of a sustained decrease in the price of our common stock during the fourth quarter of 2018 caused by a significant decline in oil prices over the same period, the Company performed another goodwill impairment test as of December 31, 2018. The impairment test performed by the Company indicated that the carrying value of its reporting unit exceeded its fair value and that an impairment loss should be recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to the reporting unit . Based on these results, the Company recorded a non-cash impairment charge of $40.7 million , reducing the carrying value of goodwill to zero. 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 and contain considerable management judgments. |
Oil and Natural Gas Sales | 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. 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. Once a grant date has been established, the compensation is recognized over the remaining 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, 2018 . The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of December 31, 2018 , the Company has not recognized any interest or penalties related to uncertain tax benefits. |
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 in 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 May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update ("ASU") 2014-09, "Revenue from Contracts with Customers (Topic 606)" ("ASU 2014-09"), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 (collectively with ASU 2014-09, the "Revenue ASUs") to clarify principal versus agent considerations. The Revenue ASUs allow for the use of either the full or modified retrospective transition method, and the standard became effective for annual reporting periods beginning after December 15, 2017 including interim periods within that period. The Company adopted the guidance using the modified retrospective method with the effective date of January 1, 2018. The Company did not record a cumulative-effect adjustment to the opening balance of retained earnings as no adjustment was necessary. The adoption of the Revenue ASUs did not impact net income or cash flows. See Note 15 for the new disclosures required by the Revenue ASUs. 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 in the balance sheet and disclosing key information about leasing arrangements. For leases with terms of more than 12 months, ASU 2016-02 requires lessees to recognize a right-of-use asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. Both the lease asset and liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, including the presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. In January 2018, the FASB issued "Update No. 2018-01 Leases (Topic 842) - Land Easement Practical Expedient for Transition to Topic 842", which permits an entity to elect an optional transition practical expedient to not evaluate land easements existing or expiring before the entity’s adoption of ASU 2016-02 and not previously accounted for as leases. Furthermore, in July 2018, the FASB issued "Update No. 2018-11 Leases (Topic 842): Targeted Improvements", which provides for an additional transition method that allows an entity to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings (deficit) in the period of adoption. For example, comparative periods presented in the financial statements will continue to be in accordance with current guidance, Topic 840, Leases. Collectively, ASU 2016-02 and the subsequent updates will be referred to as "ASU 2016-02, as amended". The guidance is effective for fiscal years beginning after December 15, 2018 and interim periods within those years, with early adoption permitted. ASU 2016-02, as amended does not apply to leases of mineral rights to explore for or use crude oil and natural gas. In the normal course of business, we enter into contracts to support our exploration and development operations including contracts for drilling rigs, field services, well equipment, pipeline capacity, office space, and other assets. Although we are continuing to assess the full effect the guidance will have on our existing accounting policies and our consolidated financial statements, we expect that there will be an increase in disclosures and an increase in assets and liabilities in our consolidated balance sheets upon adoption due to the recording of right-of-use assets and corresponding lease liabilities . We are reviewing contracts, have contracted for lease accounting software, and are researching pertinent matters to accommodate adoption of this guidance. 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 S_3
Organization and Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Accounts Payable and Accrued Expenses | Accounts payable and accrued expenses consist of the following (in thousands): As of December 31, 2018 2017 Trade accounts payable $ 2,029 $ 624 Accrued well costs 130,784 56,348 Accrued G&A 4,913 6,017 Accrued LOE 8,366 5,249 Accrued interest 3,574 3,125 Accrued other 344 3,309 $ 150,010 $ 74,672 |
Schedule of Customers With Balances Greater Than 10% of Total Receivables | 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, 2018 2017 Company A 15% 26% Company B 13% 16% Company C 12% 23% Company D 12% * Company E * 11% * less than 10% 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, 2018 2017 2016 Company A 22% 33% * Company B 20% 24% 20% Company C 17% * * Company D 13% 17% 20% Company E 13% * * Company F * * 16% Company G * * 13% * less than 10% |
Property and Equipment (Tables)
Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 2017 Oil and gas properties, full cost method: Costs of proved properties: Producing and non-producing $ 2,385,958 $ 1,629,789 Less, accumulated depletion and full cost ceiling impairments (840,513 ) (659,205 ) Subtotal, proved properties, net 1,545,445 970,584 Costs of wells in progress 227,262 106,269 Costs of unproved properties and land, not subject to depletion: Lease acquisition and other costs 731,058 786,469 Land 9,395 7,200 Subtotal, unproved properties and land 740,453 793,669 Costs of other property and equipment: Other property and equipment 9,642 8,134 Less, accumulated depreciation (4,102 ) (2,080 ) Subtotal, other property and equipment, net 5,540 6,054 Total property and equipment, net $ 2,518,700 $ 1,876,576 |
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, 2018 2017 2016 Capitalized overhead $ 12,775 $ 10,293 $ 7,074 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, 2018 2017 2016 Acquisition of property: Unproved $ 46,039 $ 538,489 $ 365,548 Proved 136,652 139,154 152,363 Exploration costs — — 43,154 Development costs 583,660 460,875 87,782 Other property and equipment and land 3,039 4,397 7,506 Capitalized interest, capitalized G&A, and other 57,039 26,677 18,744 Total costs incurred $ 826,429 $ 1,169,592 $ 675,097 |
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, 2018 (in thousands): Period Incurred Year Ended December 31, Prior to January 1, 2016 Total as of December 31, 2018 2018 2017 2016 Unproved leasehold acquisition costs $ 78,743 $ 460,627 $ 175,666 $ 16,022 $ 731,058 Unproved development costs 50,083 — — — 50,083 Total unevaluated costs $ 128,826 $ 460,627 $ 175,666 $ 16,022 $ 781,141 |
Depletion, depreciation and a_2
Depletion, depreciation and accretion ("DD&A") (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Other Costs and Disclosures [Abstract] | |
Schedule of Depletion, Depreciation and Amortization | DD&A consisted of the following (in thousands): Year Ended December 31, 2018 2017 2016 Depletion of oil and gas properties $ 175,441 $ 109,287 $ 45,193 Depreciation and accretion 4,332 3,022 1,485 Total DD&A Expense $ 179,773 $ 112,309 $ 46,678 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 2017 Beginning asset retirement obligation $ 31,622 $ 16,458 Obligations incurred with development activities 4,174 3,398 Obligations assumed with acquisitions 26,150 24,696 Accretion expense 2,310 1,554 Obligations discharged with asset retirements and divestitures (12,267 ) (14,332 ) Revisions in previous estimates (243 ) (152 ) Ending asset retirement obligation $ 51,746 $ 31,622 Less, current portion (11,694 ) (3,246 ) Non-current portion $ 40,052 $ 28,376 |
Commodity Derivative Instrume_2
Commodity Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Commodity Derivative Contracts | The Company’s commodity derivative contracts as of December 31, 2018 are summarized below: Settlement Period Derivative Instrument Volumes (Bbls per day) Weighted Average Floor Price Weighted Average Ceiling Price Crude Oil - NYMEX WTI Jan 1, 2019 - Dec 31, 2019 Collar 6,000 $ 55.00 $ 74.31 Settlement Period Derivative Volumes (MMBtu per day) Weighted Average Floor Price Weighted Average Ceiling Price Natural Gas - NYMEX Henry Hub Jan 1, 2019 - Mar 31, 2019 Collar 30,000 $ 3.00 $ 4.50 Apr 1, 2019 - Dec 31, 2019 Collar 30,000 $ 3.00 $ 3.50 Settlement Period Derivative Instrument Volumes Weighted-Average Fixed Basis Difference Natural Gas - CIG Rocky Mountain Jan 1, 2019 - Dec 31, 2019 Swap 30,000 $ (0.75 ) Jan 1, 2019 - Mar 31, 2019 Swap 30,000 $ (0.56 ) Settlement Period Derivative Volumes Weighted-Average Fixed Price Natural Gas - NYMEX Henry Hub (MMBtu per day) Jan 1, 2019 - Mar 31, 2019 Swap 60,000 $ 4.00 Propane - Mont Belvieu (Bbls per day) Jan 1, 2019 - Dec 31, 2019 Swap 2,000 $ 37.52 |
Schedule of Fair Value of Derivatives | The following table provides a reconciliation between the net assets and liabilities reflected in 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, 2018 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 $ 39,485 $ (4,579 ) $ 34,906 Commodity derivative contracts Non-current assets $ — $ — $ — Commodity derivative contracts Current liabilities $ 4,579 $ (4,579 ) $ — Commodity derivative contracts Non-current liabilities $ — $ — $ — 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 $ — $ — $ — |
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, 2018 2017 2016 Realized gain (loss) on commodity derivatives $ (19,359 ) $ 39 $ 2,355 Unrealized gain (loss) on commodity derivatives 42,772 (4,265 ) (10,105 ) Total gain (loss) $ 23,413 $ (4,226 ) $ (7,750 ) |
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, 2018 2017 2016 Monthly settlements $ (19,359 ) $ 1,062 $ 4,396 Previously incurred premiums attributable to settled commodity contracts — (1,023 ) (2,041 ) Total realized gain (loss) $ (19,359 ) $ 39 $ 2,355 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 Level 1 Level 2 Level 3 Total Financial assets and liabilities: Commodity derivative asset $ — $ 34,906 $ — $ 34,906 Commodity derivative liability $ — $ — $ — $ — 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 |
Interest Expense (Tables)
Interest Expense (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Interest and Debt Expense [Abstract] | |
Schedule of the Components of Interest Expense | The components of interest expense are (in thousands): Year Ended December 31, 2018 2017 2016 Revolving credit facility $ 2,209 $ 2,004 $ 154 Notes payable 34,375 10,036 3,940 Amortization of debt issuance costs and other 3,926 3,084 1,638 Debt extinguishment costs — 11,842 — Less: interest capitalized (40,510 ) (15,124 ) (5,732 ) Interest expense, net $ — $ 11,842 $ — |
Equity and Stock-Based Compen_2
Equity and Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of Stock-based Compensation Expense Recognized | The amount of stock-based compensation was as follows (in thousands): Year Ended December 31, 2018 2017 2016 Stock options $ 4,543 $ 5,076 $ 5,417 Performance-vested stock units 4,212 2,938 1,047 Restricted stock units and stock bonus shares 5,972 4,977 4,232 Total stock-based compensation 14,727 12,991 10,696 Less: stock-based compensation capitalized (2,440 ) (1,766 ) (1,205 ) Total stock-based compensation expense $ 12,287 $ 11,225 $ 9,491 |
Schedule of Employee Stock Options Granted During the Period | No stock options were granted during the years ended December 31, 2018 and 2017 . During the period presented, the Company granted the following stock options: Year Ended December 31, 2016 Number of options to purchase common shares 1,067,500 Weighted-average exercise price $ 7.19 Term (in years) 10 years Vesting Period (in years) 3 - 5 years Fair Value (in thousands) $ 3,860 |
Schedule of Assumptions Used In Valuing Stock Options | The assumptions used in valuing the TSR PSUs granted were as follows: Year Ended December 31, 2018 2017 2016 Weighted-average expected term 2.8 years 2.9 years 2.7 years Weighted-average expected volatility 52 % 59 % 58 % Weighted-average risk-free rate 2.41 % 1.34 % 0.87 % The assumptions used in valuing stock options granted during the period presented were as follows: Year Ended December 31, 2016 Expected term 6.4 years Expected volatility 55 % Risk-free rate 1.25 - 2.00% 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, 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 Granted — — Exercised (823,883 ) 5.36 4,611 Expired (37,400 ) 11.22 Forfeited (122,917 ) 9.93 Outstanding, December 31, 2018 4,652,634 $ 10.06 6.4 years $ 49 Outstanding, Exercisable at December 31, 2018 3,278,330 $ 10.28 6.2 years $ 49 |
Schedule of Issued and Outstanding Stock Options | The following table summarizes information about issued and outstanding stock options as of December 31, 2018 : 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 35,000 $ 3.31 3.5 years 35,000 $ 3.31 3.5 years $5.00 - $6.99 723,800 6.30 6.5 years 398,600 6.28 5.7 years $7.00 - $10.99 1,360,334 9.42 6.4 years 897,630 9.50 6.2 years $11.00 - $13.46 2,533,500 11.57 6.4 years 1,947,100 11.58 6.4 years Total 4,652,634 $ 10.06 6.4 years 3,278,330 $ 10.28 6.2 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, 2018 , which will be recognized ratably over the remaining vesting period, is as follows: Unrecognized compensation (in thousands) $ 8,992 Remaining vesting period 2.1 years The estimated unrecognized compensation cost from stock options not vested as of December 31, 2018 , which will be recognized ratably over the remaining vesting period, is as follows: Unrecognized compensation (in thousands) $ 4,504 Remaining vesting period 1.7 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, 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 Granted 1,130,388 7.76 Vested (478,517 ) 8.96 Forfeited (99,339 ) 9.28 Not vested, December 31, 2018 1,639,918 $ 8.07 |
Schedule of Nonvested Share Activity | A summary of the status and activity of TSR 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 Granted 321,507 13.11 Vested (465,188 ) 8.09 Forfeited (28,175 ) 10.15 Not vested, December 31, 2018 780,028 $ 11.73 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. |
Weighted-Average Shares Outst_2
Weighted-Average Shares Outstanding (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 2017 2016 Weighted-average shares outstanding - basic 242,308,893 206,167,506 173,774,035 Potentially dilutive common shares from: Stock options 229,946 417,809 — TSR PSUs 1 175,412 — — Restricted stock units and stock bonus shares 306,751 158,236 — Weighted-average shares outstanding - diluted 243,021,002 206,743,551 173,774,035 1 The number of awards assumes that the associated vesting condition is met at the respective period end based on market prices as of the respective period end. 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. |
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, 2018 2017 2016 Potentially dilutive common shares from: Stock options 1 3,747,634 4,657,834 6,001,500 TSR PSUs 1,2 314,533 951,884 478,510 Goal-Based PSUs 2,3 274,898 — — Restricted stock units and stock bonus shares 1 49,907 285,448 890,336 Total 4,386,972 5,895,166 7,370,346 1 Potential common shares excluded from the weighted-average shares outstanding-diluted calculation as the securities had an anti-dilutive effect on earnings per share. 2 The number of awards reflects the target amount of shares granted. 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. 3 Potential common shares excluded from the weighted-average shares outstanding-diluted calculation as the securities are considered contingently issuable, and the performance criteria are not considered met as of period end. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 2017 2016 Current: Federal $ — $ (99 ) $ 106 State — — — Total current income tax expense (benefit) — (99 ) 106 Deferred: Federal 72,898 48,631 (74,099 ) State 12,697 4,371 (6,651 ) Total deferred income tax (benefit) expense 85,595 53,002 (80,750 ) Valuation allowance (47,628 ) (53,002 ) 80,750 Income tax expense (benefit) $ 37,967 $ (99 ) $ 106 |
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, 2018 2017 2016 Federal income tax at statutory rate $ 62,578 $ 48,410 $ (74,489 ) State income taxes, net of federal tax 12,697 4,371 (6,685 ) Statutory depletion (113 ) (159 ) (287 ) Stock-based compensation (296 ) 50 383 Non-deductible compensation 598 — — Impact of tax reform, net of valuation allowance — (99 ) Valuation allowance (47,628 ) (53,002 ) 80,750 Goodwill impairment 8,549 — — Other 1,582 330 434 Income tax expense (benefit) $ 37,967 $ (99 ) $ 106 Effective rate expressed as a percentage 13 % — % — % |
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, 2018 2017 Deferred tax assets (liabilities): Net operating loss carryforward $ 111,587 $ 43,283 Stock-based compensation 6,984 5,237 Basis of oil and gas properties (150,080 ) (5,011 ) Statutory depletion 2,434 2,795 Unrealized loss on commodity derivative (8,607 ) 1,939 Other (285 ) (615 ) (37,967 ) 47,628 Valuation allowance on tax assets — (47,628 ) Deferred tax liability, net $ (37,967 ) $ — |
Revenue from Contract with Cu_2
Revenue from Contract with Customer (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | Year Ended December 31, Revenues (in thousands): 2018 2017 2016 Oil $ 494,052 $ 261,505 $ 77,699 Natural Gas and NGLs 151,589 101,011 29,450 $ 645,641 $ 362,516 $ 107,149 |
Other Commitments and Conting_2
Other Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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) 2019 5,090 2020 4,003 2021 1,672 2022 — 2023 — Thereafter — Total 10,765 |
Lease Payments Under Capital and Operating Leases | A schedule of the minimum lease payments under non-cancellable capital and operating leases as of December 31, 2018 follows (in thousands): Year ending December 31: Vehicles Leases Office Leases 2019 $ 183 $ 896 2020 183 916 2021 204 913 2022 167 500 2023 — Thereafter — — Total minimum lease payments $ 737 $ 3,225 Less: Amount representing estimated executory cost (60 ) Net minimum lease payments 677 Less: Amount representing interest (96 ) Present value of net minimum lease payments * $ 581 * Reflected in the balance sheet as current and non-current obligations of $0.1 million and $0.5 million , respectively, within "Accounts payable and accrued expenses" and "Other liabilities," respectively. |
Supplemental Schedule of Info_2
Supplemental Schedule of Information to the Statements of Cash Flows (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, Supplemental cash flow information: 2018 2017 2016 Interest paid $ 36,134 $ 9,235 $ 3,779 Income taxes paid $ — $ — $ 106 Non-cash investing and financing activities: Accrued well costs as of period end $ 130,784 $ 54,877 $ 42,779 Asset retirement obligations incurred with development activities 4,174 3,398 773 Asset retirement obligations assumed with acquisitions 26,150 24,696 2,230 Obligations discharged with asset retirements and divestitures $ (12,267 ) $ (14,332 ) $ (4,739 ) Net changes in operating assets and liabilities: Accounts receivable $ (29,521 ) $ (72,518 ) $ (13,063 ) Accounts payable and accrued expenses 697 5,823 2,283 Revenue payable 30,219 47,345 2,254 Production taxes payable 38,489 33,311 (7,095 ) Other (341 ) (1,131 ) (790 ) Changes in operating assets and liabilities $ 39,543 $ 12,830 $ (16,411 ) |
Unaudited Oil and Gas Reserve_2
Unaudited Oil and Gas Reserves Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 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 Revision of previous estimates 1,718 41,393 5,589 14,205 Purchase of reserves in place 5,398 63,367 6,474 22,433 Extensions, discoveries, and other additions 19,892 144,337 16,946 60,894 Sale of reserves in place — — — — Production (8,392 ) (37,123 ) (3,869 ) (18,448 ) Balance, December 31, 2018 88,012 771,867 89,093 305,749 Proved developed and undeveloped reserves: 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 Developed at December 31, 2018 37,102 324,169 36,427 127,557 Undeveloped at December 31, 2018 50,910 447,698 52,666 178,192 Balance, December 31, 2018 88,012 771,867 89,093 305,749 |
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, 2018 2017 2016 Future cash inflow $ 8,831,319 $ 5,493,507 $ 2,180,673 Future production costs (2,082,036 ) (1,291,369 ) (644,093 ) Future development costs (1,372,511 ) (1,048,856 ) (584,537 ) Future income tax expense (759,280 ) (285,349 ) (90,195 ) Future net cash flows 4,617,492 2,867,933 861,848 10% annual discount for estimated timing of cash flows (1,941,844 ) (1,267,258 ) (427,587 ) Standardized measure of discounted future net cash flows $ 2,675,648 $ 1,600,675 $ 434,261 |
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, 2018 (Average) $ 61.23 $ 2.07 $ 20.74 December 31, 2017 (Average) $ 46.57 $ 2.21 $ 16.06 December 31, 2016 (Average) $ 36.07 $ 2.44 $ — |
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, 2018 2017 2016 Standardized measure, beginning of period $ 1,600,675 $ 434,261 $ 390,953 Sale and transfers, net of production costs (533,385 ) (306,754 ) (81,468 ) Net changes in prices and production costs 538,404 135,525 (64,387 ) Extensions, discoveries, and improved recovery 760,575 811,564 18,795 Changes in estimated future development costs (23,712 ) (25,969 ) (6,016 ) Previously estimated development costs incurred during the period 248,739 170,296 62,502 Revision of quantity estimates 176,264 165,267 (110,306 ) Accretion of discount 175,628 47,635 44,703 Net change in income taxes (329,894 ) (113,523 ) 5,104 Divestitures of reserves — (7,157 ) (26,839 ) Purchase of reserves in place 176,707 260,999 228,855 Changes in timing and other (114,353 ) 28,531 (27,635 ) Standardized measure, end of period $ 2,675,648 $ 1,600,675 $ 434,261 |
Unaudited Financial Data (Table
Unaudited Financial Data (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 147,233 $ 147,087 $ 160,978 $ 190,343 Expenses 69,875 79,833 81,051 140,599 Operating income 77,358 67,254 79,927 49,744 Other income (expense) (5,751 ) (14,283 ) (8,381 ) 52,121 Income before income taxes 71,607 52,971 71,546 101,865 Income tax expense 5,811 3,347 8,918 19,891 Net income $ 65,796 $ 49,624 $ 62,628 $ 81,974 Net income per common share: (1) Basic $ 0.27 $ 0.20 $ 0.26 $ 0.34 Diluted (2) $ 0.27 $ 0.20 $ 0.26 $ 0.34 Weighted-average shares outstanding: Basic 241,751,915 242,255,724 242,536,781 242,678,465 Diluted 243,166,897 244,464,776 243,560,046 243,032,793 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 1 The sum of net income 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 per share as the inclusion of the common share equivalents was anti-dilutive. |
Organization and Summary of S_4
Organization and Summary of Significant Accounting Policies (Narrative) (Details) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2018USD ($)segmentreporting | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Aug. 31, 2015 | |
Item Effected [Line Items] | ||||
Number of operating segments | segment | 1 | |||
Net cash flows, discount rate (percent) | 10.00% | 10.00% | ||
Full cost ceiling impairment | $ 0 | $ 0 | $ 215,223 | |
Number of reporting units | reporting | 1 | |||
Goodwill impairment | $ 40,711 | $ 0 | $ 0 | |
Remittance period | 30 days | |||
Minimum | ||||
Item Effected [Line Items] | ||||
Estimated useful lives | P3Y | |||
Maximum | ||||
Item Effected [Line Items] | ||||
Estimated useful lives | P5Y | |||
Building | ||||
Item Effected [Line Items] | ||||
Estimated useful lives | P39Y |
Organization and Summary of S_5
Organization and Summary of Significant Accounting Policies (Schedule of Accounts Payable and Accrued Expenses) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Trade accounts payable | $ 2,029 | $ 624 |
Accrued well costs | 130,784 | 56,348 |
Accrued G&A | 4,913 | 6,017 |
Accrued LOE | 8,366 | 5,249 |
Accrued interest | 3,574 | 3,125 |
Accrued other | 344 | 3,309 |
Accounts payable and accrued expenses | $ 150,010 | $ 74,672 |
Organization and Summary of S_6
Organization and Summary of Significant Accounting Policies (Schedule of Customer Concentration Risk) (Details) - Customer Concentration Risk | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Sales Revenue, Goods, Net | Company A | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 22.00% | 33.00% | |
Sales Revenue, Goods, Net | Company B | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 20.00% | 24.00% | 20.00% |
Sales Revenue, Goods, Net | Company C | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 17.00% | ||
Sales Revenue, Goods, Net | Company D | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 13.00% | 17.00% | 20.00% |
Sales Revenue, Goods, Net | Company E | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 13.00% | ||
Sales Revenue, Goods, Net | Company F | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 16.00% | ||
Sales Revenue, Goods, Net | Company G | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 13.00% | ||
Accounts Receivable | Company A | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 15.00% | 26.00% | |
Accounts Receivable | Company B | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 13.00% | 16.00% | |
Accounts Receivable | Company C | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 12.00% | 23.00% | |
Accounts Receivable | Company D | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 12.00% | ||
Accounts Receivable | Company E | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 11.00% |
Property and Equipment (Schedul
Property and Equipment (Schedule of Capitalized Costs) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Costs of proved properties: | ||
Producing and non-producing | $ 2,385,958 | $ 1,629,789 |
Less, accumulated depletion and full cost ceiling impairments | (840,513) | (659,205) |
Subtotal, proved properties, net | 1,545,445 | 970,584 |
Costs of wells in progress | 227,262 | 106,269 |
Costs of unproved properties and land, not subject to depletion: | ||
Unproved properties and land | 740,453 | 793,669 |
Costs of other property and equipment: | ||
Other property and equipment | 9,642 | 8,134 |
Less, accumulated depreciation | (4,102) | (2,080) |
Subtotal, other property and equipment, net | 5,540 | 6,054 |
Total property and equipment, net | 2,518,700 | 1,876,576 |
Land | ||
Costs of unproved properties and land, not subject to depletion: | ||
Unproved properties and land | 9,395 | 7,200 |
Unproved leasehold acquisition costs | ||
Costs of unproved properties and land, not subject to depletion: | ||
Unproved properties and land | $ 731,058 | $ 786,469 |
Property and Equipment (Narrati
Property and Equipment (Narrative) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Reserve Quantities [Line Items] | |||
Full cost ceiling impairment | $ 0 | $ 0 | $ 215,223 |
Unproved properties impairment | 0 | 0 | 215,223 |
Unproved properties | |||
Reserve Quantities [Line Items] | |||
Unproved properties impairment | $ 1,200 | $ 0 | $ 18,900 |
Property and Equipment (Sched_2
Property and Equipment (Schedule of Capitalized Overhead) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |||
Capitalized overhead | $ 12,775 | $ 10,293 | $ 7,074 |
Property and Equipment (Sched_3
Property and Equipment (Schedule of Costs Incurred) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Acquisition of property: | |||
Unproved | $ 46,039 | $ 538,489 | $ 365,548 |
Proved | 136,652 | 139,154 | 152,363 |
Exploration costs | 0 | 0 | 43,154 |
Development costs | 583,660 | 460,875 | 87,782 |
Other property and equipment and land | 3,039 | 4,397 | 7,506 |
Capitalized interest, capitalized G&A, and other | 57,039 | 26,677 | 18,744 |
Total costs incurred | $ 826,429 | $ 1,169,592 | $ 675,097 |
Property and Equipment (Sched_4
Property and Equipment (Schedule of Capitalized Costs Excluded from Amortization) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Property, Plant and Equipment [Line Items] | ||||
Total unevaluated costs | $ 128,826 | $ 460,627 | $ 175,666 | $ 16,022 |
Unevaluated costs, not subject to amortization | 781,141 | |||
Unproved leasehold acquisition costs | ||||
Property, Plant and Equipment [Line Items] | ||||
Total unevaluated costs | 78,743 | 460,627 | 175,666 | 16,022 |
Unevaluated costs, not subject to amortization | 731,058 | |||
Unproved development costs | ||||
Property, Plant and Equipment [Line Items] | ||||
Total unevaluated costs | 50,083 | $ 0 | $ 0 | $ 0 |
Unevaluated costs, not subject to amortization | $ 50,083 |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Narrative) (Details) $ in Thousands | 1 Months Ended | 12 Months Ended | |||||||
Sep. 30, 2018USD ($) | Aug. 31, 2018USD ($) | Dec. 31, 2017USD ($)a | Sep. 30, 2017USD ($)a | Aug. 31, 2017USD ($)a | Mar. 31, 2017USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($)a | Dec. 31, 2016USD ($) | |
Business Acquisition [Line Items] | |||||||||
Mineral acres, net | a | 30,200 | 33,100 | 30,200 | ||||||
Total purchase price | $ 37,500 | ||||||||
Cash | 37,200 | ||||||||
Mineral acres, gross | a | 72,000 | ||||||||
Proceeds from sales of oil and gas properties and other | $ 1,627 | $ 93,573 | $ 25,350 | ||||||
Disposal Group, disposed of by sale, not discontinued operations | |||||||||
Business Acquisition [Line Items] | |||||||||
Asset retirement obligations | $ 5,200 | $ 5,200 | |||||||
Acres disposed of in sale | a | 16,000 | 16,000 | |||||||
Proceeds from sales of oil and gas properties and other | $ 91,600 | ||||||||
Assumption of liabilities | $ 22,200 | $ 22,200 | |||||||
Greeley-Crescent Agreement II | D-J Basin, Colorado | |||||||||
Business Acquisition [Line Items] | |||||||||
Total purchase price | 577,500 | ||||||||
Cash | 576,400 | ||||||||
Greeley-Crescent Agreement | D-J Basin, Colorado | |||||||||
Business Acquisition [Line Items] | |||||||||
Total purchase price | $ 96,900 | $ 30,300 | |||||||
Cash | 64,200 | 6,300 | |||||||
Net liabilities assumed | 32,700 | 24,000 | |||||||
Asset retirement obligations | $ 25,800 | ||||||||
Cash held in escrow and other deposits | 18,200 | ||||||||
Escrow balance returned to company | 11,400 | ||||||||
Assumed asset retirement obligations | $ 20,900 | ||||||||
Private party August 2017 | |||||||||
Business Acquisition [Line Items] | |||||||||
Total purchase price | $ 22,600 | ||||||||
Mineral acres, gross | a | 1,000 | ||||||||
Series of individually immaterial business acquisitions | |||||||||
Business Acquisition [Line Items] | |||||||||
Total purchase price | $ 25,100 | ||||||||
Proved oil and gas properties | |||||||||
Business Acquisition [Line Items] | |||||||||
Total purchase price | 23,900 | ||||||||
Proved oil and gas properties | Greeley-Crescent Agreement II | D-J Basin, Colorado | |||||||||
Business Acquisition [Line Items] | |||||||||
Total purchase price | 60,800 | ||||||||
Proved oil and gas properties | Private party August 2017 | |||||||||
Business Acquisition [Line Items] | |||||||||
Total purchase price | $ 6,700 | ||||||||
Proved oil and gas properties | Series of individually immaterial business acquisitions | |||||||||
Business Acquisition [Line Items] | |||||||||
Total purchase price | 15,300 | ||||||||
Unproved properties | |||||||||
Business Acquisition [Line Items] | |||||||||
Total purchase price | $ 13,600 | ||||||||
Unproved properties | Greeley-Crescent Agreement II | D-J Basin, Colorado | |||||||||
Business Acquisition [Line Items] | |||||||||
Total purchase price | $ 516,700 | ||||||||
Unproved properties | Private party August 2017 | |||||||||
Business Acquisition [Line Items] | |||||||||
Total purchase price | $ 15,900 | ||||||||
Unproved properties | Series of individually immaterial business acquisitions | |||||||||
Business Acquisition [Line Items] | |||||||||
Total purchase price | 9,400 | ||||||||
Other assets and land | Series of individually immaterial business acquisitions | |||||||||
Business Acquisition [Line Items] | |||||||||
Total purchase price | $ 400 |
Depletion, depreciation and a_3
Depletion, depreciation and accretion ("DD&A") (Details) Boe in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018USD ($)Boe$ / Boe | Dec. 31, 2017USD ($)Boe$ / Boe | Dec. 31, 2016USD ($)Boe$ / Boe | |
Other Costs and Disclosures [Abstract] | |||
Depletion of oil and gas properties | $ 175,441 | $ 109,287 | $ 45,193 |
Depreciation and accretion | 4,332 | 3,022 | 1,485 |
Total DDA Expense | $ 179,773 | $ 112,309 | $ 46,678 |
Production of BOE (in Boe's) | Boe | 18,448 | 12,481 | 4,271 |
Percentage of total reserves | 5.70% | 5.20% | 4.40% |
DDA expense per BOE (in dollars per BOE) | $ / Boe | 9.74 | 9 | 10.93 |
Asset Retirement Obligations (S
Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning asset retirement obligation | $ 31,622 | $ 16,458 |
Obligations incurred with development activities | 4,174 | 3,398 |
Obligations assumed with acquisitions | 26,150 | 24,696 |
Accretion expense | 2,310 | 1,554 |
Obligations discharged with asset retirements and divestitures | (12,267) | (14,332) |
Revisions in previous estimates | (243) | (152) |
Ending asset retirement obligation | 51,746 | 31,622 |
Less, current portion | (11,694) | (3,246) |
Non-current portion | $ 40,052 | $ 28,376 |
Revolving Credit Facility (Deta
Revolving Credit Facility (Details) | 12 Months Ended | ||
Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Apr. 02, 2018USD ($) | |
Line of Credit Facility [Line Items] | |||
Amount outstanding | $ 195,000,000 | $ 0 | |
Line of credit | Bridge Loan | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | $ 25,000,000 | ||
Line of credit | Revolving credit facility | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | 1,500,000,000 | ||
Elected borrowing amount | 500,000,000 | ||
Line borrowing base | $ 650,000,000 | ||
Interest rate during period | 4.20% | 3.40% | |
Maximum funded debt to EBITDAX | 4 | ||
Current ratio covenant | 1 | ||
Line of credit | Letter of credit | |||
Line of Credit Facility [Line Items] | |||
Amount outstanding | $ 0 |
Notes Payable (Details)
Notes Payable (Details) - USD ($) | 1 Months Ended | 12 Months Ended | ||
Nov. 30, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Debt Instrument [Line Items] | ||||
Payments of Debt Issuance Costs | $ 2,588,000 | $ 13,145,000 | $ 5,159,000 | |
Senior notes | 6.25% Senior Notes Due 2025 | ||||
Debt Instrument [Line Items] | ||||
Face value of promissory note | $ 550,000,000 | |||
Debt instrument stated interest rate (percent) | 6.25% | |||
Proceeds from sale of Senior Notes | $ 538,100,000 | |||
Payments of Debt Issuance Costs | $ 11,900,000 | |||
Debt instrument effective interest rate (percent) | 6.60% | |||
Senior notes | 9% Senior notes due 2021 | ||||
Debt Instrument [Line Items] | ||||
Redemption price (percent) | 100.00% | |||
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 Instrume_3
Commodity Derivative Instruments (Schedule of Commodity Derivative Contracts) (Details) bbl / d in Thousands, MMBTU / d in Thousands | 12 Months Ended |
Dec. 31, 2018bbl / dMMBTU / d$ / bbl$ / MMBTU | |
Crude Oil | Jan 1, 2019 - Dec 31, 2019 | Collar | |
Derivatives, Fair Value [Line Items] | |
Average Volume (BBl's per day) | bbl / d | 6 |
Floor Price | $ / bbl | 55 |
Ceiling Price | $ / bbl | 74.31 |
Natural Gas | Jan 1, 2019 - Dec 31, 2019 | Swap | |
Derivatives, Fair Value [Line Items] | |
Average Volumes (MMBtu per day) | MMBTU / d | 30 |
Average fixed price (in dollars per gallon) | (0.75) |
Natural Gas | Jan 1, 2019 - Mar 31, 2019 | Collar | |
Derivatives, Fair Value [Line Items] | |
Average Volumes (MMBtu per day) | MMBTU / d | 30 |
Floor Price | 3 |
Ceiling Price | 4.50 |
Natural Gas | Jan 1, 2019 - Mar 31, 2019 | Swap | |
Derivatives, Fair Value [Line Items] | |
Average Volumes (MMBtu per day) | MMBTU / d | 30 |
Average fixed price (in dollars per gallon) | (0.56) |
Natural Gas | Apr 1, 2019 - Dec 31, 2019 | Collar | |
Derivatives, Fair Value [Line Items] | |
Average Volumes (MMBtu per day) | MMBTU / d | 30 |
Floor Price | 3 |
Ceiling Price | 3.50 |
Natural Gas | Jan 1, 2019 - Mar 31, 2019 | Swap | |
Derivatives, Fair Value [Line Items] | |
Average Volumes (MMBtu per day) | MMBTU / d | 60 |
Floor Price | 4 |
Propane | Jan 1, 2019 - Dec 31, 2019 | Swap | |
Derivatives, Fair Value [Line Items] | |
Average Volumes (MMBtu per day) | bbl / d | 2 |
Floor Price | $ / bbl | 37.52 |
Commodity Derivative Instrume_4
Commodity Derivative Instruments (Schedule of Fair Value of Derivatives) (Details) - Commodity derivative contracts - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets | ||
Derivatives, Fair Value [Line Items] | ||
Derivative asset, Gross Amount Recognized | $ 39,485 | $ 1,960 |
Derivative asset, Gross Amounts Offset in the Balance Sheet | (4,579) | (1,960) |
Derivative asset, Net | 34,906 | 0 |
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 | 4,579 | 9,825 |
Derivative liability, Gross Amounts Offset in the Balance Sheet | (4,579) | (1,960) |
Derivative liability, Net | 0 | 7,865 |
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 Instrume_5
Commodity Derivative Instruments (Schedule of Gain (Loss) Recognized in Statements of Operations) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||
Realized gain (loss) on commodity derivatives | $ (19,359) | $ 39 | $ 2,355 |
Unrealized gain (loss) on commodity derivatives | 42,772 | (4,265) | (10,105) |
Total gain (loss) | $ 23,413 | $ (4,226) | $ (7,750) |
Commodity Derivative Instrume_6
Commodity Derivative Instruments (Schedule of Hedge Realized Gains (Losses)) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||
Monthly settlements | $ (19,359) | $ 1,062 | $ 4,396 |
Previously incurred premiums attributable to settled commodity contracts | 0 | (1,023) | (2,041) |
Total realized gain (loss) | $ (19,359) | $ 39 | $ 2,355 |
Commodity Derivative Instrume_7
Commodity Derivative Instruments (Narrative) (Details) $ in Millions | Dec. 31, 2018USD ($)counterparty |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |
Deferred premium put liability | $ | $ 1.9 |
Number of counterparties | 6 |
Credit facility syndicate | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |
Number of counterparties | 5 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Level 2 | Estimate of Fair Value Measurement | ||
Financial Liabilities: | ||
Notes payable | $ 462,000 | |
Recurring | ||
Financial Assets: | ||
Commodity derivative asset | 34,906 | $ 0 |
Financial Liabilities: | ||
Commodity derivative liability | 0 | 7,865 |
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 | 34,906 | 0 |
Financial Liabilities: | ||
Commodity derivative liability | 0 | 7,865 |
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 | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Debt Instrument [Line Items] | |||
Amortization of debt issuance costs and other | $ 3,926 | $ 3,084 | $ 1,638 |
Debt extinguishment costs | 0 | 11,842 | 0 |
Less: interest capitalized | (40,510) | (15,124) | (5,732) |
Interest expense, net | 0 | 11,842 | 0 |
Revolving credit facility | Revolving credit facility | |||
Debt Instrument [Line Items] | |||
Interest from debt | 2,209 | 2,004 | 154 |
Notes payable | |||
Debt Instrument [Line Items] | |||
Interest from debt | $ 34,375 | $ 10,036 | $ 3,940 |
Equity and Stock-Based Compen_3
Equity and Stock-Based Compensation (Narrative) (Details) - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | ||
Mar. 31, 2016 | Dec. 31, 2018 | Dec. 31, 2016 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Common stock, shares authorized | 400,000,000 | 300,000,000 | ||
Unrecognized compensation | $ 4,504 | |||
Minimum | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period | 3 years | |||
Maximum | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period | 5 years | |||
2015 Equity Incentive Plan | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Number of shares authorized | 10,500,000 | |||
Number of shares available for grant | 4,446,904 | |||
Number of shares reserved for future vestings | 1,054,926 | |||
Restricted stock | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Unrecognized compensation | $ 8,992 | |||
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 | |||
Goal-based PSUs awarded | 274,898 | |||
Unrecognized compensation | $ 4,700 | |||
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% |
Equity and Stock-Based Compen_4
Equity and Stock-Based Compensation (Stock Based Compensation Expense) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total stock-based compensation | $ 14,727 | $ 12,991 | $ 10,696 |
Less: stock-based compensation capitalized | (2,440) | (1,766) | (1,205) |
Total stock-based compensation expense | 12,287 | 11,225 | 9,491 |
Stock options | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total stock-based compensation | 4,543 | 5,076 | 5,417 |
Performance stock units | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total stock-based compensation | 4,212 | 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 | $ 5,972 | $ 4,977 | $ 4,232 |
Equity and Stock-Based Compen_5
Equity and Stock-Based Compensation (Non-Qualified Stock Options Granted) (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of options to purchase common shares | 0 | 0 | 1,067,500 |
Weighted-average exercise price (in dollars per share) | $ 0 | $ 0 | $ 7.19 |
Term | 10 years | ||
Fair value | $ 3,860 | ||
Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period | 3 years | ||
Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period | 5 years |
Equity and Stock-Based Compen_6
Equity and Stock-Based Compensation (Stock Option Assumptions) (Details) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Expected term | 6 years 4 months 23 days | ||
Expected volatility (percent) | 55.00% | ||
Risk-free rate, minimum (percent) | 1.25% | ||
Risk-free rate, maximum (percent) | 2.00% | ||
Expected dividend yield (percent) | 0.00% | ||
Performance stock units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Expected term | 2 years 9 months 18 days | 2 years 10 months 7 days | 2 years 8 months 12 days |
Expected volatility (percent) | 52.00% | 59.00% | 58.00% |
Weighted-average risk-free rate | 2.41% | 1.34% | 0.87% |
Equity and Stock-Based Compen_7
Equity and Stock-Based Compensation (Stock Option Activity) (Details) - USD ($) $ / shares in Units, $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Summary of activity for stock options (in shares): | ||||
Outstanding, Beginning balance (shares) | 5,636,834 | 6,001,500 | 5,056,000 | |
Granted (shares) | 0 | 0 | 1,067,500 | |
Exercised (shares) | (823,883) | (187,666) | (20,000) | |
Expired (shares) | (37,400) | (41,000) | 0 | |
Forfeited (shares) | (122,917) | (136,000) | (102,000) | |
Outstanding, Ending balance (shares) | 5,056,000 | 4,652,634 | 5,636,834 | 6,001,500 |
Outstanding, Exercisable at end of period (shares) | 3,278,330 | |||
Weighted Average Exercise Price (in dollars per share): | ||||
Beginning balance, Weighted average exercise price (in dollars per share) | $ 9.38 | $ 9.27 | $ 9.71 | |
Granted, weighted average exercise price (in dollars per share) | 0 | 0 | 7.19 | |
Exercised, weighted average exercise price (in dollars per share) | 5.36 | 3.95 | 3.19 | |
Expired, weighted average exercise price (in dollars per share) | 11.22 | 11.98 | 0 | |
Forfeited, weighted average exercise price (in dollars per share) | 9.93 | 10.97 | 10.40 | |
Ending balance, Weighted average exercise price (in dollars per share) | $ 9.71 | 10.06 | $ 9.38 | $ 9.27 |
Outstanding, exercisable, weighted average exercise price (in dollars per share) | $ 10.28 | |||
Weighted-Average Remaining Contractual Life | ||||
Weighted average remaining contractual life | 8 years 7 months 25 days | 6 years 4 months 24 days | 7 years 4 days | 8 years |
Outstanding, Exercisable | 6 years 2 months 19 days | |||
Aggregate Intrinsic Value: | ||||
Beginning balance, aggregate intrinsic value | $ 4,351 | $ 49 | $ 4,806 | $ 6,515 |
Exercised, aggregate intrinsic value | 4,611 | 976 | 117 | |
Ending balance, aggregate intrinsic value | $ 4,351 | 49 | $ 4,806 | $ 6,515 |
Outstanding, Exercisable at end of period | $ 49 |
Equity and Stock-Based Compen_8
Equity and Stock-Based Compensation (Issued and Outstanding Option Details) (Details) - $ / shares | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Outstanding options (in shares) | 4,652,634 | |||
Weighted average exercise price (in dollars per share) | $ 9.71 | $ 10.06 | $ 9.38 | $ 9.27 |
Weighted-Average Remaining Contractual Life, Outstanding Options | 8 years 7 months 25 days | 6 years 4 months 24 days | 7 years 4 days | 8 years |
Exercisable options (in shares) | 3,278,330 | |||
Exercisable options, weighted average exercise price (in dollars per share) | $ 10.28 | |||
Weighted-Average Remaining Contractual Life, Exercisable Options | 6 years 2 months 19 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) | 35,000 | |||
Weighted average exercise price (in dollars per share) | $ 3.31 | |||
Weighted-Average Remaining Contractual Life, Outstanding Options | 3 years 6 months 18 days | |||
Exercisable options (in shares) | 35,000 | |||
Exercisable options, weighted average exercise price (in dollars per share) | $ 3.31 | |||
Weighted-Average Remaining Contractual Life, Exercisable Options | 3 years 6 months 18 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) | 723,800 | |||
Weighted average exercise price (in dollars per share) | $ 6.30 | |||
Weighted-Average Remaining Contractual Life, Outstanding Options | 6 years 5 months 19 days | |||
Exercisable options (in shares) | 398,600 | |||
Exercisable options, weighted average exercise price (in dollars per share) | $ 6.28 | |||
Weighted-Average Remaining Contractual Life, Exercisable Options | 5 years 7 months 28 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) | 1,360,334 | |||
Weighted average exercise price (in dollars per share) | $ 9.42 | |||
Weighted-Average Remaining Contractual Life, Outstanding Options | 6 years 5 months 9 days | |||
Exercisable options (in shares) | 897,630 | |||
Exercisable options, weighted average exercise price (in dollars per share) | $ 9.50 | |||
Weighted-Average Remaining Contractual Life, Exercisable Options | 6 years 2 months 12 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) | 2,533,500 | |||
Weighted average exercise price (in dollars per share) | $ 11.57 | |||
Weighted-Average Remaining Contractual Life, Outstanding Options | 6 years 4 months 24 days | |||
Exercisable options (in shares) | 1,947,100 | |||
Exercisable options, weighted average exercise price (in dollars per share) | $ 11.58 | |||
Weighted-Average Remaining Contractual Life, Exercisable Options | 6 years 4 months 17 days |
Equity and Stock-Based Compen_9
Equity and Stock-Based Compensation (Estimated Unrecognized Compensation From Stock Options and Restricted Stock Units) (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2018USD ($) | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized compensation | $ 4,504 |
Remaining vesting period | 1 year 7 months 28 days |
Restricted stock | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized compensation | $ 8,992 |
Remaining vesting period | 2 years 1 month 10 days |
Equity and Stock-Based Compe_10
Equity and Stock-Based Compensation (Restricted Stock and Performance-vested Stock Units Activity) (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Restricted stock | |||
Number of Shares | |||
Nonvested, Beginning balance (shares) | 1,087,386 | 890,336 | 915,867 |
Granted (shares) | 1,130,388 | 681,568 | 464,533 |
Vested (shares) | (478,517) | (455,772) | (424,483) |
Forfeited (shares) | (99,339) | (28,746) | (65,581) |
Nonvested, Ending balance (shares) | 1,639,918 | 1,087,386 | 890,336 |
Weighted Average Grant Date Fair Value (in dollars per share) | |||
Nonvested, beginning balance (in dollars per share) | $ 8.89 | $ 9.55 | $ 10.63 |
Granted (in dollars per share) | 7.76 | 8.29 | 7.66 |
Vested (in dollars per share) | 8.96 | 9.21 | 9.92 |
Forfeited (in dollars per share) | 9.28 | 9.74 | 8.99 |
Nonvested, ending balance (in dollars per share) | $ 8.07 | $ 8.89 | $ 9.55 |
Performance stock units | |||
Number of Shares | |||
Nonvested, Beginning balance (shares) | 951,884 | 478,510 | 0 |
Granted (shares) | 321,507 | 473,374 | 490,713 |
Vested (shares) | (465,188) | 0 | 0 |
Forfeited (shares) | (28,175) | 0 | (12,203) |
Nonvested, Ending balance (shares) | 780,028 | 951,884 | 478,510 |
Weighted Average Grant Date Fair Value (in dollars per share) | |||
Nonvested, beginning balance (in dollars per share) | $ 9.44 | $ 8.09 | $ 0 |
Granted (in dollars per share) | 13.11 | 10.79 | 8.10 |
Vested (in dollars per share) | 8.09 | 0 | 0 |
Forfeited (in dollars per share) | 10.15 | 0 | 8.22 |
Nonvested, ending balance (in dollars per share) | $ 11.73 | $ 9.44 | $ 8.09 |
Weighted-Average Shares Outst_3
Weighted-Average Shares Outstanding (Details) - shares | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||||||||||
Weighted-average shares outstanding - basic (in shares) | 242,678,465 | 242,536,781 | 242,255,724 | 241,751,915 | 222,072,930 | 200,881,447 | 200,831,063 | 200,707,891 | 242,308,893 | 206,167,506 | 173,774,035 |
Potentially dilutive common shares from: | |||||||||||
Stock options (in shares) | 229,946 | 417,809 | 0 | ||||||||
Performance-vested stock units (in shares) | 175,412 | 0 | 0 | ||||||||
Restricted stock units and stock bonus shares (in shares) | 306,751 | 158,236 | 0 | ||||||||
Weighted-average shares outstanding - diluted (in shares) | 243,032,793 | 243,560,046 | 244,464,776 | 243,166,897 | 222,917,611 | 201,460,915 | 201,224,172 | 201,309,251 | 243,021,002 | 206,743,551 | 173,774,035 |
Potentially dilutive common shares having anti-dilutive effect on earnings per share (in shares) | 4,386,972 | 5,895,166 | 7,370,346 | ||||||||
Stock options | |||||||||||
Potentially dilutive common shares from: | |||||||||||
Potentially dilutive common shares having anti-dilutive effect on earnings per share (in shares) | 3,747,634 | 4,657,834 | 6,001,500 | ||||||||
Performance stock units | |||||||||||
Potentially dilutive common shares from: | |||||||||||
Potentially dilutive common shares having anti-dilutive effect on earnings per share (in shares) | 314,533 | 951,884 | 478,510 | ||||||||
Corporate Goal PSU | |||||||||||
Potentially dilutive common shares from: | |||||||||||
Potentially dilutive common shares having anti-dilutive effect on earnings per share (in shares) | 274,898 | 0 | 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) | 49,907 | 285,448 | 890,336 | ||||||||
Minimum | Performance stock units | |||||||||||
Potentially dilutive common shares from: | |||||||||||
Performance multiplier (percent) | 0.00% | ||||||||||
Maximum | Performance stock units | |||||||||||
Potentially dilutive common shares from: | |||||||||||
Performance multiplier (percent) | 200.00% |
Defined Contribution Plan (Deta
Defined Contribution Plan (Details) - USD ($) $ in Millions | Jan. 01, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Retirement Benefits [Abstract] | ||||
Employer matching contribution percent of employees' gross pay | 100.00% | |||
Percent of employer matching contribution | 6.00% | |||
Contribution cost recognized | $ 0.9 | $ 0.7 | $ 0.4 |
Income Taxes (Schedule of Compo
Income Taxes (Schedule of Components of Income Taxes) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Current: | |||||||||||
Federal | $ 0 | $ (99) | $ 106 | ||||||||
State | 0 | 0 | 0 | ||||||||
Total current income tax expense (benefit) | 0 | (99) | 106 | ||||||||
Deferred: | |||||||||||
Federal | 72,898 | 48,631 | (74,099) | ||||||||
State | 12,697 | 4,371 | (6,651) | ||||||||
Total deferred income tax (benefit) expense | 85,595 | 53,002 | (80,750) | ||||||||
Valuation allowance | (47,628) | (53,002) | 80,750 | ||||||||
Income tax expense (benefit) | $ 19,891 | $ 8,918 | $ 3,347 | $ 5,811 | $ (99) | $ 0 | $ 0 | $ 0 | $ 37,967 | $ (99) | $ 106 |
Income Taxes (Schedule of Recon
Income Taxes (Schedule of Reconciliation of Income Taxes) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |||||||||||
Federal income tax at statutory rate | $ 62,578 | $ 48,410 | $ (74,489) | ||||||||
State income taxes, net of federal tax | 12,697 | 4,371 | (6,685) | ||||||||
Statutory depletion | (113) | (159) | (287) | ||||||||
Stock-based compensation | (296) | 50 | 383 | ||||||||
Non-deductible compensation | 598 | 0 | 0 | ||||||||
Impact of tax reform, net of valuation allowance | 0 | (99) | |||||||||
Valuation allowance | (47,628) | (53,002) | 80,750 | ||||||||
Goodwill impairment | 8,549 | 0 | 0 | ||||||||
Other | 1,582 | 330 | 434 | ||||||||
Income tax expense (benefit) | $ 19,891 | $ 8,918 | $ 3,347 | $ 5,811 | $ (99) | $ 0 | $ 0 | $ 0 | $ 37,967 | $ (99) | $ 106 |
Effective rate expressed as a percentage | 13.00% | 0.00% | 0.00% |
Income Taxes (Schedule of Defer
Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Income Tax Disclosure [Abstract] | ||
Net operating loss carryforward | $ 111,587 | $ 43,283 |
Stock-based compensation | 6,984 | 5,237 |
Basis of oil and gas properties | (150,080) | (5,011) |
Statutory depletion | 2,434 | 2,795 |
Unrealized loss on commodity derivative | (8,607) | 1,939 |
Other | (285) | (615) |
Deferred tax assets (liabilities), gross | (37,967) | |
Deferred tax assets (liabilities), gross | 47,628 | |
Valuation allowance on tax assets | 0 | (47,628) |
Deferred tax liability, net | $ (37,967) | |
Deferred tax liability, net | $ 0 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) | Dec. 31, 2018USD ($) |
Operating Loss Carryforwards [Line Items] | |
Unrecognized tax benefits | $ 0 |
Domestic tax authority | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carryforward | $ 452,500,000 |
Revenue from Contract with Cu_3
Revenue from Contract with Customer (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Disaggregation of Revenue [Line Items] | |||||||||||
Oil, natural gas, and NGL revenues | $ 190,343 | $ 160,978 | $ 147,087 | $ 147,233 | $ 140,097 | $ 103,593 | $ 75,036 | $ 43,790 | $ 645,641 | $ 362,516 | $ 107,149 |
Contract assets, current | $ 1,400 | 1,400 | |||||||||
Crude Oil Product | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Oil, natural gas, and NGL revenues | 494,052 | 261,505 | 77,699 | ||||||||
Natural Gas And NGLs | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Oil, natural gas, and NGL revenues | $ 151,589 | $ 101,011 | $ 29,450 |
Other Commitments and Conting_3
Other Commitments and Contingencies (Narrative) (Details) | 12 Months Ended | ||
Dec. 31, 2018USD ($)counterpartyMMcf | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Long-term Purchase Commitment [Line Items] | |||
Transport agreement number of counterparties | counterparty | 4 | ||
Number of counterparties, commenced | counterparty | 3 | ||
Unused commitment charge | $ | $ 0 | $ 669,000 | $ 597,000 |
Rent expense | $ | $ 1,000,000 | $ 1,100,000 | $ 1,000,000 |
Operating lease, term of contract | 4 years | ||
Agreement One | |||
Long-term Purchase Commitment [Line Items] | |||
New processing plant capacity, volume per day | 200 | ||
New plant, volume commitment per day | 46.4 | ||
Commitment term | 7 years | ||
Agreement Two | |||
Long-term Purchase Commitment [Line Items] | |||
New processing plant capacity, volume per day | 200 | ||
New plant, volume commitment per day | 43.8 | ||
Commitment term | 7 years | ||
New bypass capacity, volume per day | 100 | ||
Denver | |||
Long-term Purchase Commitment [Line Items] | |||
Monthly rent expense | $ | $ 66,000 | ||
Greeley, Colorado | |||
Long-term Purchase Commitment [Line Items] | |||
Monthly rent expense | $ | $ 7,500 |
Other Commitments and Conting_4
Other Commitments and Contingencies (Volume Commitments) (Details) bbl in Thousands | Dec. 31, 2018bbl |
Commitments and Contingencies Disclosure [Abstract] | |
2,019 | 5,090 |
2,020 | 4,003 |
2,021 | 1,672 |
2,022 | 0 |
2,023 | 0 |
Thereafter | 0 |
Total | 10,765 |
Other Commitments and Conting_5
Other Commitments and Contingencies (Minimum Lease Payments Under Non-Cancelable Operating Leases) (Details) $ in Thousands | Dec. 31, 2018USD ($) |
Vehicles Leases | |
Vehicles Leases | |
2,019 | $ 183 |
2,020 | 183 |
2,021 | 204 |
2,022 | 167 |
2,023 | 0 |
Thereafter | 0 |
Total minimum operating lease payments | 737 |
Office Leases | |
Less: Amount representing estimated executory cost | (60) |
Net minimum lease payments | 677 |
Less: Amount representing interest | (96) |
Present value of net minimum lease payments | 581 |
Vehicles Leases | Accounts payable and accrued expenses | |
Office Leases | |
Present value of net minimum lease payments | 100 |
Vehicles Leases | Other liabilities | |
Office Leases | |
Present value of net minimum lease payments | 500 |
Office Leases | |
Office Leases | |
2,019 | 896 |
2,020 | 916 |
2,021 | 913 |
2,022 | 500 |
2,023 | |
Thereafter | 0 |
Total minimum capital lease payments | $ 3,225 |
Supplemental Schedule of Info_3
Supplemental Schedule of Information to the Statements of Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Supplemental cash flow information: | |||
Interest paid | $ 36,134 | $ 9,235 | $ 3,779 |
Income taxes paid | 0 | 0 | 106 |
Non-cash investing and financing activities: | |||
Accrued well costs as of period end | 130,784 | 54,877 | 42,779 |
Asset retirement obligations incurred with development activities | 4,174 | 3,398 | 773 |
Asset retirement obligations assumed with acquisitions | 26,150 | 24,696 | 2,230 |
Obligations discharged with asset retirements and divestitures | (12,267) | (14,332) | (4,739) |
Net changes in operating assets and liabilities: | |||
Accounts receivable | (29,521) | (72,518) | (13,063) |
Accounts payable and accrued expenses | 697 | 5,823 | 2,283 |
Revenue payable | 30,219 | 47,345 | 2,254 |
Production taxes payable | 38,489 | 33,311 | (7,095) |
Other | (341) | (1,131) | (790) |
Changes in operating assets and liabilities | $ 39,543 | $ 12,830 | $ (16,411) |
Unaudited Oil and Gas Reserve_3
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 | 12 Months Ended | ||
Dec. 31, 2018BoeMcfbbl | Dec. 31, 2017BoeMcfbbl | Dec. 31, 2016BoeMcfbbl | |
Oil (MBbl) | |||
Proved developed and undeveloped reserves: | |||
Beginning Balance | 69,396 | 38,032 | 26,379 |
Revision of previous estimates | 1,718 | (3,038) | (7,788) |
Purchase of reserves in place | 5,398 | 12,150 | 23,141 |
Extensions, discoveries, and other additions | 19,892 | 28,736 | 1,457 |
Sale of reserves in place | 0 | (660) | (2,900) |
Production | (8,392) | (5,824) | (2,257) |
Ending Balance | 88,012 | 69,396 | 38,032 |
Proved developed reserves: | |||
Proved developed reserves | 37,102 | 26,552 | 7,435 |
Proved undeveloped reserves: | |||
Proved undeveloped reserves | 50,910 | 42,844 | 30,597 |
Natural Gas (MMcf) | |||
Proved developed and undeveloped reserves: | |||
Beginning Balance | Mcf | 559,893 | 331,921 | 238,670 |
Revision of previous estimates | Mcf | 41,393 | (66,413) | (80,549) |
Purchase of reserves in place | Mcf | 63,367 | 117,167 | 197,103 |
Extensions, discoveries, and other additions | Mcf | 144,337 | 206,644 | 13,018 |
Sale of reserves in place | Mcf | 0 | (4,592) | (24,235) |
Production | Mcf | (37,123) | (24,834) | (12,086) |
Ending Balance | Mcf | 771,867 | 559,893 | 331,921 |
Proved developed reserves: | |||
Proved developed reserves | Mcf | 324,169 | 219,279 | 62,570 |
Proved undeveloped reserves: | |||
Proved undeveloped reserves | Mcf | 447,698 | 340,614 | 269,351 |
NGL (MBbl) | |||
Proved developed and undeveloped reserves: | |||
Beginning Balance | 63,953 | 0 | 0 |
Revision of previous estimates | 5,589 | 28,689 | 0 |
Purchase of reserves in place | 6,474 | 13,424 | 0 |
Extensions, discoveries, and other additions | 16,946 | 24,358 | 0 |
Sale of reserves in place | 0 | 0 | 0 |
Production | (3,869) | (2,518) | 0 |
Ending Balance | 89,093 | 63,953 | 0 |
Proved developed reserves: | |||
Proved developed reserves | 36,427 | 24,251 | 0 |
Proved undeveloped reserves: | |||
Proved undeveloped reserves | 52,666 | 39,702 | 0 |
MBOE | |||
Proved developed and undeveloped reserves: | |||
Balance (Boe) | Boe | 226,665 | 93,352 | 66,157 |
Revisions of previous estimates (Boe) | Boe | 14,205 | 14,581 | (21,213) |
Purchase of reserves in place (Boe) | Boe | 22,433 | 45,103 | 55,991 |
Extensions, discoveries, and other additions (Boe) | Boe | 60,894 | 87,535 | 3,627 |
Sales of reserves in place (Boe) | Boe | 0 | (1,425) | (6,939) |
Production (Boe) | Boe | (18,448) | (12,481) | (4,271) |
Balance (Boe) | Boe | 305,749 | 226,665 | 93,352 |
Proved developed reserves: | |||
Proved developed reserves (Boe) | Boe | 127,557 | 87,350 | 17,863 |
Proved undeveloped reserves: | |||
Proved undeveloped reserves (Boe) | Boe | 178,192 | 139,315 | 75,489 |
Unaudited Oil and Gas Reserve_4
Unaudited Oil and Gas Reserves Information (Narrative) (Details) Boe in Thousands | 12 Months Ended | |||
Dec. 31, 2018Boe$ / bbl$ / Mcf | Dec. 31, 2017Boe$ / bbl$ / Mcf | Dec. 31, 2016Boe$ / bbl$ / Mcf | Aug. 31, 2015 | |
Reserve Quantities [Line Items] | ||||
Net cash flows, discount rate (percent) | 10.00% | 10.00% | ||
MBOE | ||||
Reserve Quantities [Line Items] | ||||
Purchase of reserves in place (Boe) | 22,433 | 45,103 | 55,991 | |
Revisions of previous estimates (Boe) | 14,205 | 14,581 | (21,213) | |
Extensions, discoveries, and other additions (Boe) | 60,894 | 87,535 | 3,627 | |
Oil (MBbl) | ||||
Reserve Quantities [Line Items] | ||||
Price per unit used to prepare reserve estimates, based upon average prices | $ / bbl | 61.23 | 46.57 | 36.07 | |
Increase (decrease) in price per unit used to prepare reserve estimates, based upon average prices | $ / bbl | 14.66 | |||
Natural Gas (MMcf) | ||||
Reserve Quantities [Line Items] | ||||
Price per unit used to prepare reserve estimates, based upon average prices | $ / Mcf | 2.07 | 2.21 | 2.44 | |
Increase (decrease) in price per unit used to prepare reserve estimates, based upon average prices | $ / Mcf | (0.14) |
Unaudited Oil and Gas Reserve_5
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, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 31, 2015 |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | ||||
Future cash inflows | $ 8,831,319 | $ 5,493,507 | $ 2,180,673 | |
Future production costs | (2,082,036) | (1,291,369) | (644,093) | |
Future development costs | (1,372,511) | (1,048,856) | (584,537) | |
Future income tax expense | (759,280) | (285,349) | (90,195) | |
Future net cash flows | 4,617,492 | 2,867,933 | 861,848 | |
10% annual discount for estimated timing of cash flows | (1,941,844) | (1,267,258) | (427,587) | |
Standardized measure of discounted future net cash flows | $ 2,675,648 | $ 1,600,675 | $ 434,261 | $ 390,953 |
Unaudited Oil and Gas Reserve_6
Unaudited Oil and Gas Reserves Information (Schedule of Prices Used to Prepare Estimates of Oil and Gas Reserves) (Details) | Dec. 31, 2018$ / bbl$ / Mcf | Dec. 31, 2017$ / bbl$ / Mcf | Dec. 31, 2016$ / 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 | 61.23 | 46.57 | 36.07 |
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 | 2.07 | 2.21 | 2.44 |
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 | 20.74 | 16.06 | 0 |
Unaudited Oil and Gas Reserve_7
Unaudited Oil and Gas Reserves Information (Schedule of Changes in the Standardized Measure for Discounted Cash Flows) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward] | |||
Standardized measure, beginning of year | $ 1,600,675 | $ 434,261 | |
Sale and transfers, net of production costs | (533,385) | (306,754) | $ (81,468) |
Net changes in prices and production costs | 538,404 | 135,525 | (64,387) |
Extensions, discoveries, and improved recovery | 760,575 | 811,564 | 18,795 |
Changes in estimated future development costs | (23,712) | (25,969) | (6,016) |
Development costs incurred during the period | 248,739 | 170,296 | 62,502 |
Revision of quantity estimates | 176,264 | 165,267 | (110,306) |
Accretion of discount | 175,628 | 47,635 | 44,703 |
Net change in income taxes | (329,894) | (113,523) | 5,104 |
Divestitures of reserves | 0 | (7,157) | (26,839) |
Purchase of reserves in place | 176,707 | 260,999 | 228,855 |
Changes in timing and other | (114,353) | 28,531 | (27,635) |
Standardized measure, end of year | $ 2,675,648 | $ 1,600,675 | $ 434,261 |
Unaudited Financial Data (Detai
Unaudited Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Revenues | $ 190,343 | $ 160,978 | $ 147,087 | $ 147,233 | $ 140,097 | $ 103,593 | $ 75,036 | $ 43,790 | $ 645,641 | $ 362,516 | $ 107,149 |
Expenses | 140,599 | 81,051 | 79,833 | 69,875 | 71,420 | 57,461 | 48,514 | 27,536 | 371,358 | 204,931 | 318,724 |
Operating income (loss) | 49,744 | 79,927 | 67,254 | 77,358 | 68,677 | 46,132 | 26,522 | 16,254 | 274,283 | 157,585 | (211,575) |
Other income (expense) | 52,121 | (8,381) | (14,283) | (5,751) | (17,958) | (2,284) | 1,414 | 3,626 | 23,706 | (15,202) | (7,508) |
Income (Loss) before income taxes | 101,865 | 71,546 | 52,971 | 71,607 | 50,719 | 43,848 | 27,936 | 19,880 | 297,989 | 142,383 | (219,083) |
Income tax expense | 19,891 | 8,918 | 3,347 | 5,811 | (99) | 0 | 0 | 0 | 37,967 | (99) | 106 |
Net income (loss) | $ 81,974 | $ 62,628 | $ 49,624 | $ 65,796 | $ 50,818 | $ 43,848 | $ 27,936 | $ 19,880 | $ 260,022 | $ 142,482 | $ (219,189) |
Net income (loss) per common share: | |||||||||||
Basic (in dollars per share) | $ 0.34 | $ 0.26 | $ 0.20 | $ 0.27 | $ 0.23 | $ 0.22 | $ 0.14 | $ 0.10 | $ 1.07 | $ 0.69 | $ (1.26) |
Diluted (in dollars per share) | $ 0.34 | $ 0.26 | $ 0.20 | $ 0.27 | $ 0.23 | $ 0.22 | $ 0.14 | $ 0.10 | $ 1.07 | $ 0.69 | $ (1.26) |
Weighted-average shares outstanding: | |||||||||||
Basic (in shares) | 242,678,465 | 242,536,781 | 242,255,724 | 241,751,915 | 222,072,930 | 200,881,447 | 200,831,063 | 200,707,891 | 242,308,893 | 206,167,506 | 173,774,035 |
Diluted (in shares) | 243,032,793 | 243,560,046 | 244,464,776 | 243,166,897 | 222,917,611 | 201,460,915 | 201,224,172 | 201,309,251 | 243,021,002 | 206,743,551 | 173,774,035 |