| Basis of Presentation and 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 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 financial statements included herein were prepared from the records of the Company in accordance with generally accepted accounting principles in the United States (“GAAP”). In the opinion of management, all adjustments, consisting primarily of normal recurring accruals that are considered necessary for a fair statement of the consolidated financial information, have been included. |
| Use of Estimates in the Preparation of Financial Statements | Use of Estimates in the Preparation of Financial Statements The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and gas reserves; (2) cash flow estimates used in impairment testing of oil and gas properties and goodwill; (3) depreciation, depletion, amortization and accretion; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations, including the determination of any resulting goodwill; (6) accrued revenue and related receivables; (7) valuation of commodity derivative instruments; (8) accrued liabilities; (9) valuation of unit and stock-based payments, and (10) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company evaluates its estimates on an on‑going basis and bases its estimates on historical experience and on various other assumptions the Company believes to be reasonable under the circumstances. |
| Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents consist of all highly liquid investments that are readily convertible into cash and have original maturities of three months or less when purchased. |
| Cash Held in Escrow | Cash Held in Escrow Cash held in escrow includes deposits for the purchase of certain oil and gas properties as required under the related purchase and sale agreements. |
| Accounts Receivable | Accounts Receivable The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. The Company generally has the ability to withhold future revenue disbursements to recover non‑payment of joint interest billings. On an on‑going basis, management reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables as of or for the years ended December 31, 2018 and 2017 . |
| Credit Risk and Other Concentrations | Credit Risk and Other Concentrations The Company’s cash and cash equivalents are exposed to concentrations of credit risk. The Company manages and controls this risk by investing these funds with major financial institutions. The Company often has balances in excess of the federally insured limits. The Company sells oil, natural gas and NGL to various types of customers, including oil marketers, pipelines and refineries. Credit is extended based on an evaluation of the customer’s financial conditions and historical payment record. The future availability of a ready market for oil, natural gas and NGL depends on numerous factors outside the Company’s control, none of which can be predicted with certainty. For the three years ended December 31, 2018 , the Company had the following customers that exceeded 10% of total oil, natural gas and NGL revenues. The Company does not believe the loss of any single purchaser would materially impact its operating results because crude oil, natural gas and NGL are fungible products with well‑established markets and numerous purchasers. For the Year Ended December 31, 2018 2017 2016 Customer A 76 % 65 % 25 % Customer B 11 % 19 % 19 % Customer C — % 11 % — % Customer D — % — % 23 % Customer E — % — % 16 % At December 31, 2018 , the Company had commodity derivative contracts with eleven counterparties, all of whom are lenders under our credit agreement. The Company does not require collateral or other security from counterparties to support derivative instruments; however, to minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are credit worthy financial institutions deemed by management as competent and competitive market‑makers. Additionally, the Company uses master netting agreements to minimize credit‑risk exposure. The credit worthiness of the Company’s counterparties is subject to periodic review. For the years ended December 31, 2018 , 2017 and 2016 , the Company did not incur any losses with respect to counterparty contracts. None of the Company’s existing derivative instrument contracts contains credit‑risk related contingent features. |
| Inventory and Prepaid Expenses | Inventory and Prepaid Expenses The Company records well equipment inventory at the lower of cost or net realizable value. Prepaid expenses are recorded at cost. Inventory and prepaid expenses are comprised of the following (in thousands): As of December 31, 2018 2017 Well equipment inventory $ 19,916 $ 9,971 Prepaid expenses 6,900 3,046 $ 26,816 $ 13,017 |
| Oil and Gas Properties | Oil and Gas Properties The Company follows the successful efforts method of accounting for oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units‑of‑production basis over the remaining life of proved reserves and proved developed reserves, respectively. For the years ended December 31, 2018 , 2017 and 2016 , the Company excluded $144.3 million , $127.4 million and $98.7 million of capitalized costs from depletion related to wells in progress, respectively. For the years ended December 31, 2018 , 2017 and 2016 , the Company recorded depletion expense on capitalized oil and gas properties of $426.8 million , $306.7 million and $197.4 million , respectively. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed at each period end. Due to the capital‑intensive nature and the geological characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability. As of December 31, 2018 , the Company had approximately $6.1 million of suspended well costs, all capitalized less than one year and included in wells in progress at December 31, 2018 . These exploratory well costs are pending further engineering evaluation and analysis to determine if economic quantities of oil and gas reserves have been discovered. The Company expects its analysis to be complete in the second half of 2019. As of December 31, 2017 , $15.7 million of suspended well costs, all capitalized less than one year and included in wells in progress as of December 31, 2017 . At September 30, 2018, the Company completed its evaluation and moved $17.9 million of these suspended well costs to proved oil and gas properties based on the determination of proved reserves. As of December 31, 2016 , the Company had no suspended well costs recorded. Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense. The Company expensed $0.4 million and $1.4 million of costs associated with exploratory geological and geophysical costs for the years ended December 31, 2018 and 2017, respectively. There were no exploratory geological and geophysical costs incurred for the year ended December 31, 2016. The Company capitalizes interest, if debt is outstanding, during drilling operations in its exploration and development activities. For the years ended December 31, 2018 , 2017 and 2016 , the Company capitalized interest of approximately $8.2 million , $11.1 million and $5.2 million , respectively. Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized to earnings. For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property. |
| Impairment of Oil and Gas Properties | Impairment of Oil and Gas Properties Proved oil and gas properties are reviewed for impairment annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. For all of its fields, the Company estimates the expected future cash flows of its oil and gas properties and compares these undiscounted cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, estimated future operating costs, and discount rates commensurate with the risk associated with realizing the projected cash flows. Impairment expense for proved oil and gas properties is reported in impairment of long lived assets and goodwill in the consolidated statements of operations, which increases accumulated depletion, depreciation and amortization. For the years ended December 31, 2018 and 2016 , the Company recognized $16.2 million and $22.5 million , respectively, in impairment expense on proved oil and gas properties in the Company's northern field. As of September 30, 2018, the future undiscounted cash flows did not exceed its carrying amount associated with its proved oil and gas properties in its northern field. As of June 30, 2016, it was determined that the proved oil and gas properties had no remaining fair value, therefore, the full net book value of these proved oil and gas properties were impaired. For the year ended December 31, 2017 , the Company recognized no impairment expense on proved oil and gas properties. Unproved oil and gas properties consist of costs to acquire unevaluated leases as well as costs to acquire unproved reserves. The Company evaluates significant unproved oil and gas properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit‑of‑production basis. Impairment expense and lease extension payments for unproved properties is reported in exploration expenses in the consolidated statements of operations. As a result of the abandonment and impairment of unproved properties, the Company recognized $25.7 million , $15.8 million and $22.3 million in impairment expense for the years ended December 31, 2018 , 2017 and 2016 , respectively. |
| Other Property and Equipment | Other Property and Equipment Other property and equipment consists of (i) other property and equipment including, office furniture and fixtures, leasehold improvements and computer hardware and software, (iii) compressors used in Extraction’s oil and gas operations, (iii) land, compressor stations, central tank batteries, and disposal well facilities and (iv) rights of ways, pipeline, and engineering costs. Impairment expense for other property and equipment is reported in impairment of long lived assets and goodwill in the consolidated statements of operations. The Company recognized $0.4 million , $0.9 million and $0.5 million in impairment expense related to midstream facilities for the years ended December 31, 2018 , 2017 and 2016 , respectively, which increased accumulated depreciation recognized in other property and equipment, net of accumulated depreciation. The Company recognized the impairment expense for the year ended December 31, 2018 and 2017 primarily as the result of right-of-way options that were no longer in the Company's plans for developing midstream infrastructure. The Company recognized the impairment expense for the years ended December 31, 2016, as the result of contraction in the local oil and gas industry’s near term growth profile, therefore decreasing the need and support for a specifically proposed gas processing facility. Gain or loss on the sale of other property and equipment is reported in (gain) loss on sale of property and equipment in the consolidated statement of operations. The Company recognized $0.5 million of loss on the sale of other property and equipment related to the disposal of an oil pipeline that was not yet placed into service in the first quarter of 2017. Other property and equipment is recorded at cost and depreciated using the straight‑line method. The estimated useful lives of those assets depreciated under the straight-line basis are as follows: Rental equipment 1-10 years Office leasehold improvements 3-10 years Other 3-5 years Other property and equipment is comprised of the following (in thousands): As of December 31, 2018 2017 Rental equipment $ 4,043 $ 3,805 Land 27,595 22,991 Right-of-ways and pipeline 8,008 7,447 Office leasehold improvements 7,231 4,405 Other 6,946 5,578 Less: accumulated depreciation and impairment (13,974 ) (11,797 ) $ 39,849 $ 32,429 |
| Equity Method Investments | Equity Method Investments Investments in entities for which the Company exercises significant influence, but not control, are accounted for under the equity method. The Company recorded $15.5 million and $8.3 million of such investments included in other non-current assets on the consolidated balance sheets as of December 31, 2018 and 2017 , respectively. The Company recognized $2.9 million and $0.4 million of income from such investments, including the accretion of any basis difference between the carrying amount of the investment and the amount of underlying equity in net assets, included in other income on the consolidated statements of operations and equity in earnings of unconsolidated subsidiary, in which we have a minority ownership interest on the consolidated statements of cash flows for the year ended December 31, 2018 and 2017 , respectively. The Company held no such investments during the years ended December 31, 2016. |
| Deferred Lease Incentives | Deferred Lease Incentives All incentives received from landlords for office leasehold improvements are recorded as deferred lease incentives and amortized over the term of the respective lease on a straight‑line basis as a reduction of rental expense. |
| Debt Discount and Issuance Costs | Debt Discount Costs The $430.0 million in Second Lien Notes issued in May of 2014 were issued at a 1.5% original issue discount (“OID”) and the debt discount of $6.5 million was recorded as a reduction of the Second Lien Notes. The debt discount costs related to Second Lien Notes were amortized to interest expense using the effective interest method over the term of the debt. Debt Issuance Costs Debt issuance costs include origination, legal, engineering, and other fees incurred to issue the debt in connection with the Company’s credit facility, 2021 Senior Notes, 2024 Senior Notes and 2026 Senior Notes (collectively, the "Senior Notes"). Debt issuance costs related to the credit facility are included in other non-current assets on the consolidated balance sheets and amortized to interest expense on the consolidated statement of operations on a straight‑line basis over the respective borrowing term. Debt issuance costs related to the Senior Notes are amortized to interest expense using the effective interest method over the term of the debt. |
| Commodity Derivative Instruments | Commodity Derivative Instruments The Company has entered into commodity derivative instruments to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production. The commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and commodity derivative liabilities. The Company has not designated any of the derivative contracts as fair value or cash flow hedges. Therefore, the Company does not apply hedge accounting to the commodity derivative instruments. Net gains and losses on commodity derivative instruments are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses on commodity derivative instruments are recorded in the commodity derivative gain (loss) line on the consolidated statements of operations. The Company’s cash flow is only impacted when the actual settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows. Any premiums paid on derivative contracts are capitalized as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid. Premium payments are reflected in cash flows from operating activities in the Company's consolidated statements of cash flows. Over time, as the derivative contracts settle, the differences between the cash received and the premiums paid or fair value of contracts acquired are recognized in net gains or losses on commodity or interest rate derivate contracts, and the cash received is reflected in cash flows from operating activities in the Company's consolidated statements of cash flows. The Company’s valuation estimate takes into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. The consideration of these factors result in an estimated exit‑price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non‑biased, verifiable, and consistent methodology for valuing commodity derivative instruments. Please refer to Note 6 — Commodity Derivative Instruments for additional discussion on commodity derivative instruments. |
| Goodwill and Other Intangible Assets | Goodwill and Other Intangible Assets The Company applies the provisions of ASC 350, Intangibles-Goodwill and Other . Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. The Company tests goodwill for impairment annually on September 30, or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. The goodwill test is performed at the reporting unit level, which represents the Company’s oil and gas operations in its core DJ Basin field. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. Any sharp prolonged decreases in the prices of oil and natural gas as well as continued declines in the quoted market price of the Company’s common shares could change the estimates of the fair value of the reporting unit and could result in an impairment charge. The Company performed a quantitative assessment as of September 30, 2018, which concluded the fair value of the reporting unit was greater than its carrying amount. The Company identified triggering events as of December 31, 2018, due to the decrease in commodity pricing and the quoted market price of the Company's common shares compared to September 30, 2018. As such, the Company performed a quantitative assessment as of December 31, 2018 , utilizing an income approach based on estimates of the expected discounted future cash flows of the reporting unit's oil and gas properties, which concluded the fair value of the reporting unit was not greater than its carrying amount. As a result, the Company recorded goodwill impairment of $54.2 million , the entirety of the balance, for the year ended December 31, 2018 . The Company performed a quantitative assessment as of September 30, 2017, which concluded the fair value of the reporting unit was greater than its carrying amount. The Company performed a qualitative assessment as of December 31, 2017 and 2016, which concluded the fair value of the reporting unit was more-likely-than-not greater than its carrying amount. Costs relating to the acquisition of internal-use software licenses are capitalized when incurred and amortized over the estimated useful life of the license, which is typically one to three years. The Company recorded $3.0 million , $2.3 million and $0.3 million of internal-use software for the years ended December 31, 2018 , 2017 and 2016 , respectively, on the consolidated balance sheets within the goodwill and other intangible assets line item. Accumulated amortization for the years ended December 31, 2018 , and 2017 was $3.1 million and $1.1 million , respectively. The Company recognized $2.1 million , $1.0 million and $0.1 million amortization expense for the years ended December 31, 2018 , 2017 and 2016 , respectively. |
| Fair Value of Financial Instruments | 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) and long‑term debt. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short‑term maturities. The carrying amount of the Company’s credit facility approximates fair value as it bears interest at variable rates over the term of the loan. The Company’s Senior Notes are recorded at cost and the fair value is disclosed in Note 8 — Fair Value Measurements . Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments. |
| Asset Retirement Obligation | Asset Retirement Obligation The Company recognizes estimated liabilities for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long‑lived asset are recorded at the time the Company makes the decision to complete the well or a well is acquired. For additional discussion on asset retirement obligations please refer to Note 7 — Asset Retirement Obligations. |
| Environmental Liabilities | Environmental Liabilities The Company is subject to federal, state and local environmental laws and regulations. These laws regulate the release, disposal or discharge of materials into the environment or otherwise relating to environmental protection and may require the Company to remove or mitigate the environmental effects of the discharge, disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a non‑capital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted values unless the timing of cash payments for the liability or component is fixed or determinable. Management has determined that no significant environmental liabilities existed as of December 31, 2018 . |
| Revenue Recognition | Revenue Recognition Revenues from the sale of oil, natural gas and NGL are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. The Company recognizes revenues from the sale of oil, natural gas and NGL using the sales method of accounting, whereby revenue is recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2018 , the Company has an oil imbalance of 22 MBbl, which the Company intends to settle with the counterparty in crude oil barrels. There were no material imbalances at December 31, 2017 or 2016 . |
| Unit and Stock-Based Payments | Unit and Stock‑Based Payments The Company and its predecessor, Holdings, has granted restricted unit awards ("RUAs"), restricted stock units ("RSUs"), stock option awards and performance stock awards ("PSAs") to certain directors, officers and employees of the Company, which therefore required the Company to recognize the expense in its financial statements. All unit and stock‑based payments to directors, officers and employees are measured at fair value on the grant date and expensed over the relevant service period. The fair value of stock option awards is determined by using the Black-Scholes option pricing model. The fair value of the PSAs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. All unit and stock‑based payment expense is recognized using the straight‑line method and is included within general and administrative expenses in the consolidated statements of operations and unit and stock-based compensation in the consolidated statements of cash flows. Forfeitures are recorded as they occur. Please refer to Note 11 — Unit and Stock‑Based Compensation for additional discussion on unit and stock‑based payments. |
| Income Taxes | Income Taxes The Company accounts for income taxes using the asset and liability method. 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 basis and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. The tax returns and the amount of taxable income or loss are subject to examination by deferral and state taxing authorities. The Company periodically assesses whether it is more likely than not that it will generate sufficient taxable income to realize its deferred income tax assets, including net operating losses. In making this determination, the Company considers all the available positive and negative evidence and makes certain assumptions. The Company considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends, and its outlook for future years. The Company believes it is more likely than not that certain net operating losses can be carried forward and utilized. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The Company does not currently have uncertain tax positions. On December 22, 2017, United States legislation referred to as the Tax Cuts and Jobs Act (the "TCJA") was signed into law. Many of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes changes to the Internal Revenue Code of 1986 (as amended, the "Code"). The most significant change included in the TCJA is a reduction in the corporate federal income tax rate from 35% to 21%. As a result of the enactment date of December 22, 2017, the Company was required to remeasure the deferred tax assets and liabilities at the rate in which they are expected to reverse. This re-measurement of deferred tax assets and liabilities required the Company to analyze and record a one-time adjustment to reduce the overall deferred tax liability in the consolidated balance sheets and affect a corresponding income tax benefit in the consolidated statements of operations for the year ended December 31, 2017. The Company believes the accounting is complete regarding the revaluation of the deferred tax balances. This resulted in the recording of an income tax benefit of $23.4 million , as well as a corresponding reduction in the deferred tax liability as of December 31, 2017. During the third quarter of 2018, we completed the accounting for the income tax effect of the TCJA's limit on compensation under Internal Revenue Code Sec. 162(m) and stock-based compensation for covered employees. This resulted in a $0.4 million reduction in deferred tax assets that had been recorded as a provisional amount as of December 31, 2017 . There are no remaining provisional amounts associated with the TCJA as of December 31, 2018 . Extraction Oil & Gas Holdings, LLC, the Company’s accounting predecessor, was a limited liability company that was not subject to U.S. federal income tax. |
| Earnings Per Share | Earnings Per Share Basic earnings per share (“EPS”) includes no dilution and is computed by dividing net income (loss) available to common shareholders by the weighted-average number of shares outstanding during the period. Diluted EPS reflects the potential dilution of securities that could share in the earnings available to common shareholders of the Company. The Company uses the “if-converted” method to determine the potential dilutive effects of its Series A Preferred Stock, and the treasury stock method to determine the potential dilutive effect of outstanding restricted stock units and stock option awards. The Company’s EPS calculation for the year ended December 31, 2016 includes only the net income (loss) for the period subsequent to IPO and Corporate Reorganization which occurred on October 12, 2016 and has omitted EPS prior to this date. In addition, the basic weighted average shares outstanding calculation for the year ended December 31, 2016 is based on the actual days in which the shares were outstanding for the period from October 12, 2016, to December 31, 2016. |
| Segment Reporting | Segment Reporting Beginning in the fourth quarter of 2018, the Company had two operating segments, (i) the exploration, development and production of oil, natural gas and NGL (the "exploration and production segment") and (ii) the construction and support of midstream assets to gather and process crude oil and gas production (the "gathering and facilities segment"). Prior to the fourth quarter of 2018, the Company had a single operating segment. The gathering systems and facilities operating segment is currently under development. Capital expenditures associated with gathering systems and facilities are being incurred to develop midstream infrastructure to support the Company's development of its oil and gas leasehold along with third-party activity. The activity of the exploration and production segment and gathering systems and facilities operating segment are being monitored by our chief operating decision maker ("CODM"). The Company expects the first phase of the gathering systems and facilities to be operational during the second half of 2019. Revenues associated with the exploration and production segment are derived from the sale of our oil and natural gas production, as well as the sale of NGL that are extracted from our natural gas during processing. Revenues and operating expenses associated with the gathering systems and facilities operations will be primarily derived from intersegment transactions for services provided to the Company's exploration, development and production operations by Elevation Midstream, LLC., an unrestricted subsidiary to the Company. All intersegment transactions are and will be eliminated upon consolidation, including revenues and operating expenses during the construction of and from gathering services provided by Elevation Midstream to the Company. The CODM considers Adjusted EBITDAX as the measure of segment performance under ASC 280, Segment Reporting . Accounting policies for each segment are the same as the accounting policies as described herein. For more information about Segments, see Note 15 — Segment Information. All of the Company’s operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States. |
| Recent Accounting Pronouncements | Recent Accounting Pronouncements The accounting standard‑setting organizations frequently issue new or revised accounting rules. The Company regularly reviews new pronouncements to determine their impact, if any, on its consolidated financial statements and related disclosures. In August 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2018-15, which aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software and hosting arrangements that include an internal-use software license. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019, including interim reporting periods within that reporting period. The Company is currently evaluating this new standard to determine the potential impact to its financial statements and related disclosures. In August 2018, the FASB issued ASU No. 2018-13, which improves the disclosure requirements on fair value measurements. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019, including interim reporting periods within that reporting period. The Company is currently evaluating this new standard to determine the potential impact to its financial statements and related disclosures. In May 2017, the FASB issued ASU No. 2017-09, which provides clarification and reduces both (1) diversity in practice and (2) cost and complexity when applying the guidance in Topic 718 Compensation - Stock Compensation, to a change to the terms or conditions of a share-based payment award. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that reporting period. The Company adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial statements and related disclosures. In February 2017, the FASB issued ASU No. 2017-05, which provided clarification regarding the guidance on accounting for the derecognition of nonfinancial assets. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that fiscal year. The Company adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial statements and related disclosures. In January 2017, the FASB issued ASU No. 2017-04, which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019. Early adoption is permitted for interim and annual goodwill impairment tests performed on testing dates after January 1, 2017. The Company is currently evaluating the impact of adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements and related disclosures. In January 2017, the FASB issued ASU No. 2017-01, which clarifies the definition of a business when evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial statements and related disclosures; however, this standard may result in more transactions being accounted for as asset acquisitions rather than business combinations. In November 2016, the FASB issued ASU No. 2016-18, which intends to clarify how entities should present restricted cash and restricted cash equivalents in the statement of cash flows. This amendment was effective retrospectively for reporting periods beginning after December 15, 2017. The Company adopted this ASU on January 1, 2018 and the retrospective adoption increased the Company's beginning cash balances within the statement of cash flows for the prior period presented in the table below. The adoption had no other material impact on the cash flow statement and had no impact on the Company's results of operations or financial position. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets to the consolidated statement of cash flows: As of December 31, December 31, December 31, December 31, 2018 2017 2016 2015 Cash and cash equivalents $ 234,986 $ 6,768 $ 588,736 $ 97,106 Restricted cash included in cash held in escrow — — 42,200 — $ 234,986 $ 6,768 $ 630,936 $ 97,106 In August 2016, the FASB issued ASU No. 2016-15, which addresses eight specific cash flow issues, including presentation of debt prepayments or debt extinguishment costs, with the objective of reducing the existing diversity in practice. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company adopted this ASU on January 1, 2018, which requires current period make-whole premiums to be presented in financing activities in the statement of cash flows and prior period debt prepayment costs to be reclassified from operating activities to financing activities in the statement of cash flows; however, there was no impact to the total change in cash and cash equivalents from period to period. In February 2016, the FASB issued ASU No. 2016-02, which requires lessee recognition on the balance sheet of a right of use asset and a lease liability, initially measured at the present value of the lease payments. It further requires recognition in the income statement of a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis. Finally, it requires classification of all cash payments within operating activities in the statements of cash flows. It is effective for fiscal years commencing after December 15, 2018 and early adoption is permitted. The FASB subsequently issued ASU No. 2017-13, ASU No. 2018-01, ASU No. 2018-10 and ASU No. 2018-11, which provided additional implementation guidance. The Company is currently evaluating the impact this ASU will have on the consolidated financial statements and related disclosures and expects certain lease agreements with terms over one year to be classified as right-of-use assets and right-of-use liabilities, which will gross up the consolidated balance sheet as of January 1, 2019. The Company will adopt the accounting standard using a modified retrospective transition approach, which applies the provisions of the new guidance at the effective date without adjusting the comparative periods presented. The Company has elected the package of practical expedients permitted under the transition guidance with the new standard, which among other things, requires no reassessment of whether existing contracts are or contain leases as well as no reassessment of lease classification for existing leases upon adoption. The Company has also elected the optional practical expedient permitted under the transition guidance within the new standard related to land easements that allows it to carry forward its current accounting treatment for land easements on existing agreements upon adoption. The Company made an accounting policy election to keep leases with an initial term of twelve months or less off of the consolidated balance sheet. The Company is finalizing its evaluation of the impacts that the adoption of this accounting guidance will have on the consolidated financial statements and on our future consolidated balance sheet upon adoption. As a part of the implementation work, the Company is validating the inputs and outputs of the software tool used to calculate the initial and ongoing accounting balances for right-of-use assets and liabilities and finalizing the completeness of the lease population. In May 2014, the FASB issued ASU No. 2014-09, which establishes a comprehensive new revenue recognition model, referred to as ASC 606 - Revenue from Contracts with Customers, 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. The ASU allows for the use of either the full or modified retrospective transition method. In August 2015, the FASB issued ASU No. 2015-14, which deferred ASU No. 2014-09 for one year, and was effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. The FASB subsequently issued ASU No. 2016-08, ASU No. 2016-10, ASU No. 2016-11, ASU No. 2016-12, ASU No. 2016-20, ASU No. 2017-13, ASU No. 2017-14 and ASU No. 2019-20, which provided additional implementation guidance. Refer to —Adoption of ASC 606 for more information. Adoption of ASC 606 On January 1, 2018, the Company adopted ASC 606. The Company adopted ASC 606 using the modified retrospective method to apply the new standard to all new contracts entered into on or after January 1, 2018 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. The impact of adoption in the year ended December 31, 2018 results are as follows (in thousands): Under ASC 606 Under ASC 605 Change Revenues: Oil sales $ 840,687 $ 840,687 $ — Natural gas sales 105,629 121,180 (15,551 ) NGL sales 114,427 134,558 (20,131 ) Total Revenues 1,060,743 1,096,425 (35,682 ) Operating Expenses: Transportation and gathering $ 39,411 $ 75,093 $ (35,682 ) Revenues less transportation and gathering $ 1,021,332 $ 1,021,332 $ — Changes to sales of natural gas and NGL, and transportation and gathering expenses are due to the conclusion that certain midstream processing entities are the Company's customers in natural gas processing and marketing agreements in accordance with the five-step process in ASC 606. This is a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC 605 where the Company determined it was the principal, the midstream processor was the agent and the third-party end user was its customer. As a result, the Company modified its presentation of revenues and operating expenses for these agreements. Revenues related to these agreements are now presented on a net basis for proceeds expected to be received from the midstream processing entity. Revenues from the sale of oil, natural gas and NGL, where the Company is a non-operating interest partner, are considered in the scope of ASC 808 - Collaborative Arrangements . Therefore, ASC 606 did not change the presentation of these revenues. Transportation and gathering expense related to other agreements incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities will continue to be presented as transportation and gathering expense. Revenues from Contracts with Customers Sales of oil, natural gas and NGL are recognized at the point control of the commodity is transferred to the customer and collectability is reasonably assured. The majority of the Company's contracts' pricing provisions are tied to a commodity 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 NGL fluctuates to remain competitive with the other available oil, natural gas and NGL supplies. Oil Sales Under the Company's crude purchase and marketing contracts, the Company generally sells oil production at the wellhead and collects an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead at the net price received. The Company utilizes the sales method to account for producer imbalances, which continues to be applicable under ASC 606. As of December 31, 2018 , the Company has an oil imbalance of 22 MBbl, which the Company intends to settle with the counterparty in crude oil barrels. Natural Gas and NGL Sales Under the Company's natural gas processing contracts, the Company delivers 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 the Company for the resulting sales of NGL and residue gas. In these scenarios, we evaluate whether we are the principal or the agent in the transaction, and the point at which control of the hydrocarbons transfer to the customer. For those contracts where the Company has concluded the midstream processing entity is the Company's agent and the third-party end user is its customer (generally the Company's fixed-fee gathering and processing agreements), the Company recognizes revenue on a gross basis, with transportation and gathering expense presented as an operating expense in the consolidated statements of operations. Alternatively, for those contracts where the Company has concluded the midstream processing entity is its customer and controls the hydrocarbons (generally the Company's percentage of proceeds gathering and processing agreements), the Company recognizes natural gas and NGL revenues based on the net amount of the proceeds received from the midstream processing company. In certain natural gas processing agreements, the Company may elect to take its residue gas and/or NGL in-kind at the tailgate of the midstream entity's processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when the control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering and processing expense attributable to the gas processing contracts, as well as any transportation expense incurred to deliver the product to the purchaser, are presented as transportation and gathering expense in the consolidated statements of operations. Performance Obligations A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price of a contract that has an original expected duration of one year or less. For the Company's product sales that have a contract term greater than one year, the Company has 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. The Company records revenue on its oil, natural gas and NGL sales at the time production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the customer and the net commodity price that will be received for the sale of these commodity products. The Company records the differences between the revenue estimated and the actual amounts received for product sales in the month that payment is received from the customer. The Company has internal controls over its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the period from January 1, 2018 to December 31, 2018 , revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. Contract Balances Under the Company's various sales contracts, the Company invoices customers once its performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's product sales contracts do not give rise to contract assets or liabilities under ASC 606. The following table presents the Company's revenues disaggregated by revenue source. Transportation and gathering costs in the following table are not all of the transportation and gathering expenses that the Company incurs, only the expenses that are netted against revenues pursuant to ASC 606. Prior period amounts have not been adjusted under the modified retrospective method. For the Year Ended December 31, 2018 2017 2016 Revenues: Oil sales $ 840,687 $ 419,904 $ 194,059 Natural gas sales 121,180 92,322 48,652 NGL sales 134,558 92,070 35,378 Transportation and gathering included in revenues (35,682 ) — — Total Revenues $ 1,060,743 $ 604,296 $ 278,089 There are no other accounting standards applicable to the Company that have been issued but not yet adopted by the Company as of December 31, 2018 , and through the date of this filing that would have a material impact on the Company’s consolidated financial statements and related disclosures. |
