Extraction Oil & Gas (XOG) 10-K 27 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2017	Feb. 23, 2018	Jun. 30, 2017
Document and Entity Information
Entity Registrant Name	Extraction Oil & Gas, Inc.
Entity Central Index Key	1,655,020
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 1.2
Entity Common Stock, Shares Outstanding		172,760,468
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current Assets:
Cash and cash equivalents	$ 6,768	$ 588,736
Accounts receivable
Trade	46,047	23,154
Oil, natural gas and NGL sales	93,301	34,066
Inventory and prepaid expenses	13,017	7,722
Commodity derivative asset	4,132	0
Total Current Assets	163,265	653,678
Property and Equipment (successful efforts method), at cost:
Proved oil and gas properties	3,011,526	1,851,052
Unproved oil and gas properties	686,968	452,577
Wells in progress	127,418	98,747
Less: accumulated depletion, depreciation and amortization	(709,662)	(402,912)
Net oil and gas properties	3,116,250	1,999,464
Other property and equipment, net of accumulated depreciation (Note 2)	37,318	32,721
Net Property and Equipment	3,153,568	2,032,185
Non-Current Assets:
Cash held in escrow	0	42,200
Goodwill and other intangible assets, net of accumulated amortization	55,453	54,489
Other non-current assets	12,383	2,224
Total Non-Current Assets	67,836	98,913
Total Assets	3,384,669	2,784,776
Current Liabilities:
Accounts payable and accrued liabilities	211,581	131,134
Revenue payable	52,805	35,162
Production taxes payable	37,444	27,327
Commodity derivative liability	67,428	56,003
Accrued interest payable	23,807	19,621
Asset retirement obligations	6,873	5,300
Total Current Liabilities	399,938	274,547
Non-Current Liabilities:
Credit facility	90,000	0
Senior Notes, net of unamortized debt issuance costs (Note 5)	933,361	538,141
Production taxes payable	57,982	35,838
Commodity derivative liability	17,274	6,738
Other non-current liabilities	5,973	3,466
Asset retirement obligations	62,667	50,808
Deferred tax liability	42,326	106,026
Total Non-Current Liabilities	1,209,583	741,017
Total Liabilities	1,609,521	1,015,564
Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized; 185,280 and 185,280 issued and outstanding, respectively	158,383	153,139
Stockholders' Equity:
Common Stock, $0.01 par value; 900,000,000 shares authorized; 172,059,814 and 171,834,605 issued and outstanding, respectively	1,718	1,718
Treasury Stock, at cost, 165,385 and 0 shares	(2,105)	0
Additional paid-in capital	2,114,795	2,067,590
Accumulated deficit	(497,643)	(453,235)
Total Stockholders' Equity	1,616,765	1,616,073
Total Liabilities and Stockholders' Equity	$ 3,384,669	$ 2,784,776

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parentheticals) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Common stock, par value and other disclosures
Common stock, Par value per share (in dollars per share)	$ 0.01
Common Stock, shares authorized (in shares)	900,000,000
Common Stock, shares issued (in shares)	172,059,814	171,834,605
Common Stock, shares outstanding (in shares)	172,059,814	171,834,605
Treasury stock, at cost (in shares)	165,385	0
Series A Convertible Preferred Stock
Series A Convertible Preferred Stock
Convertible Preferred Stock, par value (in dollars per share)	$ 0.01
Convertible Preferred Stock, shares authorized (in shares)	50,000,000
Convertible Preferred Stock, shares issued (in shares)	185,280	185,280
Convertible Preferred Stock, shares outstanding (in shares)	185,280	185,280

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Oil sales	$ 419,904	$ 194,059	$ 157,024
Natural gas sales	92,322	48,652	26,019
NGL sales	92,070	35,378	14,707
Total Revenues	604,296	278,089	197,750
Operating Expenses:
Lease operating expenses	111,306	62,043	30,628
Production taxes	51,367	20,730	17,035
Exploration expenses	36,256	36,422	18,636
Depletion, depreciation, amortization and accretion	314,999	205,348	146,547
Impairment of long lived assets	1,647	23,425	15,778
Other operating expenses	451	10,891	2,353
Acquisition transaction expenses	0	2,719	6,000
General and administrative expenses	110,167	232,388	37,149
Total Operating Expenses	626,193	593,966	274,126
Operating Loss	(21,897)	(315,877)	(76,376)
Other Income (Expense):
Commodity derivatives gain (loss)	(36,332)	(100,947)	79,932
Interest expense	(51,889)	(68,843)	(51,030)
Other income	2,010	386	210
Total Other Income (Expense)	(86,211)	(169,404)	29,112
Net Loss Before Income Taxes	(108,108)	(485,281)	(47,264)
Income tax benefit	63,700	29,280	0
Net Loss	$ (44,408)	$ (456,001)	$ (47,264)
Loss Per Common Share (Note 12)
Basic and diluted (in dollars per share)	$ (0.35)	$ (1.54)
Weighted Average Common Shares Outstanding
Basic and diluted (in shares)	171,910	149,029

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS' AND STOCKHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Members' Units	Members' UnitsTranche A units	Members' UnitsPreferred Tranche C units	Common Stock	Treasury Stock	Additional Paid in Capital	Retained Earnings (Deficit)
Balance at beginning of period at Dec. 31, 2014	$ 545,188	$ 495,158						$ 50,030
Balance at beginning of period (in units or shares) at Dec. 31, 2014			227,903
CHANGES IN MEMBERS’ AND STOCKHOLDERS’ EQUITY
Units issued (in units)				78,444
Units issued	254,986	254,986
Unit issuance costs	(4,648)	(4,648)
Restricted stock units issued (in units)			3,198
Unit-based compensation	5,970	5,970
Net loss	(47,264)							(47,264)
Accretion of beneficial conversion feature on Series A Preferred Stock	0
Balance at end of period (in units or shares) at Dec. 31, 2015			231,101	78,444
Balance at end of period at Dec. 31, 2015	754,232	751,466						2,766
CHANGES IN MEMBERS’ AND STOCKHOLDERS’ EQUITY
Units issued (in units)				37,345
Units issued	121,370	121,370
Unit issuance costs	(1,022)	(1,022)
Restricted stock units issued (in units)			7,661
Unit-based compensation	14,922	14,922
Net loss	(456,001)							(456,001)
Units repurchased (in units)			(1,327)	(82)
Units repurchased	(8,429)	(8,429)
Settlement of promissory notes issued to officers	5,562	5,562
Stock-based compensation	185,386						$ 185,386
Corporate Reorganization of Extraction Oil & Gas Holdings and Extraction Oil & Gas Inc. (in units or shares)			(237,435)	(115,707)	108,461
Corporate Reorganization of Extraction Oil & Gas Holdings and Extraction Oil & Gas, Inc.		$ (883,869)			$ 1,085		882,784
Net deferred tax liability due to Corporate Reorganization	(135,306)						(135,306)
Issuance of common stock (in shares)					38,333
Issuance of common stock in initial public offering	728,333				$ 383		727,950
Issuance of common stock in a private placement (in shares)					25,041
Issuance of common stock in private placement	456,999				$ 250		456,749
Common stock issuance costs	(62,437)						(62,437)
Dividends paid on Series A Preferred Units	(15,000)						(15,000)
Series A Preferred Units issuance costs	(1,233)						(1,233)
Series B Preferred Unit and Series A Preferred Stock dividends	(2,958)						(2,958)
Beneficial conversion feature on Series A Preferred Stock	32,696						32,696
Accretion of beneficial conversion feature on Series A Preferred Stock	(1,041)						(1,041)
Balance at end of period (in units or shares) at Dec. 31, 2016					171,835
Balance at end of period at Dec. 31, 2016	1,616,073				$ 1,718		2,067,590	(453,235)
CHANGES IN MEMBERS’ AND STOCKHOLDERS’ EQUITY
Net loss	(44,408)							(44,408)
Units repurchased	(65,607)
Settlement of promissory notes issued to officers	0
Stock-based compensation							65,607
Net deferred tax liability due to Corporate Reorganization	(135,300)
Common stock issuance costs	(319)						(319)
Dividends paid on Series A Preferred Units	(10,885)						(10,885)
Accretion of beneficial conversion feature on Series A Preferred Stock	(5,394)						(5,394)
Repurchase of common stock (in shares)						165
Repurchase of common stock	(2,105)					$ (2,105)
Shares issued under LTIP, including payment of tax withholdings using withheld shares (in shares)					225
Shares issued under LTIP, including payment of tax withholdings using withheld shares	(1,804)						(1,804)
Balance at end of period (in units or shares) at Dec. 31, 2017					172,060	165
Balance at end of period at Dec. 31, 2017	$ 1,616,765				$ 1,718	$ (2,105)	$ 2,114,795	$ (497,643)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net loss	$ (44,408)	$ (456,001)	$ (47,264)
Reconciliation of net loss to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	314,999	205,348	146,547
Abandonment and impairment of unproved properties	15,808	22,318	16,414
Impairment of long lived assets	1,647	23,425	15,778
Loss on sale of property and equipment	451	0	0
Non-cash acquisition transaction expenses	0	0	6,000
Amortization of debt issuance costs and debt discount	4,260	19,088	5,604
Deferred rent	(294)	551	488
Commodity derivatives (gain) loss	36,332	100,947	(79,932)
Settlements on commodity derivatives	(11,985)	42,827	55,770
Premiums paid on commodity derivatives	(475)	(611)	(5,744)
Earnings in unconsolidated subsidiary	(415)	0	0
Distributions from unconsolidated subsidiary	415	0	0
Deferred income tax benefit	(63,700)	(29,280)	0
Unit and stock-based compensation	65,607	200,308	5,970
Changes in current assets and liabilities:
Accounts receivable—trade	(22,634)	(574)	7,723
Accounts receivable—oil, natural gas and NGL sales	(59,235)	(18,128)	(4,520)
Inventory and prepaid expenses	(523)	(1,110)	(1,024)
Accounts payable and accrued liabilities	31,202	(19,187)	24,452
Revenue payable	17,643	(6,602)	2,984
Production taxes payable	32,252	14,585	19,085
Accrued interest payable	4,186	19,171	277
Asset retirement expenditures	(4,168)	(687)	(1,742)
Due to related party	0	0	(183)
Net cash provided by operating activities	316,965	116,388	166,683
Cash flows from investing activities:
Oil and gas property additions	(1,370,787)	(449,600)	(391,250)
Acquired oil and gas properties	(17,225)	(419,009)	(120,524)
Sale of property and equipment	5,155	2,656	4,742
Other property and equipment additions	(22,189)	(7,655)	(23,045)
Distributions from unconsolidated subsidiary, return of capital	518	0	0
Cash held in escrow	42,200	(42,200)	10,071
Net cash used in investing activities	(1,362,328)	(915,808)	(520,006)
Cash flows from financing activities:
Borrowings under credit facility	565,000	263,000	125,000
Repayments under credit facility	(475,000)	(488,000)	0
Proceeds from the issuance of Senior Notes	394,000	550,000	0
Repayments of Second Lien Notes	0	(430,000)	0
Proceeds from the issuance of units	0	121,370	254,986
Repurchase of units	(2,105)	(2,867)	0
Payment of employee payroll withholding taxes	(1,804)	0	0
Issuance of common stock	0	1,185,332	0
Issuance of Series A Preferred Units	0	75,000	0
Redemption of Series A Preferred Units	0	(88,688)	0
Proceeds from the issuance of Series B Preferred Units	0	(185,280)	0
Debt issuance costs	(4,627)	(14,102)	(2,876)
Unit and common stock issuance costs	(1,668)	(64,554)	(5,706)
Net cash provided by financing activities	463,395	1,291,050	371,404
Increase (decrease) in cash and cash equivalents	(581,968)	491,630	18,081
Cash and cash equivalents at beginning of period	588,736	97,106	79,025
Cash and cash equivalents at end of the period	6,768	588,736	97,106
Supplemental cash flow information:
Property and equipment included in accounts payable and accrued liabilities	151,571	105,450	72,236
Acquisition transaction expenses paid through oil and gas properties	0	0	6,000
Cash paid for interest	54,492	31,280	50,380
Cash paid for Second Lien Notes prepayment penalty	0	4,300	0
Write-off of deposit on acquisition	0	10,000	0
Accretion of beneficial conversion feature	5,394	1,041	0
Noncash settlement of promissory notes issued to officers	0	5,562	0
Increase in dividends payable	484	0	0
Non-cash contribution to unconsolidated subsidiary	8,738	0	0
Series B Preferred Units
Cash flows from financing activities:
Dividends on preferred stock/units	0	(721)	0
Series A Preferred Stock
Cash flows from financing activities:
Dividends on preferred stock/units	$ (10,401)	$ 0	$ 0

Business and Organization

Business and Organization	12 Months Ended
	Dec. 31, 2017
Limited Liability Company or Limited Partnership, Business Organization and Operations [Abstract]
Business and Organization	Business and Organization Extraction Oil & Gas, Inc. (the “Company” or “Extraction”) is an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin (the “DJ Basin”) of Colorado. The Company and its subsidiaries are focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Rocky Mountain region, as well as the design and support of midstream assets to gather and process crude oil and gas production focused in the DJ Basin of Colorado. Extraction is a public company listed for trading on the NASDAQ Global Select Market under the symbol "XOG". The consolidated financial statements for the period January 1, 2016 through October 12, 2016 and for the year ended December 31, 2015 are based on the financial statements of the Company's accounting predecessor, Extraction Oil & Gas Holdings, LLC ("Holdings") prior to the corporate reorganization (the "Corporate Reorganization"), pursuant to which, in connection with the initial public offering of the Company (the "Offering" or "IPO"), (i) on October 11, 2016, a former subsidiary of Extraction Oil & Gas Holdings, LLC, Extraction Oil & Gas, LLC, converted into the Company, and (ii) on October 17, 2016, Holdings merged with and into the Company with the Extraction as the surviving entity.

Basis of Presentation and Signi

Basis of Presentation and Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation and Significant Accounting Policies	Basis of Presentation and Significant Accounting Policies 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 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 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 includes deposits for the purchase of certain oil and gas properties as required under the related purchase and sale agreements. 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, 2017 and 2016 . 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, 2017 , 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, 2017 2016 2015 Customer A 65 % 25 % — Customer B 19 % 19 % 17 % Customer C 11 % — % — % Customer D — % 23 % 30 % Customer E — % 16 % 17 % Customer F — % — % 24 % At December 31, 2017 , the Company had commodity derivative contracts with seven 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. Three of the seven counterparties to the derivative instruments are highly rated entities with corporate ratings at A3 classifications or above by Moody’s. Three additional counterparties have a corporate rating of Baa1 by Moody’s. One counterparty is a private entity and has a corporate rating of NAIC-2 by the National Association of Insurance Commissioners. For the years ended December 31, 2017 , 2016 and 2015, 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 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, 2017 2016 Well equipment inventory $ 9,971 $ 5,135 Prepaid expenses 3,046 2,587 $ 13,017 $ 7,722 Additionally, the Company recognized approximately $0.7 million and $0.4 million of impairment expense on well equipment inventory for the years ended December 31, 2017 and 2016 , respectively. There was no impairment on inventory recognized for the year ended December 31, 2015 . 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, 2017 , 2016 and 2015 , the Company excluded $127.4 million , $98.7 million and $59.4 million of capitalized costs from depletion related to wells in progress, respectively. For the years ended December 31, 2017 , 2016 and 2015 , the Company recorded depletion expense on capitalized oil and gas properties of $306.7 million , $197.4 million and $140.2 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, 2017 , the Company had approximately $15.7 million of suspended well costs, all capitalized less than one year. The suspended well costs are included in wells in progress at December 31, 2017. 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 2018. As of December 31, 2016, the Company did not have any suspended well costs as the analysis on economic and operating viability of the 2015 project was complete. As of December 31, 2015 , the Company had approximately $17.3 million in suspended well costs recorded, all capitalized less than one year, related to four exploratory wells in the northern field. The suspended well costs were included in wells in progress at December 31, 2015 . These exploratory well costs were pending further engineering evaluation and analysis to determine if economic quantities of oil and gas reserves had been discovered. At June 30, 2016, the Company completed its evaluation and moved $21.8 million of these suspended well costs to proved oil and gas properties based on the determination of proved reserves. 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 $1.4 million of costs associated with exploratory geological and geophysical costs for the year ended December 31, 2017. There were no exploratory geological and geophysical costs incurred for the years ended December 31, 2016 and 2015. The Company capitalizes interest, if debt is outstanding, during drilling operations in its exploration and development activities. For the years ended December 31, 2017 , 2016 and 2015 , the Company capitalized interest of approximately $11.1 million , $5.2 million and $5.3 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 accumulate 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 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 in the consolidated statements of operations, which increases accumulated depletion, depreciation and amortization. For the year ended December 31, 2017 , the Company recognized no impairment expense on proved oil and gas properties. For the years ended December 31, 2016 and 2015, the Company recognized $22.5 million and $9.5 million , respectively, in impairment expense on proved oil and gas properties in the Company's northern field. The future undiscounted cash flows did not exceed its carrying amount associated with its proved oil and gas properties in its northern field and 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 at June 30, 2016 and 2015. In December 2015, the Company sold proved oil and gas properties for proceeds of $4.7 million . As a result, these assets were fair valued on the date of the transaction in accordance with ASC 360 , Property, Plant and Equipment . The net book value of these assets exceeded the fair value by $2.7 million , which the Company recognized as impairment expense. The Company recognized $12.2 million in impairment expense that was attributable to proved oil and gas properties for the year ended December 31, 2015 . 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 $15.8 million , $22.3 million and $16.4 million in impairment expense for the years ended December 31, 2017 , 2016 and 2015 , respectively. Other Property and Equipment Other property and equipment consists of (i) midstream assets such as rights of way, pipelines, equipment and engineering costs, (ii) compressors used in Extraction’s oil and gas operations, (iii) land, compressor stations, central tank batteries, and disposal well facilities and (iv) other property and equipment including, office furniture and fixtures, leasehold improvements and computer hardware and software. Impairment expense for other property and equipment is reported in impairment of long lived assets in the consolidated statements of operations. The Company recognized $0.9 million , $0.5 million and $3.6 million in impairment expense related to midstream facilities for the years ended December 31, 2017 , 2016 and 2015 , 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, 2017 primarily as the result of right-of-way options that were no longer in the Company's plans for developing midstream infrastucture. The Company recognized the impairment expense for the years ended December 31, 2016 and 2015, 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 other operating expenses 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. Approximately $7.3 million of midstream assets, net of impairment expense, have not been placed into service and therefore are not currently being depreciated. 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, 2017 2016 Rental equipment $ 3,805 $ 2,910 Land 22,991 12,978 Midstream facilities 12,336 16,530 Office leasehold improvements 4,405 4,360 Other 5,578 4,786 Less: accumulated depreciation (11,797 ) (8,843 ) $ 37,318 $ 32,721 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 $8.3 million of such investments included in other non-current assets on the consolidated balance sheets as of December 31, 2017. The Company recognized $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, 2017. The Company held no such investments during the years ended December 31, 2016 and 2015. 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 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 and 2024 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 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 The Company applies the provisions of ASC 350, Intangibles-Goodwill and Other . Goodwill represents the excess of the purchase price over the estimated 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 an 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 year or less. The Company recorded $2.3 million and $0.3 million of internal-use software for the years ended December 31, 2017 and 2016 on the consolidated balance sheets within the goodwill and other intangible assets line item. Accumulated amortization for the years ended December 31, 2017 and 2016 was $1.1 million and $0.1 million , respectively. The Company recognized $1.0 million and $0.1 million amortization expense for the years ended December 31, 2017 and 2016, respectively. There was no capitalized internal-use software, accumulated amortization or amortization expense for the year ended December 31, 2015 . 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 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 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, 2017 . 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. There were no material imbalances at December 31, 2017 , 2016 or 2015. Unit and Stock‑Based Payments The Company and its predecessor, Holdings, has granted restricted unit awards ("RUAs") to certain employees and nonemployee consultants of the Company, 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. Unit‑based payments to nonemployees are measured at fair value at each financial reporting date and expensed over the period of performance, such that aggregate expense recognized is equal to the fair value of the restricted units on the date performance is completed. 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 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 is 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 will require 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. The Company currently evaluating other potential impacts of the TCJA. 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 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, stock option awards and performance stock 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 weigh

Oil and Gas Properties

Oil and Gas Properties	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Oil and Gas Properties	Oil and Gas Properties The Company’s oil and gas properties are entirely within the United States. The net capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands): As of December 31, 2017 2016 Proved oil and gas properties $ 3,011,526 $ 1,851,052 Unproved oil and gas properties (1) 686,968 452,577 Wells in progress (2) 127,418 98,747 Total capitalized costs (3) $ 3,825,912 $ 2,402,376 Accumulated depletion, depreciation and amortization (709,662 ) (402,912 ) Net capitalized costs $ 3,116,250 $ 1,999,464 (1) Unproved oil and gas properties represent unevaluated costs the Company excludes from the amortization base until proved reserves are established or impairment is determined. (2) Costs from wells in progress are excluded from the amortization base until production commences. (3) Includes accumulated interest capitalized of $24.5 million , $13.4 million and $8.2 million as of December 31, 2017 , 2016 and 2015 , respectively. The following table presents information regarding the Company’s net costs incurred in oil and gas property acquisition, exploration and development activities (in thousands): For the Year Ended December 31, 2017 2016 Property acquisition costs: Proved $ 139,481 $ 319,832 Unproved 382,213 220,213 Exploration costs (1) 17,074 13,588 Development costs 894,040 317,228 Total $ 1,432,808 $ 870,861 Total excluding asset retirement costs $ 1,420,235 $ 863,874 (1) Exploration costs do not include impairment and abandonment costs of unproved properties, which are included in the line item exploration expenses in the consolidated statements of operations.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Acquisitions	Acquisitions November 2017 Acquisition On November 15, 2017, the Company acquired an unaffiliated oil and gas company's interest in approximately 36,600 net acres of leasehold and primarily non-producing properties located in Arapahoe County, Colorado, (the "November 2017 Acquisition"). Upon closing the seller received $214.3 million in cash, subject to customary purchase price adjustments. The Company also recorded a liability of $12.2 million for the final settlement payment due in April 2018 in conjunction with November 2017 Acquisition, which has been reflected in the December 31, 2017 consolidated balance sheets within the accounts payable and accrued liabilities line item. This transaction has been accounted for as an asset acquisition. The acquisition provides new development opportunities in the Core DJ Basin. July 2017 Acquisition On July 7, 2017, the Company acquired an unaffiliated oil and gas company’s interests in approximately 12,500 net acres of leasehold and primarily non-producing properties located primarily in Adams County, Colorado, (the "July 2017 Acquisition"). Upon closing the seller received total consideration of $84.0 million in cash. The effective date for the July 2017 Acquisition is July 1, 2017. This transaction has been accounted for as an asset acquisition. The acquisition provides new development opportunities in the Core DJ Basin. June 2017 Acquisition On June 8, 2017, the Company acquired an unaffiliated oil and gas company’s interests in approximately 160 net acres of leasehold and related producing properties located in Weld County, Colorado (the “June 2017 Acquisition”). The Company paid approximately $13.4 million in cash consideration in connection with the closing of the June 2017 Acquisition. The effective date for the acquisition was January 1, 2017, with purchase price adjustments calculated as of the closing date of June 8, 2017. The acquisition increased the Company's interest in existing operated wells. The acquired producing properties contributed $3.7 million of revenue and $3.0 million of earnings, respectively, for the year ended December 31, 2017. The acquired producing properties contributed no revenue and earnings for the years ended December 31, 2016 and 2015. No significant transaction costs related to the acquisition were incurred for the years ended December 31, 2017, 2016 and 2015. The June 2017 Acquisition was accounted for using the acquisition method under ASC 805, Business Combinations , which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of June 8, 2017. In August 2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands): Purchase Price June 8, 2017 Consideration given Cash $ 13,395 Total consideration given $ 13,395 Allocation of Purchase Price Proved oil and gas properties $ 13,495 Total fair value of oil and gas properties acquired $ 13,495 Asset retirement obligations $ (100 ) Fair value of net assets acquired $ 13,395 November 2016 Acquisition On November 22, 2016, the Company acquired an unaffiliated oil and gas company’s interest in approximately 9,200 net acres of leaseholds located in the Core DJ Basin for approximately $120.0 million , including customary closing adjustments. The Company also made a $41.1 million deposit in November 2016 in conjunction with the November 2016 Acquisition, which has been reflected in the December 31, 2016 consolidated balance sheets within the cash held in escrow line item. The deposit was made for two additional closings of leaseholds located in the Core DJ Basin. The first closing occurred in January 2017 and added approximately 5,300 net acres for approximately $26.8 million . The second closing occurred in July 2017 and added approximately 640 net acres for approximately $10.9 million . This transaction has been accounted for as an asset acquisition. October 2016 Acquisition On October 3, 2016, the Company acquired an unaffiliated oil and gas company’s interests in approximately 6,400 net acres of leasehold, and related producing and non‑producing properties located primarily in Weld County, Colorado, along with various other related rights, permits, contracts, equipment, rights of way, gathering systems and other assets (the “Bayswater Assets” and the acquisition, the “October 2016 Acquisition”). The seller received aggregate consideration of approximately $405.3 million in cash. The effective date for the acquisition was July 1, 2016, with purchase price adjustments calculated as of the closing date on October 3, 2016. The acquisition provides new development opportunities in the DJ Basin as well as increases the Company’s existing working interest, as the majority of the locations are located on acreage in which the Company already owns a majority working interest and operates. The acquired producing properties contributed revenue of $17.2 million for the year ended December 31, 2016. The Company determined that it is not practical to calculate net income associated with October 2016 Acquisition. The Company incurred $2.6 million of transaction costs related to the acquisition for year ended December 31, 2016. These transaction costs are recorded in the consolidated statements of operations within the acquisition transaction expenses line item. No transaction costs related to the acquisition were incurred for the years ended December 31, 2017 and 2015 . The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations , which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of October 3, 2016. In February 2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands): Purchase Price October 3, 2016 Consideration given Cash $ 405,335 Total consideration given $ 405,335 Allocation of Purchase Price Proved oil and gas properties $ 252,522 Unproved oil and gas properties 109,800 Total fair value of oil and gas properties acquired $ 362,322 Goodwill (1) $ 54,220 Working capital (7,185 ) Asset retirement obligations (4,022 ) Fair value of net assets acquired $ 405,335 Working capital acquired was estimated as follows: Accounts receivable $ 955 Revenue payable (3,012 ) Production taxes payable (4,244 ) Accrued liabilities (884 ) Total working capital $ (7,185 ) (1) Goodwill is primarily attributable to a decrease in commodity prices from the time the acquisition was negotiated and commodity prices on October 3, 2016 and the operational and financial synergies expected to be realized from the acquisition. Goodwill recognized as a result of the Bayswater Acquisition is not deductible for income tax purposes. Option to Acquire Additional Assets from October 2016 Acquisition Upon the closing of the October 2016 Acquisition, the Company made a $10.0 million non‑refundable payment for an option to purchase additional assets from the seller of the October 2016 Acquisition (the “Additional Assets”) for an additional $190.0 million , for a total purchase price for the Additional Assets of $200.0 million . The option may be exercised at any time until March 31, 2017. If the Company does not exercise the option to acquire the Additional Assets, the seller will have the right until April 30, 2017 to elect to sell those assets to the Company for an additional $120.0 million , for a total purchase price for the Additional Assets of $130.0 million . In March 2017, the Company entered into an amendment to this agreement with Bayswater to terminate both the Company's and Bayswater’s options for no further consideration. The $10.0 million was expensed in the fourth quarter of 2016 to other operating expenses within the consolidated statements of operations. August 2016 Acquisition On August 23, 2016, the Company acquired an unaffiliated oil and gas company’s interests in approximately 1,400 net acres of leasehold located primarily in Weld County, Colorado, along with various other related rights, permits, contracts, equipment, rights of way and other assets (the “August 2016 Acquisition”). The seller received aggregate consideration of approximately $17.5 million in cash. The effective date for the acquisition was August 31, 2016, with purchase price adjustments calculated as of the closing date of August 23, 2016. The acquisition provided new development opportunities in the DJ Basin as well as additions adjacent to the Company’s core project area. The Company incurred $0.1 million of transaction costs related to the acquisition. These transaction costs were recorded in the condensed consolidated statements of operations within the acquisition transaction expenses line item in the third quarter of 2016. The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations , which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of August 23, 2016. In March 2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands): Purchase Price August 23, 2016 Consideration given Cash $ 17,504 Total consideration given $ 17,504 Allocation of Purchase Price Proved oil and gas properties $ 12,362 Unproved oil and gas properties 8,566 Total fair value of oil and gas properties acquired $ 20,928 Working capital $ (9 ) Asset retirement obligations (3,415 ) Fair value of net assets acquired $ 17,504 Working capital acquired was estimated as follows: Production taxes payable (9 ) Total working capital $ (9 ) March 2015 Acquisition On March 10, 2015, the Company acquired an unaffiliated oil and gas company’s interests in approximately 39,000 net acres of leasehold, and related producing properties located primarily in Adams, Broomfield, Boulder and Weld Counties, Colorado, along with various other related rights, permits, contracts, equipment, rights of way, gathering systems and other assets (the “March 2015 Acquisition”). The seller received aggregate consideration of approximately $120.5 million in cash. The effective date for the acquisition was January 1, 2014, with purchase price adjustments calculated as of the closing date on March 10, 2015. The acquisition provided new development opportunities in the DJ Basin as well as additions adjacent to the Company’s core project area and the acquired producing properties contributed revenue of $8.0 million to the Company for the year ended December 31, 2015. The Company determined that it is not practical to calculate net income associated with March 2015 Acquisition. The Company incurred $0.5 million of transaction costs related to the acquisition for the year ended December 31, 2015. These transaction costs are recorded in the consolidated statements of operations within the general and administrative expenses line item. No transaction costs related to the acquisition were incurred for the years ended December 31, 2017 and 2016. Additionally, the Company incurred $6.0 million of non‑cash transaction costs associated with a finder’s fee to an unaffiliated third‑party. The Company assigned an over‑riding royalty interest in the proved and unproved oil and gas properties acquired in the March 2015 Acquisition, which had a fair value of $6.0 million on the measurement date. These transaction costs are recorded in the consolidated statements of operations within the acquisition transaction expense line item. The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations , which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of March 10, 2015. In November 2015, the Company completed the transaction’s post‑closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands): Purchase Price March 10, 2015 Consideration given Cash $ 120,524 Total consideration given $ 120,524 Allocation of Purchase Price Proved oil and gas properties $ 80,952 Unproved oil and gas properties 69,450 Total fair value of oil and gas properties acquired $ 150,402 Working capital $ (1,996 ) Asset retirement obligations (27,882 ) Fair value of net assets acquired $ 120,524 Working capital acquired was estimated as follows: Accounts receivable $ 462 Revenue payable (718 ) Production taxes payable (1,740 ) Total working capital $ (1,996 ) Pro Forma Financial Information (Unaudited) For the years ended December 31, 2017 and 2016 , the following pro forma financial information represents the combined results for the Company and the properties acquired in June 2017 as if the acquisition and related financing had occurred on January 1, 2016 and for the properties acquired in October 2016 as if the acquisition and related financing had occurred on January 1, 2015. For the year ended December 31, 2015 , the following pro forma financial information represents the combined results for the Company and the properties acquired in March 2015 as if the acquisition and related financing had occurred on January 1, 2015 (all in thousands, except per share data). For purposes of the pro forma financial information, it was assumed that the June 2017 Acquisition was funded through cash. For purposes of the pro forma financial information, it was assumed that the October 2016 Acquisition was funded through the issuance of $260.3 million in convertible preferred securities and borrowings under the revolving credit facility. For purposes of the pro forma financial information, it was assumed that the Company issued equity to finance the March 2015 Acquisition. The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion expense of $1.6 million , $23.1 million and $1.5 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. No pro forma adjustments were made for non-recurring transaction costs for the year ended December 31, 2017 . T he pro forma information includes the effects of a decrease in non-recurring transaction costs that are included in general and administrative expenses and acquisition transaction expenses o f $2.6 million and $6.4 million for the years ended December 31, 2016 and 2015 , respectively. No pro forma adjustments were made for incremental interest expense on acquisition financing for the year ended December 31, 2017 . The pro forma information includes the effects of adjustments for the incremental interest expense on acquisition financing of $4.0 million and $4.0 million for the years ended December 31, 2016 and 2015 , respectively. The pro forma information includes the effects of adjustments for income ta xes of $0.6 million for the year ended December 31, 2017 . No pro forma adjustments were made for the effect of income taxes for the years ended December 31, 2016 and 2015 as the acquisitions occurred before the Corporate Reorganization. Additionally, the pro forma financial information excludes the effects the August 2016 Acquisition as these pro forma adjustments were de minimis. The following pro forma results (in thousands, except per share data) do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to int egrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results. Net income (loss) per share is not applicable for the period prior to the Corporate Reorganization. For the Year Ended December 31, 2017 2016 2015 Revenues $ 606,460 $ 325,355 $ 214,259 Net loss $ (44,231 ) $ (441,571 ) $ (33,524 ) Loss per share Basic and diluted $ (0.35 ) $ (1.54 )

Long Term Debt

Long Term Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt	Long‑Term Debt As of the dates indicated the Company’s long‑term debt consisted of the following (in thousands): As of December 31, 2017 2016 Credit facility due November 29, 2018 $ 90,000 $ — 2021 Senior Notes due July 15, 2021 550,000 550,000 2024 Senior Notes due May 15, 2024 400,000 — Unamortized debt issuance costs on Senior Notes (16,639 ) (11,859 ) Total long-term debt $ 1,023,361 $ 538,141 Credit Facility On September 4, 2014, Holdings entered into a credit facility with a syndicate of banks, which is subject to a borrowing base. In connection with the IPO and the merger of Holdings into the Company, the Company assumed all of the obligations of Holdings under the credit facility and became the borrower thereunder. In August 2017, the Company entered into an amendment and restatement of its existing credit facility (prior to amendment and restatement, the "Prior Credit Facility"), to provide aggregate commitments of $1.5 billion with a syndicate of banks, which is subject to a borrowing base. The credit facility matures on the earlier of (a) August 16, 2022, (b) January 15, 2021 if (and only if) the Company's 2021 Senior Notes (as defined below) have not been refinanced or repaid in full on or prior to January 15, 2021, (c) April 15, 2021, if (and only if) (i) the Series A Preferred Stock of the Company (the "Series A Preferred Stock") have not been converted into common equity or redeemed prior to April 15, 2021, and (ii) prior to April 15, 2021, the maturity date of the Series A Preferred Stock has not been extended to a date that is no earlier than six months after August 16, 2022 or (d) the earlier termination in whole of the commitments. No principal payments are generally required until the credit agreement matures or in the event that the borrowing base falls below the outstanding balance. Subsequent to December 31, 2017, the Company repaid in full its 2021 Senior Notes. As of December 31, 2017 , the credit facility was subject to a borrowing base of $525.0 million . As of December 31, 2017 , the Company had $90.0 million of borrowings outstanding. As of December 31, 2016 , with respect to the Prior Credit Facility, the Company had no outstanding borrowings. As of December 31, 2017 and, with respect to the Prior Credit Facility, December 31, 2016 , the Company had standby letters of credit of $25.7 million and $0.6 million , respectively. At December 31, 2017 , the undrawn balance under the credit facility was $435.0 million . As of the date of this filing, the Company had $50.0 million borrowings outstanding under the credit facility. The amount available to be borrowed under the Company's revolving credit facility is subject to a borrowing base that is redetermined semiannually on each May 1 and November 1, and will depend on the volumes of the Company's proved oil and gas reserves and estimated cash flows from these reserves and other information deemed relevant by the administrative agent under the Company's revolving credit facility. In January 2018, the Company completed the November 1, 2017 borrowing base redetermination. As a result of the redetermination, the borrowing base increased to $750.0 million , subject to the current maximum lending commitments of $650.0 million . Interest on the credit facility is payable at one of the following two variable rates as selected by the Company: a base rate based on the Prime Rate or the Eurodollar rate, based on LIBOR. Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the facility as outlined in the Pricing Grid. Additionally, the credit facility provides for a commitment fee of 0.375% to 0.50% , depending on borrowing base usage. The grid below shows the Base Rate Margin and Eurodollar Margin depending on the applicable Borrowing Base Utilization Percentage (as defined in the credit facility) as of the date of this filing: Borrowing Base Utilization Grid LIBOR Base Rate Commitment Borrowing Base Utilization Percentage Utilization Margin Margin Fee Level 1 < 25 2.00 % 1.00 % 0.375 % Level 2 ≥ 25% < 50 2.25 % 1.25 % 0.375 % Level 3 ≥ 50% < 75 2.50 % 1.50 % 0.500 % Level 4 ≥ 75% < 90 2.75 % 1.75 % 0.500 % Level 5 ≥ 90 3.00 % 2.00 % 0.500 % The credit facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on dividends, distributions, redemptions and restricted payments covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on the sale of property, mergers, consolidations and other similar transactions covenants. Additionally, the credit facility limits the Company from hedging in excess of 85% of its anticipated production volumes. The credit facility also contains financial covenants requiring the Company to comply with a current ratio of the Company's consolidated current assets (includes unused commitments under the Company's revolving credit facility and unrestricted cash and excludes derivative assets) to the Company's consolidated current liabilities (excludes obligations under the Company's revolving credit facility, the second lien notes and certain derivative assets), of not less than 1.0 to 1.0 and to maintain, on the last day of each quarter, a net leverage ratio, which is the ratio of (i) consolidated debt less cash balances to (ii) the Company's consolidated EBITDAX for the four fiscal quarter period most recently ended, not to exceed 4.0 to 1.0 as of the last day of such fiscal quarter; provided that (a) for the quarter ending December 31, 2017, consolidated EBITDAX will be based on the last nine months' consolidated EBITDAX multiplied by 4/3 and (b) for the quarters ending on or after March 31, 2018, consolidated EBITDAX will be based on the last twelve months’ consolidated EBITDAX. The Company was in compliance with all financial covenants under the credit facility as of December 31, 2017. Any borrowings under the credit facility are collateralized by substantially all of the assets of the Company and its subsidiaries, including oil and gas properties, personal property and the equity interests of the subsidiaries of the Company. The Company has entered into oil and natural gas hedging transactions with several counterparties that are also lenders under the credit facility. The Company’s obligations under these hedging contracts are secured by the collateral securing the credit facility. 2021 Senior Notes In July 2016, the Company issued at par $550.0 million principal amount of 7.875% Senior Notes due July 15, 2021 (the “2021 Senior Notes” and the offering, the "2021 Senior Notes Offering"). The 2021 Senior Notes bear an annual interest rate of 7.875% . The interest on the 2021 Senior Notes is payable on January 15 and July 15 of each year commencing on January 15, 2017. The Company received net proceeds of approximately $537.2 million after deducting discounts and fees. The 2021 Senior Notes also contain affirmative and negative covenants that, among other things, limit the Company's and the Guarantors' ability to make investments; declare or pay any dividend or make any other payment to holders of the Company’s or any of its Guarantors’ equity interests; repurchase or redeem any equity interests of the Company; repurchase or redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company's affiliates; engage in any business other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2021 Senior Notes (the “2021 Senior Notes Indenture”) also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2021 Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the 2021 Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2021 Senior Notes may declare all outstanding 2021 Senior Notes to be due and payable immediately. The Company was in compliance with all financial covenants under the 2021 Senior Notes Indenture as of December 31, 2017 . Concurrent with the 2026 Notes Offering, the Company commenced a cash tender offer to purchase any and all of its 2021 Senior Notes. On January 24, 2018 the Company received approximately $500.6 million aggregate principal amount of the 2021 Senior Notes which were validly tendered (and not validly withdrawn). As a result, on January 25, 2018 the Company made a cash payment of approximately $534.2 million , which included principal of approximately $500.6 million , a make-whole premium of approximately $32.6 million and accrued and unpaid interest of approximately $1.0 million . On February 17, 2018, the Company redeemed approximately $49.4 million aggregate principal amount of the 2021 Senior Notes that remained outstanding after the Tender Offer and made a cash payment of approximately $52.7 million to the remaining holders of the 2021 Senior Notes, which includes a make-whole premium of $3.0 million and accrued and unpaid interest of approximately $0.3 million . 2024 Senior Notes In August 2017, the Company issued at par $400.0 million principal amount of 7.375% Senior Notes due May 15, 2024 (the “2024 Senior Notes” and the offering, the “2024 Senior Notes Offering”). The 2024 Senior Notes bear an annual interest rate of 7.375% . The interest on the 2024 Senior Notes is payable on May 15 and November 15 of each year commencing on November 15, 2017. The Company received net proceeds of approximately $392.6 million after deducting discounts and fees. The Company's 2024 Senior Notes are its senior unsecured obligations and rank equally in right of payment with all of its other senior indebtedness and senior to any of its subordinated indebtedness. The Company's 2024 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of its current subsidiaries and by certain future restricted subsidiaries that guarantees its indebtedness under a credit facility (the “2024 Senior Note Guarantors”). The 2024 Senior Notes are effectively subordinated to all of the Company's secured indebtedness (including all borrowings and other obligations under its revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any of its future subsidiaries that do not guarantee the 2024 Senior Notes. The 2024 Senior Notes also contain affirmative and negative covenants that, among other things, limit the Company's and the Guarantors' ability to make investments; declare or pay any dividend or make any other payment to holders of the Company’s or any of its Guarantors’ equity interests; repurchase or redeem any equity interests of the Company; repurchase or redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company's affiliates; engage in any business other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2024 Senior Notes (the “2024 Senior Notes Indenture”) also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2024 Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the 2024 Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2024 Senior Notes may declare all outstanding 2024 Senior Notes to be due and payable immediately. The Company was in compliance with all financial covenants under the 2024 Senior Notes Indenture as of December 31, 2017 . 2026 Senior Notes In January, 2018, the Company closed a private offering of its 2026 Senior Notes (the “2026 Senior Notes” and the offering, the "2026 Senior Notes Offering") that resulted in net proceeds of approximately $737.9 million after deducting discounts and fees. The Company used $534.2 million of the net proceeds from the 2026 Senior Notes Offering to tender for its 2021 Senior Notes, $52.7 million to redeem any 2021 Senior Notes not tendered and the remainder for general corporate purposes. The Company's 2026 Senior Notes bear interest at an annual rate of 5.625% . Interest on the Company's 2026 Senior Notes is payable on February 1 and August 1 of each year, and the first interest payment will be made on August 1, 2018. The Company's 2026 Senior Notes will mature on February 1, 2026. The Company's 2026 Senior Notes are the Company's senior unsecured obligations and rank equally in right of payment with all of the Company's other senior indebtedness and senior to any of the Company's subordinated indebtedness. The Company's 2026 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of the Company's current subsidiaries and by certain future restricted subsidiaries that guarantee the Company's indebtedness under a credit facility. The 2026 Senior Notes are effectively subordinated to all of the Company's secured indebtedness (including all borrowings and other obligations under the Company's revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any of the Company's future subsidiaries that do not guarantee the 2026 Senior Notes. The 2026 Senior Notes also contain affirmative and negative covenants that, among other things, limit the Company’s and the Guarantors’ ability to make investments; declare or pay any dividend or make any other payment to holders of the Company’s or any of its Guarantors’ equity interests; repurchase or redeem any equity interests of the Company; repurchase or redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company’s affiliates; engage in any business other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2026 Senior Notes (the “2026 Senior Notes Indenture”) also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2026 Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the 2026 Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2024 Senior Notes may declare all outstanding 2026 Senior Notes to be due and payable immediately. Second Lien Notes On May 29, 2014, Holdings entered into a five year, $430.0 million term loan facility with a syndicate of lenders (the “Second Lien Notes”). The Second Lien Notes would have matured on May 29, 2019. Holdings had drawn the full $430.0 million under the Second Lien Notes that bore an average interest rate of approximately 10.7% . The interest rates were fixed and interest was payable semi‑annually. In July 2016, the Second Lien Notes were repaid and terminated in conjunction with the 2021 Senior Notes Offering. The Company used the proceeds from the 2021 Senior Notes (as discussed below) to repay the outstanding $430.0 million of principal and a $4.3 million prepayment penalty. The prepayment penalty was expensed during the year ended December 31, 2016 in the consolidated statements of operations within the interest expense line item. Additionally, during the year ended December 31, 2016, the Company wrote off approximately $15.1 million of unamortized debt discount and debt issuance costs that were related to the Second Lien Notes. The write off of the unamortized debt discount and debt issuance costs were recorded in the consolidated statements of operations within the interest expense line item. Debt Discount Costs on Second Lien Notes The Company’s Second Lien Notes were issued with an original issue discount (OID) of $6.5 million . In July 2016, the Company repaid the Second Lien Notes in full and accelerated the remaining unamortized balance of $4.3 million . This expense was recorded in the consolidated statements of operations within the interest expense line item. As of December 31, 2017 , there was no remaining balance on the OID. Debt Issuance Costs As of December 31, 2017 and 2016 , the Company had debt issuance costs net of accumulated amortization of $3.8 million and $2.2 million , respectively, related to its credit facility which has been reflected on the Company’s consolidated balance sheet within the line item other non‑current assets. As of December 31, 2017 , the Company had debt issuance costs net of accumulated amortization of $16.6 million related to its 2021 and 2024 Senior Notes (collectively, the "Senior Notes"), and as of December 31, 2016 , the Company had debt issuance costs net of accumulated amortization of $11.9 million related to its 2021 Senior Notes, which has been reflected on the Company's consolidated balance sheet within the line item Senior Notes, net of unamortized debt issuance costs. Upon the repayment of the Company’s Second Lien Notes, the Company accelerated the amortization of the remaining $10.8 million of unamortized debt issuance costs. This expense was recorded in the consolidated statements of operations within the interest expense line item. As of December 31, 2017 and 2016 , there was no remaining balance on debt issuance costs associated with the Second Lien Notes. Debt issuance costs include origination, legal, engineering, and other fees incurred in connection with the Company’s credit facility and Senior Notes. For the years ended December 31, 2017 , 2016 , and 2015 , the Company recorded amortization expense related to the debt issuance costs of $4.3 million , $14.4 million and $3.1 million , respectively. Interest Incurred On Long‑Term Debt For the years ended December 31, 2017 , 2016 and 2015 , the Company incurred interest expense on long‑term debt of $58.7 million , $50.5 million and $50.5 million , respectively and capitalized interest of $11.1 million , $5.2 million and $5.3 million , for the years ended December 31, 2017 , 2016 and 2015 , respectively, which has been reflected in the Company’s financial statements. Also included in interest expense for the year ended December 31, 2016 is a prepayment penalty of $4.3 million related to the Company’s repayment of its Second Lien Notes in July 2016.

Commodity Derivative Instrument

Commodity Derivative Instruments	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivative Instruments	Commodity Derivative Instruments The Company has entered into commodity derivative instruments, as described below. The Company has utilized swaps, put options and call options to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production. A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. A put option has an established floor price. The buyer of the put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless. Some of the Company’s purchased put options have deferred premiums. For the deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement. A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless. The Company combines swaps, purchased put options, purchased call options, sold put options and sold call options in order to achieve various hedging strategies. Some examples of the Company’s hedging strategies are collars which include purchased put options and sold call options, three-way collars which include purchased put options, sold put options and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap. The objective of the Company’s use of commodity derivative instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these commodity derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes. The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with seven counterparties, all of whom are lenders under our credit agreement. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparties 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. There are no credit‑risk‑related contingent features or circumstances in which the features could be triggered in derivative instruments that are in a net liability position at the end of the reporting period. The Company’s commodity derivative contracts as of December 31, 2017 are summarized below: 2018 2019 NYMEX WTI Crude Swaps: Notional volume (Bbl) 5,100,000 — Weighted average fixed price ($/Bbl) $ 51.61 $ — NYMEX WTI Crude Sold Calls: Notional volume (Bbl) 8,290,000 5,100,000 Weighted average sold call price ($/Bbl) $ 56.18 $ 55.93 NYMEX WTI Crude Sold Puts: Notional volume (Bbl) 13,438,800 5,100,000 Weighted average sold put price ($/Bbl) $ 39.10 $ 39.82 NYMEX WTI Crude Purchased Puts: Notional volume (Bbl) 12,327,600 5,100,000 Weighted average purchased put price ($/Bbl) $ 44.81 $ 49.69 NYMEX HH Natural Gas Swaps: Notional volume (MMBtu) 40,800,000 — Weighted average fixed price ($/MMBtu) $ 3.10 $ — NYMEX HH Natural Gas Purchased Puts: Notional volume (MMBtu) 2,400,000 — Weighted average purchased put price ($/MMBtu) $ 3.00 $ — NYMEX HH Natural Gas Sold Calls: Notional volume (MMBtu) 2,400,000 — Weighted average sold call price ($/MMBtu) $ 3.15 $ — CIG Basis Gas Swaps: Notional volume (MMBtu) 6,300,000 — Weighted average fixed basis price ($/MMBtu) $ (0.31 ) $ — The following tables detail the fair value of the Company’s derivative instruments, including the gross amounts and adjustments made to net the derivative instruments for the presentation in the balance sheets (in thousands): As of December 31, 2017 Net Amounts of Gross Amounts Assets and of Recognized Gross Amounts Liabilities Gross Amounts Assets and Offset in the Presented in the not Offset in the Net Location on Balance Sheet Liabilities Balance Sheet (1) Balance Sheet Balance Sheet (2) Amounts (3) Current assets $ 22,118 $ (17,986 ) $ 4,132 $ — $ 4,132 Non-current assets $ 13,686 $ (13,686 ) $ — $ — $ — Current liabilities $ (85,414 ) $ 17,986 $ (67,428 ) $ — $ (84,702 ) Non-current liabilities $ (30,960 ) $ 13,686 $ (17,274 ) $ — $ — As of December 31, 2016 Net Amounts of Gross Amounts Assets and of Recognized Gross Amounts Liabilities Gross Amounts Assets and Offset in the Presented in the not Offset in the Net Location on Balance Sheet Liabilities Balance Sheet (1) Balance Sheet Balance Sheet (2) Amounts (3) Current assets $ 12,620 $ (12,620 ) $ — $ — $ — Non-current assets $ 14,993 $ (14,993 ) $ — $ — $ — Current liabilities $ (68,623 ) $ 12,620 $ (56,003 ) $ — $ (62,741 ) Non-current liabilities $ (21,731 ) $ 14,993 $ (6,738 ) $ — $ — (1) Agreements are in place with all of the Company’s financial trading counterparties that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. (2) Netting for balance sheet presentation is performed by current and non‑current classification. This adjustment represents amounts subject to an enforceable master netting arrangement, which are not netted on the balance sheet. There are no amounts of related financial collateral received or pledged. (3) Net amounts are not split by current and non‑current. All counterparties in a net asset position are shown in the current asset line item and all counterparties in a net liability position are shown in the current liability line item. The table below sets forth the commodity derivatives gain (loss) for the years ended December 31, 2017 , 2016 and 2015 (in thousands). Commodity derivatives gain (loss) are included under other income (expense). For the Year Ended December 31, 2017 2016 2015 Commodity derivatives gain (loss) $ (36,332 ) $ (100,947 ) $ 79,932

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The Company follows accounting for asset retirement obligations in accordance with ASC 410, Asset Retirement and Environmental Obligations , which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The Company’s asset retirement obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut‑in wells at the end of their productive lives in accordance with applicable local, state and federal laws, and applicable lease terms. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred; the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement costs are depleted with proved oil and gas properties using the unit of production method. The following table summarizes the activities of the Company’s asset retirement obligations for the periods indicated (in thousands): For the Year Ended December 31, 2017 2016 Balance beginning of period $ 56,108 $ 44,367 Liabilities incurred or acquired 9,802 8,945 Liabilities settled (4,169 ) (1,155 ) Revisions in estimated cash flows 2,630 (1,695 ) Accretion expense 5,169 5,646 Balance end of period $ 69,540 $ 56,108

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements ASC 820, Fair Value Measurement and Disclosure , establishes a hierarchy for inputs used in measuring fair value 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 developed 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 developed 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 are 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; • Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations. 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. There were no transfers between levels during any periods presented below. The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2017 and December 31, 2016 by level within the fair value hierarchy (in thousands): Fair Value Measurements at December 31, 2017 Using Level 1 Level 2 Level 3 Total Financial Assets: Commodity derivative assets $ — $ 4,132 $ — $ 4,132 Financial Liabilities: Commodity derivative liabilities $ — $ 84,702 $ — $ 84,702 Fair Value Measurements at December 31, 2016 Using Level 1 Level 2 Level 3 Total Financial Assets: Commodity derivative assets $ — $ — $ — $ — Financial Liabilities: Commodity derivative liabilities $ — $ 62,741 $ — $ 62,741 The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above: Commodity Derivative Instruments The Company determines its estimate of the fair value of derivative instruments using a market based approach that takes into account several factors, including quoted market prices in active markets, implied market volatility factors, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit rating. In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. Derivative instruments utilized by the Company consist of swaps, put options, and call options. The oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are valued using public indices, the instruments themselves are traded with third‑party counterparties and are not openly traded on an exchange. 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) 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 approximated fair value as it bears interest at variable rates over the term of the loan. The fair value of the 2021 Senior Notes and 2024 Senior Notes was derived from available market data. As such, the Company has classified the 2021 Senior Notes and 2024 Senior Notes as Level 2. Please refer to Note 5 — Long‑Term Debt for further information. The Company’s policy is to recognize transfers between levels at the end of the period. This disclosure (in thousands) does not impact the Company’s financial position, results of operations or cash flows. At December 31, 2017 At December 31, 2016 Carrying Carrying Amount Fair Value Amount Fair Value Credit facility $ 90,000 $ 90,000 $ — $ — 2021 Senior Notes (1) $ 540,382 $ 583,000 $ 538,141 $ 588,500 2024 Senior Notes (2) $ 392,979 $ 427,000 $ — $ — (1) The carrying amount of the 2021 Senior Notes includes unamortized debt issuance costs of $9.6 million and $ 11.9 million as of December 31, 2017 and 2016, respectively. (2) The carrying amount of the 2024 Senior Notes includes unamortized debt issuance costs of $7.0 million as of December 31, 2017. Non‑Recurring Fair Value Measurements The Company applies the provisions of the fair value measurement standard on a non‑recurring basis to its non‑financial assets and liabilities, including proved property and goodwill. These assets and liabilities are not measured at fair value on a recurring basis, but are subject to fair value adjustments when facts are circumstances arise that indicate a need for measurement. The Company utilizes fair value on a non‑recurring basis to review its proved oil and gas properties for potential impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. The Company uses an income approach analysis based on the net discounted future cash‑flows of producing property. The future cash‑flows are based on Management’s estimates for the future. Unobservable inputs included future estimates of oil and gas production, as the case may be, from the Company’s reserve reports, commodity prices based on the sales contract terms or forward price curves, operating and development costs, and a discount rate based on a market-based weighted average cost of capital (all of which are Level 3 inputs within the fair value hierarchy). No impairment expense was recognized for the year ended December 31, 2017 on proved oil and gas properties. For the years ended December 31, 2016 and 2015, the Company recognized $22.5 million and $9.5 million in impairment expense on proved oil and gas properties. The impairment expense for the years ended December 31, 2016 and 2015 is related to impairment of the assets in the Company’s northern field. The future undiscounted cash flows did not exceed its carrying amount associated with its proved oil and gas properties in the Company’s northern field and 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 at June 30, 2016 and 2015, respectively. Additionally, during 2015, the Company sold proved oil and gas properties for proceeds of $4.7 million . In connection with the sale, the Company determined that assets’ net book value exceeded the fair value of such properties by $2.7 million . The Company recognized that amount as an impairment expense for the year ended December 31, 2015. The Company applies the provisions of ASC 350, Intangibles-Goodwill and Other . Goodwill represents the excess of the purchase price over the estimated 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 an 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. The Company’s other non‑recurring fair value measurements include the purchase price allocations for the fair value of assets and liabilities acquired through business combinations, please refer to Note 4 — Acquisitions . The fair value of assets and liabilities acquired through business combinations is calculated using a discounted‑cash flow approach using level 3 inputs. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk‑adjusted oil and gas reserves, commodity prices, development costs, and operating costs, based on market participant assumptions. The fair value of assets or liabilities associated with purchase price allocations is on a non‑recurring basis and is not measured in periods after initial recognition.

Equity

Equity	12 Months Ended
	Dec. 31, 2017
Stockholders' Equity Note [Abstract]
Equity	Equity Private Placement of Common Stock On December 15, 2016, the Company completed the issuance of 25.0 million shares of common stock, at a price of $18.25 per share, in connection with the Private Placement (the “Private Placement”). The Private Placement resulted in approximately $457.0 million of gross proceeds and approximately $441.9 million of net proceeds, after deducting placement agent commissions and offering expenses. Proceeds from the Private Placement were to be used for general corporate purposes, including to fund the Company’s 2017 capital expenditures. Initial Public Offering On October 17, 2016, the Company completed its initial public offering, issuing 38.3 million shares of common stock, par value $0.01 per share (“common stock”), which include the full exercise of the underwriters’ over-allotment option of 5.0 million shares at a price of $19.00 per share. The net proceeds of the offering were $681.0 million , after deducting underwriting discounts and commissions and offering expenses, of approximately $47.3 million . The proceeds from the Offering were used to (i) redeem in full the Series A Preferred Units for $90.0 million and (ii) to repay borrowings under the Company’s revolving credit facility for $291.6 million . The remaining net proceeds were to be used for general corporate purposes, including to fund 2017 capital expenditures. The material terms of the Offering are described in the Company’s final prospectus, dated October 11, 2016 and filed with the SEC pursuant to Rule 424(b)(4) of the Securities Act of 1933, as amended, on October 13, 2016. Series A Preferred Units On October 3, 2016, the Company issued $75.0 million in Series A Preferred Units (the “Series A Preferred Units”) to fund a portion of the purchase price for the October 2016 Acquisition. The Series A Preferred Units were entitled to receive a cash dividend of 10% per year, payable quarterly in arrears. All holders of Series A Preferred Units were also members of Holdings. The Company used $90.0 million of the net proceeds from its IPO to redeem the Series A Preferred Units in full on October 17, 2016, including a premium of $15.0 million which is recorded within additional paid in capital in the consolidated statement of changes in members’ and stockholders’ equity. For further discussion on the October 2016 Acquisition, please refer to Note 4 — Acquisitions. Series A Preferred Stock and Series B Preferred Units On October 3, 2016, the Company issued $185.3 million in convertible preferred securities ("Series B Preferred Units") to fund a portion of the purchase price for the October 2016 Acquisition. The Series B Preferred Units were entitled to receive a cash dividend of 10% per year, payable quarterly in arrears, and the Company had the ability to pay up to 50% of the quarterly dividend in kind. For the year ended December 31, 2016, the Company paid $0.7 million of dividends associated with the Series B Preferred Units. The Company did not make any payments in kind on the Series B Preferred Units from the date of issuance of the Series B Preferred Units through the Offering. The Series B Preferred Units converted in connection with the closing of the IPO into 185,280 shares of Series A Convertible Preferred Stock (the "Series A Preferred Stock") that are entitled to receive a cash dividend of 5.875% per year, payable quarterly in arrears, and the Company has the ability to pay such quarterly dividends in kind at a dividend rate of 10% per year (decreased proportionately to the extent such quarterly dividends are paid in cash). For the year ended December 31, 2017, the Company accrued $2.7 million of dividends associated with the Series A Preferred Stock, or $14.69 per share, which were paid in January 2018. The Company did not make any payments in kind on the Series A Preferred Stock from the date of the Offering through December 31, 2017. Beginning on or after the later of (a) 90 days after the closing of the Offering and (b) the earlier of 120 days after the closing of the Offering and the expiration of the lock-up period contained in the underwriting agreement entered into in connection with the Offering ("Lock-Up Period End Date"), the Series A Preferred Stock will be convertible into shares of the Company's common stock at the election of the holders of the Series A Preferred Stock ("Series A Preferred Holders") at a conversion ratio per share of Series A Preferred Stock of 61.9195 . Beginning on or after the Lock-Up Period End Date until the three year anniversary of the closing of the Offering, the Company may elect to convert the Series A Preferred Stock at a conversion ratio per share of Series A Preferred Stock of 61.9195 , but only if the closing price of the Company’s common stock trades at or above a certain premium to the Company’s initial offering price, such premium to decrease with time. In certain situations, including a change of control, the Series A Preferred Stock may be redeemed for cash in an amount equal to the greater of (i) 135% of the liquidation preference of the Series A Preferred Stock and (ii) a 17.5% annualized internal rate of return on the liquidation preference of the Series A Preferred Stock. The Series A Preferred Stock mature on October 15, 2021, at which time they are mandatorily redeemable for cash at the liquidation preference.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes On December 22, 2017, the Tax Cuts and Jobs Act (the “TCJA”) was enacted making significant changes to the Internal Revenue Code. The Company has calculated its best estimate of the impact of the TCJA in its year end income tax provision in accordance with its understanding of the TCJA and guidance available as of the date of this filing. Many of the provisions in the TCJA have an effective date for years beginning after December 31, 2017, including the lowering of the U.S. corporate rate from 35 percent to 21 percent. However, as a result of the enactment date of December 22, 2017, the Company is required to remeasure the deferred tax assets and liabilities at the rate in which they are expected to reverse. The Company provisionally recorded an income tax benefit in the amount of $23.4 million related to the remeasurement of the net deferred tax liability. The Company is currently evaluating other potential impacts of the TCJA. The SEC staff has issued Staff Accounting Bulletin No. 118, which allows registrants to record provisional amounts during a one year "measurement period" similar to that used when accounting for business combinations. Impacts of this TCJA are expected to be recorded at the time a reasonable estimate for all or a portion of the effects can be made, and provisional amounts can be recognized and adjusted as information becomes available, prepared or analyzed. The Company has made a reasonable estimate and recorded the provisional deferred tax liability regarding the 100% cost recovery of qualified property acquired and placed in service after September 27, 2017 in the amount of $13.0 million . Also, the Company has made a reasonable estimate and recorded a portion of the deferred tax asset of $13.9 million related to stock-based compensation as provisional associated with covered employees. We believe these compensation plans for covered employees continue to qualify as deductible and would be grandfathered under the IRC Sec. 162(m) as of December 31, 2017. The tax consequences of items taking effect after December 31, 2017 will be analyzed by the Company during 2018, some of the items the Company has identified that will have an impact on the Company are; i) deductibility of future compensation and awards for covered employees, ii) deductibility of meals and entertainment, iii) interest expense deductions, iv) the repeal of like-kind exchanges for non-real property, v) the repeal of the corporate alternative minimum tax and vi) the limitation of the use of NOLs to 80 percent of taxable income. The Company will make a good faith effort to analyze and complete the accounting under ASC Topic 740 of these items prior to the end of the measurement period Holdings, the Company’s accounting predecessor, was a limited liability company that was not subject to U.S. federal income tax. As part of the Corporate Reorganization, the members of Holdings exchanged all of their member units for shares of the Company’s common stock. For additional discussion on the Corporate Reorganization, see Note 1 — Business and Organization. As a result of the Corporate Reorganization, the Company identified and established the deferred tax assets and liabilities for differences between the book and tax basis of Holdings. The Company recorded a net deferred tax liability of approximately $135.3 million . As this Corporate Reorganization is being accounted for as a transaction under common control the offset of the net deferred tax liability was recorded to additional paid-in capital within the consolidated balance sheet. The components of the income tax expense (benefit) were as follows (in thousands): For the Year Ended December 31, 2017 2016 Current: Federal $ — $ — State, net of federal benefit — — Total current income tax benefit $ — $ — Deferred: Federal $ (61,719 ) $ (26,962 ) State, net of federal benefit (1,981 ) (2,318 ) Total deferred income tax benefit $ (63,700 ) $ (29,280 ) Income tax benefit $ (63,700 ) $ (29,280 ) The following table reconciles the income tax expense (benefit) with income tax expense at the federal statutory rate (in thousands): For the Year Ended December 31, 2017 2016 Loss before income taxes (108,108 ) (485,281 ) Federal income taxes at statutory rate (37,838 ) (169,849 ) Net loss prior to Corporate Reorganization — 80,463 State income taxes, net of federal benefit (3,118 ) (2,318 ) Nondeductible stock-based compensation 2,264 62,284 Enactment of the Tax Cuts and Jobs Act (23,412 ) — Other (1,596 ) 140 Income tax expense (benefit) (63,700 ) (29,280 ) Net loss $ (44,408 ) $ (456,001 ) The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities were as follows (in thousands): As of December 31, 2017 2016 Deferred Tax Assets: Net operating loss carryforward $ 205,806 $ 35,719 Commodity derivatives 19,984 24,068 Stock-based compensation 13,853 2,824 Other 17,053 14,309 Total deferred tax assets 256,696 76,920 Deferred Tax Liabilities: Excess basis of oil and gas properties (299,022 ) (182,946 ) Total deferred tax liabilities (299,022 ) (182,946 ) Deferred Tax Liability, net $ (42,326 ) $ (106,026 ) Management considers whether some portion or all of the deferred tax assets will be realized based on a more likely than not standard of judgment. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. The Company has net operating loss carryforwards (NOLs) for U.S. income tax purposes that have been generated from the Company's operations of approximately $834.7 million . Due to the Act, these NOLs will not expire and are not subject to the 80 percent limitation of taxable income arising in future tax years. The utilization of such NOL carryforwards may be limited upon the occurrence of certain ownership changes as stipulated in Section 382 of the Internal Revenue Code of 1986, as amended (the "Code"). As of December 31, 2017, the Company determined that the statutory provision of Section 382 will not limit the Company’s ability to realize future tax benefits. As of December 31, 2017, the Company believes it will be able to generate sufficient future taxable income within the carryforward period and accordingly, believes that it is more likely than not that its deferred income tax assets will be fully realized. The Company files income tax returns in the U.S. federal jurisdiction and in Colorado. The statute of limitations related to the 2016 and 2017 tax returns are open through 2020 and 2021 respectively, however, the ability for the tax authority to adjust the NOL will continue until three years after the NOL is utilized. As of December 31, 2017 , the Company believes that it has no liability for uncertain tax positions. If the Company were to determine there were any uncertain tax positions, the Company would recognize the liability and related interest and penalties within income tax expense. As of December 31, 2017 , the Company had no provision for interest or penalties related to uncertain tax positions.

Unit-Based Compensation

Unit-Based Compensation	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Unit and Stock-Based Compensation	Unit and Stock-Based Compensation Extraction Long Term Incentive Plan In October 2016, the Board of Directors adopted the Extraction Oil & Gas, Inc. 2016 Long Term Incentive Plan (the “2016 Plan” or “LTIP”), pursuant to which employees, consultants, and directors of the Company and its affiliates performing services for the Company are eligible to receive awards. The 2016 Plan provides for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, bonus stock, dividend equivalents, other stock-based awards, substitute awards, annual incentive awards, and performance awards intended to align the interests of participants with those of stockholders. In accordance with the terms of the LTIP, 20.2 million shares of common stock have been reserved for issuance pursuant to awards under the LTIP. Extraction has granted awards under the LTIP to certain directors, officers and employees, including stock options, restricted stock units and performance stock awards. Restricted Stock Units (“RSUs”) Restricted stock units granted under the LTIP (“RSUs”) vest over either (i) a one -year service period, with 100% of the units vesting at the end of the service period, or (ii) a three -year service period with 25% , 25% and 50% of the units vesting in year one , two and three , respectively. Grant date fair value was determined based on the value of Extraction’s common stock on the date of issuance. The Company assumed a forfeiture rate of zero as part of the grant date estimate of compensation cost. As of January 1, 2017, the Company elected to account for stock-based compensation forfeitures as they occur, as a result of the adoption of ASU No. 2016-09. The Company recorded $31.8 million and $5.5 million of stock-based compensation costs related to RSUs for the years ended December 31, 2017 and 2016, respectively. No stock-based compensation costs related to RSUs were recorded for the year ended December 31, 2015 . As of December 31, 2017 , there was $45.7 million of total unrecognized compensation cost related to the unvested RSUs granted to certain employees that is expected to be recognized over a weighted average period of 2.0 years . The following table summarizes the RSU activity from January 1, 2016 through December 31, 2017 and provides information for RSUs outstanding at the dates indicated. Weighted Average Number of Grant Date Shares Fair Value Non-vested RSUs at January 1, 2016 — $ — Granted 3,237,500 $ 21.41 Forfeited — $ — Vested — $ — Non-vested RSUs at December 31, 2016 3,237,500 $ 21.41 Granted 1,369,083 $ 16.37 Forfeited (445,366 ) $ 19.85 Vested (1,254,744 ) $ 20.85 Non-vested RSUs at December 31, 2017 2,906,473 $ 19.51 Stock Options Expense on the stock options are recognized on a straight-line basis over the service period of the award less awards forfeited. The fair value of the stock options were measured at the grant date using the Black Scholes valuation model. The Company utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited historical exercise data available in estimating the expected term of the stock options. Expected volatility is based on the volatility of the historical stock prices of the Company’s peer group. The risk-free rates are based on the yields of U.S. Treasury instruments with comparable terms. A dividend yield and forfeiture rate of zero were assumed. Stock options granted under the LTIP vest ratably over three years and are exercisable immediately upon vesting through the tenth anniversary of the grant date. To fulfill options exercised, the Company issues new shares. The Company recorded $15.7 million and $2.9 million of stock-based compensation costs related to the stock options for the years ended December 31, 2017 and 2016, respectively. The Company did not record any stock-based compensation expense related to stock options for the year ended December 31, 2015 . As of December 31, 2017 , there was $27.2 million of unrecognized compensation cost related to the stock options that is expected to be recognized over a weighted-average period of 1.8 years . The following table summarizes the assumptions used for the Black-Scholes valuation model to calculate the stock-based compensation expense for the years presented. For the Year Ended December 31, 2017 December 31, 2016 Risk free rates 2.0 % 1.4 % Dividend yield — — Expected volatility 58.9 % 47.2 % Expected term (in years) 6.0 6.0 The weighted average fair value at the date of grant for stock options granted is as follows: Weighted average per share $ 8.66 $ 8.75 Total options granted 744,428 4,500,000 Total weighted average fair value of shares granted (in thousands) $ 6,445 $ 39,375 The following table summarizes the stock option activity from January 1, 2016 through December 31, 2017 and provides information for stock options outstanding at the dates indicated. Weighted Average Number of Exercise Shares Price Non-vested Stock Options at January 1, 2016 — $ — Granted 4,500,000 $ 19.00 Forfeited — $ — Vested — $ — Non-vested Stock Options at December 31, 2016 4,500,000 $ 19.00 Granted 744,428 $ 15.53 Forfeited — $ — Vested (1,748,138 ) $ 18.52 Non-vested Stock Options at December 31, 2017 3,496,290 $ 18.50 The following table summarizes information about outstanding and exercisable stock options as of December 31, 2017. Outstanding Options Exercisable Options Weighted-Average Weighted-Average Weighted-Average Exercise Options Remaining Contractual Life Exercise Price Options Price per Share 4,500,000 8.9 years $ 19.00 1,500,000 $ 19.00 744,428 9.8 years $ 15.53 248,138 $ 15.53 5,244,428 9.0 years $ 18.50 1,748,138 $ 18.52 Performance Stock Awards The Company granted performance stock awards ("PSAs") to certain executives under the LTIP in October 2017. The number of shares of the Company's common stock that may be issued to settle PSAs ranges from zero to one times the number of PSAs awarded. The shares issued for PSAs 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 PSAs will be settled in shares of the Company's common stock following the end of the three-year performance cycle. Any PSAs that have not vested at the end of the applicable measurement period are forfeited. The vesting criterion for the PSAs is based on a comparison of the Company's total shareholder return ("TSR") for the measurement period compared to 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 PSAs 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. Those outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results with be obtained for those iterations. In the case of the Company's PSAs, the Company cannot predict with certainty the path its stock price or the stock prices of its peer 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 PSAs. 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 as well as the volatilities for each of the Company's peers. The assumptions used in valuing the PSAs granted were as follows: For the Year Ended December 31, 2017 Risk free rates 1.5 % Dividend yield — Expected volatility 45.0 % The Company recorded $0.8 million of stock-based compensation costs related to PSAs for the year ended December 31, 2017. The Company did not record any stock-based compensation expense related to PSAs for the years ended December 31, 2016 and 2015. As of December 31, 2017, there was $6.6 million of unrecognized compensation cost related to the PSAs that is expected to be recognized over a weighted-average period of 2.0 years . The following table summarizes the PSA activity from January 1, 2017 through December 31, 2017 and provides information for PSAs outstanding at the dates indicated. Weighted Average Number of Grant Date Shares (1) Fair Value Non-Vested PSAs as of January 1, 2017 — $ — Granted 832,163 $ 8.85 Forfeited — $ — Vested — $ — Non-Vested PSAs as of December 31, 2017 832,163 $ 8.85 (1) The number of awards assumes that the associated maximum 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 one, depending on the level of satisfaction of the vesting condition. Incentive Restricted Stock Units (“Incentive RSUs”) In November 2016, after the Holdings’ Incentive Units were converted to the 9.1 million shares of common stock, holders of the Holding’s Incentive Units contributed 2.7 million shares of common stock to Extraction Employee Incentive, LLC (“Employee Incentive”), which is owned solely by certain officers of the Company. Employee Incentive issued restricted stock units (“Incentive RSUs”) to certain employees. Incentive RSUs vest over a three year service period, with 25% , 25% and 50% of the units vesting in year one, two and three, respectively. Grant date fair value was determined based on the value of Extraction’s common stock on the date of issuance. The Company assumed a forfeiture rate of zero as part of the grant date estimate of compensation cost. On July 10, 2017, the partners of Employee Incentive amended the vesting schedule in which 25% vested on July 17, 2017 and the remaining Incentive RSUs will vest 25% , 25% and 25% each six months thereafter, over the remaining 18 months service period. Grant date fair value was determined based on the value of Extraction’s common stock on the date of issuance. The Company assumed a forfeiture rate of zero as part of the grant date estimate of compensation cost. As of January 1, 2017, the Company elected to account for stock-based compensation forfeitures as they occur, as a result of the adoption of ASU No. 2016-09. The Company withholds shares as Incentive RSUs vest to satisfy tax withholding obligations of employees and as these shares are issued and outstanding, the withheld shares are included in treasury stock on the consolidated balance sheets. The Company recorded $17.3 million and $2.4 million of stock-based compensation costs related to Incentive RSUs for the years ended December 31, 2017 and 2016, respectively. No stock-based compensation costs related to Incentive RSUs were recorded for the year ended December 31, 2015 . These costs were included in the consolidated statements of operations within the general and administrative expenses line item. As of December 31, 2017 , there was $21.3 million of total unrecognized compensation cost related to the unvested Incentive RSUs granted to certain employees that is expected to be recognized over a weighted average period of 1.0 year . The following table summarizes the Incentive RSU activity from January 1, 2016 through December 31, 2017 and provides information for Incentive RSUs outstanding at the dates indicated. Weighted Average Number of Grant Date Shares Fair Value Non-vested Incentive RSUs at January 1, 2016 — $ — Granted 2,717,968 $ 20.45 Forfeited (3,600 ) $ 20.45 Vested — $ — Non-vested Incentive RSUs at December 31, 2016 2,714,368 $ 20.45 Granted — $ — Forfeited (710,993 ) $ 20.45 Vested (507,200 ) $ 20.45 Non-vested Incentive RSUs at December 31, 2017 1,496,175 $ 20.45 Holdings’ Membership Unit Incentive Plan On May 29, 2014, Holdings adopted the 2014 Membership Unit Incentive Plan (“2014 Plan”). The 2014 Plan provided for the compensation of employees, non‑employee managers and consultants of the Company and its affiliates through grants of restricted unit awards (“Holdings’ RUAs”) and incentive units (“Holdings’ Incentive Units”). The 2014 Plan was terminated as a result of the Corporate Reorganization in October 2016. Holdings’ RUAs Holdings’ RUAs vested over a three ‑year service period, with 25% , 25% and 50% of the units vesting in year one, two and three, respectively. The Company estimated fair value of the RUAs on their grant date based upon estimated volatility, market comparable risk free rate, estimated forfeiture rate and a discount for lack of marketability. Grant date fair value was determined based on the value of Holdings’ Equity Units on the date of the grant. Due to a lack of historical data, the Company used the experience of other entities in the same industry to estimate a forfeiture rate. Expected forfeitures are then included as part of the grant date estimate of compensation cost. No unit-based compensation costs related to Holdings' RUA grants were recorded for December 31, 2017 . The Company recorded $16.8 million and $5.3 million of unit-based compensation costs related to Holdings’ RUA grants for the years ended December 31, 2016 and 2015 , respectively. These costs are included in the consolidated statements of operations within the general and administrative expenses line item. In connection with the Corporate Reorganization in 2016, the Holdings Membership Unit Incentive Plan ("2014 Plan") was terminated. As of December 31, 2017, there is no unrecognized compensation cost related to unvested RUAs granted to employees. The following table summarizes the Holdings’ RUA activity from January 1, 2015 through December 31, 2016 and provides information for Holdings’ RUAs outstanding at the dates indicated. Weighted Average Number of Grant Date Shares Fair Value Non-vested RUAs at January 1, 2015 9,365,896 $ 2.22 Granted 196,047 $ 2.68 Forfeited (53,063 ) $ 2.21 Vested (3,197,638 ) $ 2.22 Non-vested RUAs at December 31, 2015 6,311,242 $ 2.23 Granted 1,531,542 $ 5.84 Forfeited (181,817 ) $ 2.68 Vested (7,660,967 ) $ 2.94 Non-vested RUAs at December 31, 2016 — $ — PRL RUAs PRL granted RUAs to certain employees, including Extraction employees (“PRL RUAs”). PRL RUAs vested over a three years service period, with 25% , 25% and 50% of the units vesting in year one, two and three, respectively. Grant date fair value was determined based on the value of PRL’s Equity Units on the date of the grant. PRL uses its past experience to estimate a forfeiture rate and expected forfeitures are included as part of the grant date estimate of compensation cost. No unit-based compensation costs related to PRL RUA grants were recorded for the year ended December 31, 2017 . The Company recorded $0.5 million and $0.8 million of unit-based compensation costs related to PRL RUA grants for the years ended December 31, 2016 and 2015 , respectively. These costs are included in the consolidated statements of operations within the general and administrative expenses line item. In connection with the Corporate Reorganization in 2016, the Holdings Membership Unit Incentive Plan ("2014 Plan") was terminated. As of December 31, 2017 , there was no unrecognized compensation cost related to the PRL RUAs as all awards were fully vested. Holdings’ Incentive Units In accordance with the 2014 Plan and the Holdings LLC Agreement, Holdings issued 3.0 million Holdings’ incentive units to certain members of management in the fourth quarter of 2015. All of Holdings’ Incentive Units were non‑voting and subject to certain vesting and performance conditions. The Holdings’ Incentive Units vested over a three year service period, with 25% , 25% and 50% of the units vesting in year 1, year 2 and year 3, respectively (with vesting between the first and third anniversaries occurring pro-rata based on the number of full months elapsed since the last vesting date), and in full upon a change of control, as defined in the Holdings LLC Agreement. The Holdings’ Incentive Units were accounted for as liability awards under ASC 718, Compensation-Stock Compensation , with compensation expense based on period‑end fair value. In connection with the IPO, the Board of Managers of Holdings accelerated the vesting of the Holdings’ Incentive Units. The Company’s IPO and change of control triggered the conversion of these units into approximately 9.1 million common shares of the Company based on the 10 -day volume weighted average price of the Company’s common stock following its IPO as set forth in the Holdings Third Amended and Restated LLC Agreement. For the year ended December 31, 2016, the Company recognized approximately $172.1 million in non-cash, share-based compensation expense in connection with the conversion of the Holdings’ Incentive Units into the Company’s common stock. No incentive compensation expense was recorded for the year ended December 31, 2015 because it was not probable that the performance criterion would be met.

Earnings (Loss) per Share

Earnings (Loss) per Share	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Earnings (Loss) per Share	Earnings (Loss) Per Share Basic earnings per share (“EPS”) includes no dilution and is computed by dividing net income (loss) 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 of the Company. The Company uses the “if-converted” method to determine potential dilutive effects of Series A Preferred Stock and the treasury method to determine the potential dilutive effects of outstanding restricted stock awards, stock options and PSAs. EPS for the year ended December 31, 2016 is calculated for the period from October 12, 2016, the effective date of the Corporate Reorganization, to December 31, 2016. EPS information is not applicable for reporting periods prior to the Corporate Reorganization. The basic weighted average shares outstanding calculation is based on the actual days in which the shares were outstanding for the period from October 12, 2016 to December 31, 2016. Please refer to Note 1 — Business and Organization and Note 9 — Equity for additional discussion regarding the Corporate Reorganization. The components of basic and diluted EPS were as follows: From October 12, 2016 Year Ended December 31, 2017 to December 31, 2016 Basic and Diluted EPS (in thousands, except per share data) Net Loss $ (44,408 ) $ (226,107 ) Less: Adjustment to reflect Series A Preferred Stock dividend (10,885 ) (2,958 ) Less: Adjustment to reflect accretion of Series A Preferred Stock discount (5,394 ) (1,041 ) Net loss attributable to common shareholders $ (60,687 ) $ (230,106 ) Weighted Average Common Shares Outstanding (1) (2) Basic and diluted 171,910 149,029 Net Loss Allocated to Common Shareholders per Common Share Basic and diluted $ (0.35 ) $ (1.54 ) (1) For the year ended December 31, 2017, 8,566,983 potentially dilutive shares were not included in the calculation above, as they had an anti-dilutive effect on EPS, including restricted stock awards, stock options outstanding and performance stock awards contingently issuable, if December 31, 2017 was the end of the measurement period. Additionally, the 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded. (2) For the period of October 12 through December 31, 2016, 7,737,500 potentially dilutive shares were not included in the calculation above, as they had an anti-dilutive effect on EPS, including restricted stock awards and stock options outstanding for the period. Additionally, the 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Leases The Company leases two office spaces in Denver, Colorado, two office spaces in Greeley, Colorado and one office space in Houston, Texas under separate operating lease agreements. The Denver, Colorado leases expire on February 29, 2020 and May 31, 2026, respectively. The Greeley and Houston leases expire on August 19, 2019, June 30, 2019 and October 31, 2017, respectively. Total rental commitments under non-cancelable leases for office space were $35.7 million at December 31, 2017 . The future minimum lease payments under these non-cancelable leases are as follows: $3.0 million in 2018 , $3.5 million in 2019 , $3.4 million in 2020 , $3.4 million in 2021 , $3.3 million in 2022 and $19.1 million thereafter. Rent expense was $2.3 million , $1.9 million , and $1.1 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. On June 4, 2015, the Company subleased the remaining term of one of its Denver office leases that expires February 29, 2020. The sublease will decrease the Company’s future lease payments by $0.5 million . Drilling Rigs As of December 31, 2017 , the Company was subject to commitments on three dilling rigs. In the event of early termination of these contracts, the Company would be obligated to pay an aggregate amount of approximately $8.9 million as of December 31, 2017 , as required under the terms of the contracts. In March 2015, the Company early terminated one of its drilling rig contracts for approximately $1.7 million , which was recorded in the consolidated statements of operations within the other operating expenses line item. In February 2016, the Company provided notice to terminate one of its drilling rigs that was subject to commitment at December 31, 2015. As part of this termination, the Company was obligated to pay $1.0 million in the second quarter of 2016. In January 2017, the Company provided notice for termination on one drilling rig and paid no termination fees. Delivery Commitments As of December 31, 2017, the Company’s oil marketer is subject to a firm transportation agreement that commenced in November 2016 and has a ten -year term with a monthly minimum delivery commitment of 45,000 Bbl/d in year one, 55,800 Bbl/d in year two, 61,800 Bbl/d in years three through seven and 58,000 Bbl/d in years eight through ten. In May 2017, the Company amended its agreement with its oil marketer that requires it to sell all of its crude oil from an area of mutual interest in exchange for a make-whole provision that allows the Company to satisfy any minimum volume commitment deficiencies incurred by its oil marketer with future barrels of crude oil in excess of their minimum volume commitment through October 31, 2018. In December 2017, the Company extended the term of this agreement through October 31, 2019 and has posted a letter of credit in the amount of $35.0 million . The Company evaluates its contracts for loss contingencies and accrues for such losses, if the loss can be reasonably estimated and deemed probable. The Company also has one long-term crude oil gathering commitment with an unconsolidated subsidiary, in which we have a minority ownership interest. It has a term of ten years with a minimum volume commitment of an average 9,167 Bbl/d in year one, 17,967 Bbl/d in year two, 18,800 Bbl/d for years three through five and 10,000 Bbl/d for years six through ten. The remaining aggregate amount of estimated payments under these agreements is approximately $927.3 million . In collaboration with several other producers and a midstream provider, on December 15, 2016 and August 7, 2017, the Company agreed to participate in expansions of natural gas gathering and processing capacity in the DJ Basin. The plan includes two new processing plants as well as the expansion of related gathering systems, which are currently expected to be completed by mid-2018 and mid-2019, respectively, although the exact start-up dates are undetermined at this time. The Company’s share of these commitments will require 51.5 MMcf and 20.6 MMcf per day, respectively, to be delivered after the plants' in-service dates for a period of seven years thereafter. The Company may be required to pay a shortfall fee for any volumes under these commitments. These contractual obligations can be reduced by the Company’s proportionate share of the collective volumes delivered to the plants by other third party incremental volumes available to the midstream provider at the new facilities that are in excess of the total commitments. The Company is also required for the first three years of each contract to guarantee a certain target profit margin on these volumes sold. Under its current drilling plans, the Company expects to meet these volume commitments. Acquisition of Undeveloped Leasehold Acreage The Company was party to an agreement through November 15, 2017 with an unrelated third party for which it has paid $214.3 million and is required to pay an additional $12.2 million in April 2018, subject to certain customary closing conditions, to lease a total of approximately 36,600 net acres of undeveloped leasehold. Additionally, in January 2018, the Company acquired approximately 1,200 net acres of undeveloped leasehold from an unrelated third party for $11.6 million , subject to certain customary closing conditions. General The Company is subject to contingent liabilities with respect to existing or potential claims, lawsuits, and other proceedings, including those involving environmental, tax, and other matters, certain of which are discussed more specifically below. The Company accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such accruals are based on developments to date and the Company’s estimates of the outcomes of these matters and its experience in contesting, litigating, and settling other matters. As the scope of the liabilities becomes better defined, there will be changes in the estimates of future costs, which management currently believes will not have a material effect on the Company’s financial position, results of operations, or cash flows. As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost or the Company may be required to pay damages if certain performance conditions are not met. Legal Matters In the ordinary course of business, the Company may at times be subject to claims and legal actions. Management believes it is remote that the impact of such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows. Management is unaware of any material pending litigation brought against the Company requiring the reserve of a contingent liability as of the date of this filing. We were issued a Compliance Advisory in July 2015 from the Colorado Department of Public Health and Environment (“CDPHE”), which alleged air quality violations at certain of our facilities regarding leakages of volatile organic compounds from storage tanks, all of which were promptly addressed. On January 31, 2018, we entered into a Compliance Order on Consent with the CDPHE that provides for a field-wide administrative settlement of these issues. The Compliance Order provides that we will implement changes to our design, operation, maintenance and recordkeeping of many of our field-wide storage tank systems to enhance our emissions management. Agreed upon and planned efforts include, but are not limited to, vapor control system modifications and verification, increased inspection and monitoring, and installation and operation of certain emission mitigation projects at certain facilities constructed in 2018 and 2019. The two primary elements of the Compliance Order are: (i) a monetary penalty of $138,600 ; and (ii) injunctive relief with an estimated cost of approximately $500,000 , primarily representing capital enhancements to our operations. Certain expenditures for the injunctive relief have already been incurred prior to entry of the Compliance Order, with the remainder expected to be incurred over the next few years. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our consolidated financial statements.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Office Lease with Related Affiliate In April 2016, the Company subleased office space to Star Peak Capital, LLC, of which a member of the Board of Directors is an owner, for $1,400 per month. The sublease commenced on May 1, 2016 and expires on February 28, 2020. Units Repurchased from Officer In May 2016, the Company repurchased 60,605 Tranche A Units and 82,578 Tranche C Units from its former Chief Accounting Officer, for $3.25 per unit for an aggregate purchase price of approximately $0.5 million . Promissory Notes In May 2014, the Company received full recourse promissory notes from two officers under which the Company advanced $5.4 million to the employees to meet their capital contributions. The promissory notes were due on May 29, 2021, or earlier in the event of termination or certain change in control events as stipulated in the individual promissory notes and any distributions of capital contributions were considered mandatory prepayments. The promissory notes had a stated interest rate of LIBOR plus 1% per annum. The promissory notes were recorded as a reduction of members’ equity. In September 2016, the Company redeemed 1.2 million units from two of its executive officers, for an aggregate purchase price of $7.8 million . On the same date, the executive officers used $5.6 million of the redemption value to settle in full and terminate their obligations under the promissory notes, including accrued interest thereon. Second Lien Notes Several lenders of Second Lien Notes were also members of Holdings. Of the $430.0 million outstanding on the Second Lien Notes as of December 31, 2015, members held approximately $311.7 million . These members were paid $314.8 million upon repayment and termination of the Second Lien Notes in July 2016, including the prepayment penalty. 2021 Senior Notes Several lenders of 2021 Senior Notes are also 5% stockholders of the Company. As of the initial issuance of the $550.0 million principal amount on the 2021 Senior Notes, members held $63.5 million . 2024 Senior Notes Several lenders of the 2024 Senior Notes are also 5% stockholders of the Company. As of the initial issuance in August 2017 of the $400.0 million principal amount on the 2024 Senior Notes, such stockholders held $54.9 million . 2026 Senior Notes Several lenders of the 2026 Senior Notes are also 5% stockholders of the Company. As of the initial issuance in January 2018 of the $750.0 million principal amount on the 2026 Senior Notes, such stockholders held $56.2 million . Series A Preferred Units All holders of the $75.0 million of Series A Preferred Units were also members of Holdings. The Company used $90.0 million of the net proceeds from its IPO to redeem the Series A Preferred Units in full on October 17, 2016, which included a premium of $15.0 million . Series A Preferred Stock and Series B Preferred Units As of the initial issuance of the $185.3 million of Series B Preferred Units, members of Holdings held approximately $135.3 million . Upon closing of the IPO, members of Holdings held $185.3 million of the Series A Preferred Stock. Private Placement of Common Stock Several participants in the Private Placement are also 5% stockholders of the Company. As of the initial issuance of $457.0 million of common stock in December 2016, such stockholders purchased 2,503,370 shares for $45.7 million . Related Party—Employees Mr. Troy Owens, brother of Mr. Matthew R. Owens, the Company's President and a member of the Company's Board of Directors, is employed by the Company as an engineer. Consistent with market compensation for his services, Mr. Troy Owens received approximately $0.3 million and $0.2 million in aggregate cash compensation relating to the fiscal years ended December 31, 2017 and 2016, respectively. In addition, Mr. Troy Owens received certain long-term incentives during the same periods in the form of restricted stock units that vest over a period of three years.

Supplemental Oil and Gas Reserv

Supplemental Oil and Gas Reserve Information (Unaudited)	12 Months Ended
	Dec. 31, 2017
Disclosure of Other Reserve Information [Abstract]
Supplemental Oil and Gas Reserve Information (Unaudited)	Supplemental Oil and Gas Reserve Information (Unaudited) Results of Operations for Oil, Natural Gas and NGL Producing Properties The following are the results of operations (in thousands) of the Company’s oil and gas producing activities, before corporate overhead and interest expenses. The Company assumed a statutory tax rate of 38% for all years presented, although the Company was not subject to federal and state income taxes prior to the Corporate Reorganization. For the Year Ended December 31, 2017 2016 2015 Revenues $ 604,296 $ 278,089 $ 197,750 Operating Expenses: Production expenses 162,673 82,773 47,663 Exploration expenses 36,256 36,422 18,636 Depletion and accretion 311,916 203,073 144,228 Impairment of proved properties — 22,438 12,207 Results of operations before income tax expense 93,451 (66,617 ) (24,984 ) Income tax (expense) benefit (35,511 ) 25,314 9,494 Results of Operations $ 57,940 $ (41,303 ) $ (15,490 ) Oil, Natural Gas and NGL Reserve Quantities (Unaudited) The reserves at December 31, 2017 , 2016 and 2015 presented below were prepared by the independent engineering firm Ryder Scott Company, L.P. All reserves are located within the DJ Basin. Proved oil, natural gas and NGL reserves are the estimated quantities of oil, natural gas and NGL which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil, natural gas and NGL reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. The principal methodologies employed are decline curve analysis and analogy. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. The following table sets forth information for the years ended December 31, 2017 , 2016 and 2015 with respect to changes in the Company’s proved (i.e. proved developed and undeveloped) reserves: Crude Oil Natural Gas NGL MBoe Mbbls MMcf Mbbls Total Balance as of December 31, 2014 45,164.9 166,416.1 19,451.0 92,352.0 Revisions of previous estimates (2,961.0 ) (2,825.8 ) 2,281.9 (1,150.1 ) Purchase of reserves 11,831.7 64,392.7 7,533.3 30,097.1 Extensions, discoveries, and other additions 23,098.7 85,781.0 11,663.4 49,058.9 Sale of reserves (1,688.5 ) (10,357.1 ) (1,212.1 ) (4,626.8 ) Production (3,945.6 ) (10,823.0 ) (1,334.6 ) (7,084.0 ) Balance as of December 31, 2015 71,500.2 292,583.9 38,382.9 158,647.1 Revisions of previous estimates (15,576.8 ) 35,803.1 1,988.8 (7,620.8 ) Purchase of reserves 18,473.6 78,761.6 9,680.7 41,281.2 Extensions, discoveries, and other additions 21,885.4 120,798.3 14,679.9 56,698.5 Sale of reserves — — — — Production (5,287.4 ) (20,211.5 ) (2,284.0 ) (10,940.0 ) Balance as of December 31, 2016 90,995.0 507,735.4 62,448.3 238,066.0 Revisions of previous estimates (625.9 ) 9,349.8 1,961.6 2,894.0 Purchase of reserves 10,761.2 11,183.6 1,563.3 14,188.3 Extensions, discoveries, and other additions 19,738.4 130,295.4 15,033.6 56,487.9 Sale of reserves — — — — Production (9,593.7 ) (32,395.2 ) (3,900.8 ) (18,893.7 ) Balance as of December 31, 2017 111,275.0 626,169.0 77,106.0 292,742.5 Proved Developed Reserves, included above Balance as of December 31, 2015 14,248.6 53,011.7 7,058.3 30,142.3 Balance as of December 31, 2016 17,158.0 107,918.0 13,354.0 48,498.4 Balance as of December 31, 2017 37,078.0 222,236.0 27,932.0 102,049.3 Proved Undeveloped Reserves, included above Balance as of December 31, 2015 57,251.5 239,572.2 31,324.6 128,504.8 Balance as of December 31, 2016 73,837.0 399,817.4 49,094.3 189,567.5 Balance as of December 31, 2017 74,197.0 403,933.0 49,174.0 190,693.2 • The values for the 2017 oil, natural gas and NGL reserves are based on the 12-month arithmetic average of the first day of the month prices for the period from January through December 31, 2017 . The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $51.34 per barrel (West Texas Intermediate price) for crude oil and NGL and $2.98 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2017 was $42.89 per barrel for oil, $1.73 per Mcf for natural gas and $20.28 per barrel for NGL. • The values for the 2016 oil, natural gas and NGL reserves are based on the 12-month arithmetic average of the first day of the month prices for the period from January through December 31, 2016 . The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $42.75 per barrel (West Texas Intermediate price) for crude oil and NGL and $2.49 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2016 was $34.91 per barrel for oil, $1.39 per Mcf for natural gas and $11.63 per barrel for NGL. • The values for the 2015 oil, natural gas and NGL reserves are based on the 12 month arithmetic average of the first day of the month prices for the period from January through December 31, 2015 . The unweighted arithmetic average first-day-of-month prices for the prior twelve months were $50.28 per barrel (West Texas Intermediate price) for crude oil and NGL and $2.58 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2015 was $43.28 per barrel for oil, $2.11 per Mcf for natural gas and $10.65 per barrel for NGL. For the year ended December 31, 2017 , the Company had upward revisions of previous estimates of 2,894.0 MBoe. As a result of ongoing drilling and completion activities during 2017 , the Company reported extensions, discoveries, and other additions of 56,487.9 MBoe. Additionally, during 2017 the Company purchased reserves of 14,188.3 MBoe. For the year ended December 31, 2016 , the Company had downward revisions of previous estimates of 7,620.8 MBoe. As a result of ongoing drilling and completion activities during 2016 , the Company reported extensions, discoveries, and other additions of 56,698.5 MBoe. Additionally, during 2016 the Company purchased reserves of 41,281.2 MBoe. For the year ended December 31, 2015 , the Company had upward revisions of previous estimates of 1,150.1 MBoe. These revisions are primarily the result of well performance exceeding previous estimates. As a result of ongoing drilling and completion activities during 2015 , the Company reported extensions, discoveries, and other additions of 49,058.9 MBoe. Additionally, during 2015 the Company purchased reserves of 30,097.1 MBoe. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves The Company follows the guidelines prescribed in ASC 932, Extractive Activities-Oil and Gas for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The following summarizes the policies used in the preparation of the accompanying oil, natural gas and NGL reserve disclosures, standardized measures of discounted future net cash flows from proved oil, natural gas and NGL reserves and the reconciliations of standardized measures from year to year. The information is based on estimates of proved reserves attributable to the Company’s interest in oil and gas properties as of December 31 of the years presented. These estimates were prepared by Ryder Scott Company L.P., independent petroleum engineers. The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (1) Estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions. (2) The estimated future cash flows are compiled by applying the trailing twelve month average of the first of the month prices applied to the Company’s proved reserve year-end quantities. (3) The future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions, plus Company overhead incurred. (4) Future net cash flows are discounted to present value by applying a discount rate of 10% . The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations, since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company’s oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. The following are the principal sources of change in the standardized measure (in thousands): For the Year Ended December 31, 2017 2016 2015 Future crude oil, natural gas and NGL sales $ 7,422,335 $ 4,610,848 $ 4,119,888 Future production costs (2,227,370 ) (1,429,202 ) (1,193,560 ) Future development costs (1,662,859 ) (1,579,628 ) (1,141,330 ) Future income tax expense (212,923 ) (42,859 ) — Future net cash flows $ 3,319,183 $ 1,559,159 $ 1,784,998 10% annual discount (1,440,177 ) (836,163 ) (949,115 ) Standardized measure of discounted future net cash flows (1) $ 1,879,006 $ 722,996 $ 835,883 (1) The Company’s calculations of the standardized measure of discounted future net cash flows does not include the effect of estimated future income tax expenses for the year ended December 31, 2015 as the Company was a limited liability company and not subject to income taxes. For the years ended December 31, 2017 and 2016, future income tax expenses in the Company’s calculation of the standardized measure of discounted future net cash flows are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and gas properties, other deductions, credit and allowances relating to the Company’s proved reserves. For purposes of the standardized measure calculation, it was assumed that all of the Company’s operations are attributable to the Company’s oil and gas assets. If the Company had been subject to entity-level income taxation, the unaudited pro forma future income tax expense at December 31, 2015 would have been $327.9 million and the unaudited standardized measure would have been $680.3 million . The following summary sets forth the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure prescribed in ASC 932, Extractive Activities-Oil and Gas (in thousands): For the Year Ended December 31, 2017 2016 2015 Balance at beginning of period $ 722,996 $ 835,883 $ 1,387,472 Sales of crude oil, natural gas and NGL, net (441,623 ) (195,316 ) (150,087 ) Net change in prices and production costs 586,271 (325,236 ) (1,292,364 ) Net change in future development costs 3,959 (49,213 ) 175,944 Extensions and discoveries 330,160 96,982 284,216 Acquisitions of reserves 59,745 156,675 240,989 Sale of reserves — — (50,018 ) Revisions of previous quantity estimates 188,421 19,161 (28,391 ) Previously estimated development costs incurred 331,550 123,085 102,060 Net changes in income taxes (79,181 ) (17,611 ) — Accretion of discount 74,061 83,588 156,723 Other 102,647 (5,002 ) 9,339 Balance at end of period $ 1,879,006 $ 722,996 $ 835,883

Unaudited Quarterly Financial D

Unaudited Quarterly Financial Data	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Unaudited Quarterly Financial Data	Unaudited Quarterly Financial Data The following is a summary of the unaudited quarterly financial data for each of the quarters from first quarter 2016 through fourth quarter 2017 (in thousands, except per share data). Historical results are not necessarily indicative of the results to be expected in future periods. You should read this data together with the Company's consolidated financial statements and the related notes included elsewhere in this Annual Report: Three Months Ended March 31, June 30, September 30, December 31, 2017 2017 2017 2017 Oil, Natural gas and NGL sales $ 89,639 $ 119,766 $ 180,861 $ 214,030 Operating Income (1) $ 10,210 $ 16,480 $ 41,084 $ 58,850 Net Income (Loss) $ 8,716 $ 7,240 $ (29,796 ) $ (30,568 ) Basic and Diluted Income (Loss) Per Common Share $ 0.03 $ 0.02 $ (0.20 ) $ (0.20 ) Three Months Ended March 31, June 30, September 30, December 31, 2016 2016 2016 2016 Oil, Natural gas and NGL sales $ 45,133 $ 65,364 $ 72,902 $ 94,690 Operating Income (Loss) (1) $ (16,635 ) $ (3,593 ) $ 4,556 $ 5,640 Net Loss $ (45,519 ) $ (127,614 ) $ (37,267 ) $ (245,601 ) Basic and Diluted Loss Per Common Share $ (1.54 ) (1) Oil, Natural gas and NGL sales revenue less lease operating expenses, production taxes and depreciation, depletion, amortization and accretion. (2) EPS for the year ended December 31, 2016 is calculated for the period from October 12, 2016, the effective date of the Corporate Reorganization, to December 31, 2016 . EPS information is not applicable for reporting periods prior to the Corporate Reorganization.

Basis of Presentation and Sig23

Basis of Presentation and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Basis of Presentation The 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, 2017 and 2016 .
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, 2017 , 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, 2017 2016 2015 Customer A 65 % 25 % — Customer B 19 % 19 % 17 % Customer C 11 % — % — % Customer D — % 23 % 30 % Customer E — % 16 % 17 % Customer F — % — % 24 % At December 31, 2017 , the Company had commodity derivative contracts with seven 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. Three of the seven counterparties to the derivative instruments are highly rated entities with corporate ratings at A3 classifications or above by Moody’s. Three additional counterparties have a corporate rating of Baa1 by Moody’s. One counterparty is a private entity and has a corporate rating of NAIC-2 by the National Association of Insurance Commissioners. For the years ended December 31, 2017 , 2016 and 2015, 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, 2017 2016 Well equipment inventory $ 9,971 $ 5,135 Prepaid expenses 3,046 2,587 $ 13,017 $ 7,722
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, 2017 , 2016 and 2015 , the Company excluded $127.4 million , $98.7 million and $59.4 million of capitalized costs from depletion related to wells in progress, respectively. For the years ended December 31, 2017 , 2016 and 2015 , the Company recorded depletion expense on capitalized oil and gas properties of $306.7 million , $197.4 million and $140.2 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, 2017 , the Company had approximately $15.7 million of suspended well costs, all capitalized less than one year. The suspended well costs are included in wells in progress at December 31, 2017. 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 2018. As of December 31, 2016, the Company did not have any suspended well costs as the analysis on economic and operating viability of the 2015 project was complete. As of December 31, 2015 , the Company had approximately $17.3 million in suspended well costs recorded, all capitalized less than one year, related to four exploratory wells in the northern field. The suspended well costs were included in wells in progress at December 31, 2015 . These exploratory well costs were pending further engineering evaluation and analysis to determine if economic quantities of oil and gas reserves had been discovered. At June 30, 2016, the Company completed its evaluation and moved $21.8 million of these suspended well costs to proved oil and gas properties based on the determination of proved reserves. 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 $1.4 million of costs associated with exploratory geological and geophysical costs for the year ended December 31, 2017. There were no exploratory geological and geophysical costs incurred for the years ended December 31, 2016 and 2015. The Company capitalizes interest, if debt is outstanding, during drilling operations in its exploration and development activities. For the years ended December 31, 2017 , 2016 and 2015 , the Company capitalized interest of approximately $11.1 million , $5.2 million and $5.3 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 accumulate 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 in the consolidated statements of operations, which increases accumulated depletion, depreciation and amortization. For the year ended December 31, 2017 , the Company recognized no impairment expense on proved oil and gas properties. For the years ended December 31, 2016 and 2015, the Company recognized $22.5 million and $9.5 million , respectively, in impairment expense on proved oil and gas properties in the Company's northern field. The future undiscounted cash flows did not exceed its carrying amount associated with its proved oil and gas properties in its northern field and 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 at June 30, 2016 and 2015. In December 2015, the Company sold proved oil and gas properties for proceeds of $4.7 million . As a result, these assets were fair valued on the date of the transaction in accordance with ASC 360 , Property, Plant and Equipment . The net book value of these assets exceeded the fair value by $2.7 million , which the Company recognized as impairment expense. The Company recognized $12.2 million in impairment expense that was attributable to proved oil and gas properties for the year ended December 31, 2015 . 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 $15.8 million , $22.3 million and $16.4 million in impairment expense for the years ended December 31, 2017 , 2016 and 2015 , respectively.
Other Property and Equipment	Other Property and Equipment Other property and equipment consists of (i) midstream assets such as rights of way, pipelines, equipment and engineering costs, (ii) compressors used in Extraction’s oil and gas operations, (iii) land, compressor stations, central tank batteries, and disposal well facilities and (iv) other property and equipment including, office furniture and fixtures, leasehold improvements and computer hardware and software. Impairment expense for other property and equipment is reported in impairment of long lived assets in the consolidated statements of operations. The Company recognized $0.9 million , $0.5 million and $3.6 million in impairment expense related to midstream facilities for the years ended December 31, 2017 , 2016 and 2015 , 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, 2017 primarily as the result of right-of-way options that were no longer in the Company's plans for developing midstream infrastucture. The Company recognized the impairment expense for the years ended December 31, 2016 and 2015, 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 other operating expenses 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. Approximately $7.3 million of midstream assets, net of impairment expense, have not been placed into service and therefore are not currently being depreciated. 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, 2017 2016 Rental equipment $ 3,805 $ 2,910 Land 22,991 12,978 Midstream facilities 12,336 16,530 Office leasehold improvements 4,405 4,360 Other 5,578 4,786 Less: accumulated depreciation (11,797 ) (8,843 ) $ 37,318 $ 32,721
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 $8.3 million of such investments included in other non-current assets on the consolidated balance sheets as of December 31, 2017. The Company recognized $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, 2017. The Company held no such investments during the years ended December 31, 2016 and 2015.
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 and 2024 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 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 an 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 year or less. The Company recorded $2.3 million and $0.3 million of internal-use software for the years ended December 31, 2017 and 2016 on the consolidated balance sheets within the goodwill and other intangible assets line item. Accumulated amortization for the years ended December 31, 2017 and 2016 was $1.1 million and $0.1 million , respectively. The Company recognized $1.0 million and $0.1 million amortization expense for the years ended December 31, 2017 and 2016, respectively. There was no capitalized internal-use software, accumulated amortization or amortization expense for the year ended December 31, 2015 .
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, 2017 .
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. There were no material imbalances at December 31, 2017 , 2016 or 2015.
Unit and Stock-Based Payments	Unit and Stock‑Based Payments The Company and its predecessor, Holdings, has granted restricted unit awards ("RUAs") to certain employees and nonemployee consultants of the Company, 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. Unit‑based payments to nonemployees are measured at fair value at each financial reporting date and expensed over the period of performance, such that aggregate expense recognized is equal to the fair value of the restricted units on the date performance is completed. 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 is 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 will require 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. The Company currently evaluating other potential impacts of the TCJA. 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 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, stock option awards and performance stock 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 The Company operates in only one industry segment, which is the exploration and production of oil, natural gas and NGL and related midstream activities. The Company’s wholly‑owned midstream subsidiaries are currently in the design phase and no revenue generating activities have commenced. 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 May 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 is effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that reporting period. Early adoption is permitted for fiscal years beginning after December 15, 2016, including the interim reporting periods within that fiscal year. The Company has completed its evaluation and the adoption of this ASU is not expected to have a significant effect on its 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 is effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that fiscal year. 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. 2017-04, 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 is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted for transactions for which the acquisition date occurs before the issuance date or effective date of the amendments, only when the transaction has not been reported in the financial statements that have been issued. The Company is currently evaluating this ASU and believes it could have a material impact to its consolidated financial statements and related disclosures, as it 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 will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. 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 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. In addition, in November 2016, the FASB issued ASU No. 2016-18, which requires that amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company has completed its evaluation and the adoption of this ASU is not expected to have a significant effect on its consolidated financial statements and related disclosures. In March 2016, the FASB issued ASU No. 2016-09, which simplifies the accounting for share-based payment award transactions, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the consolidated statement of cash flows. ASU No. 2016-09 was effective for public companies for annual and interim reporting beginning after December 15, 2016, including interim periods within those fiscal years. The Company adopted this guidance during the first quarter of 2017. As a result of adoption of this guidance, the Company elected to account for the forfeiture of stock-based compensation forfeitures as they occur. The adoption of this standard did not have a significant impact on the Company's consolidated financial statements and related disclosures. In March 2016, the FASB issued ASU No. 2016-06, which clarifies the requirements to assess whether an embedded put or call option is clearly and closely related to the debt host, solely in accordance with the four step decision sequence in FASB ASB Topic 815, Derivatives and Hedging, as amended by this ASU. This standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and should be applied using a modified retrospective approach. The Company adopted this ASU in the first quarter of 2017 and the adoption of this ASU did not have a material impact on the its consolidated financial statements and related disclosures. 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 and ASU No. 2018-01, which provided additional implementation guidance. The Company is currently evaluating the impact this ASU will have on its consolidated financial statements and related disclosures. As a part of the assessment work to-date, the Company formed an implementation team, completed training of the new guidance and is developing a strategy for implementation. In May 2014, the FASB issued ASU No. 2014-09, which establishes a comprehensive new revenue recognition model 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 is effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of reporting periods beginning after December 15, 2016. 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 and ASU No. 2017-14, which provided additional implementation guidance. The Company completed its review of contracts in each of its revenue streams and has developed accounting policies to address the provisions of this ASU. While the Company does not expect operating income (loss) to be materially impacted, the Company does expect total revenues and total expenses to change as a result of certain contracts where title of production transfers to customers at the wellhead. Further, the Company evaluated the design of its pre-adoption and adoption controls and had developed new or modified certain controls to address risks associated with recognizing revenue under the new standard as the Company continues the implementation process. The Company will continue to evaluate the impact of this and other provisions of the ASU on its accounting policies, internal controls, and consolidated financial statements and related disclosures and has not finalized any estimates of the potential impacts. The Company will adopt this new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings, if necessary. 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, 2017 , and through the date of this filing that would have a material impact on the Company’s consolidated financial statements and related disclosures.

Basis of Presentation and Sig24

Basis of Presentation and Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Revenue by Major Customers	For the Year Ended December 31, 2017 2016 2015 Customer A 65 % 25 % — Customer B 19 % 19 % 17 % Customer C 11 % — % — % Customer D — % 23 % 30 % Customer E — % 16 % 17 % Customer F — % — % 24 %
Schedule of inventory and prepaid expenses	Inventory and prepaid expenses are comprised of the following (in thousands): As of December 31, 2017 2016 Well equipment inventory $ 9,971 $ 5,135 Prepaid expenses 3,046 2,587 $ 13,017 $ 7,722
Schedule of other property and equipment	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, 2017 2016 Rental equipment $ 3,805 $ 2,910 Land 22,991 12,978 Midstream facilities 12,336 16,530 Office leasehold improvements 4,405 4,360 Other 5,578 4,786 Less: accumulated depreciation (11,797 ) (8,843 ) $ 37,318 $ 32,721

Oil and Gas Properties (Tables)

Oil and Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Schedule of net capitalized costs related to oil and gas producing activities	The Company’s oil and gas properties are entirely within the United States. The net capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands): As of December 31, 2017 2016 Proved oil and gas properties $ 3,011,526 $ 1,851,052 Unproved oil and gas properties (1) 686,968 452,577 Wells in progress (2) 127,418 98,747 Total capitalized costs (3) $ 3,825,912 $ 2,402,376 Accumulated depletion, depreciation and amortization (709,662 ) (402,912 ) Net capitalized costs $ 3,116,250 $ 1,999,464 (1) Unproved oil and gas properties represent unevaluated costs the Company excludes from the amortization base until proved reserves are established or impairment is determined. (2) Costs from wells in progress are excluded from the amortization base until production commences. (3) Includes accumulated interest capitalized of $24.5 million , $13.4 million and $8.2 million as of December 31, 2017 , 2016 and 2015 , respectively.
Schedule of net costs incurred in oil and gas property acquisition, exploration and development activities	The following table presents information regarding the Company’s net costs incurred in oil and gas property acquisition, exploration and development activities (in thousands): For the Year Ended December 31, 2017 2016 Property acquisition costs: Proved $ 139,481 $ 319,832 Unproved 382,213 220,213 Exploration costs (1) 17,074 13,588 Development costs 894,040 317,228 Total $ 1,432,808 $ 870,861 Total excluding asset retirement costs $ 1,420,235 $ 863,874 (1) Exploration costs do not include impairment and abandonment costs of unproved properties, which are included in the line item exploration expenses in the consolidated statements of operations.

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Schedule summarizing the purchase price and allocation of fair value of assets acquired and liabilities assumed	The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands): Purchase Price October 3, 2016 Consideration given Cash $ 405,335 Total consideration given $ 405,335 Allocation of Purchase Price Proved oil and gas properties $ 252,522 Unproved oil and gas properties 109,800 Total fair value of oil and gas properties acquired $ 362,322 Goodwill (1) $ 54,220 Working capital (7,185 ) Asset retirement obligations (4,022 ) Fair value of net assets acquired $ 405,335 Working capital acquired was estimated as follows: Accounts receivable $ 955 Revenue payable (3,012 ) Production taxes payable (4,244 ) Accrued liabilities (884 ) Total working capital $ (7,185 ) (1) Goodwill is primarily attributable to a decrease in commodity prices from the time the acquisition was negotiated and commodity prices on October 3, 2016 and the operational and financial synergies expected to be realized from the acquisition. Goodwill recognized as a result of the Bayswater Acquisition is not deductible for income tax purposes. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands): Purchase Price March 10, 2015 Consideration given Cash $ 120,524 Total consideration given $ 120,524 Allocation of Purchase Price Proved oil and gas properties $ 80,952 Unproved oil and gas properties 69,450 Total fair value of oil and gas properties acquired $ 150,402 Working capital $ (1,996 ) Asset retirement obligations (27,882 ) Fair value of net assets acquired $ 120,524 Working capital acquired was estimated as follows: Accounts receivable $ 462 Revenue payable (718 ) Production taxes payable (1,740 ) Total working capital $ (1,996 ) The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands): Purchase Price August 23, 2016 Consideration given Cash $ 17,504 Total consideration given $ 17,504 Allocation of Purchase Price Proved oil and gas properties $ 12,362 Unproved oil and gas properties 8,566 Total fair value of oil and gas properties acquired $ 20,928 Working capital $ (9 ) Asset retirement obligations (3,415 ) Fair value of net assets acquired $ 17,504 Working capital acquired was estimated as follows: Production taxes payable (9 ) Total working capital $ (9 ) The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands): Purchase Price June 8, 2017 Consideration given Cash $ 13,395 Total consideration given $ 13,395 Allocation of Purchase Price Proved oil and gas properties $ 13,495 Total fair value of oil and gas properties acquired $ 13,495 Asset retirement obligations $ (100 ) Fair value of net assets acquired $ 13,395
Schedule of Pro Forma Financial Information	For the Year Ended December 31, 2017 2016 2015 Revenues $ 606,460 $ 325,355 $ 214,259 Net loss $ (44,231 ) $ (441,571 ) $ (33,524 ) Loss per share Basic and diluted $ (0.35 ) $ (1.54 )

Long Term Debt (Tables)

Long Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule of long-term debt	As of the dates indicated the Company’s long‑term debt consisted of the following (in thousands): As of December 31, 2017 2016 Credit facility due November 29, 2018 $ 90,000 $ — 2021 Senior Notes due July 15, 2021 550,000 550,000 2024 Senior Notes due May 15, 2024 400,000 — Unamortized debt issuance costs on Senior Notes (16,639 ) (11,859 ) Total long-term debt $ 1,023,361 $ 538,141
Schedule of Borrowing Base Utilization Grid	The grid below shows the Base Rate Margin and Eurodollar Margin depending on the applicable Borrowing Base Utilization Percentage (as defined in the credit facility) as of the date of this filing: Borrowing Base Utilization Grid LIBOR Base Rate Commitment Borrowing Base Utilization Percentage Utilization Margin Margin Fee Level 1 < 25 2.00 % 1.00 % 0.375 % Level 2 ≥ 25% < 50 2.25 % 1.25 % 0.375 % Level 3 ≥ 50% < 75 2.50 % 1.50 % 0.500 % Level 4 ≥ 75% < 90 2.75 % 1.75 % 0.500 % Level 5 ≥ 90 3.00 % 2.00 % 0.500 %

Commodity Derivative Instrume28

Commodity Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of commodity derivative contracts	The Company’s commodity derivative contracts as of December 31, 2017 are summarized below: 2018 2019 NYMEX WTI Crude Swaps: Notional volume (Bbl) 5,100,000 — Weighted average fixed price ($/Bbl) $ 51.61 $ — NYMEX WTI Crude Sold Calls: Notional volume (Bbl) 8,290,000 5,100,000 Weighted average sold call price ($/Bbl) $ 56.18 $ 55.93 NYMEX WTI Crude Sold Puts: Notional volume (Bbl) 13,438,800 5,100,000 Weighted average sold put price ($/Bbl) $ 39.10 $ 39.82 NYMEX WTI Crude Purchased Puts: Notional volume (Bbl) 12,327,600 5,100,000 Weighted average purchased put price ($/Bbl) $ 44.81 $ 49.69 NYMEX HH Natural Gas Swaps: Notional volume (MMBtu) 40,800,000 — Weighted average fixed price ($/MMBtu) $ 3.10 $ — NYMEX HH Natural Gas Purchased Puts: Notional volume (MMBtu) 2,400,000 — Weighted average purchased put price ($/MMBtu) $ 3.00 $ — NYMEX HH Natural Gas Sold Calls: Notional volume (MMBtu) 2,400,000 — Weighted average sold call price ($/MMBtu) $ 3.15 $ — CIG Basis Gas Swaps: Notional volume (MMBtu) 6,300,000 — Weighted average fixed basis price ($/MMBtu) $ (0.31 ) $ —
Schedule of fair value of derivative instruments in statement of financial position	The following tables detail the fair value of the Company’s derivative instruments, including the gross amounts and adjustments made to net the derivative instruments for the presentation in the balance sheets (in thousands): As of December 31, 2017 Net Amounts of Gross Amounts Assets and of Recognized Gross Amounts Liabilities Gross Amounts Assets and Offset in the Presented in the not Offset in the Net Location on Balance Sheet Liabilities Balance Sheet (1) Balance Sheet Balance Sheet (2) Amounts (3) Current assets $ 22,118 $ (17,986 ) $ 4,132 $ — $ 4,132 Non-current assets $ 13,686 $ (13,686 ) $ — $ — $ — Current liabilities $ (85,414 ) $ 17,986 $ (67,428 ) $ — $ (84,702 ) Non-current liabilities $ (30,960 ) $ 13,686 $ (17,274 ) $ — $ — As of December 31, 2016 Net Amounts of Gross Amounts Assets and of Recognized Gross Amounts Liabilities Gross Amounts Assets and Offset in the Presented in the not Offset in the Net Location on Balance Sheet Liabilities Balance Sheet (1) Balance Sheet Balance Sheet (2) Amounts (3) Current assets $ 12,620 $ (12,620 ) $ — $ — $ — Non-current assets $ 14,993 $ (14,993 ) $ — $ — $ — Current liabilities $ (68,623 ) $ 12,620 $ (56,003 ) $ — $ (62,741 ) Non-current liabilities $ (21,731 ) $ 14,993 $ (6,738 ) $ — $ — (1) Agreements are in place with all of the Company’s financial trading counterparties that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. (2) Netting for balance sheet presentation is performed by current and non‑current classification. This adjustment represents amounts subject to an enforceable master netting arrangement, which are not netted on the balance sheet. There are no amounts of related financial collateral received or pledged. (3) Net amounts are not split by current and non‑current. All counterparties in a net asset position are shown in the current asset line item and all counterparties in a net liability position are shown in the current liability line item.
Schedule of commodity derivatives gain (loss) included in other income (expense)	The table below sets forth the commodity derivatives gain (loss) for the years ended December 31, 2017 , 2016 and 2015 (in thousands). Commodity derivatives gain (loss) are included under other income (expense). For the Year Ended December 31, 2017 2016 2015 Commodity derivatives gain (loss) $ (36,332 ) $ (100,947 ) $ 79,932

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Schedule summarizing activities of asset retirement obligations	The following table summarizes the activities of the Company’s asset retirement obligations for the periods indicated (in thousands): For the Year Ended December 31, 2017 2016 Balance beginning of period $ 56,108 $ 44,367 Liabilities incurred or acquired 9,802 8,945 Liabilities settled (4,169 ) (1,155 ) Revisions in estimated cash flows 2,630 (1,695 ) Accretion expense 5,169 5,646 Balance end of period $ 69,540 $ 56,108

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Schedule of financial assets and liabilities accounted for at fair value 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 as of December 31, 2017 and December 31, 2016 by level within the fair value hierarchy (in thousands): Fair Value Measurements at December 31, 2017 Using Level 1 Level 2 Level 3 Total Financial Assets: Commodity derivative assets $ — $ 4,132 $ — $ 4,132 Financial Liabilities: Commodity derivative liabilities $ — $ 84,702 $ — $ 84,702 Fair Value Measurements at December 31, 2016 Using Level 1 Level 2 Level 3 Total Financial Assets: Commodity derivative assets $ — $ — $ — $ — Financial Liabilities: Commodity derivative liabilities $ — $ 62,741 $ — $ 62,741
Schedule of fair value of financial instruments	This disclosure (in thousands) does not impact the Company’s financial position, results of operations or cash flows. At December 31, 2017 At December 31, 2016 Carrying Carrying Amount Fair Value Amount Fair Value Credit facility $ 90,000 $ 90,000 $ — $ — 2021 Senior Notes (1) $ 540,382 $ 583,000 $ 538,141 $ 588,500 2024 Senior Notes (2) $ 392,979 $ 427,000 $ — $ — (1) The carrying amount of the 2021 Senior Notes includes unamortized debt issuance costs of $9.6 million and $ 11.9 million as of December 31, 2017 and 2016, respectively. (2) The carrying amount of the 2024 Senior Notes includes unamortized debt issuance costs of $7.0 million as of December 31, 2017.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of components of the income tax expense (benefit)	The components of the income tax expense (benefit) were as follows (in thousands): For the Year Ended December 31, 2017 2016 Current: Federal $ — $ — State, net of federal benefit — — Total current income tax benefit $ — $ — Deferred: Federal $ (61,719 ) $ (26,962 ) State, net of federal benefit (1,981 ) (2,318 ) Total deferred income tax benefit $ (63,700 ) $ (29,280 ) Income tax benefit $ (63,700 ) $ (29,280 )
Schedule of reconciliation of the income tax expense (benefit) with income tax expense at the federal statutory rate	The following table reconciles the income tax expense (benefit) with income tax expense at the federal statutory rate (in thousands): For the Year Ended December 31, 2017 2016 Loss before income taxes (108,108 ) (485,281 ) Federal income taxes at statutory rate (37,838 ) (169,849 ) Net loss prior to Corporate Reorganization — 80,463 State income taxes, net of federal benefit (3,118 ) (2,318 ) Nondeductible stock-based compensation 2,264 62,284 Enactment of the Tax Cuts and Jobs Act (23,412 ) — Other (1,596 ) 140 Income tax expense (benefit) (63,700 ) (29,280 ) Net loss $ (44,408 ) $ (456,001 )
Schedule of deferred tax assets and liabilities	The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities were as follows (in thousands): As of December 31, 2017 2016 Deferred Tax Assets: Net operating loss carryforward $ 205,806 $ 35,719 Commodity derivatives 19,984 24,068 Stock-based compensation 13,853 2,824 Other 17,053 14,309 Total deferred tax assets 256,696 76,920 Deferred Tax Liabilities: Excess basis of oil and gas properties (299,022 ) (182,946 ) Total deferred tax liabilities (299,022 ) (182,946 ) Deferred Tax Liability, net $ (42,326 ) $ (106,026 )

Unit and Stock-Based Compensati

Unit and Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of non-vested restricted award activity	The following table summarizes the Holdings’ RUA activity from January 1, 2015 through December 31, 2016 and provides information for Holdings’ RUAs outstanding at the dates indicated. Weighted Average Number of Grant Date Shares Fair Value Non-vested RUAs at January 1, 2015 9,365,896 $ 2.22 Granted 196,047 $ 2.68 Forfeited (53,063 ) $ 2.21 Vested (3,197,638 ) $ 2.22 Non-vested RUAs at December 31, 2015 6,311,242 $ 2.23 Granted 1,531,542 $ 5.84 Forfeited (181,817 ) $ 2.68 Vested (7,660,967 ) $ 2.94 Non-vested RUAs at December 31, 2016 — $ — The following table summarizes the Incentive RSU activity from January 1, 2016 through December 31, 2017 and provides information for Incentive RSUs outstanding at the dates indicated. Weighted Average Number of Grant Date Shares Fair Value Non-vested Incentive RSUs at January 1, 2016 — $ — Granted 2,717,968 $ 20.45 Forfeited (3,600 ) $ 20.45 Vested — $ — Non-vested Incentive RSUs at December 31, 2016 2,714,368 $ 20.45 Granted — $ — Forfeited (710,993 ) $ 20.45 Vested (507,200 ) $ 20.45 Non-vested Incentive RSUs at December 31, 2017 1,496,175 $ 20.45 Weighted Average Number of Grant Date Shares Fair Value Non-vested RSUs at January 1, 2016 — $ — Granted 3,237,500 $ 21.41 Forfeited — $ — Vested — $ — Non-vested RSUs at December 31, 2016 3,237,500 $ 21.41 Granted 1,369,083 $ 16.37 Forfeited (445,366 ) $ 19.85 Vested (1,254,744 ) $ 20.85 Non-vested RSUs at December 31, 2017 2,906,473 $ 19.51
Schedule of assumptions used for the Black-Scholes valuation model	The assumptions used in valuing the PSAs granted were as follows: For the Year Ended December 31, 2017 Risk free rates 1.5 % Dividend yield — Expected volatility 45.0 % For the Year Ended December 31, 2017 December 31, 2016 Risk free rates 2.0 % 1.4 % Dividend yield — — Expected volatility 58.9 % 47.2 % Expected term (in years) 6.0 6.0 The weighted average fair value at the date of grant for stock options granted is as follows: Weighted average per share $ 8.66 $ 8.75 Total options granted 744,428 4,500,000 Total weighted average fair value of shares granted (in thousands) $ 6,445 $ 39,375
Schedule summarizing stock option activity	Outstanding Options Exercisable Options Weighted-Average Weighted-Average Weighted-Average Exercise Options Remaining Contractual Life Exercise Price Options Price per Share 4,500,000 8.9 years $ 19.00 1,500,000 $ 19.00 744,428 9.8 years $ 15.53 248,138 $ 15.53 5,244,428 9.0 years $ 18.50 1,748,138 $ 18.52 Weighted Average Number of Exercise Shares Price Non-vested Stock Options at January 1, 2016 — $ — Granted 4,500,000 $ 19.00 Forfeited — $ — Vested — $ — Non-vested Stock Options at December 31, 2016 4,500,000 $ 19.00 Granted 744,428 $ 15.53 Forfeited — $ — Vested (1,748,138 ) $ 18.52 Non-vested Stock Options at December 31, 2017 3,496,290 $ 18.50 The following table summarizes the PSA activity from January 1, 2017 through December 31, 2017 and provides information for PSAs outstanding at the dates indicated. Weighted Average Number of Grant Date Shares (1) Fair Value Non-Vested PSAs as of January 1, 2017 — $ — Granted 832,163 $ 8.85 Forfeited — $ — Vested — $ — Non-Vested PSAs as of December 31, 2017 832,163 $ 8.85

Earnings (Loss) Per Share (Tabl

Earnings (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Schedule of computations of basic and diluted net loss per share	The components of basic and diluted EPS were as follows: From October 12, 2016 Year Ended December 31, 2017 to December 31, 2016 Basic and Diluted EPS (in thousands, except per share data) Net Loss $ (44,408 ) $ (226,107 ) Less: Adjustment to reflect Series A Preferred Stock dividend (10,885 ) (2,958 ) Less: Adjustment to reflect accretion of Series A Preferred Stock discount (5,394 ) (1,041 ) Net loss attributable to common shareholders $ (60,687 ) $ (230,106 ) Weighted Average Common Shares Outstanding (1) (2) Basic and diluted 171,910 149,029 Net Loss Allocated to Common Shareholders per Common Share Basic and diluted $ (0.35 ) $ (1.54 ) (1) For the year ended December 31, 2017, 8,566,983 potentially dilutive shares were not included in the calculation above, as they had an anti-dilutive effect on EPS, including restricted stock awards, stock options outstanding and performance stock awards contingently issuable, if December 31, 2017 was the end of the measurement period. Additionally, the 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded. (2) For the period of October 12 through December 31, 2016, 7,737,500 potentially dilutive shares were not included in the calculation above, as they had an anti-dilutive effect on EPS, including restricted stock awards and stock options outstanding for the period. Additionally, the 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded.

Supplemental Oil and Gas Rese34

Supplemental Oil and Gas Reserve Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Other Reserve Information [Abstract]
Schedule of Results of Operations for Oil, Natural Gas and NGL Producing Properties	For the Year Ended December 31, 2017 2016 2015 Revenues $ 604,296 $ 278,089 $ 197,750 Operating Expenses: Production expenses 162,673 82,773 47,663 Exploration expenses 36,256 36,422 18,636 Depletion and accretion 311,916 203,073 144,228 Impairment of proved properties — 22,438 12,207 Results of operations before income tax expense 93,451 (66,617 ) (24,984 ) Income tax (expense) benefit (35,511 ) 25,314 9,494 Results of Operations $ 57,940 $ (41,303 ) $ (15,490 )
Schedule of changes in proved developed and undeveloped reserves	The following table sets forth information for the years ended December 31, 2017 , 2016 and 2015 with respect to changes in the Company’s proved (i.e. proved developed and undeveloped) reserves: Crude Oil Natural Gas NGL MBoe Mbbls MMcf Mbbls Total Balance as of December 31, 2014 45,164.9 166,416.1 19,451.0 92,352.0 Revisions of previous estimates (2,961.0 ) (2,825.8 ) 2,281.9 (1,150.1 ) Purchase of reserves 11,831.7 64,392.7 7,533.3 30,097.1 Extensions, discoveries, and other additions 23,098.7 85,781.0 11,663.4 49,058.9 Sale of reserves (1,688.5 ) (10,357.1 ) (1,212.1 ) (4,626.8 ) Production (3,945.6 ) (10,823.0 ) (1,334.6 ) (7,084.0 ) Balance as of December 31, 2015 71,500.2 292,583.9 38,382.9 158,647.1 Revisions of previous estimates (15,576.8 ) 35,803.1 1,988.8 (7,620.8 ) Purchase of reserves 18,473.6 78,761.6 9,680.7 41,281.2 Extensions, discoveries, and other additions 21,885.4 120,798.3 14,679.9 56,698.5 Sale of reserves — — — — Production (5,287.4 ) (20,211.5 ) (2,284.0 ) (10,940.0 ) Balance as of December 31, 2016 90,995.0 507,735.4 62,448.3 238,066.0 Revisions of previous estimates (625.9 ) 9,349.8 1,961.6 2,894.0 Purchase of reserves 10,761.2 11,183.6 1,563.3 14,188.3 Extensions, discoveries, and other additions 19,738.4 130,295.4 15,033.6 56,487.9 Sale of reserves — — — — Production (9,593.7 ) (32,395.2 ) (3,900.8 ) (18,893.7 ) Balance as of December 31, 2017 111,275.0 626,169.0 77,106.0 292,742.5 Proved Developed Reserves, included above Balance as of December 31, 2015 14,248.6 53,011.7 7,058.3 30,142.3 Balance as of December 31, 2016 17,158.0 107,918.0 13,354.0 48,498.4 Balance as of December 31, 2017 37,078.0 222,236.0 27,932.0 102,049.3 Proved Undeveloped Reserves, included above Balance as of December 31, 2015 57,251.5 239,572.2 31,324.6 128,504.8 Balance as of December 31, 2016 73,837.0 399,817.4 49,094.3 189,567.5 Balance as of December 31, 2017 74,197.0 403,933.0 49,174.0 190,693.2 • The values for the 2017 oil, natural gas and NGL reserves are based on the 12-month arithmetic average of the first day of the month prices for the period from January through December 31, 2017 . The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $51.34 per barrel (West Texas Intermediate price) for crude oil and NGL and $2.98 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2017 was $42.89 per barrel for oil, $1.73 per Mcf for natural gas and $20.28 per barrel for NGL. • The values for the 2016 oil, natural gas and NGL reserves are based on the 12-month arithmetic average of the first day of the month prices for the period from January through December 31, 2016 . The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $42.75 per barrel (West Texas Intermediate price) for crude oil and NGL and $2.49 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2016 was $34.91 per barrel for oil, $1.39 per Mcf for natural gas and $11.63 per barrel for NGL. • The values for the 2015 oil, natural gas and NGL reserves are based on the 12 month arithmetic average of the first day of the month prices for the period from January through December 31, 2015 . The unweighted arithmetic average first-day-of-month prices for the prior twelve months were $50.28 per barrel (West Texas Intermediate price) for crude oil and NGL and $2.58 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2015 was $43.28 per barrel for oil, $2.11 per Mcf for natural gas and $10.65 per barrel for NGL.
Schedule of principal sources of change in the standardized measure	The following are the principal sources of change in the standardized measure (in thousands): For the Year Ended December 31, 2017 2016 2015 Future crude oil, natural gas and NGL sales $ 7,422,335 $ 4,610,848 $ 4,119,888 Future production costs (2,227,370 ) (1,429,202 ) (1,193,560 ) Future development costs (1,662,859 ) (1,579,628 ) (1,141,330 ) Future income tax expense (212,923 ) (42,859 ) — Future net cash flows $ 3,319,183 $ 1,559,159 $ 1,784,998 10% annual discount (1,440,177 ) (836,163 ) (949,115 ) Standardized measure of discounted future net cash flows (1) $ 1,879,006 $ 722,996 $ 835,883 (1) The Company’s calculations of the standardized measure of discounted future net cash flows does not include the effect of estimated future income tax expenses for the year ended December 31, 2015 as the Company was a limited liability company and not subject to income taxes. For the years ended December 31, 2017 and 2016, future income tax expenses in the Company’s calculation of the standardized measure of discounted future net cash flows are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and gas properties, other deductions, credit and allowances relating to the Company’s proved reserves. For purposes of the standardized measure calculation, it was assumed that all of the Company’s operations are attributable to the Company’s oil and gas assets. If the Company had been subject to entity-level income taxation, the unaudited pro forma future income tax expense at December 31, 2015 would have been $327.9 million and the unaudited standardized measure would have been $680.3 million .
Schedule of future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure	The following summary sets forth the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure prescribed in ASC 932, Extractive Activities-Oil and Gas (in thousands): For the Year Ended December 31, 2017 2016 2015 Balance at beginning of period $ 722,996 $ 835,883 $ 1,387,472 Sales of crude oil, natural gas and NGL, net (441,623 ) (195,316 ) (150,087 ) Net change in prices and production costs 586,271 (325,236 ) (1,292,364 ) Net change in future development costs 3,959 (49,213 ) 175,944 Extensions and discoveries 330,160 96,982 284,216 Acquisitions of reserves 59,745 156,675 240,989 Sale of reserves — — (50,018 ) Revisions of previous quantity estimates 188,421 19,161 (28,391 ) Previously estimated development costs incurred 331,550 123,085 102,060 Net changes in income taxes (79,181 ) (17,611 ) — Accretion of discount 74,061 83,588 156,723 Other 102,647 (5,002 ) 9,339 Balance at end of period $ 1,879,006 $ 722,996 $ 835,883

Unaudited Quarterly Financial35

Unaudited Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Summary of unaudited quarterly financial data	You should read this data together with the Company's consolidated financial statements and the related notes included elsewhere in this Annual Report: Three Months Ended March 31, June 30, September 30, December 31, 2017 2017 2017 2017 Oil, Natural gas and NGL sales $ 89,639 $ 119,766 $ 180,861 $ 214,030 Operating Income (1) $ 10,210 $ 16,480 $ 41,084 $ 58,850 Net Income (Loss) $ 8,716 $ 7,240 $ (29,796 ) $ (30,568 ) Basic and Diluted Income (Loss) Per Common Share $ 0.03 $ 0.02 $ (0.20 ) $ (0.20 ) Three Months Ended March 31, June 30, September 30, December 31, 2016 2016 2016 2016 Oil, Natural gas and NGL sales $ 45,133 $ 65,364 $ 72,902 $ 94,690 Operating Income (Loss) (1) $ (16,635 ) $ (3,593 ) $ 4,556 $ 5,640 Net Loss $ (45,519 ) $ (127,614 ) $ (37,267 ) $ (245,601 ) Basic and Diluted Loss Per Common Share $ (1.54 ) (1) Oil, Natural gas and NGL sales revenue less lease operating expenses, production taxes and depreciation, depletion, amortization and accretion. (2) EPS for the year ended December 31, 2016 is calculated for the period from October 12, 2016, the effective date of the Corporate Reorganization, to December 31, 2016 . EPS information is not applicable for reporting periods prior to the Corporate Reorganization.

Basis of Presentation and Sig36

Basis of Presentation and Significant Accounting Policies - Cash and Receivables (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Accounts Receivable
Allowance for uncollectible receivables	$ 0	$ 0

Basis of Presentation and Sig37

Basis of Presentation and Significant Accounting Policies - Credit Risk (Details) - Oil, natural gas and NGL revenues	12 Months Ended
	Dec. 31, 2017counterpartycontract	Dec. 31, 2016	Dec. 31, 2015
Customer concentration risk | Customer A
Credit Risk and Other Concentrations
Concentration risk, percentage	65.00%	25.00%
Customer concentration risk | Customer B
Credit Risk and Other Concentrations
Concentration risk, percentage	19.00%	19.00%	17.00%
Customer concentration risk | Customer C
Credit Risk and Other Concentrations
Concentration risk, percentage	11.00%
Customer concentration risk | Customer D
Credit Risk and Other Concentrations
Concentration risk, percentage		23.00%	30.00%
Customer concentration risk | Customer E
Credit Risk and Other Concentrations
Concentration risk, percentage		16.00%	17.00%
Customer concentration risk | Customer F
Credit Risk and Other Concentrations
Concentration risk, percentage			24.00%
Credit concentration risk
Credit Risk and Other Concentrations
Number of counterparties	7
Number of derivative contracts containing credit-risk contingent features | contract	1
Credit concentration risk | Moody's, Baa1 Rating
Credit Risk and Other Concentrations
Number of counterparties	3
Credit concentration risk | Moody's, A3 Rating | Minimum
Credit Risk and Other Concentrations
Number of counterparties	3

Basis of Presentation and Sig38

Basis of Presentation and Significant Accounting Policies - Inventory and Prepaid Expenses (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Inventory and Prepaid Expenses
Well equipment inventory	$ 9,971,000	$ 5,135,000
Prepaid expenses	3,046,000	2,587,000
Inventory and prepaid expenses	13,017,000	7,722,000
Well equipment inventory, impairment expense	$ 700,000	$ 400,000	$ 0

Basis of Presentation and Sig39

Basis of Presentation and Significant Accounting Policies - Oil and Gas Properties (Details)	Jun. 30, 2016USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)well
Capitalized Costs Excluded
Capitalized costs excluded from depletion		$ 127,400,000	$ 98,700,000	$ 59,400,000
Depletion of Oil and Gas Properties
Depletion expense		306,700,000	197,400,000	140,200,000
Oil and gas properties, other information
Exploratory well costs suspended pending further engineering evaluation		15,700,000	0	$ 17,300,000
Number of exploratory wells with suspended well costs | well				4
Suspended exploratory well costs transferred to proved oil and gas properties	$ 21,800,000
Exploratory geological and geophysical costs		1,400,000	0	$ 0
Interest costs capitalized, exploration and development activities		$ 11,100,000	$ 5,200,000	$ 5,300,000

Basis of Presentation and Sig40

Basis of Presentation and Significant Accounting Policies - Impairment of Oil and Gas Properties (Details) - USD ($)	1 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Impairment of Oil and Gas Properties
Sale of property and equipment	$ 4,700,000	$ 5,155,000	$ 2,656,000	$ 4,742,000
Abandonment and impairment of unproved properties		15,808,000	22,318,000	16,414,000
Impairment of long-lived assets
Impairment of Oil and Gas Properties
Impairment of proved properties	$ 2,700,000			12,200,000
Exploration expenses
Impairment of Oil and Gas Properties
Abandonment and impairment of unproved properties		15,800,000	22,300,000	16,400,000
Northern Field | Impairment of long-lived assets
Impairment of Oil and Gas Properties
Impairment of proved properties		$ 0	$ 22,500,000	$ 9,500,000

Basis of Presentation and Sig41

Basis of Presentation and Significant Accounting Policies - Other Property and Equipment, Impairments (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Property and Equipment
Impairment of long lived assets		$ 1,647	$ 23,425	$ 15,778
Loss on sale of property and equipment	$ (500)	(451)	0	0
Midstream facilities
Other Property and Equipment
Impairment of long lived assets		900	$ 500	$ 3,600
Assets not yet placed in service, net of impairment		$ 7,300
Rental equipment | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives of assets depreciated under straight-line basis (in years)		1 year
Rental equipment | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives of assets depreciated under straight-line basis (in years)		10 years
Office leasehold improvements | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives of assets depreciated under straight-line basis (in years)		3 years
Office leasehold improvements | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives of assets depreciated under straight-line basis (in years)		10 years
Other | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives of assets depreciated under straight-line basis (in years)		3 years
Other | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives of assets depreciated under straight-line basis (in years)		5 years

Basis of Presentation and Sig42

Basis of Presentation and Significant Accounting Policies - Other Property and Equipment, Net (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Other Property and Equipment
Total Other Property and Equipment	$ 37,318	$ 32,721
Other Property and Equipment
Other Property and Equipment
Less: accumulated depreciation	(11,797)	(8,843)
Total Other Property and Equipment	37,318	32,721
Rental equipment
Other Property and Equipment
Other property and equipment, gross	3,805	2,910
Land
Other Property and Equipment
Other property and equipment, gross	22,991	12,978
Midstream facilities
Other Property and Equipment
Other property and equipment, gross	12,336	16,530
Office leasehold improvements
Other Property and Equipment
Other property and equipment, gross	4,405	4,360
Other
Other Property and Equipment
Other property and equipment, gross	$ 5,578	$ 4,786

Basis of Presentation and Sig43

Basis of Presentation and Significant Accounting Policies - Equity Method Investments (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Investment included in other non-current assets	$ 8,300,000	$ 0	$ 0
Earnings in unconsolidated affiliates	$ 415,000	$ 0	$ 0

Basis of Presentation and Sig44

Basis of Presentation and Significant Accounting Policies - Deferred Discount and Issuance Costs (Details) - Second Lien Notes due May 29, 2019 - USD ($)	Dec. 31, 2017	Dec. 31, 2015	May 29, 2014
Debt Discount Costs
Unamortized debt discount	$ 0	$ 6,500,000	$ 6,500,000
Holdings
Debt Discount Costs
Face amount of debt			$ 430,000,000
Original issue discount rate (as a percent)			1.50%

Basis of Presentation and Sig45

Basis of Presentation and Significant Accounting Policies - Goodwill and Other Intangible Assets (Details) - Internal-use software licenses - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Goodwill and Other Intangible Assets
Intangible assets acquired	$ 2,300,000	$ 300,000	$ 0
Accumulated amortization	1,100,000	100,000	0
Amortization expense	$ 1,000,000	$ 100,000	$ 0
Maximum
Goodwill and Other Intangible Assets
Estimated useful life (in years)	1 year

Basis of Presentation and Sig46

Basis of Presentation and Significant Accounting Policies - Environmental Liabilities, Income Taxes, and Other (Details)	Dec. 22, 2017USD ($)	Dec. 31, 2017USD ($)segmentregion
Environmental Liabilities
Environmental liabilities		$ 0
Income Taxes
Uncertain tax positions		$ 0
Income tax benefit recorded related to the remeasurement of the net	$ 23,400,000
Segment Reporting
Number of operating segments | segment		1
Number of geographic areas | region		1

Oil and Gas Properties - Net Ca

Oil and Gas Properties - Net Capitalized Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil and gas properties
Proved oil and gas properties	$ 3,011,526	$ 1,851,052
Unproved oil and gas properties	686,968	452,577
Wells in progress	127,418	98,747
Total capitalized costs	3,825,912	2,402,376
Less: accumulated depletion, depreciation and amortization	(709,662)	(402,912)
Net oil and gas properties	3,116,250	1,999,464
Accumulated interest capitalized	$ 24,500	$ 13,400	$ 8,200

Oil and Gas Properties - Net Co

Oil and Gas Properties - Net Costs Incurred (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Property acquisition costs
Proved	$ 139,481	$ 319,832
Unproved	382,213	220,213
Exploration costs	17,074	13,588
Development costs	894,040	317,228
Total	1,432,808	870,861
Total excluding asset retirement costs	$ 1,420,235	$ 863,874

Acquisitions - November 2017 Ac

Acquisitions - November 2017 Acquisition (Details) - November 2017 Acquisition $ in Millions	Nov. 15, 2017USD ($)a	Dec. 31, 2017USD ($)
Acquisitions
Acres acquired or to be acquired | a	36,600
Total consideration given	$ 214.3
Liability for final settlement payment		$ 12.2

Acquisitions Acquisitions - Jul

Acquisitions Acquisitions - July 2017 Acquisition (Details) - July 2017 Acquisition $ in Millions	Jul. 07, 2017USD ($)a
Acquisitions
Acres acquired or to be acquired | a	12,500
Total consideration given | $	$ 84

Acquisitions - June 2017 Acquis

Acquisitions - June 2017 Acquisition (Details) - June 2017 Acquisition $ in Thousands	Jun. 08, 2017USD ($)a	Dec. 31, 2017USD ($)
Acquisitions
Acres acquired or to be acquired | a	160
Revenue contributed since acquisition		$ 3,700
Earnings contributed since acquisition		$ 3,000
Consideration given
Cash	$ 13,395
Total consideration given	13,395
Allocation of Purchase Price
Proved oil and gas properties	13,495
Total fair value of oil and gas properties acquired	13,495
Asset retirement obligations	(100)
Fair value of net assets acquired	$ 13,395

Acquisitions - November 2016 Ac

Acquisitions - November 2016 Acquisition (Details) $ in Thousands	Nov. 22, 2016USD ($)acontract	Jul. 31, 2017USD ($)a	Jan. 31, 2017USD ($)a	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Acquisitions
Deposit				$ 0	$ 42,200
November 2016 Acquisition
Acquisitions
Acres acquired or to be acquired | a	9,200	640	5,300
Total consideration given	$ 120,000	$ 10,900	$ 26,800
November 2016 Acquisition | Cash Held in Escrow
Acquisitions
Deposit	$ 41,100
November 2016 Acquisition | Cash Held in Escrow | Proposed
Acquisitions
Number of additional closings | contract	2

Acquisitions - October 2016 Acq

Acquisitions - October 2016 Acquisition (Details)	Oct. 03, 2016USD ($)a	Dec. 31, 2016USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Acquisitions
Acquisition transaction expenses			$ 0	$ 2,719,000	$ 6,000,000
Other information
Nonrefundable deposit paid in conjunction with acquisition			17,225,000	419,009,000	120,524,000
Write-off of deposit on acquisition			0	10,000,000	0
Other Operating Expenses
Other information
Write-off of deposit on acquisition		$ 10,000,000
October 2016 Acquisition
Acquisitions
Acres acquired | a	6,400
Revenue contributed since acquisition				17,200,000
Acquisition transaction expenses			$ 0	$ 2,600,000	$ 0
Consideration given
Cash	$ 405,335,000
Total consideration given	405,335,000
Allocation of Purchase Price
Proved oil and gas properties	252,522,000
Unproved oil and gas properties	109,800,000
Total fair value of oil and gas properties acquired	362,322,000
Goodwill	54,220,000
Working capital	(7,185,000)
Asset retirement obligations	(4,022,000)
Fair value of net assets acquired	405,335,000
Working capital acquired was estimated as follows:
Accounts receivable	955,000
Revenue payable	(3,012,000)
Production taxes payable	(4,244,000)
Accrued liabilities	(884,000)
Total working capital	(7,185,000)
October 2016 Acquisition, Seller Option Expiring April 30, 2017 | Proposed
Consideration given
Cash	120,000,000
Total consideration given	130,000,000
October 2016 Acquisition, Purchase Option Expiring March 31, 2017 | Proposed
Consideration given
Cash	190,000,000
Total consideration given	200,000,000
October 2016 Acquisition, Purchase Option Expiring March 31, 2017 | Cash Held in Escrow
Other information
Nonrefundable deposit paid in conjunction with acquisition	$ 10,000,000

Acquisitions - August 2016 Acqu

Acquisitions - August 2016 Acquisition (Details) $ in Thousands	Aug. 23, 2016USD ($)a	Sep. 30, 2016USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Acquisitions
Acquisition transaction expenses			$ 0	$ 2,719	$ 6,000
August 2016 Acquisition
Acquisitions
Acres acquired | a	1,400
Consideration given
Cash	$ 17,504
Total consideration given	17,504
Allocation of Purchase Price
Proved oil and gas properties	12,362
Unproved oil and gas properties	8,566
Total fair value of oil and gas properties acquired	20,928
Working capital	(9)
Asset retirement obligations	(3,415)
Fair value of net assets acquired	17,504
Working capital acquired was estimated as follows:
Production taxes payable	(9)
Total working capital	$ (9)
August 2016 Acquisition | Acquisition transaction expense
Acquisitions
Acquisition transaction expenses		$ 100

Acquisitions - March 2015 Acqui

Acquisitions - March 2015 Acquisition (Details) a in Thousands	Mar. 10, 2015USD ($)a	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Acquisitions
Acquisition transaction expenses		$ 0	$ 2,719,000	$ 6,000,000
March 2015 Acquisition
Acquisitions
Acres acquired | a	39
Revenue contributed since acquisition	$ 120,500,000			8,000,000
Finder's fee accrued	6,000,000
Consideration given
Cash	120,524,000
Total consideration given	120,524,000
Allocation of Purchase Price
Proved oil and gas properties	80,952,000
Unproved oil and gas properties	69,450,000
Total fair value of oil and gas properties acquired	150,402,000
Working capital	(1,996,000)
Asset retirement obligations	(27,882,000)
Fair value of net assets acquired	120,524,000
Working capital acquired was estimated as follows:
Accounts receivable	462,000
Revenue payable	(718,000)
Production taxes payable	(1,740,000)
Total working capital	(1,996,000)
March 2015 Acquisition | General and administrative expense
Acquisitions
Acquisition transaction expenses		$ 0		$ 500,000
March 2015 Acquisition | Acquisition transaction expense
Acquisitions
Acquisition transaction expenses	$ 6,000,000

Acquisitions - Pro Forma Inform

Acquisitions - Pro Forma Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pro Forma Financial Information
Depletion, depreciation, amortization and accretion	$ 314,999,000	$ 205,348,000	$ 146,547,000
Acquisition transaction expenses	0	2,719,000	6,000,000
Income tax benefit	(63,700,000)	(29,280,000)	0
Amortization of debt issuance costs and debt discount	4,260,000	19,088,000	5,604,000
Revenues	606,460,000	325,355,000	214,259,000
Net income (loss)	$ (44,231,000)	$ (441,571,000)	(33,524,000)
Loss per share - Basic and diluted (in dollars per unit)	$ (0.35)	$ (1.54)
Adjustment to Depletion, Depreciation, Amortization and Accretion Expense
Pro Forma Financial Information
Depletion, depreciation, amortization and accretion	$ 1,600,000	$ 23,100,000	1,500,000
Adjustment for acquisition transaction expenses
Pro Forma Financial Information
Acquisition transaction expenses		2,600,000	6,400,000
Adjustment for effect of income taxes
Pro Forma Financial Information
Income tax benefit	600,000	0	0
Adjustment for the amortization of debt issuance and debt discount costs
Pro Forma Financial Information
Amortization of debt issuance costs and debt discount	0	0
Adjustment for interest expense
Pro Forma Financial Information
Incremental interest expense on acquisition financing		4,000,000	4,000,000
October 2016 Acquisition
Pro Forma Financial Information
Funding provided through issuance of convertible preferred securities and borrowings under revolving credit facility	260,300,000
Acquisition transaction expenses	$ 0	$ 2,600,000	$ 0

Long Term Debt - Components (De

Long Term Debt - Components (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Debt Instruments [Abstract]
Total long-term debt	$ 1,023,361	$ 538,141
Credit facility due November 29, 2018
Debt Instruments [Abstract]
Debt outstanding	90,000	0
2021 Senior Notes due July 15, 2021
Debt Instruments [Abstract]
Debt outstanding	550,000	550,000
2024 Senior Notes due May 15, 2024
Debt Instruments [Abstract]
Debt outstanding	400,000	0
Unamortized debt issuance costs on Senior Notes
Debt Instruments [Abstract]
Unamortized debt issuance costs on Senior Notes	$ (16,639)	$ (11,859)

Long Term Debt - Credit Facilit

Long Term Debt - Credit Facility (Details)	12 Months Ended
	Dec. 31, 2017USD ($)factorvariable_ratefiscal_quarter	Feb. 27, 2018USD ($)	Jan. 31, 2018USD ($)	Aug. 31, 2017USD ($)	Mar. 13, 2017USD ($)	Dec. 31, 2016USD ($)
Debt Instruments [Abstract]
Line of credit, amount outstanding	$ 90,000,000					$ 0
Second Lien Notes due May 29, 2019 | Interest Expense
Debt Instruments [Abstract]
Total commitments				$ 1,500,000,000
Credit facility due November 29, 2018
Debt Instruments [Abstract]
Borrowing base	525,000,000
Line of credit, amount outstanding	90,000,000				$ 0	0
Undrawn balance under credit facility	$ 435,000,000
Number of variable rates available | variable_rate	2
Variable interest rate terms and debt covenant ratios
Number of quarters used for calculation of Net Debt to EBITDAX | fiscal_quarter	4
Period used for calculation of Net debt to EBITDAX ratio	9 months
Credit facility due November 29, 2018 | Subsequent Event
Debt Instruments [Abstract]
Borrowing base			$ 650,000,000
Line of credit, amount outstanding		$ 50,000,000
Borrowing base			$ 750,000,000
Credit facility due November 29, 2018 | Minimum
Variable interest rate terms and debt covenant ratios
Commitment fee, percent	0.375%
Debt Covenant, Current ratio	1
Credit facility due November 29, 2018 | Maximum
Variable interest rate terms and debt covenant ratios
Commitment fee, percent	0.50%
Hedging limit percentage	85.00%
Debt Covenant, Net Debt to EBITDAX ratio	4
Credit facility due November 29, 2018 | Borrowing Base, Utilization Level 1
Variable interest rate terms and debt covenant ratios
Commitment fee, percent	0.375%
Borrowing base utilization percentage, maximum	25.00%
Credit facility due November 29, 2018 | Borrowing Base, Utilization Level 2
Variable interest rate terms and debt covenant ratios
Commitment fee, percent	0.375%
Borrowing base utilization percentage, minimum	25.00%
Borrowing base utilization percentage, maximum	50.00%
Credit facility due November 29, 2018 | Borrowing Base, Utilization Level 3
Variable interest rate terms and debt covenant ratios
Commitment fee, percent	0.50%
Borrowing base utilization percentage, minimum	50.00%
Borrowing base utilization percentage, maximum	75.00%
Credit facility due November 29, 2018 | Borrowing Base, Utilization Level 4
Variable interest rate terms and debt covenant ratios
Commitment fee, percent	0.50%
Borrowing base utilization percentage, minimum	75.00%
Borrowing base utilization percentage, maximum	90.00%
Credit facility due November 29, 2018 | Borrowing Base, Utilization Level 5
Variable interest rate terms and debt covenant ratios
Commitment fee, percent	0.50%
Borrowing base utilization percentage, minimum	90.00%
Credit facility due November 29, 2018 | LIBOR | Borrowing Base, Utilization Level 1
Variable interest rate terms and debt covenant ratios
Margin rate, percent	2.00%
Credit facility due November 29, 2018 | LIBOR | Borrowing Base, Utilization Level 2
Variable interest rate terms and debt covenant ratios
Margin rate, percent	2.25%
Credit facility due November 29, 2018 | LIBOR | Borrowing Base, Utilization Level 3
Variable interest rate terms and debt covenant ratios
Margin rate, percent	2.50%
Credit facility due November 29, 2018 | LIBOR | Borrowing Base, Utilization Level 4
Variable interest rate terms and debt covenant ratios
Margin rate, percent	2.75%
Credit facility due November 29, 2018 | LIBOR | Borrowing Base, Utilization Level 5
Variable interest rate terms and debt covenant ratios
Margin rate, percent	3.00%
Credit facility due November 29, 2018 | Base Rate | Borrowing Base, Utilization Level 1
Variable interest rate terms and debt covenant ratios
Margin rate, percent	1.00%
Credit facility due November 29, 2018 | Base Rate | Borrowing Base, Utilization Level 2
Variable interest rate terms and debt covenant ratios
Margin rate, percent	1.25%
Credit facility due November 29, 2018 | Base Rate | Borrowing Base, Utilization Level 3
Variable interest rate terms and debt covenant ratios
Margin rate, percent	1.50%
Credit facility due November 29, 2018 | Base Rate | Borrowing Base, Utilization Level 4
Variable interest rate terms and debt covenant ratios
Margin rate, percent	1.75%
Credit facility due November 29, 2018 | Base Rate | Borrowing Base, Utilization Level 5
Variable interest rate terms and debt covenant ratios
Margin rate, percent	2.00%
Credit facility due November 29, 2018 | Quarter ending March 31, 2018
Variable interest rate terms and debt covenant ratios
Annualized EBITDAX multiplier | factor	1.3333
Credit facility due November 29, 2018 | Standby Letters of Credit
Debt Instruments [Abstract]
Letters of credit outstanding	$ 25,700,000					$ 600,000

Long Term Debt - 2021 Senior No

Long Term Debt - 2021 Senior Notes (Details) - 2021 Senior Notes due July 15, 2021 - USD ($)	Feb. 17, 2018	Jan. 25, 2018	Jan. 24, 2018	Jul. 31, 2016	Dec. 31, 2017	Dec. 31, 2016
Debt Instruments [Abstract]
Face amount of debt				$ 550,000,000
Interest rate percentage				7.875%
Proceeds from debt, net of discounts and issuance costs				$ 537,200,000
Debt outstanding					$ 550,000,000	$ 550,000,000
Immediate Due and Payable clause, percentage of holdings					25.00%
Subsequent Event
Debt Instruments [Abstract]
Aggregate principal amount received	$ 49,400,000		$ 500,600,000
Cash payment	52,700,000	$ 534,200,000
Cash payment of principal		500,600,000
Make-whole premium	3,000,000	32,600,000
Accrued and unpaid interest	$ 300,000	$ 1,000,000

Long Term Debt Long Term Debt -

Long Term Debt Long Term Debt - 2024 Senior Notes (Details) - 2024 Senior Notes due May 15, 2024 - USD ($)	1 Months Ended	12 Months Ended
	Aug. 31, 2017	Dec. 31, 2017
Debt Instruments [Abstract]
Face amount of debt	$ 400,000,000
Interest rate percentage	7.375%
Proceeds from debt, net of discounts and issuance costs	$ 392,600,000
Immediate Due and Payable clause, percentage of holdings		25.00%

Long Term Debt - 2026 Senior No

Long Term Debt - 2026 Senior Notes (Details) - USD ($) $ in Thousands	Feb. 17, 2018	Jan. 25, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jul. 31, 2016
Debt Instrument [Line Items]
Proceeds from the issuance of Senior Notes			$ 394,000	$ 550,000	$ 0
Senior Notes due 2026
Debt Instrument [Line Items]
Immediate Due and Payable clause, percentage of holdings			25.00%
Senior Notes due 2026 | Subsequent Event
Debt Instrument [Line Items]
Proceeds from the issuance of Senior Notes		$ 737,900
Interest rate percentage		5.625%
2021 Senior Notes due July 15, 2021
Debt Instrument [Line Items]
Interest rate percentage						7.875%
Immediate Due and Payable clause, percentage of holdings			25.00%
2021 Senior Notes due July 15, 2021 | Subsequent Event
Debt Instrument [Line Items]
Cash payment	$ 52,700	$ 534,200

Long Term Debt - Second Lien No

Long Term Debt - Second Lien Notes (Details) - USD ($)	May 29, 2014	Jul. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instruments [Abstract]
Payments to extinguish debt			$ 0	$ 430,000,000	$ 0
Cash paid for Second Lien Notes prepayment penalty			0	4,300,000	0
Write-off of unamortized debt discount and debt issuance costs			4,260,000	19,088,000	5,604,000
Second Lien Notes due May 29, 2019
Debt Disclosure [Abstract]
Debt issuance costs			0	0
Debt Instruments [Abstract]
Debt outstanding					$ 430,000,000
Payments to extinguish debt		$ 430,000,000
Second Lien Notes due May 29, 2019 | Interest Expense
Debt Disclosure [Abstract]
Debt issuance costs			$ 16,600,000
Debt Instruments [Abstract]
Cash paid for Second Lien Notes prepayment penalty		$ 4,300,000
Write-off of unamortized debt discount and debt issuance costs				$ 15,100,000
Holdings | Second Lien Notes due May 29, 2019
Debt Instruments [Abstract]
Term of debt instrument (in years)	5 years
Face amount of debt	$ 430,000,000
Debt outstanding	$ 430,000,000
Interest rate percentage	10.70%

Long Term Debt - Debt Discount,

Long Term Debt - Debt Discount, Issuance Costs, Interest (Details) - USD ($)	1 Months Ended	12 Months Ended
	Jul. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	May 29, 2014
Debt Instruments [Abstract]
Amortization of debt issuance costs		$ 4,300,000	$ 14,400,000	$ 3,100,000
Interest Incurred On Long Term Debt
Interest expense		58,700,000	50,500,000	50,500,000
Interest costs capitalized		11,100,000	5,200,000	5,300,000
Cash paid for Second Lien Notes prepayment penalty		0	4,300,000	0
Credit facility due November 29, 2018 | Other non-current assets
Debt Instruments [Abstract]
Accumulated amortization, debt issuance costs		3,800,000	2,200,000
2021 Senior Notes due July 15, 2021
Debt Instruments [Abstract]
Debt issuance costs			11,900,000
Second Lien Notes due May 29, 2019
Debt Instruments [Abstract]
Unamortized debt discount		0		$ 6,500,000	$ 6,500,000
Debt issuance costs		0	$ 0
Second Lien Notes due May 29, 2019 | Interest Expense
Debt Instruments [Abstract]
Amortization of debt discount	$ 4,300,000
Debt issuance costs		$ 16,600,000
Amortization of debt issuance costs	10,800,000
Interest Incurred On Long Term Debt
Cash paid for Second Lien Notes prepayment penalty	$ 4,300,000

Commodity Derivative Instrume64

Commodity Derivative Instruments - Summary of Contracts (Details)	12 Months Ended
	Dec. 31, 2017USD ($)MMBTUcounterparty$ / bbl$ / MMBTUbbl
Commodity derivative contracts
Number of counterparties | counterparty	7
Number of counterparties, terminated by default | counterparty	1
Derivative instruments in a net liability position with credit-risk-related contingent features | $	$ 0
Crude | Swaps, 2018
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	5,100,000
Weighted average fixed price, Swaps (in dollars per unit) | $ / bbl	51.61
Crude | Swap, 2019
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	0
Weighted average fixed price, Swaps (in dollars per unit) | $ / bbl	0
Crude | Calls, 2018 | Sold
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	8,290,000
Weighted average fixed price, Calls (in $/BBl or $/MMBtu) | $ / bbl	56.18
Crude | Calls, 2019 | Sold
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	5,100,000
Weighted average fixed price, Calls (in $/BBl or $/MMBtu) | $ / bbl	55.93
Crude | Puts, 2018 | Sold
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	13,438,800
Weighted average fixed price, Puts (in dollars per barrel) | $ / bbl	39.10
Crude | Puts, 2018 | Purchased
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	12,327,600
Weighted average put price (in $/Bbl or $/MMBtu) | $ / bbl	44.81
Crude | Puts, 2019 | Sold
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	5,100,000
Weighted average fixed price, Puts (in dollars per barrel) | $ / bbl	39.82
Crude | Puts, 2019 | Purchased
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	5,100,000
Weighted average put price (in $/Bbl or $/MMBtu) | $ / bbl	49.69
Natural Gas | Swaps, 2018
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	40,800,000
Weighted average fixed price, Swaps (in dollars per unit) | $ / MMBTU	3.10
Natural Gas | Swap, 2019
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	0
Weighted average fixed price, Swaps (in dollars per unit) | $ / MMBTU	0
Natural Gas | Calls, 2018 | Sold
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	2,400,000
Weighted average fixed price, Calls (in $/BBl or $/MMBtu) | $ / MMBTU	3.15
Natural Gas | Calls, 2019 | Sold
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	0
Weighted average fixed price, Calls (in $/BBl or $/MMBtu) | $ / MMBTU	0
Natural Gas | Puts, 2018 | Purchased
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	2,400,000
Weighted average put price (in $/Bbl or $/MMBtu) | $ / MMBTU	3
Natural Gas | Puts, 2019 | Purchased
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	0
Weighted average put price (in $/Bbl or $/MMBtu) | $ / MMBTU	0
Natural Gas | Basis Swaps, 2018
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	6,300,000
Weighted average fixed price ($/MMBtu) | $ / MMBTU	(0.31)
Natural Gas | Basis Swaps, 2019
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	0
Weighted average fixed price ($/MMBtu) | $ / MMBTU	0

Commodity Derivative Instrume65

Commodity Derivative Instruments - Gross and Net Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Gross amounts and adjustments made for net derivative liabilities
Net Amounts	$ (84,702)	$ (62,741)
Current assets
Gross amounts and adjustments made for net derivative assets
Gross Amounts of Recognized Assets	22,118	12,620
Gross Amounts Offset in the Balance Sheet	(17,986)	(12,620)
Net Amounts of Assets Presented in the Balance Sheet	4,132	0
Net Amounts	4,132	0
Non-current assets
Gross amounts and adjustments made for net derivative assets
Gross Amounts of Recognized Assets	13,686	14,993
Gross Amounts Offset in the Balance Sheet	(13,686)	(14,993)
Net Amounts of Assets Presented in the Balance Sheet	0	0
Current liabilities
Gross amounts and adjustments made for net derivative liabilities
Gross Amounts of Recognized Liabilities	(85,414)	(68,623)
Gross Amounts Offset in the Balance Sheet	17,986	12,620
Net Amounts of Liabilities Presented in the Balance Sheet	(67,428)	(56,003)
Non-current liabilities
Gross amounts and adjustments made for net derivative liabilities
Gross Amounts of Recognized Liabilities	(30,960)	(21,731)
Gross Amounts Offset in the Balance Sheet	13,686	14,993
Net Amounts of Liabilities Presented in the Balance Sheet	$ (17,274)	$ (6,738)

Commodity Derivative Instrume66

Commodity Derivative Instruments - Gain (Loss) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other income (expense)
Income (loss) on derivatives
Commodity derivatives gain (loss)	$ (36,332)	$ (100,947)	$ 79,932

Asset Retirement Obligations -

Asset Retirement Obligations - Summary (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset retirement obligations
Balance beginning of period	$ 56,108	$ 44,367
Liabilities incurred or acquired	9,802	8,945
Liabilities settled	(4,169)	(1,155)
Revisions in estimated cash flows	2,630	(1,695)
Accretion expense	5,169	5,646
Balance end of period	$ 69,540	$ 56,108

Fair Value Measurements - Recur

Fair Value Measurements - Recurring Basis (Details) - Recurring - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Financial Assets:
Commodity derivative assets	$ 4,132	$ 0
Financial Liabilities:
Commodity derivative liabilities	84,702	62,741
Level 1
Financial Assets:
Commodity derivative assets	0	0
Financial Liabilities:
Commodity derivative liabilities	0	0
Level 2
Financial Assets:
Commodity derivative assets	4,132	0
Financial Liabilities:
Commodity derivative liabilities	84,702	62,741
Level 3
Financial Assets:
Commodity derivative assets	0	0
Financial Liabilities:
Commodity derivative liabilities	$ 0	$ 0

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Carrying Amount | Credit facility due November 29, 2018
Fair Value of Financial Instruments
Long-term debt	$ 90,000	$ 0
Carrying Amount | 2021 Senior Notes due July 15, 2021
Fair Value of Financial Instruments
Long-term debt	540,382	538,141
Unamortized debt discount and debt issuance costs	9,600	11,900
Carrying Amount | 2024 Senior Notes due May 15, 2024
Fair Value of Financial Instruments
Long-term debt	392,979	0
Unamortized debt discount and debt issuance costs	7,000
Fair value | Credit facility due November 29, 2018
Fair Value of Financial Instruments
Long-term debt	90,000	0
Fair value | 2021 Senior Notes due July 15, 2021
Fair Value of Financial Instruments
Long-term debt	583,000	588,500
Fair value | 2024 Senior Notes due May 15, 2024
Fair Value of Financial Instruments
Long-term debt	$ 427,000	$ 0

Fair Value Measurements - Nonre

Fair Value Measurements - Nonrecurring (Details) - USD ($)	1 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Non Recurring Fair Value Measurements
Proved oil and gas properties		$ 3,011,526,000	$ 1,851,052,000
Sale of property and equipment	$ 4,700,000	5,155,000	2,656,000	$ 4,742,000
Northern Field
Non Recurring Fair Value Measurements
Proved oil and gas properties		0
Impairment of long-lived assets
Non Recurring Fair Value Measurements
Impairment of proved properties	$ 2,700,000			12,200,000
Impairment of long-lived assets | Northern Field
Non Recurring Fair Value Measurements
Impairment of proved properties		$ 0	$ 22,500,000	$ 9,500,000

Equity - Private Offering (Deta

Equity - Private Offering (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	Dec. 15, 2016	Dec. 31, 2016	Dec. 31, 2016
Private Placement
Initial Public Offering
Proceeds from issuance of stock, gross		$ 457
Common Stock
Initial Public Offering
Shares issued (in shares)			38,333
Common Stock | Private Placement
Initial Public Offering
Shares issued (in shares)	25,000
Price per share (in dollars per share)	$ 18.25
Proceeds from issuance of stock, gross	$ 457
Proceeds from offering, net	$ 441.9

Equity - Initial Public Offerin

Equity - Initial Public Offering (Details) - USD ($) $ / shares in Units, $ in Thousands	Oct. 17, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Initial Public Offering
Par value per share (in dollars per share)		$ 0.01
Offering costs		$ 1,668	$ 64,554	$ 5,706
Redemption price, including premium		65,607	8,429
Repayments under credit facility		$ 475,000	$ 488,000	$ 0
IPO | Credit facility due November 29, 2018
Initial Public Offering
Repayments under credit facility	$ 291,600
IPO | Series A Preferred Units
Initial Public Offering
Redemption price, including premium	$ 90,000
Common Stock
Initial Public Offering
Shares issued (in shares)			38,333,000
Common Stock | IPO
Initial Public Offering
Shares issued (in shares)	38,300,000
Par value per share (in dollars per share)	$ 0.01
Price per share (in dollars per share)	$ 19
Proceeds from offering, net of discounts, commissions and offering expenses	$ 681,000
Offering costs	$ 47,300
Common Stock | Over-Allotment Option
Initial Public Offering
Shares issued (in shares)	5,000,000

Equity - Series A Preferred Uni

Equity - Series A Preferred Units, Series A Preferred Stock and Series B Preferred Units (Details) - USD ($) $ / shares in Units, $ in Thousands	Oct. 17, 2016	Oct. 03, 2016	Oct. 31, 2016	Dec. 31, 2017	Dec. 31, 2016
Subsidiary, Sale of Stock [Line Items]
Issuance of stock					$ 728,333
Redemption premium paid				$ 10,885	15,000
Series A Convertible Preferred Stock
Subsidiary, Sale of Stock [Line Items]
Dividend rate (as a percent)			5.875%
Increase in dividends payable				$ 2,700
Dividends payable (usd per share)				$ 14.69
Conversion ratio during lock-up period			61.9195
Conversion period			3 years
Conversion ratio, after lock-up period and before third anniversary			61.9195
Redemption price as a percent of liquidation preference			135.00%
Annualized internal rate of return (as a percent)			17.50%
Minimum | Series A Convertible Preferred Stock
Subsidiary, Sale of Stock [Line Items]
Lock up period after close of offering (in days)			90 days
Maximum | Series A Convertible Preferred Stock
Subsidiary, Sale of Stock [Line Items]
Percentage of quarterly dividend that may be paid in kind			10.00%
Lock up period after close of offering (in days)		120 days
Additional Paid in Capital
Subsidiary, Sale of Stock [Line Items]
Issuance of stock					727,950
Redemption premium paid				$ 10,885	15,000
Series A Preferred Units
Subsidiary, Sale of Stock [Line Items]
Issuance of stock		$ 75,000
Dividend rate (as a percent)		10.00%
Redemption of Series A Preferred Units	$ 90,000
Series A Preferred Units | Additional Paid in Capital
Subsidiary, Sale of Stock [Line Items]
Redemption premium paid	$ 15,000
Series B Preferred Units
Subsidiary, Sale of Stock [Line Items]
Issuance of stock		$ 185,300		$ 185,300
Dividend rate (as a percent)		10.00%
Dividends paid					$ 700
Series B Preferred Units | Series A Convertible Preferred Stock | IPO
Subsidiary, Sale of Stock [Line Items]
Number of shares received in conversion		185,280
Series B Preferred Units | Maximum
Subsidiary, Sale of Stock [Line Items]
Percentage of quarterly dividend that may be paid in kind		50.00%

Income Taxes - Components (Deta

Income Taxes - Components (Details) - USD ($) $ in Thousands	Dec. 22, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income tax benefit recorded related to the remeasurement of the net	$ 23,400
Provisional deferred tax liability		$ 13,000
Stock-based compensation		13,853	$ 2,824
Net deferred tax liability due to corporate reorganization		135,300	135,306
Current:
Federal		0	0
State, net of federal benefit		0	0
Total current income tax benefit		0	0
Deferred:
Federal		(61,719)	(26,962)
State, net of federal benefit		(1,981)	(2,318)
Total deferred income tax benefit		(63,700)	(29,280)
Income tax benefit		$ (63,700)	$ (29,280)	$ 0

Income Taxes - Effective Tax Ra

Income Taxes - Effective Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	3 Months Ended									12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reconciliation of income tax expense (benefit) with income tax expense at the federal statutory rate
Loss before income taxes										$ (108,108)	$ (485,281)	$ (47,264)
Federal income taxes at statutory rate										(37,838)	(169,849)
Net loss prior to Corporate Reorganization										0	80,463
State income taxes, net of federal benefit										(3,118)	(2,318)
Nondeductible stock-based compensation										2,264	62,284
Enactment of the Tax Cuts and Jobs Act										(23,412)	0
Other										(1,596)	140
Income tax benefit										(63,700)	(29,280)	0
Net Loss	$ (30,568)	$ (29,796)	$ 7,240	$ 8,716	$ (245,601)	$ (226,107)	$ (37,267)	$ (127,614)	$ (45,519)	$ (44,408)	$ (456,001)	$ (47,264)

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Deferred Tax Assets:
Net operating loss carryforward	$ 205,806	$ 35,719
Commodity derivatives	19,984	24,068
Stock-based compensation	13,853	2,824
Other	17,053	14,309
Total deferred tax assets	256,696	76,920
Deferred Tax Liabilities:
Excess basis of oil and gas properties	(299,022)	(182,946)
Total deferred tax liabilities	(299,022)	(182,946)
Deferred Tax Liability, net	$ (42,326)	$ (106,026)

Income Taxes - NOL Carryforward

Income Taxes - NOL Carryforward (Details) $ in Millions	Dec. 31, 2017USD ($)
U.S.
NOL Carryforwards
Net operating loss carryforwards (NOLs)	$ 834.7

Income Taxes - Uncertain Tax Po

Income Taxes - Uncertain Tax Positions (Details)	Dec. 31, 2017USD ($)
Income Tax Disclosure [Abstract]
Liability fo uncertain tax positions	$ 0
Provision for interest or penalties related to uncertain tax positions	$ 0

Unit and Stock-Based Compensa79

Unit and Stock-Based Compensation - Long Term Incentive Plan (Details) shares in Millions	Oct. 31, 2016shares
2016 Long Term Incentive Plan
Share-based compensation
Shares reserved for issuance	20.2

Unit and Stock-Based Compensa80

Unit and Stock-Based Compensation - Long Term Incentive Plan RSUs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Vesting Year One | RSUs - One Year Vesting
Incentive Units
Service period, in years	1 year
Vesting percentage	100.00%
Vesting Year One | RSUs - Three Year Vesting
Incentive Units
Service period, in years	3 years
Vesting percentage	25.00%
Vesting period, in years	1 year
Vesting Year Two | RSUs - Three Year Vesting
Incentive Units
Vesting percentage	25.00%
Vesting period, in years	2 years
Vesting Year Three | RSUs - Three Year Vesting
Incentive Units
Vesting percentage	50.00%
Vesting period, in years	3 years
2016 Long Term Incentive Plan | RSUs
Compensation costs
Share-based compensation expense	$ 31.8	$ 5.5	$ 0
Unrecognized compensation cost	$ 45.7
Weighted-average period for recognition, unvested awards	2 years

Unit and Stock-Based Compensa81

Unit and Stock-Based Compensation - Long Term Incentive Plan RSUs Rollforward (Details) - 2016 Long Term Incentive Plan - RSUs - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Number of Shares
Non-vested units at beginning of period (in shares)	3,237,500	0
Granted (in shares)	1,369,083	3,237,500
Forfeited (in shares)	(445,366)	0
Vested (in shares)	(1,254,744)	0
Non-vested units at end of period (in shares)	2,906,473	3,237,500
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per share)	$ 21.41	$ 0
Granted (in dollars per share)	16.37	21.41
Forfeited (in dollars per share)	19.85	0
Vested (in dollars per share)	20.85	0
Non-vested units at end of period (in dollars per share)	$ 19.51	$ 21.41

Unit and Stock-Based Compensa82

Unit and Stock-Based Compensation - Long Term Incentive Plan Options (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Weighted average grant date fair value
Weighted average per share (in dollars per share)	$ 15.53	$ 19
Total options granted (in shares)	744,428	4,500,000
2016 Long Term Incentive Plan | Stock Options
Compensation costs
Forfeiture rate (as a percent)	0.00%
Share-based compensation expense	$ 15,700	$ 2,900	$ 0
Unrecognized compensation costs	$ 27,200
Weighted-average period for recognition, unvested awards	1 year 9 months 18 days
Assumptions used for the Black-Scholes valuation model
Vesting period, in years	3 years
Risk free rates (as a percent)	2.00%	1.40%
Dividend yield (as a percent)	0.00%	0.00%
Expected volatility (as a percent)	58.90%	47.20%
Expected life (in years)	6 years	6 years
Weighted average grant date fair value
Weighted average per share (in dollars per share)	$ 8.66	$ 8.75
Total options granted (in shares)	744,428	4,500,000
Total weighted average fair value of shares granted (in thousands)	$ 6,445	$ 39,375

Unit and Stock-Based Compensa83

Unit and Stock-Based Compensation - Long Term Incentive Plan Options Rollforward (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Number of Shares
Non-vested Stock Options at beginning of period (in shares)	4,500,000	0
Granted (in shares)	744,428	4,500,000
Forfeited (in shares)	0	0
Vested (in shares)	(1,748,138)	0
Non-vested Stock Options at end of period (in shares)	3,496,290	4,500,000
Weighted Average Exercise Price (in dollars per share)
Non-vested options at beginning of period (in dollars per share)	$ 19	$ 0
Granted (in dollars per share)	15.53	19
Forfeited (in dollars per share)	0	0
Vested (in dollars per share)	18.52	0
Non-vested options at end of period (in dollars per share)	$ 18.50	$ 19

Unit and Stock-Based Compensa84

Unit and Stock-Based Compensation - Issued and Outstanding Plan Options (Details) - $ / shares	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016
Share-based compensation
Non-vested Stock Options at beginning of period (in shares)		4,500,000	0
Total options granted (in shares)		744,428	4,500,000
Non-vested Stock Options at end of period (in shares)	3,496,290	3,496,290	4,500,000
Non-vested options at beginning of period (in dollars per share)		$ 19	$ 0
Granted (in dollars per share)		15.53	19
Non-vested options at end of period (in dollars per share)	$ 18.50	$ 18.50	$ 19
2016 Long Term Incentive Plan
Share-based compensation
Weighted-Average Remaining Contractual Life at beginning of period (in years)	9 years
Weighted-Average Remaining Contractual Life at end of period (in years)	9 years
2016 Long Term Incentive Plan | Stock Options
Share-based compensation
Non-vested Stock Options at beginning of period (in shares)		4,500,000
Total options granted (in shares)		744,428
Non-vested Stock Options at end of period (in shares)	5,244,428	5,244,428	4,500,000
Weighted-Average Remaining Contractual Life at beginning of period (in years)			8 years 10 months 24 days
Weighted-Average Remaining Contractual Life in period (in years)		9 years 9 months 18 days
Weighted-Average Remaining Contractual Life at end of period (in years)			8 years 10 months 24 days
Non-vested options at beginning of period (in dollars per share)		$ 19
Granted (in dollars per share)		15.53
Non-vested options at end of period (in dollars per share)	$ 18.50	$ 18.50	$ 19
Non-vested Stock Options, exercisable, at beginning of period (in shares)		1,500,000
Options exercisable in period (in shares)		248,138
Non-vested Stock Options, exercisable, at end of period (in shares)	1,748,138	1,748,138	1,500,000
Options exercisable at beginning of period (in dollars per share)		$ 19
Options exercisable in period (in dollars per share)		15.53
Options exercisable at end of period (in dollars per share)	$ 18.52	$ 18.52	$ 19

Unit and Stock-Based Compensa85

Unit and Stock-Based Compensation - Performance Stock Awards (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based compensation
Unit-based compensation	$ 65,607	$ 200,308	$ 5,970
Performance Stock Awards
Share-based compensation
Risk free rates (as a percent)	1.50%
Dividend yield (as a percent)	0.00%
Expected volatility (as a percent)	45.00%
Unit-based compensation	$ 800
Unrecognized compensation cost	$ 6,600
Weighted-average period for recognition, unvested awards	2 years

Unit and Stock-Based Compensa86

Unit and Stock-Based Compensation - Performance Stock Awards Rollforward (Details) - Performance Stock Awards	12 Months Ended
	Dec. 31, 2017$ / sharesshares
Number of Shares
Non-vested units at beginning of period (in shares) | shares	0
Granted (in shares) | shares	832,163
Forfeited (in shares) | shares	0
Vested (in shares) | shares	0
Non-vested units at end of period (in shares) | shares	832,163
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per share) | $ / shares	$ 0
Granted (in dollars per share) | $ / shares	8.85
Forfeited (in dollars per share) | $ / shares	0
Vested (in dollars per share) | $ / shares	0
Non-vested units at end of period (in dollars per share) | $ / shares	$ 8.85

Unit and Stock-Based Compensa87

Unit and Stock-Based Compensation - Incentive Restricted Stock Units (Details) - USD ($) shares in Millions	Jul. 17, 2017	Nov. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Compensation costs
Unit-based compensation			$ 65,607,000	$ 200,308,000	$ 5,970,000
Common Stock | Management | Employee Incentive
Incentive Units
Shares contributed to Extraction Employee Incentive, LLC		2.7
Employee Incentive RSUs
Incentive Units
Forfeiture rate (as a percent)	0.00%
Compensation costs
Unrecognized compensation cost			$ 21,300,000
Weighted-average period for recognition, unvested awards			1 year
Employee Incentive RSUs | General and administrative expense
Compensation costs
Unit-based compensation			$ 17,300,000	2,400,000	0
Employee Incentive RSUs | Vesting Year One
Incentive Units
Vesting percentage	25.00%	25.00%
Employee Incentive RSUs | Vesting Year Two
Incentive Units
Vesting percentage	25.00%	25.00%
Employee Incentive RSUs | Vesting Year Three
Incentive Units
Vesting percentage	25.00%	50.00%
Employee Incentive RSUs | Vesting Year Four
Incentive Units
Vesting percentage	25.00%
Employee Incentive RSUs | Management
Incentive Units
Vesting period, in years	18 months	3 years
2014 Membership Unit Incentive Plan (“2014 Plan”) | Holdings Incentive Units | Management
Incentive Units
Vesting period, in years			3 years
Compensation costs
Unit-based compensation				0	0
2014 Membership Unit Incentive Plan (“2014 Plan”) | Holdings Incentive Units | Management | Vesting Year One
Incentive Units
Vesting percentage			25.00%
2014 Membership Unit Incentive Plan (“2014 Plan”) | Holdings Incentive Units | Management | Vesting Year Two
Incentive Units
Vesting percentage			25.00%
2014 Membership Unit Incentive Plan (“2014 Plan”) | Holdings Incentive Units | Management | Vesting Year Three
Incentive Units
Vesting percentage			50.00%
2014 Membership Unit Incentive Plan (“2014 Plan”) | Holdings Incentive Units | Common Stock | Management
Incentive Units
Accelerated vesting (in units)		9.1
Compensation costs
Unit-based compensation				$ 172,100,000	$ 0

Unit and Stock-Based Compensa88

Unit and Stock-Based Compensation - Incentive Restricted Stock Units Rollforward (Details) - Employee Incentive RSUs - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Number of Shares
Non-vested units at beginning of period (in shares)	2,714,368	0
Granted (in shares)	0	2,717,968
Forfeited (in shares)	(710,993)	(3,600)
Vested (in shares)	(507,200)	0
Non-vested units at end of period (in shares)	1,496,175	2,714,368
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per share)	$ 20.45	$ 0
Granted (in dollars per share)	0	20.45
Forfeited (in dollars per share)	20.45	20.45
Vested (in dollars per share)	20.45	0
Non-vested units at end of period (in dollars per share)	$ 20.45	$ 20.45

Unit and Stock-Based Compensa89

Unit and Stock-Based Compensation - Holdings' RUAs (Details) - 2014 Membership Unit Incentive Plan (“2014 Plan”) - Holdings' RUAs - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Holdings' RUA's
Vesting period, in years	3 years
Units vested		7,660,967	3,197,638
Compensation costs
Unit-based compensation costs	$ 0	$ 16.8	$ 5.3
Tax benefit recognized related to unit based compensation	$ 0	$ 0	$ 0
Vesting Year One
Holdings' RUA's
Vesting percentage	25.00%
Vesting Year Two
Holdings' RUA's
Vesting percentage	25.00%
Vesting Year Three
Holdings' RUA's
Vesting percentage	50.00%

Unit and Stock-Based Compensa90

Unit and Stock-Based Compensation - Holdings' RUAs - Rollforward (Details) - 2014 Membership Unit Incentive Plan (“2014 Plan”) - Holdings' RUAs - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Number of Shares
Non-vested units at beginning of period (in shares)	6,311,242	9,365,896
Granted (in shares)	1,531,542	196,047
Forfeited (in shares)	(181,817)	(53,063)
Vested (in shares)	(7,660,967)	(3,197,638)
Non-vested units at end of period (in shares)	0	6,311,242
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per share)	$ 2.23	$ 2.22
Granted (in dollars per share)	5.84	2.68
Forfeited (in dollars per share)	2.68	2.21
Vested (in dollars per share)	2.94	2.22
Non-vested units at end of period (in dollars per share)	$ 0	$ 2.23

Unit and Stock-Based Compensa91

Unit and Stock-Based Compensation - PRL RUAs (Details) - PRL RUAs - USD ($) $ in Millions	12 Months Ended			31 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016
General and administrative expense
Compensation costs
Unit-based compensation costs	$ 0	$ 0.5	$ 0.8
Unrecognized compensation cost	$ 0
PRL
PRL RSUs
Vesting period, in years				3 years
PRL | Vesting Year One
PRL RSUs
Vesting percentage				25.00%
PRL | Vesting Year Two
PRL RSUs
Vesting percentage				25.00%
PRL | Vesting Year Three
PRL RSUs
Vesting percentage				50.00%

Unit and Stock-Based Compensa92

Unit and Stock-Based Compensation - Holdings' Incentive Units (Details) - USD ($) shares in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Nov. 30, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Compensation costs
Unit-based compensation			$ 65,607,000	$ 200,308,000	$ 5,970,000
2014 Membership Unit Incentive Plan (“2014 Plan”) | Management | Holdings Incentive Units
Incentive Units
Vesting period, in years			3 years
Compensation costs
Unit-based compensation				0	0
2014 Membership Unit Incentive Plan (“2014 Plan”) | Management | Holdings Incentive Units | Common Stock
Incentive Units
Accelerated vesting (in units)	9.1
Days used for determining valuation of volume weighted average stock price	10 days
Compensation costs
Unit-based compensation				$ 172,100,000	$ 0
2014 Membership Unit Incentive Plan (“2014 Plan”) | Management | Vesting Year One | Holdings Incentive Units
Incentive Units
Vesting percentage			25.00%
2014 Membership Unit Incentive Plan (“2014 Plan”) | Management | Vesting Year Two | Holdings Incentive Units
Incentive Units
Vesting percentage			25.00%
2014 Membership Unit Incentive Plan (“2014 Plan”) | Management | Vesting Year Three | Holdings Incentive Units
Incentive Units
Vesting percentage			50.00%
Holdings | 2014 Membership Unit Incentive Plan (“2014 Plan”) | Management | Holdings Incentive Units
Incentive Units
Issued (in units)		3

Earnings (Loss) Per Share - Com

Earnings (Loss) Per Share - Components (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended									12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Basic and Diluted EPS (in thousands, except per share data)
Net Loss	$ (30,568)	$ (29,796)	$ 7,240	$ 8,716	$ (245,601)	$ (226,107)	$ (37,267)	$ (127,614)	$ (45,519)	$ (44,408)	$ (456,001)	$ (47,264)
Less: Adjustment to reflect Series A Preferred Stock dividend						(2,958)				(10,885)
Less: Adjustment to reflect accretion of Series A Preferred Stock discount						(1,041)				(5,394)
Net loss attributable to common shareholders						$ (230,106)				$ (60,687)
Weighted Average Common Shares Outstanding
Basic and diluted (in shares)						149,029				171,910	149,029
Net Loss Allocated to Common Shareholders per Common Share
Basic and diluted (in dollars per share)	$ (0.20)	$ (0.20)	$ 0.02	$ 0.03	$ (1.54)	$ (1.54)				$ (0.35)	$ (1.54)

Earnings (Loss) Per Share - Ant

Earnings (Loss) Per Share - Antidilutive Securities (Details) - shares	12 Months Ended	15 Months Ended
	Dec. 31, 2017	Dec. 31, 2017
Restricted stock and stock option awards
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive securities (in shares)	8,566,983	7,737,500
Series A Convertible Preferred Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive securities (in shares)	11,472,445	11,472,445

Commitments and Contingencies -

Commitments and Contingencies - Leases (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)office	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Jun. 04, 2015USD ($)office
Office Space Leases
Future minimum lease payments
Total rental commitments under non cancelable leases	$ 35.7
2,018	3
2,019	3.5
2,020	3.4
2,021	3.4
2,022	3.3
Thereafter	19.1
Rent expense	$ 2.3	$ 1.9	$ 1.1
Denver, Colorado | Subleases
Leases
Number of office spaces under lease | office	2			1
Future minimum lease payments
Sublease rental, future lease payments				$ 0.5
Greeley, Colorado | Subleases
Leases
Number of office spaces under lease | office	2
Houston, Texas | Office Space Leases
Leases
Number of office spaces under lease | office	1

Commitments and Contingencies96

Commitments and Contingencies - Drilling Rigs (Details) $ in Millions	1 Months Ended			3 Months Ended	12 Months Ended
	Feb. 29, 2016rig	Jan. 31, 2016rig	Mar. 31, 2015USD ($)rig	Jun. 30, 2017USD ($)	Dec. 31, 2017USD ($)rig
Other Operating Expenses
Drilling Rigs
Drilling rig termination fee				$ 1
Drilling Rig Commitments
Drilling Rigs
Number of drilling rigs | rig					3
Early termination obligation					$ 8.9
Number of terminated drilling rigs | rig	1	1	1
Drilling Rig Commitments | Other Operating Expenses
Drilling Rigs
Drilling rig termination fee			$ 1.7

Commitments and Contingencies97

Commitments and Contingencies - Delivery Commitments, Acquisition of Undeveloped Leasehold Acreage and Legal Matters (Details)	Nov. 15, 2017USD ($)a	Jan. 31, 2018USD ($)a	Dec. 31, 2017USD ($)bbl / dcontractfacilityMMcf	Apr. 30, 2018USD ($)
Delivery commitments
Target profit margin guarantee, period			3 years
Payments for other commitments | $	$ 214,300,000
Net acres of undeveloped leasehold | a	36,600
Monetary penalty for compliance order | $			$ 138,600
Estimated cost for injunctive relief | $			$ 500,000
Subsequent Event
Delivery commitments
Payments for other commitments | $		$ 11,600,000
Net acres of undeveloped leasehold | a		1,200
Scenario, Forecast
Delivery commitments
Commitments | $				$ 12,200,000
Long Term Crude Oil Delivery Commitment, November 2016, Ten Year Term
Delivery commitments
Term of commitment			10 years
Delivery commitment, in barrels per day (Bpd), year one			9,167
Delivery commitment, in barrels per day (Bpd), year two			17,967
Letters of credit outstanding | $			$ 35,000,000
Delivery commitment, in barrels per day (Bpd), years three through five			18,800
Delivery commitment, in barrels per day (Bpd), years six through ten			10,000
Long Term Crude Oil Delivery Commitment, November 2016, Ten Year Term | Minimum
Delivery commitments
Delivery commitment, in barrels per day (Bpd), year one			45,000
Delivery commitment, in barrels per day (Bpd), year two			55,800
Delivery commitment, in barrels per day (Bpd), years three through seven			61,800
Delivery commitment, in barrels per day (Bpd), years eight through ten			58,000
Long Term Crude Oil Gathering Commitments
Delivery commitments
Number of delivery commitments | contract			1
Long Term Crude Oil Delivery Commitments
Delivery commitments
Aggregate estimated payments due | $			$ 927,300,000
Natural Gas Gathering and Processing Expansion Commitment
Delivery commitments
Number of processing plants | facility			2
Extraction Oil & Gas, Inc. | Natural Gas Gathering and Processing Expansion Commitment | Minimum
Delivery commitments
Delivery commitment (in MMcf/d) | MMcf			20.6
Extraction Oil & Gas, Inc. | Natural Gas Gathering and Processing Expansion Commitment | Maximum
Delivery commitments
Term of commitment			7 years
Delivery commitment (in MMcf/d) | MMcf			51.5

Related Party Transactions - Du

Related Party Transactions - Due From Related Parties (Details)	1 Months Ended				12 Months Ended
	Sep. 30, 2016USD ($)officershares	May 31, 2016USD ($)$ / sharesshares	Apr. 30, 2016USD ($)	May 31, 2014USD ($)officer	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)shares
Units Repurchased from Officer
Aggregate purchase price					$ 65,607,000	$ 8,429,000
Promissory Notes
Settlement of promissory notes issued to officers					$ 0	5,562,000
Members' Units
Units Repurchased from Officer
Aggregate purchase price						8,429,000
Promissory Notes
Settlement of promissory notes issued to officers						$ 5,562,000
Tranche A units | Members' Units
Units Repurchased from Officer
Units repurchased (in units) | shares						1,327,000
Preferred Tranche C units | Members' Units
Units Repurchased from Officer
Units repurchased (in units) | shares						82,000
Board member | Star Peak Capital Office Lease
Office Lease with Related Affiliate
Monthly rent			$ 1,400
Former Chief Accounting Officer | Units Repurchased
Units Repurchased from Officer
Price per share (in dollars per share) | $ / shares		$ 3.25
Aggregate purchase price		$ 500,000
Former Chief Accounting Officer | Units Repurchased | Tranche A units
Units Repurchased from Officer
Units repurchased (in units) | shares		60,605
Former Chief Accounting Officer | Units Repurchased | Preferred Tranche C units
Units Repurchased from Officer
Units repurchased (in units) | shares		82,578
Officers | Promissory Notes
Promissory Notes
Number of officers | officer				2
Notes receivable				$ 5,400,000
Officers | Promissory Notes | LIBOR
Promissory Notes
Basis spread (as a percent)				1.00%
Officers | Promissory Notes | Members' Units
Units Repurchased from Officer
Units repurchased (in units) | shares	1,200,000
Aggregate purchase price	$ 7,800,000
Promissory Notes
Number of officers | officer	2
Officers | Promissory Notes | Receivables from Officers to meet Capital Contributions
Promissory Notes
Settlement of promissory notes issued to officers	$ 5,600,000

Related Party Transactions - 99

Related Party Transactions - Due to Related Parties (Details) - USD ($)	Oct. 17, 2016	Oct. 03, 2016	Dec. 31, 2016	Jul. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jan. 31, 2018	Aug. 31, 2017
Notes
Payments to extinguish debt					$ 0	$ 430,000,000	$ 0
Issuance of stock						728,333,000
Redemption price, including premium					65,607,000	8,429,000
Private Placement
Notes
Proceeds from issuance of stock, gross			$ 457,000,000
Series A Preferred Units
Notes
Issuance of stock		$ 75,000,000
Series B Preferred Units
Notes
Issuance of stock		$ 185,300,000			185,300,000
Holdings' Members | Series A Convertible Preferred Stock
Notes
Issuance of stock					185,300,000
Holdings' Members | Series A Preferred Units
Notes
Issuance of stock	$ 75,000,000
Redemption price, including premium	90,000,000
Redemption premium	$ 15,000,000
Holdings' Members | Series B Preferred Units
Notes
Issuance of stock					135,300,000
Existing Shareholders | Private Placement
Notes
Percentage of company stock owned			5.00%
Proceeds from issuance of stock, gross			$ 45,700,000
Shares issued (in shares)			2,503,370
Mr. Troy Owens
Due to Related Party
Cash compensation					$ 300,000	200,000
Mr. Troy Owens | RSUs
Due to Related Party
Vesting period, in years					3 years
Second Lien Notes due May 29, 2019
Notes
Debt outstanding							430,000,000
Payments to extinguish debt				$ 430,000,000
Second Lien Notes due May 29, 2019 | Related Party Debt Transaction | Holdings' Members
Notes
Debt outstanding							$ 311,700,000
Payments to extinguish debt				314,800,000
2021 Senior Notes due July 15, 2021
Notes
Debt outstanding			$ 550,000,000		$ 550,000,000	550,000,000
Face amount of debt				$ 550,000,000
2021 Senior Notes due July 15, 2021 | Related Party Debt Transaction
Notes
Debt outstanding					550,000,000
2021 Senior Notes due July 15, 2021 | Related Party Debt Transaction | Holdings' Members
Notes
Debt outstanding					$ 63,500,000
Percentage of company stock owned					5.00%
2024 Senior Notes due May 15, 2024
Notes
Debt outstanding			$ 0		$ 400,000,000	$ 0
Face amount of debt									$ 400,000,000
2024 Senior Notes due May 15, 2024 | Related Party Debt Transaction | Holdings' Members
Notes
Debt outstanding									54,900,000
Percentage of company stock owned					5.00%
Face amount of debt									$ 400,000,000
Senior Notes due 2026 | Related Party Debt Transaction | Holdings' Members
Notes
Percentage of company stock owned					5.00%
Senior Notes due 2026 | Related Party Debt Transaction | Holdings' Members | Subsequent Event
Notes
Debt outstanding								$ 56,200,000
Face amount of debt								$ 750,000,000

Supplemental Oil and Gas Res100

Supplemental Oil and Gas Reserve Information (Unaudited) - Results of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of Other Reserve Information [Abstract]
Statutory tax rate assumed (as a percent)	38.00%
Revenues	$ 604,296	$ 278,089	$ 197,750
Operating Expenses:
Production expenses	162,673	82,773	47,663
Exploration expenses	36,256	36,422	18,636
Depletion and accretion	311,916	203,073	144,228
Impairment of proved properties	0	22,438	12,207
Results of operations before income tax expense	93,451	(66,617)	(24,984)
Income tax (expense) benefit	(35,511)	25,314	9,494
Results of Operations	$ 57,940	$ (41,303)	$ (15,490)

Supplemental Oil and Gas Res101

Supplemental Oil and Gas Reserve Information (Unaudited) - Change in Proved Reserves (Details)	12 Months Ended
	Dec. 31, 2017MBoe$ / bbl$ / Mcf$ / MMBTUMBblsMMcf	Dec. 31, 2016MBoe$ / bbl$ / Mcf$ / MMBTUMBblsMMcf	Dec. 31, 2015MBoe$ / bbl$ / Mcf$ / MMBTUMBblsMMcf
Proved developed and undeveloped reserves (MBoe)
Balance at beginning of period (in MBoe) | MBoe	238,066	158,647.1	92,352
Revision of previous estimates (in MBoe) | MBoe	2,894	(7,620.8)	(1,150.1)
Purchased reserves (in MBoe) | MBoe	14,188.3	41,281.2	30,097.1
Extensions, discoveries and other additions (in MBoe) | MBoe	56,487.9	56,698.5	49,058.9
Sale of reserves (in MBoe) | MBoe	0	0	(4,626.8)
Production (in MBoe) | MBoe	(18,893.7)	(10,940)	(7,084)
Balance at end of period (in MBoe) | MBoe	292,742.5	238,066	158,647.1
Proved Developed Reserves, included above (in MBoe) | MBoe	102,049.3	48,498.4	30,142.3
Proved Undeveloped Reserves, included above (in MBoe) | MBoe	190,693.2	189,567.5	128,504.8
Crude Oil
Proved developed and undeveloped reserves (Mbbls and MMcf)
Balance as of beginning of period (in Mbbls or MMcf)	90,995	71,500.2	45,164.9
Revisions of previous estimates (in Mbbls or MMcf)	(625.9)	(15,576.8)	(2,961)
Purchase of reserves (in Mbbls or MMcf)	10,761.2	18,473.6	11,831.7
Extensions, discoveries, and other additions (in Mbbls or MMcf)	19,738.4	21,885.4	23,098.7
Sale of reserves (in Mbbls or MMcf)	0	0	(1,688.5)
Production (in Mbbls or MMcf)	(9,593.7)	(5,287.4)	(3,945.6)
Balance as of end of period (in Mbbls or MMcf)	111,275	90,995	71,500.2
Proved Developed Reserves, included above (in Mbbls or MMcf)	37,078	17,158	14,248.6
Proved Undeveloped Reserves, included above (in Mbbls or MMcf)	74,197	73,837	57,251.5
Unweighted arithmetic average first-day-of-the-month prices for the prior twelve months (per unit) | $ / bbl	51.34	42.75	50.28
Adjusted unweighted arithmetic average first-day-of-the-month prices for the prior twelve months (per unit) | $ / bbl	42.89	34.91	43.28
Natural Gas
Proved developed and undeveloped reserves (Mbbls and MMcf)
Balance as of beginning of period (in Mbbls or MMcf) | MMcf	507,735.4	292,583.9	166,416.1
Revisions of previous estimates (in Mbbls or MMcf) | MMcf	9,349.8	35,803.1	(2,825.8)
Purchase of reserves (in Mbbls or MMcf) | MMcf	11,183.6	78,761.6	64,392.7
Extensions, discoveries, and other additions (in Mbbls or MMcf) | MMcf	130,295.4	120,798.3	85,781
Sale of reserves (in Mbbls or MMcf) | MMcf	0	0	(10,357.1)
Production (in Mbbls or MMcf) | MMcf	(32,395.2)	(20,211.5)	(10,823)
Balance as of end of period (in Mbbls or MMcf) | MMcf	626,169	507,735.4	292,583.9
Proved Developed Reserves, included above (in Mbbls or MMcf) | MMcf	222,236	107,918	53,011.7
Proved Undeveloped Reserves, included above (in Mbbls or MMcf) | MMcf	403,933	399,817.4	239,572.2
Unweighted arithmetic average first-day-of-the-month prices for the prior twelve months (per unit) | $ / MMBTU	2.98	2.49	2.58
Adjusted unweighted arithmetic average first-day-of-the-month prices for the prior twelve months (per unit) | $ / Mcf	1.73	1.39	2.11
NGL
Proved developed and undeveloped reserves (Mbbls and MMcf)
Balance as of beginning of period (in Mbbls or MMcf)	62,448.3	38,382.9	19,451
Revisions of previous estimates (in Mbbls or MMcf)	1,961.6	1,988.8	2,281.9
Purchase of reserves (in Mbbls or MMcf)	1,563.3	9,680.7	7,533.3
Extensions, discoveries, and other additions (in Mbbls or MMcf)	15,033.6	14,679.9	11,663.4
Sale of reserves (in Mbbls or MMcf)	0	0	(1,212.1)
Production (in Mbbls or MMcf)	(3,900.8)	(2,284)	(1,334.6)
Balance as of end of period (in Mbbls or MMcf)	77,106	62,448.3	38,382.9
Proved Developed Reserves, included above (in Mbbls or MMcf)	27,932	13,354	7,058.3
Proved Undeveloped Reserves, included above (in Mbbls or MMcf)	49,174	49,094.3	31,324.6
Adjusted unweighted arithmetic average first-day-of-the-month prices for the prior twelve months (per unit) | $ / bbl	20.28	11.63	10.65

Supplemental Oil and Gas Res102

Supplemental Oil and Gas Reserve Information (Unaudited) - Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Discounted future net cash flows
Future crude oil, natural gas and NGL sales	$ 7,422,335	$ 4,610,848	$ 4,119,888
Future production costs	(2,227,370)	(1,429,202)	(1,193,560)
Future development costs	(1,662,859)	(1,579,628)	(1,141,330)
Future income tax expense	(212,923)	(42,859)	0
Future net cash flows	3,319,183	1,559,159	1,784,998
10% annual discount	(1,440,177)	(836,163)	(949,115)
Standardized measure of discounted future net cash flows(1)	$ 1,879,006	$ 722,996	835,883	$ 1,387,472
Pro forma
Discounted future net cash flows
Future income tax expense			(327,900)
Standardized measure of discounted future net cash flows(1)			$ 680,300

Supplemental Oil and Gas Res103

Supplemental Oil and Gas Reserve Information (Unaudited) - Discounted Future Net Cash Flows Rollforward (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Change in the standardized measure
Balance at beginning of period	$ 722,996	$ 835,883	$ 1,387,472
Sales of crude oil, natural gas and NGL, net	(441,623)	(195,316)	(150,087)
Net change in prices and production costs	586,271	(325,236)	(1,292,364)
Net change in future development costs	3,959	(49,213)	175,944
Extensions and discoveries	330,160	96,982	284,216
Acquisitions of reserves	59,745	156,675	240,989
Sale of reserves	0	0	(50,018)
Revisions of previous quantity estimates	188,421	19,161	(28,391)
Previously estimated development costs incurred	331,550	123,085	102,060
Net changes in income taxes	(79,181)	(17,611)	0
Accretion of discount	74,061	83,588	156,723
Other	102,647	(5,002)	9,339
Balance at end of period	$ 1,879,006	$ 722,996	$ 835,883

Unaudited Quarterly Financia104

Unaudited Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended									12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Oil, Natural gas and NGL sales	$ 214,030	$ 180,861	$ 119,766	$ 89,639	$ 94,690		$ 72,902	$ 65,364	$ 45,133	$ 604,296	$ 278,089	$ 197,750
Operating Income (Loss)	58,850	41,084	16,480	10,210	5,640		4,556	(3,593)	(16,635)	(21,897)	(315,877)	(76,376)
Net Income (Loss)	$ (30,568)	$ (29,796)	$ 7,240	$ 8,716	$ (245,601)	$ (226,107)	$ (37,267)	$ (127,614)	$ (45,519)	$ (44,408)	$ (456,001)	$ (47,264)
Basic and Diluted Loss Per Common Share (in dollars per share)	$ (0.20)	$ (0.20)	$ 0.02	$ 0.03	$ (1.54)	$ (1.54)				$ (0.35)	$ (1.54)