Extraction Oil & Gas (XOG) 10-Q 6 Nov 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Nov. 02, 2018
Document and Entity Information
Entity Registrant Name	Extraction Oil & Gas, Inc.
Entity Central Index Key	1,655,020
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2,018
Entity Current Reporting Status	Yes
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		176,188,312

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($)	Sep. 30, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 274,065,000	$ 6,768,000
Accounts receivable
Trade	44,565,000	46,047,000
Oil, natural gas and NGL sales	107,166,000	93,301,000
Inventory and prepaid expenses	26,676,000	13,017,000
Commodity derivative asset	13,226,000	4,132,000
Total Current Assets	465,698,000	163,265,000
Property and Equipment (successful efforts method), at cost:
Proved oil and gas properties	3,778,498,000	3,011,526,000
Unproved oil and gas properties	657,837,000	686,968,000
Wells in progress	108,426,000	127,418,000
Less: accumulated depletion, depreciation and amortization	(1,029,539,000)	(709,662,000)
Net oil and gas properties	3,515,222,000	3,116,250,000
Gathering Systems And Facilities, Successful Effort Method, Net	63,998,000	4,889,000
Other property and equipment, net of accumulated depreciation	37,829,000	32,429,000
Net Property and Equipment	3,617,049,000	3,153,568,000
Non-Current Assets:
Goodwill and other intangible assets, net of accumulated amortization	56,446,000	55,453,000
Other non-current assets	19,132,000	12,383,000
Total Non-Current Assets	75,578,000	67,836,000
Total Assets	4,158,325,000	3,384,669,000
Current Liabilities:
Accounts payable and accrued liabilities	200,137,000	211,581,000
Revenue payable	113,751,000	52,805,000
Production taxes payable	61,497,000	37,444,000
Commodity derivative liability	143,576,000	67,428,000
Accrued interest payable	18,792,000	23,807,000
Asset retirement obligations	12,928,000	6,873,000
Total Current Liabilities	550,681,000	399,938,000
Long-term Line of Credit, Noncurrent	290,000,000	90,000,000
Non-Current Liabilities:
Senior Notes, net of unamortized debt issuance costs	1,132,115,000	933,361,000
Production taxes payable	83,586,000	57,982,000
Commodity derivative liability	8,786,000	17,274,000
Other non-current liabilities	8,966,000	5,973,000
Asset retirement obligations	56,423,000	62,667,000
Deferred tax liability	54,626,000	42,326,000
Total Non-Current Liabilities	1,634,502,000	1,209,583,000
Total Liabilities	2,185,183,000	1,609,521,000
Commitments and Contingencies—Note 11
Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized; 185,280 issued and outstanding	162,813,000	158,383,000
Stockholders' Equity:
Common stock, $0.01 par value; 900,000,000 shares authorized; 175,861,466 and 172,059,814 issued and outstanding	1,718,000	1,718,000
Additional paid-in capital	2,146,918,000	2,114,795,000
Treasury stock, at cost, 485,117 and 165,385 shares	(6,539,000)	(2,105,000)
Accumulated deficit	(475,640,000)	(497,643,000)
Total Extraction Oil & Gas, Inc. Stockholders' Equity	1,666,457,000	1,616,765,000
Noncontrolling interest—Note 1	143,872,000	0
Total Stockholders' Equity	1,810,329,000	1,616,765,000
Total Liabilities and Stockholders' Equity	$ 4,158,325,000	$ 3,384,669,000

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Parentheticals) - $ / shares	Sep. 30, 2018	Dec. 31, 2017
Series A Convertible Preferred Stock
Convertible Preferred Stock, par value (in dollars per share)	$ 0.01	$ 0.01
Convertible Preferred Stock, shares authorized (in shares)	50,000,000	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
Common stock, par value and other disclosures
Common stock, Par value per share (in dollars per share)	$ 0.01	$ 0.01
Common Stock, shares authorized (in shares)	900,000,000	900,000,000
Common Stock, shares issued (in shares)	171,893,157	171,834,605
Common Stock, shares outstanding (in shares)	171,893,157	171,834,605
Treasury stock (in shares)	165,385	0

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenues:
Oil sales	$ 225,467	$ 132,075	$ 619,211	$ 269,597
Natural gas sales	23,103	24,672	66,991	63,095
NGL sales	33,590	24,114	86,369	57,574
Total Revenues	282,160	180,861	772,571	390,266
Operating Expenses:
Lease operating expenses	20,283	15,465	61,760	41,626
Gas Gathering, Transportation, Marketing and Processing Costs	11,786	13,802	29,284	34,129
Production taxes	21,605	16,290	66,317	33,254
Exploration expenses	11,038	7,181	21,326	24,431
Depletion, depreciation, amortization and accretion	107,315	94,220	310,296	213,483
Impairment of long lived assets	16,166	0	16,294	675
(Gain) loss on sale of property and equipment and assets of unconsolidated subsidiary	(83,559)	0	(143,461)	451
Acquisition transaction expenses	0	0	0	68
General and administrative expenses	35,365	28,741	100,565	77,916
Total Operating Expenses	139,999	175,699	462,381	426,033
Operating Income (Loss)	142,161	5,162	310,190	(35,767)
Other Income (Expense):
Commodity derivatives gain (loss)	(35,913)	(37,875)	(175,752)	46,423
Interest expense	(20,725)	(15,080)	(103,229)	(33,761)
Other income	1,827	891	3,094	1,709
Total Other Income (Expense)	(54,811)	(52,064)	(275,887)	14,371
Income (Loss) Before Income Taxes	87,350	(46,902)	34,303	(21,396)
Income tax (expense) benefit	(22,200)	17,106	(12,300)	7,556
Net Loss	$ 65,150	$ (29,796)	$ 22,003	$ (13,840)
Earnings Per Common Share
Basic and diluted (in dollars per share)	$ 0.33	$ (0.20)	$ 0.03	$ (0.15)
Weighted Average Common Shares Outstanding
Basic and diluted (in shares)	175,814,000	171,845,000	175,269,000	171,838,000

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS' AND STOCKHOLDERS' EQUITY - 9 months ended Sep. 30, 2018 - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Treasury Stock	Additional Paid in Capital	Retained Deficit	Extraction Oil & Gas, Inc. Stockholders' Equity	Noncontrolling Interest [Member]
Balance at beginning of period (in units or shares) at Dec. 31, 2017		172,060	165
Balance at beginning of period at Dec. 31, 2017	$ 1,616,765	$ 1,718	$ (2,105)	$ 2,114,795	$ (497,643)	$ 1,616,765	$ 0
CHANGES IN MEMBERS' AND STOCKHOLDERS' EQUITY
Proceeds from Issuance of Preferred Stock and Preference Stock	148,500						148,500
Payments For Issuance of Preferred Stock Units	(7,933)						(7,933)
Preferred Units commitment fees and dividends paid-in-kind				(3,305)		(3,305)	3,305
Stock Issued During Period, Shares, Share-based Compensation, Gross		2,794
Stock-based compensation	50,883			50,883		50,883
Series A Preferred Stock dividends	(8,164)			(8,164)		(8,164)
Accretion of beneficial conversion feature on Series A Preferred Stock	(4,429)			(4,429)		(4,429)
Treasury Stock, Shares, Acquired			320
Treasury Stock, Value, Acquired, Cost Method			$ (4,434)			(4,434)
Restricted Stock, Shares Issued Net of Shares for Tax Withholdings		1,007
Payments Related to Tax Withholding for Share-based Compensation	(2,862)
Net loss	22,003				22,003	22,003
Balance at end of period (in units or shares) at Sep. 30, 2018		175,861	485
Balance at end of period at Sep. 30, 2018	$ 1,810,329	$ 1,718	$ (6,539)	$ 2,146,918	$ (475,640)	$ 1,666,457	$ 143,872

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash flows from operating activities:
Net loss	$ 22,003	$ (13,840)
Reconciliation of net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	310,296	213,483
Abandonment and impairment of unproved properties	15,463	5,684
Impairment of long lived assets	16,294	675
(Gain) loss on sale of property and equipment	(59,849)	451
Gain (Loss) on Disposition of Assets	(83,612)	0
Amortization of debt issuance costs	12,303	3,181
Deferred rent	442	(229)
Commodity derivatives (gain) loss	175,752	(46,423)
Settlements on commodity derivatives	(93,482)	(8,893)
Premiums paid on commodity derivatives	(17,271)	0
Equity in earnings of unconsolidated affiliate	(1,886)	(256)
Proceeds from Equity Method Investment, Distribution	1,684	131
Debt Instrument, Make Whole Provision, Operating Activities	35,600	0
Deferred income tax expense (benefit)	12,300	(7,556)
Stock-based compensation	50,883	46,707
Changes in current assets and liabilities:
Accounts receivable—trade	4,573	(29,099)
Accounts receivable—oil, natural gas and NGL sales	(13,865)	(36,359)
Inventory and prepaid expenses	(637)	(180)
Accounts payable and accrued liabilities	(14,780)	1,653
Revenue payable	60,946	6,047
Production taxes payable	49,657	13,520
Accrued interest payable	(5,015)	(5,553)
Asset retirement expenditures	(9,437)	(1,408)
Net cash provided by operating activities	468,362	141,736
Cash flows from investing activities:
Oil and gas property additions	(774,787)	(1,015,700)
Acquired oil and gas properties	0	(17,225)
Sale of property and equipment	72,345	5,155
Payments To Acquire Gathering Systems And Facilities	(41,359)	(7,685)
Other property and equipment additions	(11,944)	(1,923)
Payments to Acquire Interest in Subsidiaries and Affiliates	(6,000)	0
Proceeds from Equity Method Investment, Distribution, Return of Capital	0	116
Proceeds from Sale of Other Assets, Investing Activities	83,612	0
Net cash used in investing activities	(678,133)	(1,037,262)
Cash flows from financing activities:
Borrowings under credit facility	590,000	250,000
Repayments of Lines of Credit	(390,000)	(250,000)
Proceeds from Issuance of Senior Long-term Debt	739,664	394,000
Early Repayment of Subordinated Debt	550,000	0
Make-whole premium paid on 2021 Senior Notes	(35,600)	0
Proceeds from Issuance of Preferred Stock and Preference Stock	148,500	0
Preferred Unit issuance Costs	(6,933)
Payments For Issuance of Preferred Stock Units	7,933	0
Treasury Stock, Value, Acquired, Cost Method	(4,434)	0
Payments Related to Tax Withholding for Share-based Compensation	(2,862)	(2,832)
Dividends on Series A Preferred Stock	(8,164)	(7,680)
Debt issuance costs	(3,103)	(3,273)
Equity issuance costs	0	(1,486)
Net cash provided by financing activities	477,068	378,729
Increase (decrease) in cash, cash equivalents and restricted cash	267,297	(516,797)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	6,768	630,936
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	274,065	114,139
Supplemental cash flow information:
Property and equipment included in accounts payable and accrued liabilities	148,156	130,022
Cash paid for interest	66,673	44,703
Payment for Debt Extinguishment or Debt Prepayment Cost	35,329	0
Promissory Notes Issued to Officers	(35,329)	0
Accretion of beneficial conversion feature of Series A Preferred Stock	4,429	3,992
Noncash or Part Noncash Acquisition, Investments Acquired	0	8,307
Increase in dividend payable	$ 0	$ 484

Business and Organization

Business and Organization	9 Months Ended
	Sep. 30, 2018
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". On July 3, 2018, Elevation Midstream, LLC (“Elevation”), a Delaware limited liability company and subsidiary of the Company, entered into a securities purchase agreement (the “Securities Purchase Agreement”) with a third party (the "Purchaser"), pursuant to which Elevation agreed to sell 150,000 Preferred Units (the “Elevation Preferred Units”) of Elevation at a price of $990 per Elevation Preferred Unit with an aggregate liquidation preference of $150.0 million (the “Private Placement”), in a transaction exempt from the registration requirements under the Securities Act of 1933, as amended (the “Securities Act”). The Private Placement closed on July 3, 2018 (the “Closing Date”), funded on July 19, 2018 and resulted in net proceeds of approximately $141.9 million , $25.4 million of which was a reimbursement for previously incurred midstream capital expenditures and general and administrative expenses. These Preferred Units are non-recourse to Extraction and represent the noncontrolling interest presented on the condensed consolidated statement of changes in stockholders' equity. Elevation is a separate entity and the assets and credit of Elevation are not available to satisfy the debts and other obligations of the Company or its other subsidiaries. As of September 30, 2018, $182.0 million of cash was held by Elevation and is earmarked for construction of pipeline infrastructure to serve the development of acreage in its Hawkeye and Southwest Wattenberg areas. As of September 30, 2018 and December 31, 2017, Elevation capital expenditures represented all of the gathering systems and facilities line item in the condensed consolidated balance sheet and the gathering systems and facilities additions in the condensed consolidated statement of cash flows. During the twenty-eight months following the Closing Date (the “Commitment Period”), subject to the satisfaction of certain financial and operational metrics and certain other customary closing conditions, Elevation has the right to require the Purchaser to purchase additional Elevation Preferred Units on the terms set forth in the Securities Purchase Agreement. Elevation may require the Purchaser to purchase additional Elevation Preferred Units, in increments of at least $25.0 million , up to an aggregate amount of $350.0 million . During the Commitment Period, Elevation is required to pay the Purchaser a quarterly commitment fee payable in cash or in kind of 1.0% per annum on any undrawn amounts of such additional $350.0 million commitment. Elevation recognized $0.9 million of commitment fees paid-in-kind for the three and nine months ended September 30, 2018 , included under the Preferred Unit commitment fees and dividends paid-in-kind line item in the condensed consolidated statement of changes in stockholders' equity. The Elevation Preferred Units will entitle the Purchaser to receive quarterly dividends at a rate of 8.0% per annum (the “Dividend”). In respect of quarters ending prior to and including June 30, 2020, the Dividend is payable in cash or in kind at the election of Elevation. After June 30, 2020, the Dividend is payable solely in cash. Elevation recognized $2.4 million of dividends paid-in-kind for the three and nine months ended September 30, 2018 , included under the Preferred Unit commitment fees and dividends paid-in-kind line item in the condensed consolidated statement of changes in stockholders' equity.

Basis of Presentation, Signific

Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements	9 Months Ended
	Sep. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements	Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements Basis of Presentation The unaudited condensed 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”) and the Securities and Exchange Commission rules and regulation for interim financial reporting. In the opinion of management, all adjustments, consisting primarily of normal recurring accruals that are considered necessary for a fair statement of the condensed consolidated financial information, have been included. However, operating results for the period presented are not necessarily indicative of the results that may be expected for a full year. Interim condensed consolidated financial statements and the year-end balance sheet do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes included in the Company’s Annual Report. Significant Accounting Policies The significant accounting policies followed by the Company are set forth in Note 2 to the Company’s consolidated financial statements in its Annual Report and are supplemented by the notes to the unaudited condensed consolidated financial statements in this report. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report. Recent Accounting Pronouncements In August 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2018-15, which aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software and hosting arrangements that include an internal-use software license. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019, including interim reporting periods within that reporting period. The Company is currently evaluating this new standard to determine the potential impact to its financial statements and related disclosures. In August 2018, the FASB issued ASU No. 2018-13, which improves the disclosure requirements on fair value measurements. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019, including interim reporting periods within that reporting period. The Company is currently evaluating this new standard to determine the potential impact to its financial statements and related disclosures. In May 2017, the FASB issued ASU No. 2017-09, which provides clarification and reduces both (1) diversity in practice and (2) cost and complexity when applying the guidance in Topic 718 Compensation - Stock Compensation, to a change to the terms or conditions of a share-based payment award. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that reporting period. The Company adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial statements and related disclosures. In February 2017, the FASB issued ASU No. 2017-05, which provided clarification regarding the guidance on accounting for the derecognition of nonfinancial assets. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that fiscal year. The Company adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial statements and related disclosures. In January 2017, the FASB issued ASU No. 2017-04, which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019. Early adoption is permitted for interim and annual goodwill impairment tests performed on testing dates after January 1, 2017. The Company is currently evaluating the impact of adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements and related disclosures. In January 2017, the FASB issued ASU No. 2017-01, which clarifies the definition of a business when evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial statements and related disclosures; however, this standard may result in more transactions being accounted for as asset acquisitions rather than business combinations. In November 2016, the FASB issued ASU No. 2016-18, which intends to clarify how entities should present restricted cash and restricted cash equivalents in the statement of cash flows. This amendment was effective retrospectively for reporting periods beginning after December 15, 2017. The Company adopted this ASU on January 1, 2018 and the retrospective adoption increased the Company's beginning cash balances within the statement of cash flows for the prior period presented in the table below. The adoption had no other material impact on the cash flow statement and had no impact on the Company's results of operations or financial position. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets to the consolidated statement of cash flows: As of September 30, December 31, September 30, December 31, 2018 2017 2017 2016 Cash and cash equivalents $ 274,065 $ 6,768 $ 114,139 $ 588,736 Restricted cash included in cash held in escrow — — — 42,200 $ 274,065 $ 6,768 $ 114,139 $ 630,936 In August 2016, the FASB issued ASU No. 2016-15, which addresses eight specific cash flow issues, including presentation of debt prepayments or debt extinguishment costs, with the objective of reducing the existing diversity in practice. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company adopted this ASU on January 1, 2018, which requires current period make-whole premiums to be presented in financing activities in the statement of cash flows and prior period debt prepayment costs to be reclassified from operating activities to financing activities in the statement of cash flows; however, there will be no impact to the total change in cash and cash equivalents from period to period. In February 2016, the FASB issued ASU No. 2016-02, which requires lessee recognition on the balance sheet of a right of use asset and a lease liability, initially measured at the present value of the lease payments. It further requires recognition in the income statement of a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis. Finally, it requires classification of all cash payments within operating activities in the statements of cash flows. It is effective for fiscal years commencing after December 15, 2018 and early adoption is permitted. The FASB subsequently issued ASU No. 2017-13, ASU No. 2018-01, ASU No. 2018-10 and ASU No. 2018-11, which provided additional implementation guidance. The Company is currently evaluating the impact this ASU will have on the consolidated financial statements and related disclosures and expects certain lease agreements with terms over one year to be classified as right-of-use assets and right-of-use liabilities, which will gross up the consolidated balance sheet as of January 1, 2019. As a part of the implementation work, the Company is finalizing its initial conclusions with its external consulting firm, implementing a software tool used to calculate the initial and ongoing accounting balances for right-of-use assets and liabilities, and is assessing the completeness of the lease population. In May 2014, the FASB issued ASU No. 2014-09, which establishes a comprehensive new revenue recognition model, referred to as ASC 606 - Revenue from Contracts with Customers, designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The ASU allows for the use of either the full or modified retrospective transition method. In August 2015, the FASB issued ASU No. 2015-14, which deferred ASU No. 2014-09 for one year, and was effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. The FASB subsequently issued ASU No. 2016-08, ASU No. 2016-10, ASU No. 2016-11, ASU No. 2016-12, ASU No. 2016-20, ASU No. 2017-13 and ASU No. 2017-14, which provided additional implementation guidance. Refer to —Adoption of ASC 606 for more information. Adoption of ASC 606 On January 1, 2018, the Company adopted ASC 606 - Revenue from Contracts with Customers ("ASC 606"). The Company adopted ASC 606 using the modified retrospective method to apply the new standard to all new contracts entered into on or after January 1, 2018 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. The impact of adoption in the current period results are as follows (in thousands): For the Three Months Ended For the Nine Months Ended Under ASC 606 Under ASC 605 Change Under ASC 606 Under ASC 605 Change Revenues: Oil sales $ 225,467 $ 225,467 $ — $ 619,211 $ 619,211 $ — Natural gas sales 23,103 26,394 (3,291 ) 66,991 76,492 (9,501 ) NGL sales 33,590 39,154 (5,564 ) 86,369 101,349 (14,980 ) Total Revenues 282,160 291,015 (8,855 ) 772,571 797,052 (24,481 ) Operating Expenses: Transportation and gathering $ 11,786 $ 20,641 $ (8,855 ) $ 29,284 $ 53,765 $ (24,481 ) Net Income $ 65,150 $ 65,150 $ — $ 22,003 $ 22,003 $ — Changes to sales of natural gas and NGL, and transportation and gathering expenses are due to the conclusion that certain midstream processing entities are the Company's customers in natural gas processing and marketing agreements in accordance with the five-step process in ASC 606. This is a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC 605 where the Company determined it was the principal, the midstream processor was the agent and the third-party end user was its customer. As a result, the Company modified its presentation of revenues and operating expenses for these agreements. Revenues related to these agreements are now presented on a net basis for proceeds expected to be received from the midstream processing entity. Transportation and gathering expense related to other agreements incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities will continue to be presented as transportation and gathering expense. Revenues from Contracts with Customers Sales of oil, natural gas and NGL are recognized at the point control of the commodity is transferred to the customer and collectability is reasonably assured. The majority of the Company's contracts' pricing provisions are tied to a commodity market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas and NGL fluctuates to remain competitive with the other available oil, natural gas and NGL supplies. Oil Sales Under the Company's crude purchase and marketing contracts, the Company generally sells oil production at the wellhead and collects an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead at the net price received. The Company utilizes the sales method to account for producer imbalances, which continues to be applicable under ASC 606. As of September 30, 2018 , the Company has an oil imbalance of 54 MBbl, which the Company intends to settle with the counterparty in crude oil barrels. Natural Gas and NGL Sales Under the Company's natural gas processing contracts, the Company delivers natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity's system. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGL and residue gas. In these scenarios, we evaluate whether we are the principal or the agent in the transaction, and the point at which control of the hydrocarbons transfer to the customer. For those contracts where the Company has concluded the midstream processing entity is the Company's agent and the third-party end user is its customer (generally the Company's fixed-fee gathering and processing agreements), the Company recognizes revenue on a gross basis, with transportation and gathering expense presented as an operating expense in the consolidated statements of operations. Alternatively, for those contracts where the Company has concluded the midstream processing entity is its customer and controls the hydrocarbons (generally the Company's percentage of proceeds gathering and processing agreements), the Company recognizes natural gas and NGL revenues based on the net amount of the proceeds received from the midstream processing company. In certain natural gas processing agreements, the Company may elect to take its residue gas and/or NGL in-kind at the tailgate of the midstream entity's processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when the control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering and processing expense attributable to the gas processing contracts, as well as any transportation expense incurred to deliver the product to the purchaser, are presented as transportation and gathering expense in the consolidated statements of operations. Performance Obligations A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price of a contract that has an original expected duration of one year or less. For the Company's product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14(a), which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company records revenue on its oil, natural gas and NGL sales at the time production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the customer and the net commodity price that will be received for the sale of these commodity products. The Company records the differences between the revenue estimated and the actual amounts received for product sales in the month that payment is received from the customer. The Company has internal controls over its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the period from January 1, 2018 to September 30, 2018 , revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. Contract Balances Under the Company's various sales contracts, the Company invoices customers once its performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's product sales contracts do not give rise to contract assets or liabilities under ASC 606. The following table presents the Company's revenues disaggregated by revenue source. Transportation and gathering costs in the following table are not all of the transportation and gathering expenses that the Company incurs, only the expenses that are netted against revenues pursuant to ASC 606. Prior period amounts have not been adjusted under the modified retrospective method. For the Three Months For the Nine Months 2018 2017 2018 2017 Revenues: Oil sales $ 225,467 $ 132,075 $ 619,211 $ 269,597 Natural gas sales 26,394 24,672 76,492 63,095 NGL sales 39,154 24,114 101,349 57,574 Transportation and gathering included in revenues (8,855 ) — (24,481 ) — Total Revenues $ 282,160 $ 180,861 $ 772,571 $ 390,266 Other than as disclosed above or in the Company’s Annual Report, there are no other accounting standards applicable to the Company that would have a material effect on the Company’s consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company through the date of this filing.

Acquisitions

Acquisitions	9 Months Ended
	Sep. 30, 2018
Business Combinations [Abstract]
Acquisitions	Acquisitions and Divestitures August 2018 Divestiture On August 3, 2018, Elevation received proceeds of $83.6 million and recognized a gain of $83.6 million for the three and nine months ended September 30, 2018 , upon the sale of assets of DJ Holdings, LLC, a subsidiary of Discovery Midstream Partners, LP, of which Elevation held a 10% membership interest. The Company acquired its interest in exchange for the contribution of an acreage dedication, which is considered a nonfinancial asset. April 2018 Divestitures In April 2018, the Company completed various sales of its interests in approximately 15,100 net acres of leasehold and primarily non-producing properties for aggregate sales proceeds of approximately $72.3 million and recognized a gain of $59.9 million for the three and nine months ended September 30, 2018 . April 2018 Acquisition On April 19, 2018, the Company acquired an unaffiliated oil and gas company's interest in approximately 1,000 net acres of non-producing leasehold primarily located in Arapahoe County, Colorado, (the "April 2018 Acquisition"). Upon closing the seller received approximately $9.4 million in cash. This transaction has been accounted for as an asset acquisition. The acquisition provided new development opportunities in the Core DJ Basin. January 2018 Acquisition On January 8, 2018, the Company acquired an unaffiliated oil and gas company's interest in approximately 1,200 net acres of non-producing leasehold located in Arapahoe County, Colorado, (the "January 2018 Acquisition"). Upon closing the seller received approximately $11.6 million in cash. This transaction has been accounted for as an asset acquisition. The acquisition provided new development opportunities in the Core DJ Basin. 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 paid $12.2 million for the final settlement payment in April 2018 in conjunction with the November 2017 Acquisition. This transaction has been accounted for as an asset acquisition. The acquisition provided 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 and producing properties located primarily in Adams County, Colorado, along with various other related rights, permits, contracts, equipment, rights of way, gathering systems and other assets (the "July 2017 Acquisition"). Upon closing the seller received total consideration of $84.0 million in cash, subject to customary purchase price adjustments. The effective date for the July 2017 Acquisition is July 1, 2017. This transaction has been accounted for as an asset acquisition. The acquisition provided 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 $0.8 million and $2.6 million of revenue and $0.6 million and $2.0 million of earnings, respectively, for three and nine months ended September 30, 2018 . The acquired producing properties contributed $1.5 million and $2.2 million of revenue and $1.1 million and $1.7 million of earnings, respectively, for the three and nine months ended September 30, 2017 . No significant transaction costs related to the acquisition were incurred for the three and nine months ended September 30, 2018 and 2017 . 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 Pro Forma Financial Information (Unaudited) For the three and nine months ended September 30, 2017 , the following pro forma financial information represents the combined results for the Company and the properties acquired in the June 2017 Acquisition as if the acquisition had occurred on January 1, 2017. The June 2017 Acquisition has no impact on the historical results of the Company for the three and nine months ended September 30, 2018 . For purposes of pro forma financial information, it was assumed that the June 2017 Acquisition was funded through cash. For the three and nine months ended September 30, 2017 , the pro forma financial information includes effects of adjustments for DD&A expense of $1.6 million and income tax expense of $0.6 million . 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 integrate the properties acquired. Asset acquisitions are not included in pro forma financial information, as it is not required. 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. For the Three Months Ended September 30, For the Nine Months Ended September 30, 2017 2017 Revenues $ 180,861 $ 392,430 Operating expenses $ 175,699 $ 427,912 Net loss $ (29,796 ) $ (13,663 ) Loss per common share, basic and diluted $ (0.20 ) $ (0.15 )

Long Term Debt

Long Term Debt	9 Months Ended
	Sep. 30, 2018
Debt Instrument [Line Items]
Long-Term Debt	Long‑Term Debt As of the dates indicated, the Company’s long‑term debt consisted of the following (in thousands): September 30, December 31, Credit facility due August 16, 2022 (or an earlier time as set forth in the credit facility) $ 290,000 $ 90,000 2021 Senior Notes due July 15, 2021 — 550,000 2024 Senior Notes due May 15, 2024 400,000 400,000 2026 Senior Notes due February 1, 2026 750,000 — Unamortized debt issuance costs on Senior Notes (17,885 ) (16,639 ) Total long-term debt 1,422,115 1,023,361 Less: current portion of long-term debt — — Total long-term debt, net of current portion $ 1,422,115 $ 1,023,361 Credit Facility 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) 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 (c) 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. In January 2018, the Company amended its revolving credit facility to (i) increase the borrowing base from $525.0 million to $750.0 million , subject to the current elected commitments of $650.0 million , (ii) increase the maximum amount for the letter of credit issued in favor of a purchaser of its crude oil from $25.0 million to $35.0 million , and (iii) amend certain provisions of the credit agreement, including the commitments and allocations of each lender. In connection with the 2026 Senior Notes Offering (as defined below), the borrowing base was automatically reduced to $700.0 million ; however, the current elected commitments remained at $650.0 million . In February 2018, the Company entered into a consent agreement and amended its revolving credit facility to (i) provide for consent by the lenders to (a) the designation of Elevation Midstream, LLC as an unrestricted subsidiary and (b) the transfer of certain assets by the Company and one of the guarantors to such unrestricted subsidiary; and (ii) amend certain provisions of the credit agreement, including the incurrence of indebtedness covenant to permit certain indebtedness in connection with certain transportation service agreements with such unrestricted subsidiary. In May 2018, the Company amended its revolving credit facility to (i) increase the borrowing base from $700.0 million to $800.0 million , subject to current elected commitments of $650.0 million and (ii) reduce each of the applicable interest rate margins for borrowings by 0.50%. In October 2018, the Company amended its revolving credit facility to (i) provide the lenders consent to postpone the November 1, 2018 scheduled borrowing base redetermination until December 15, 2018 and (ii) permit the Company to make payments with respect to its own equity, subject to certain terms, conditions and financial thresholds. As of September 30, 2018 , the credit facility was subject to a borrowing base of $800.0 million , subject to current elected commitments of $650.0 million . As of September 30, 2018 and, with respect to the Prior Credit Facility, December 31, 2017 , the Company had outstanding borrowings of $290.0 million and $90.0 million , respectively. As of September 30, 2018 and, with respect to the Prior Credit Facility, December 31, 2017 , the Company had standby letters of credit of $35.7 million and $25.7 million , respectively. At September 30, 2018 , the undrawn balance under the credit facility was $360.0 million . As of the date of this filing, the Company has $240.0 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 (except that the November 1, 2018 redetermination was postponed to December 15, 2018 with the consent of the lenders), 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. 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 below. 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 Borrowing Base Utilization Percentage Utilization Eurodollar Margin Base Rate Margin Commitment Fee Rate Level 1 < 25% 1.50 % 0.50 % 0.375 % Level 2 ≥ 25% < 50% 1.75 % 0.75 % 0.375 % Level 3 ≥ 50% < 75% 2.00 % 1.00 % 0.500 % Level 4 ≥ 75% < 90% 2.25 % 1.25 % 0.500 % Level 5 ≥ 90% 2.50 % 1.50 % 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 entering into hedges 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 its consolidated current assets (includes availability under the revolving credit facility and unrestricted cash and excludes derivative assets) to its consolidated current liabilities (excludes obligations under the revolving credit facility, senior notes and certain derivative liabilities), of not less than 1.0 to 1.0 and to maintain, on the last day of each quarter, a ratio of consolidated debt less cash balances to its consolidated EBITDAX (EBITDAX is defined as net income adjusted for certain cash and non-cash items including DD&A, exploration expense, gains/losses on derivative instruments, amortization of certain debt issuance costs, non-cash compensation expense, interest expense and prepayment premiums on extinguishment of debt) for the four fiscal quarter period most recently ended, of not greater than 4.0 : 1.0 . The Company was in compliance with all financial covenants under the credit facility as of September 30, 2018 and through the filing of this report. Any borrowings under the credit facility are collateralized by substantially all of the assets of the Company and certain of its subsidiaries, including oil and gas properties, personal property and the equity interests of those subsidiaries. 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. Elevation is a separate entity and the assets and credit of Elevation are not available to satisfy the debts and other obligations of the Company or its other subsidiaries. As of September 30, 2018, $182.0 million of cash was held by Elevation and is earmarked for construction of pipeline infrastructure to serve the development of acreage in its Hawkeye and Southwest Wattenberg areas. 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 bore an annual interest rate of 7.875% . The interest on the 2021 Senior Notes was 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. Concurrent with the 2026 Senior Notes Offering (as defined below), 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 includes a 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 included 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 which commenced on November 15, 2017. The Company received net proceeds of approximately $392.6 million after deducting 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 certain of the Company's current subsidiaries and by certain future restricted subsidiaries that guarantees its indebtedness under a credit facility (the “2024 Senior Note Guarantors”). The 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 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. 2026 Senior Notes In January 2018, the Company issued at par $750.0 million principal amount of 5.625% Senior Notes due February 1, 2026 (the “2026 Senior Notes” and the offering, the “2026 Senior Notes Offering”). The 2026 Senior Notes bear an annual interest rate of 5.625% . The interest on the 2026 Senior Notes is payable on February 1 and August 1 of each year commencing on August 1, 2018. The Company received net proceeds of approximately $737.9 million after deducting fees. The Company used $534.2 million of the net proceeds from the 2026 Senior Notes Offering to fund the tender offer 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 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 certain 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 certain of the Company's future restricted 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 2026 Senior Notes may declare all outstanding 2026 Senior Notes to be due and payable immediately. Debt Issuance Costs As of September 30, 2018 , the Company had debt issuance costs, net of accumulated amortization, of $3.7 million related to its credit facility which has been reflected on the Company’s balance sheet within the line item other non‑current assets. As of September 30, 2018 , the Company had debt issuance costs, net of accumulated amortization, of $17.9 million related to its 2024 and 2026 Senior Notes (collectively, the "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. Debt issuance costs include origination, legal, engineering and other fees incurred in connection with the Company’s credit facility and Senior Notes. For the three and nine months ended September 30, 2018 , the Company recorded amortization expense related to debt issuance costs of $0.9 million and $12.3 million , respectively, as compared to $1.5 million and $3.2 million for the three and nine months ended September 30, 2017 , respectively. Debt issuance costs for the nine months ended September 30, 2018 include $9.4 million of acceleration of amortization expense upon the repayment of the Company's 2021 Senior Notes. The repayment of the Company's 2021 Senior Notes had no impact to amortization expense for the three months ended September 30, 2018 . Interest Incurred on Long‑Term Debt For the three and nine months ended September 30, 2018 , the Company incurred interest expense on long‑term debt of $21.5 million and $61.6 million , respectively, as compared to $16.5 million and $39.2 million for the three and nine months ended September 30, 2017 , respectively. For the three and nine months ended September 30, 2018 , the Company capitalized interest expense on long term debt of $1.7 million and $6.3 million , respectively, as compared to $2.9 million and $8.6 million for the three and nine months ended September 30, 2017 , respectively, which has been reflected in the Company’s condensed consolidated financial statements. Also included in interest expense for the nine months ended September 30, 2018 is a make-whole premium of $35.6 million related to the Company's repayment of its 2021 Senior Notes in January and February 2018. The repayment of the Company's 2021 Senior Notes had no impact to interest expense for the three months ended September 30, 2018 .

Commodity Derivative Instrument

Commodity Derivative Instruments	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivative Instruments	Commodity Derivative Instruments The Company has entered into commodity derivative instruments, as described below. 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 twelve counterparties. 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 September 30, 2018 are summarized below: 2018 2019 NYMEX WTI Crude Swaps: Notional volume (Bbl) 1,050,000 — Weighted average fixed price ($/Bbl) $ 52.91 $ — NYMEX WTI Crude Purchased Puts: Notional volume (Bbl) 2,250,000 9,300,000 Weighted average purchased put price ($/Bbl) $ 49.81 $ 51.44 NYMEX WTI Crude Sold Calls: Notional volume (Bbl) 2,250,000 9,300,000 Weighted average sold call price ($/Bbl) $ 58.33 $ 64.78 NYMEX WTI Crude Sold Puts: Notional volume (Bbl) 3,300,000 8,700,000 Weighted average sold put price ($/Bbl) $ 40.00 $ 41.69 NYMEX HH Natural Gas Swaps: Notional volume (MMBtu) 9,900,000 25,800,000 Weighted average fixed price ($/MMBtu) $ 3.02 $ 2.77 NYMEX HH Natural Gas Purchased Puts: Notional volume (MMBtu) 600,000 3,000,000 Weighted average purchased put price ($/MMBtu) $ 3.00 $ 2.99 NYMEX HH Natural Gas Sold Calls: Notional volume (MMBtu) 600,000 3,000,000 Weighted average sold call price ($/MMBtu) $ 3.15 $ 3.36 NYMEX HH Natural Gas Sold Puts: Notional volume (MMBtu) — 3,000,000 Weighted average sold put price ($/MMBtu) $ — $ 2.50 CIG Basis Gas Swaps: Notional volume (MMBtu) 11,040,000 31,200,000 Weighted average fixed basis price ($/MMBtu) $ (0.68 ) $ (0.75 ) 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 condensed consolidated balance sheets (in thousands): As of September 30, 2018 Location on Balance Sheet Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offsets in the Balance Sheet (1) Net Amounts of Assets and Liabilities Presented in the Balance Sheet Gross Amounts not Offset in the Balance Sheet (2) Net Amounts (3) Current assets $ 92,161 $ (78,935 ) $ 13,226 $ (2,145 ) $ 11,081 Non-current assets $ 7,085 $ (7,085 ) $ — $ — $ — Current liabilities $ (222,511 ) $ 78,935 $ (143,576 ) $ 2,145 $ (150,217 ) Non-current liabilities $ (15,871 ) $ 7,085 $ (8,786 ) $ — $ — As of December 31, 2017 Location on Balance Sheet Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offsets in the Balance Sheet (1) Net Amounts of Assets and Liabilities Presented in the Balance Sheet Gross Amounts not Offset in the Balance Sheet (2) Net 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 ) $ — $ — (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 condensed consolidated balance sheets. 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 three and nine months ended September 30, 2018 and 2017 (in thousands). Commodity derivatives gain (loss) is included under the other income (expense) line item in the condensed consolidated statements of operations. For the Three Months Ended September 30, For the Nine Months Ended September 30, 2018 2017 2018 2017 Commodity derivatives gain (loss) $ (35,913 ) $ (37,875 ) $ (175,752 ) $ 46,423

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2018
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 period indicated (in thousands): For the Nine Months Ended September 30, 2018 For the Year Ended December 31, 2017 Balance beginning of period $ 69,540 $ 56,108 Liabilities incurred or acquired 1,705 9,802 Liabilities settled (9,581 ) (4,169 ) Revisions in estimated cash flows 3,698 2,630 Accretion expense 3,989 5,169 Balance end of period $ 69,351 $ 69,540

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2018
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 September 30, 2018 and December 31, 2017 by level within the fair value hierarchy (in thousands): Fair Value Measurements at Level 1 Level 2 Level 3 Total Financial Assets: Commodity derivative assets $ — $ 13,226 $ — $ 13,226 Financial Liabilities: Commodity derivative liabilities $ — $ 152,362 $ — $ 152,362 Fair Value Measurements at 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 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 values of the 2021 Senior Notes, 2024 Senior Notes and 2026 Senior Notes were derived from available market data. As such, the Company has classified the 2021 Senior Notes, 2024 Senior Notes and 2026 Senior Notes as Level 2. Please refer to Note 4 - 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 September 30, 2018 At December 31, 2017 Carrying Amount Fair Value Carrying Amount Fair Value Credit Facility $ 290,000 $ 290,000 $ 90,000 $ 90,000 2021 Senior Notes (1) $ — $ — $ 540,382 $ 583,000 2024 Senior Notes (2) $ 393,638 $ 393,520 $ 392,979 $ 427,000 2026 Senior Notes (3) $ 738,477 $ 667,500 $ — $ — (1) The carrying amount of the 2021 Senior Notes includes unamortized debt issuance costs of $9.6 million as of December 31, 2017 . There were no unamortized debt issuance costs as of September 30, 2018 . (2) The carrying amount of the 2024 Senior Notes includes unamortized debt issuance costs of $6.4 million and $7.0 million as of September 30, 2018 and December 31, 2017 , respectively. (3) The carrying amount of the 2026 Senior Notes includes unamortized debt issuance costs of $11.5 million as of September 30, 2018 . There were no unamortized debt issuance costs 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 and circumstances arise that indicate a need for remeasurement. 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, and at least annually, 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 include 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 and 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). For the three and nine months ended September 30, 2018 , the Company recognized $16.2 million in impairment expense on its proved oil and gas properties related to impairment of assets in its northern field. The fair value did not exceed the Company's carrying amount associated with its proved oil and gas properties in its northern field. No impairment expense was recognized for the three and nine months ended September 30, 2017 on proved oil and gas properties. The Company applies the provisions of ASC 350, Intangibles-Goodwill and Other . Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. The Company tests goodwill for impairment annually on September 30, or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. The goodwill test is performed at the reporting unit level, which represents the Company’s oil and gas operations in its core DJ Basin field. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. Any sharp prolonged decreases in the prices of oil and natural gas as well as continued declines in the quoted market price of the Company’s common shares could change the estimates of the fair value of the reporting unit and could result in an impairment charge. The Company uses an income approach analysis based on the net discounted future cash flows of producing property utilizing market participant inputs. The future cash flows are based on Management’s estimates for the future. Unobservable inputs include estimates of oil and gas production, as the case may be, from the Company’s reserve reports, commodity prices based on 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). The Company performed a quantitative assessment as of September 30, 2018 , which concluded the fair value of the reporting unit was greater than its carrying amount. The Company’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 3 — Acquisitions and Divestitures . 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.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The Company computes an estimated annual effective rate each quarter based on the current and forecasted operating results. The income tax expense or benefit associated with the interim period is computed using the most recent estimated annual effective rate applied to the year-to-date ordinary income or loss, plus the tax effect of any significant discrete or infrequently occurring items recorded during the interim period. The computation of the annual estimated effective tax rate at each interim period requires certain estimates and significant judgment including, but not limited to, the expected operating income (loss) for the year, projections of the proportion of income earned and taxed in various jurisdictions, permanent differences and the likelihood of recovering deferred tax assets generated in the current year. The accounting estimates used to compute the provision for income taxes may change as new events occur, more experience is obtained and additional information becomes known or as the tax environment changes. The effective combined U.S. federal and state income tax rate for the nine months ended September 30, 2018 was 35.9% . During the nine months ended September 30, 2018 , the Company recognized income tax expense of $12.3 million . The effective rate for the nine months ended September 30, 2018 differs from the statutory U.S. federal income tax rate of 21.0% primarily due to state income taxes and estimated permanent differences. The most significant difference during the nine months ended September 30, 2018 was a discrete item regarding the tax deficiency of the stock-based compensation compared to the compensation recognized for financial reporting purposes. The Company anticipates the potential for increased periodic volatility in future effective tax rates from the impact of stock-based compensation tax deductions as they are treated as discrete tax items. On December 22, 2017, the Tax Cut and Jobs Act (the "TCJA") was enacted, making significant changes to the Internal Revenue Code. The Company calculated its best estimate of the impact of the TCJA in its December 31, 2017 income tax provision in accordance with its understanding of the TCJA and guidance available as of the date of that filing. During the nine months ended September 30, 2018 , the Company completed the accounting for the income tax effect of the TCJA's limit on compensation under Internal Revenue Code Sec. 162(m) and stock-based compensation for covered employees. This resulted in a $0.4 million reduction in deferred tax assets that had been recorded as a provisional amount as of December 31, 2017 . There are no remaining provision amounts associated with the TCJA as of September 30, 2018 .

Unit and Stock-Based Compensati

Unit and Stock-Based Compensation	9 Months Ended
	Sep. 30, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Unit and Stock-Based Compensation	Stock‑Based Compensation Extraction Long Term Incentive Plan In October 2016, the Company’s 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. The Company reserved 20.2 million shares of common stock 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 Restricted stock units granted under the LTIP (“RSUs”) generally vest over either a one or three-year service period, with 100% vesting in year one or 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 $7.1 million and $20.7 million of stock-based compensation costs related to RSUs for the three and nine months ended September 30, 2018 , respectively, as compared to $3.3 million and $9.9 million for the three and nine months ended September 30, 2017 , respectively. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of September 30, 2018 , there was $38.7 million of total unrecognized compensation cost related to the unvested RSUs granted to certain directors, officers and employees that is expected to be recognized over a weighted average period of 1.6 years . The following table summarizes the RSU activity from January 1, 2018 through September 30, 2018 and provides information for RSUs outstanding at the dates indicated. Number of Shares Weighted Average Grant Date Fair Value Non-vested RSUs at January 1, 2018 2,906,473 $ 19.51 Granted 1,121,768 $ 12.82 Forfeited (45,150) $ 15.91 Vested (317,161) $ 15.90 Non-vested RSUs at September 30, 2018 3,665,930 $ 17.80 Stock Options Expense on the stock options is recognized on a straight-line basis over the service period of the award less awards forfeited. The fair value of the stock options was 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 will issue new shares. The Company recorded $3.8 million and $11.3 million of stock-based compensation costs related to the stock options for the three and nine months ended September 30, 2018 , respectively, as compared to $3.3 million and $9.9 million for the three and nine months ended September 30, 2017 , respectively. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of September 30, 2018 , there was $15.9 million of unrecognized compensation cost related to the stock options that is expected to be recognized over a weighted average period of 1.1 years . The following table summarizes the stock option activity from January 1, 2018 through September 30, 2018 and provides information for stock options outstanding at the dates indicated. Number of Options Weighted Average Exercise Price Non-vested Stock Options at January 1, 2018 3,496,290 $ 18.50 Granted — $ — Forfeited — $ — Vested — $ — Non-vested Stock Options at September 30, 2018 3,496,290 $ 18.50 Performance Stock Awards The Company granted performance stock awards ("PSAs") to certain executives under the LTIP in October 2017 and March 2018. 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. Generally, the shares issued for PSAs are determined based on the satisfaction of a time-based vesting schedule and a weighting of one or more of the following: i) absolute total stockholder return ("ATSR"), ii) relative total stockholder return ("RTSR"), as compared to the Company's peer group and iii) cash return on capital invested ("CROCI") measured over a three year period and vest in their entirety at the end of the three-year measurement period. Any PSAs that have not vested at the end of the applicable measurement period are forfeited. The vesting criterion that is associated with the RTSR is based on a comparison of the Company's shareholder return for the measurement period compared to that of a group of peer companies for the same measurement period. As the ATSR and RTSR vesting criteria are linked to the Company's share price, they each are considered a market condition for purposes of calculating the grant-date fair value of the awards. The vesting criterion that is associated with the CROCI is considered a performance 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 will 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 Company recorded $1.6 million and $4.2 million of stock-based compensation costs related to PSAs for the three and nine months ended September 30, 2018 , respectively. The Company did not record any stock-based compensation related to PSAs for the three and nine months ended September 30, 2017 . These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. The outstanding and unvested shares were included in the condensed consolidated statement of stockholders' equity within the stock-based compensation line item. As of September 30, 2018 , there was $10.7 million of total unrecognized compensation cost related to the unvested PSAs granted to certain executives 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, 2018 through September 30, 2018 and provides information for PSAs outstanding at the dates indicated. Number of Shares (1) Weighted Average Grant Date Fair Value Non-vested PSAs at January 1, 2018 832,163 $ 8.85 Granted 1,961,920 $ 9.06 Forfeited — $ — Vested — $ — Non-vested PSAs at September 30, 2018 2,794,083 $ 9.00 (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 Officers of the Company 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 vested over a three -year service period, with 25% , 25% and 50% of the units vesting in year one , two and three , respectively. On July 17, 2017, the partners of Employee Incentive amended the vesting schedule in which 25% vested immediately and the remaining Incentive RSUs vest 25% , 25% and 25% each six months thereafter, over the remaining 18-month 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. As the vesting of any Incentive RSUs will be satisfied with shares of common stock that are already issued and outstanding, the Incentive RSUs do not have any impact on the Company’s diluted earnings per share calculation. The Company recorded $4.9 million and $14.7 million of stock-based compensation costs related to Incentive RSUs for the three and nine months ended September 30, 2018 , respectively. The Company recorded $5.9 million and $12.2 million of stock-based compensation costs related to Incentive RSUs for the three and nine months ended September 30, 2017 . These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of September 30, 2018 , there was $5.7 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 0.3 years . The following table summarizes the Incentive RSU activity from January 1, 2018 through September 30, 2018 and provides information for Incentive RSUs outstanding at the dates indicated. Number of Shares Weighted Average Grant Date Fair Value Non-vested Incentive RSUs at January 1, 2018 1,496,175 $ 20.45 Granted — $ — Forfeited (41,400) $ 20.45 Vested (978,775) $ 20.45 Non-vested Incentive RSUs at September 30, 2018 476,000 $ 20.45

Earnings (Loss) Per Share

Earnings (Loss) Per Share	9 Months Ended
	Sep. 30, 2018
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) available to common shareholders by the weighted average number of shares outstanding during the period. Diluted EPS reflects the potential dilution of securities that could share in the earnings of the Company. The Company uses the “if-converted” method to determine potential dilutive effects of the Company’s outstanding Series A Preferred Stock (the “Series A Preferred Stock”) and the treasury method to determine the potential dilutive effects of outstanding restricted stock awards and stock options. The basic weighted average shares outstanding calculation is based on the actual days in which the shares were outstanding for the three and nine months ended September 30, 2018 and 2017 . The components of basic and diluted EPS were as follows (in thousands, except per share data): For the Three Months Ended For the Nine Months Ended September 30, September 30, 2018 2017 2018 2017 Basic and Diluted Income (Loss) Per Share Net Income (Loss) $ 65,150 $ (29,796 ) $ 22,003 $ (13,840 ) Less: Noncontrolling Interest (3,305 ) — (3,305 ) — Less: Adjustment to reflect Series A Preferred Stock dividends (2,721 ) (2,721 ) (8,164 ) (8,164 ) Less: Adjustment to reflect accretion of Series A Preferred Stock discount (1,515 ) (1,365 ) (4,429 ) (3,992 ) Adjusted net income (loss) available to common shareholders, basic and diluted $ 57,609 $ (33,882 ) $ 6,105 $ (25,996 ) Denominator: Weighted average common shares outstanding, basic and diluted (1) (2) 175,814 171,845 175,269 171,838 Income (Loss) Per Common Share Basic and diluted $ 0.33 $ (0.20 ) $ 0.03 $ (0.15 ) (1) For the three months ended September 30, 2018 , 347,343 dilutive restricted stock awards were excluded from the calculation above, as the impact of these awards were inconsequential to dilutive weighted average shares outstanding and dilutive EPS. Additionally, 5,244,428 common shares for stock options were excluded as they were out-of-the-money and 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were excluded, as they would have had an anti-dilutive effect on EPS. For the nine months ended September 30, 2018 , 537,706 dilutive restricted stock awards were excluded from the calculation above, as the impact of these awards were inconsequential to dilutive weighted average shares outstanding and dilutive EPS. Additionally, 5,244,428 common shares for stock options were excluded as they were out-of-the-money and 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were excluded, as they would have had an anti-dilutive effect on EPS. (2) For the three and nine months ended September 30, 2017 , 8,552,814 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. Additionally, 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded, as they would have had an anti-dilutive effect on EPS.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2018
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 October 31, 2019, June 30, 2019 and January 31, 2022, respectively. Total rental commitments under non‑cancelable leases for office space were $33.6 million at September 30, 2018 . The future minimum lease payments under these non‑cancelable leases are as follows: $0.8 million in 2018 , $3.5 million in 2019 , $3.4 million in 2020 , $3.4 million in 2021 , $3.4 million in 2022 and $19.1 million thereafter. Rent expense was $1.0 million and $2.7 million for the three and nine months ended September 30, 2018 , respectively, as compared to $0.5 million and $1.7 million for the three and nine months ended September 30, 2017 , 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 $0.4 million . Drilling Rigs As of September 30, 2018 , the Company was subject to commitments on three drilling rigs, contracted through November 2018, February 2019 and May 2019, respectively. In the event of early termination of these contracts, the Company would be obligated to pay an aggregate amount of approximately $7.3 million as of September 30, 2018 , as required under the terms of the contracts. Delivery Commitments As of September 30, 2018 , the Company’s oil marketer was 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 two long-term crude oil gathering commitments with an unconsolidated subsidiary, in which the Company has a minority ownership interest. The first agreement commenced in November 2016 and has a term of ten years for an average of 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 second agreement will commence in or around July 2019 and has a term of ten years for an average of 8,000 Bbl/d in year one, 20,000 Bbl/d in year two, 35,000 Bbl/d in year three, 40,000 Bbl/d in years four through eight, 30,000 Bbl/d in year nine and 25,000 Bbl/d in year ten. The aggregate amount of estimated remaining payments under these agreements is $967.5 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. The first plant commenced operations in August 2018 and the second plant is expected to be completed by mid-2019, although the exact start-up date is undetermined at this time. The Company’s share of these commitments will require 51.5 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 during 2017 with an unrelated third party for which it has paid $247.6 million through September 30, 2018 to complete its leasing program of approximately 38,800 net acres of undeveloped leasehold. 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 From time to time, the Company is party to ongoing legal proceedings in the ordinary course of business. While the outcome of these proceedings cannot be predicted with certainty, the Company does not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on the Company's business, financial condition, results of operations or liquidity.

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2018
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. 2021 Senior Notes Several 5% stockholders of the Company were also holders of the 2021 Senior Notes prior to the Tender Offer and the redemption of the 2021 Senior Notes. As of the initial issuance in July 2016 of the $550.0 million principal amount on the 2021 Senior Notes, such stockholders held $63.5 million . 2024 Senior Notes Several holders 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 holders 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 . Increased Ownership in an Unconsolidated Subsidiary In May 2018, the Company exercised an option to increase its ownership percentage in an unconsolidated subsidiary funded with a $35.3 million promissory note. This note was extinguished with the transfer of units to the unconsolidated subsidiary. The Company also contributed an acreage dedication and minimum volume commitment.

Basis of Presentation, Signif_2

Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements (Policies)	9 Months Ended
	Sep. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Basis of Presentation The unaudited condensed 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”) and the Securities and Exchange Commission rules and regulation for interim financial reporting. In the opinion of management, all adjustments, consisting primarily of normal recurring accruals that are considered necessary for a fair statement of the condensed consolidated financial information, have been included. However, operating results for the period presented are not necessarily indicative of the results that may be expected for a full year. Interim condensed consolidated financial statements and the year-end balance sheet do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes included in the Company’s Annual Report.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In August 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2018-15, which aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software and hosting arrangements that include an internal-use software license. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019, including interim reporting periods within that reporting period. The Company is currently evaluating this new standard to determine the potential impact to its financial statements and related disclosures. In August 2018, the FASB issued ASU No. 2018-13, which improves the disclosure requirements on fair value measurements. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019, including interim reporting periods within that reporting period. The Company is currently evaluating this new standard to determine the potential impact to its financial statements and related disclosures. In May 2017, the FASB issued ASU No. 2017-09, which provides clarification and reduces both (1) diversity in practice and (2) cost and complexity when applying the guidance in Topic 718 Compensation - Stock Compensation, to a change to the terms or conditions of a share-based payment award. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that reporting period. The Company adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial statements and related disclosures. In February 2017, the FASB issued ASU No. 2017-05, which provided clarification regarding the guidance on accounting for the derecognition of nonfinancial assets. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that fiscal year. The Company adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial statements and related disclosures. In January 2017, the FASB issued ASU No. 2017-04, which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019. Early adoption is permitted for interim and annual goodwill impairment tests performed on testing dates after January 1, 2017. The Company is currently evaluating the impact of adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements and related disclosures. In January 2017, the FASB issued ASU No. 2017-01, which clarifies the definition of a business when evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial statements and related disclosures; however, this standard may result in more transactions being accounted for as asset acquisitions rather than business combinations. In November 2016, the FASB issued ASU No. 2016-18, which intends to clarify how entities should present restricted cash and restricted cash equivalents in the statement of cash flows. This amendment was effective retrospectively for reporting periods beginning after December 15, 2017. The Company adopted this ASU on January 1, 2018 and the retrospective adoption increased the Company's beginning cash balances within the statement of cash flows for the prior period presented in the table below. The adoption had no other material impact on the cash flow statement and had no impact on the Company's results of operations or financial position. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets to the consolidated statement of cash flows: As of September 30, December 31, September 30, December 31, 2018 2017 2017 2016 Cash and cash equivalents $ 274,065 $ 6,768 $ 114,139 $ 588,736 Restricted cash included in cash held in escrow — — — 42,200 $ 274,065 $ 6,768 $ 114,139 $ 630,936 In August 2016, the FASB issued ASU No. 2016-15, which addresses eight specific cash flow issues, including presentation of debt prepayments or debt extinguishment costs, with the objective of reducing the existing diversity in practice. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company adopted this ASU on January 1, 2018, which requires current period make-whole premiums to be presented in financing activities in the statement of cash flows and prior period debt prepayment costs to be reclassified from operating activities to financing activities in the statement of cash flows; however, there will be no impact to the total change in cash and cash equivalents from period to period. In February 2016, the FASB issued ASU No. 2016-02, which requires lessee recognition on the balance sheet of a right of use asset and a lease liability, initially measured at the present value of the lease payments. It further requires recognition in the income statement of a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis. Finally, it requires classification of all cash payments within operating activities in the statements of cash flows. It is effective for fiscal years commencing after December 15, 2018 and early adoption is permitted. The FASB subsequently issued ASU No. 2017-13, ASU No. 2018-01, ASU No. 2018-10 and ASU No. 2018-11, which provided additional implementation guidance. The Company is currently evaluating the impact this ASU will have on the consolidated financial statements and related disclosures and expects certain lease agreements with terms over one year to be classified as right-of-use assets and right-of-use liabilities, which will gross up the consolidated balance sheet as of January 1, 2019. As a part of the implementation work, the Company is finalizing its initial conclusions with its external consulting firm, implementing a software tool used to calculate the initial and ongoing accounting balances for right-of-use assets and liabilities, and is assessing the completeness of the lease population. In May 2014, the FASB issued ASU No. 2014-09, which establishes a comprehensive new revenue recognition model, referred to as ASC 606 - Revenue from Contracts with Customers, designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The ASU allows for the use of either the full or modified retrospective transition method. In August 2015, the FASB issued ASU No. 2015-14, which deferred ASU No. 2014-09 for one year, and was effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. The FASB subsequently issued ASU No. 2016-08, ASU No. 2016-10, ASU No. 2016-11, ASU No. 2016-12, ASU No. 2016-20, ASU No. 2017-13 and ASU No. 2017-14, which provided additional implementation guidance. Refer to —Adoption of ASC 606 for more information.

Basis of Presentation, Signif_3

Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements (Tables)	9 Months Ended
	Sep. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Restrictions on Cash and Cash Equivalents [Table Text Block]	The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets to the consolidated statement of cash flows: As of September 30, December 31, September 30, December 31, 2018 2017 2017 2016 Cash and cash equivalents $ 274,065 $ 6,768 $ 114,139 $ 588,736 Restricted cash included in cash held in escrow — — — 42,200 $ 274,065 $ 6,768 $ 114,139 $ 630,936
Schedule of Cash and Cash Equivalents [Table Text Block]	The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets to the consolidated statement of cash flows: As of September 30, December 31, September 30, December 31, 2018 2017 2017 2016 Cash and cash equivalents $ 274,065 $ 6,768 $ 114,139 $ 588,736 Restricted cash included in cash held in escrow — — — 42,200 $ 274,065 $ 6,768 $ 114,139 $ 630,936
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]	The impact of adoption in the current period results are as follows (in thousands): For the Three Months Ended For the Nine Months Ended Under ASC 606 Under ASC 605 Change Under ASC 606 Under ASC 605 Change Revenues: Oil sales $ 225,467 $ 225,467 $ — $ 619,211 $ 619,211 $ — Natural gas sales 23,103 26,394 (3,291 ) 66,991 76,492 (9,501 ) NGL sales 33,590 39,154 (5,564 ) 86,369 101,349 (14,980 ) Total Revenues 282,160 291,015 (8,855 ) 772,571 797,052 (24,481 ) Operating Expenses: Transportation and gathering $ 11,786 $ 20,641 $ (8,855 ) $ 29,284 $ 53,765 $ (24,481 ) Net Income $ 65,150 $ 65,150 $ — $ 22,003 $ 22,003 $ —
Disaggregation of Revenue [Table Text Block]	The following table presents the Company's revenues disaggregated by revenue source. Transportation and gathering costs in the following table are not all of the transportation and gathering expenses that the Company incurs, only the expenses that are netted against revenues pursuant to ASC 606. Prior period amounts have not been adjusted under the modified retrospective method. For the Three Months For the Nine Months 2018 2017 2018 2017 Revenues: Oil sales $ 225,467 $ 132,075 $ 619,211 $ 269,597 Natural gas sales 26,394 24,672 76,492 63,095 NGL sales 39,154 24,114 101,349 57,574 Transportation and gathering included in revenues (8,855 ) — (24,481 ) — Total Revenues $ 282,160 $ 180,861 $ 772,571 $ 390,266

Acquisitions (Tables)

Acquisitions (Tables)	9 Months Ended
	Sep. 30, 2018
Acquisitions
Schedule of Pro Forma Financial Information	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 integrate the properties acquired. Asset acquisitions are not included in pro forma financial information, as it is not required. 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. For the Three Months Ended September 30, For the Nine Months Ended September 30, 2017 2017 Revenues $ 180,861 $ 392,430 Operating expenses $ 175,699 $ 427,912 Net loss $ (29,796 ) $ (13,663 ) Loss per common share, basic and diluted $ (0.20 ) $ (0.15 )
June 2017 Acquisition
Acquisitions
Schedule summarizing the purchase price and allocation of fair value of assets acquired and liabilities assumed	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

Long Term Debt (Tables)

Long Term Debt (Tables)	9 Months Ended
	Sep. 30, 2018
Debt Instrument [Line Items]
Schedule of long-term debt	As of the dates indicated, the Company’s long‑term debt consisted of the following (in thousands): September 30, December 31, Credit facility due August 16, 2022 (or an earlier time as set forth in the credit facility) $ 290,000 $ 90,000 2021 Senior Notes due July 15, 2021 — 550,000 2024 Senior Notes due May 15, 2024 400,000 400,000 2026 Senior Notes due February 1, 2026 750,000 — Unamortized debt issuance costs on Senior Notes (17,885 ) (16,639 ) Total long-term debt 1,422,115 1,023,361 Less: current portion of long-term debt — — Total long-term debt, net of current portion $ 1,422,115 $ 1,023,361
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 Borrowing Base Utilization Percentage Utilization Eurodollar Margin Base Rate Margin Commitment Fee Rate Level 1 < 25% 1.50 % 0.50 % 0.375 % Level 2 ≥ 25% < 50% 1.75 % 0.75 % 0.375 % Level 3 ≥ 50% < 75% 2.00 % 1.00 % 0.500 % Level 4 ≥ 75% < 90% 2.25 % 1.25 % 0.500 % Level 5 ≥ 90% 2.50 % 1.50 % 0.500 %

Commodity Derivative Instrume_2

Commodity Derivative Instruments (Tables)	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of commodity derivative contracts	The Company’s commodity derivative contracts as of September 30, 2018 are summarized below: 2018 2019 NYMEX WTI Crude Swaps: Notional volume (Bbl) 1,050,000 — Weighted average fixed price ($/Bbl) $ 52.91 $ — NYMEX WTI Crude Purchased Puts: Notional volume (Bbl) 2,250,000 9,300,000 Weighted average purchased put price ($/Bbl) $ 49.81 $ 51.44 NYMEX WTI Crude Sold Calls: Notional volume (Bbl) 2,250,000 9,300,000 Weighted average sold call price ($/Bbl) $ 58.33 $ 64.78 NYMEX WTI Crude Sold Puts: Notional volume (Bbl) 3,300,000 8,700,000 Weighted average sold put price ($/Bbl) $ 40.00 $ 41.69 NYMEX HH Natural Gas Swaps: Notional volume (MMBtu) 9,900,000 25,800,000 Weighted average fixed price ($/MMBtu) $ 3.02 $ 2.77 NYMEX HH Natural Gas Purchased Puts: Notional volume (MMBtu) 600,000 3,000,000 Weighted average purchased put price ($/MMBtu) $ 3.00 $ 2.99 NYMEX HH Natural Gas Sold Calls: Notional volume (MMBtu) 600,000 3,000,000 Weighted average sold call price ($/MMBtu) $ 3.15 $ 3.36 NYMEX HH Natural Gas Sold Puts: Notional volume (MMBtu) — 3,000,000 Weighted average sold put price ($/MMBtu) $ — $ 2.50 CIG Basis Gas Swaps: Notional volume (MMBtu) 11,040,000 31,200,000 Weighted average fixed basis price ($/MMBtu) $ (0.68 ) $ (0.75 )
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 condensed consolidated balance sheets (in thousands): As of September 30, 2018 Location on Balance Sheet Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offsets in the Balance Sheet (1) Net Amounts of Assets and Liabilities Presented in the Balance Sheet Gross Amounts not Offset in the Balance Sheet (2) Net Amounts (3) Current assets $ 92,161 $ (78,935 ) $ 13,226 $ (2,145 ) $ 11,081 Non-current assets $ 7,085 $ (7,085 ) $ — $ — $ — Current liabilities $ (222,511 ) $ 78,935 $ (143,576 ) $ 2,145 $ (150,217 ) Non-current liabilities $ (15,871 ) $ 7,085 $ (8,786 ) $ — $ — As of December 31, 2017 Location on Balance Sheet Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offsets in the Balance Sheet (1) Net Amounts of Assets and Liabilities Presented in the Balance Sheet Gross Amounts not Offset in the Balance Sheet (2) Net 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 ) $ — $ — (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 condensed consolidated balance sheets. 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 three and nine months ended September 30, 2018 and 2017 (in thousands). Commodity derivatives gain (loss) is included under the other income (expense) line item in the condensed consolidated statements of operations. For the Three Months Ended September 30, For the Nine Months Ended September 30, 2018 2017 2018 2017 Commodity derivatives gain (loss) $ (35,913 ) $ (37,875 ) $ (175,752 ) $ 46,423

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
Schedule summarizing activities of asset retirement obligaions	The following table summarizes the activities of the Company’s asset retirement obligations for the period indicated (in thousands): For the Nine Months Ended September 30, 2018 For the Year Ended December 31, 2017 Balance beginning of period $ 69,540 $ 56,108 Liabilities incurred or acquired 1,705 9,802 Liabilities settled (9,581 ) (4,169 ) Revisions in estimated cash flows 3,698 2,630 Accretion expense 3,989 5,169 Balance end of period $ 69,351 $ 69,540

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2018
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 September 30, 2018 and December 31, 2017 by level within the fair value hierarchy (in thousands): Fair Value Measurements at Level 1 Level 2 Level 3 Total Financial Assets: Commodity derivative assets $ — $ 13,226 $ — $ 13,226 Financial Liabilities: Commodity derivative liabilities $ — $ 152,362 $ — $ 152,362 Fair Value Measurements at 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
Schedule of fair value of financial instruments	At September 30, 2018 At December 31, 2017 Carrying Amount Fair Value Carrying Amount Fair Value Credit Facility $ 290,000 $ 290,000 $ 90,000 $ 90,000 2021 Senior Notes (1) $ — $ — $ 540,382 $ 583,000 2024 Senior Notes (2) $ 393,638 $ 393,520 $ 392,979 $ 427,000 2026 Senior Notes (3) $ 738,477 $ 667,500 $ — $ — (1) The carrying amount of the 2021 Senior Notes includes unamortized debt issuance costs of $9.6 million as of December 31, 2017 . There were no unamortized debt issuance costs as of September 30, 2018 .

Unit and Stock-Based Compensa_2

Unit and Stock-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2018
Unit and Stock-Based Compensation
Schedule summarizing stock option activity	The following table summarizes the stock option activity from January 1, 2018 through September 30, 2018 and provides information for stock options outstanding at the dates indicated. Number of Options Weighted Average Exercise Price Non-vested Stock Options at January 1, 2018 3,496,290 $ 18.50 Granted — $ — Forfeited — $ — Vested — $ — Non-vested Stock Options at September 30, 2018 3,496,290 $ 18.50
Schedule of non-vested restricted award activity	The following table summarizes the PSA activity from January 1, 2018 through September 30, 2018 and provides information for PSAs outstanding at the dates indicated. Number of Shares (1) Weighted Average Grant Date Fair Value Non-vested PSAs at January 1, 2018 832,163 $ 8.85 Granted 1,961,920 $ 9.06 Forfeited — $ — Vested — $ — Non-vested PSAs at September 30, 2018 2,794,083 $ 9.00
Incentive RSUs
Unit and Stock-Based Compensation
Schedule of non-vested restricted award activity	The following table summarizes the Incentive RSU activity from January 1, 2018 through September 30, 2018 and provides information for Incentive RSUs outstanding at the dates indicated. Number of Shares Weighted Average Grant Date Fair Value Non-vested Incentive RSUs at January 1, 2018 1,496,175 $ 20.45 Granted — $ — Forfeited (41,400) $ 20.45 Vested (978,775) $ 20.45 Non-vested Incentive RSUs at September 30, 2018 476,000 $ 20.45

Earnings (Loss) Per Share (Tabl

Earnings (Loss) Per Share (Tables)	9 Months Ended
	Sep. 30, 2018
Earnings Per Share [Abstract]
Earnings (Loss) Per Share	The components of basic and diluted EPS were as follows (in thousands, except per share data): For the Three Months Ended For the Nine Months Ended September 30, September 30, 2018 2017 2018 2017 Basic and Diluted Income (Loss) Per Share Net Income (Loss) $ 65,150 $ (29,796 ) $ 22,003 $ (13,840 ) Less: Noncontrolling Interest (3,305 ) — (3,305 ) — Less: Adjustment to reflect Series A Preferred Stock dividends (2,721 ) (2,721 ) (8,164 ) (8,164 ) Less: Adjustment to reflect accretion of Series A Preferred Stock discount (1,515 ) (1,365 ) (4,429 ) (3,992 ) Adjusted net income (loss) available to common shareholders, basic and diluted $ 57,609 $ (33,882 ) $ 6,105 $ (25,996 ) Denominator: Weighted average common shares outstanding, basic and diluted (1) (2) 175,814 171,845 175,269 171,838 Income (Loss) Per Common Share Basic and diluted $ 0.33 $ (0.20 ) $ 0.03 $ (0.15 ) (1) For the three months ended September 30, 2018 , 347,343 dilutive restricted stock awards were excluded from the calculation above, as the impact of these awards were inconsequential to dilutive weighted average shares outstanding and dilutive EPS. Additionally, 5,244,428 common shares for stock options were excluded as they were out-of-the-money and 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were excluded, as they would have had an anti-dilutive effect on EPS. For the nine months ended September 30, 2018 , 537,706 dilutive restricted stock awards were excluded from the calculation above, as the impact of these awards were inconsequential to dilutive weighted average shares outstanding and dilutive EPS. Additionally, 5,244,428 common shares for stock options were excluded as they were out-of-the-money and 11,472,445

Business and Organization Eleva

Business and Organization Elevation Securities Purchase Agreement (Details) - USD ($) $ / shares in Units, $ in Millions	28 Months Ended
	Nov. 03, 2020	Jul. 03, 2018
Subsequent Event [Line Items]
Elevation Preferred Units		150,000
Elevation Price Per Unit		$ 990
Elevation Private Placement		$ 150
Elevation Private Placement, Net Proceeds		141.9
Elevation Proceeds, Reimbursement		25.4
Elevation Incremental Commitment Increase		$ 25
Elevation Quarterly Commitment Fee		1.00%
Elevation Quarterly Preferred Unit Dividend Rate		8.00%
Preferred Units [Member]
Subsequent Event [Line Items]
Elevation Additional Preferred Unit Purchase		$ 350
Scenario, Forecast [Member]
Subsequent Event [Line Items]
Elevation Private Placement Commitment Period	28 months

Basis of Presentation, Signif_4

Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements - Schedule of Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Cash and cash equivalents	$ 274,065	$ 6,768	$ 114,139	$ 588,736
Schedule of Cash and Cash Equivalents [Table Text Block]	The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets to the consolidated statement of cash flows: As of September 30, December 31, September 30, December 31, 2018 2017 2017 2016 Cash and cash equivalents $ 274,065 $ 6,768 $ 114,139 $ 588,736 Restricted cash included in cash held in escrow — — — 42,200 $ 274,065 $ 6,768 $ 114,139 $ 630,936
Restricted Cash and Cash Equivalents	$ 0	0	0	42,200
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 274,065	$ 6,768	$ 114,139	$ 630,936

Basis of Presentation, Signif_5

Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements - Schedule of Changes Due to Recent Accounting Pronouncements (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	$ 282,160	$ 180,861	$ 772,571	$ 390,266
Net loss	65,150	(29,796)	22,003	(13,840)
Under ASC 605
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	291,015		797,052
Net loss	65,150		22,003
Accounting Standards Update 2014-09 | Change
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	(8,855)		(24,481)
Net loss	0		0
Oil sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	225,467	132,075	619,211	269,597
Oil sales | Under ASC 605
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	225,467		619,211
Oil sales | Accounting Standards Update 2014-09 | Change
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	0		0
Natural gas sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	26,394	24,672	76,492	63,095
Natural gas sales | Under ASC 605
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	26,394		76,492
Natural gas sales | Accounting Standards Update 2014-09
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	23,103		66,991
Natural gas sales | Accounting Standards Update 2014-09 | Change
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	(3,291)		(9,501)
NGL sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	39,154	24,114	101,349	57,574
NGL sales | Under ASC 605
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	39,154		101,349
NGL sales | Accounting Standards Update 2014-09
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	33,590		86,369
NGL sales | Accounting Standards Update 2014-09 | Change
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	(5,564)		(14,980)
Transportation and gathering
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Transportation and gathering	11,786	$ 0	29,284	$ 0
Transportation and gathering | Under ASC 605
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Transportation and gathering	20,641		53,765
Transportation and gathering | Accounting Standards Update 2014-09
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Transportation and gathering	(8,855)		(24,481)
Transportation and gathering | Accounting Standards Update 2014-09 | Change
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Transportation and gathering	$ (8,855)		$ (24,481)

Basis of Presentation, Signif_6

Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	$ 282,160	$ 180,861	$ 772,571	$ 390,266
Oil sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	225,467	132,075	619,211	269,597
Natural gas sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	26,394	24,672	76,492	63,095
NGL sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	39,154	24,114	101,349	57,574
Transportation and gathering included in revenues
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Transportation and gathering included in revenues	11,786	$ 0	29,284	$ 0
Accounting Standards Update 2014-09 | Natural gas sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	23,103		66,991
Accounting Standards Update 2014-09 | NGL sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenues	33,590		86,369
Accounting Standards Update 2014-09 | Transportation and gathering included in revenues
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Transportation and gathering included in revenues	$ (8,855)		$ (24,481)

Acquisitions - July 2017 Acquis

Acquisitions - July 2017 Acquisition (Details) $ in Millions	Apr. 19, 2018USD ($)	Jan. 08, 2018USD ($)	Nov. 15, 2017USD ($)	Jul. 07, 2017USD ($)a
Acquisitions
Purchase price	$ 9.4	$ 11.6	$ 214.3
July 2017 Acquisition
Acquisitions
Acres acquired or to be acquired | a				12,500
Purchase price				$ 84

Acquisitions - June 2017 Acquis

Acquisitions - June 2017 Acquisition (Details) a in Thousands, $ in Thousands	Apr. 19, 2018USD ($)	Jan. 08, 2018USD ($)	Nov. 15, 2017USD ($)	Jun. 08, 2017USD ($)a	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)
Acquisitions
Total consideration given	$ 9,400	$ 11,600	$ 214,300
Earnings					$ 65,150	$ (29,796)	$ 22,003	$ (13,840)
Acquisition transaction expenses					0	$ 0	0	$ 68
June 2017 Acquisition
Acquisitions
Acres acquired | a				0
Total consideration given				$ 13,395
Cash				13,395
Revenues					800		2,600
Earnings					$ 600		$ 2,000
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) - USD ($) $ in Millions	Apr. 19, 2018	Jan. 08, 2018	Nov. 15, 2017
Acquisitions
Purchase price	$ 9.4	$ 11.6	$ 214.3

Acquisitions - October 2016 Acq

Acquisitions - October 2016 Acquisition (Details) - USD ($)	Apr. 19, 2018	Jan. 08, 2018	Nov. 15, 2017	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Aug. 07, 2018	Dec. 31, 2017
Acquisitions
Acquisition transaction expenses				$ 0	$ 0	$ 0	$ 68,000
Consideration given
Total consideration given	$ 9,400,000	$ 11,600,000	$ 214,300,000
Other information
Long-term Line of Credit, Noncurrent				290,000,000		290,000,000		$ 240,000,000	$ 90,000,000
Credit Facility
Other information
Long-term Line of Credit, Noncurrent				$ 290,000,000		$ 290,000,000			$ 90,000,000

Acquisitions - August 2016 Acqu

Acquisitions - August 2016 Acquisition (Details) - USD ($) $ in Thousands	Apr. 19, 2018	Jan. 08, 2018	Nov. 15, 2017	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Acquisitions
Acquisition transaction expenses				$ 0	$ 0	$ 0	$ 68
Consideration given
Total consideration given	$ 9,400	$ 11,600	$ 214,300

Acquisitions - Pro Forma Inform

Acquisitions - Pro Forma Information (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Pro Forma Financial Information
Depletion, depreciation, amortization and accretion	$ 107,315	$ 94,220	$ 310,296	$ 213,483
Income tax expense (in dollars)	$ 22,200	$ (17,106)	12,300	$ (7,556)
Earnings per common share, basic and diluted (usd per share)		$ (0.20)		$ (0.15)
June 2017 Acquisition | Adjustment To Depletion Depreciation Amortization And Accretion Expense [Member]
Pro Forma Financial Information
Depletion, depreciation, amortization and accretion			1,600
June 2017 Acquisition | Adjustment for effect of income taxes
Pro Forma Financial Information
Income tax expense (in dollars)			$ 600
October 2016 Acquisition
Pro Forma Financial Information
Revenues		$ 180,861		$ 392,430
Operating expenses		175,699		427,912
Net loss		$ (29,796)		$ (13,663)

Acquisitions - Acquisitions and

Acquisitions - Acquisitions and Divestitures (Details) $ in Thousands	Apr. 19, 2018USD ($)a	Jan. 08, 2018USD ($)a	Nov. 15, 2017USD ($)a	Apr. 30, 2018USD ($)a	Sep. 30, 2018USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)
Acquisitions
Acres of Real Estate Sold | a				15,100
Sale of property and equipment				$ 72,300		$ 72,345	$ 5,155
Gain (Loss) on Disposition of Oil and Gas Property					$ 59,900
Acres Of Real Estate Purchased | a	1,000	1,200	36,600
Total consideration given	$ 9,400	$ 11,600	$ 214,300
Business Acquisition, Transaction Costs			$ 12,200

Acquisitions Divestiture - Elev

Acquisitions Divestiture - Elevation Midstream Equity Method Investment (Details) $ in Millions	Aug. 03, 2018USD ($)
Subsequent Event [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	$ 83.6
Equity Method Investment, Ownership Percentage	10.00%

Long Term Debt - Components (De

Long Term Debt - Components (Details) - USD ($)	Sep. 30, 2018	Aug. 07, 2018	Dec. 31, 2017
Long-Term Debt
Line of credit, amount outstanding	$ 290,000,000	$ 240,000,000	$ 90,000,000
Unamortized debt issuance costs on Senior Notes	(17,885,000)		(16,639,000)
Total long-term debt	1,422,115,000		1,023,361,000
Less: current portion of long-term debt	0		0
Total long-term debt, net of current portion	1,422,115,000		1,023,361,000
Credit Facility
Long-Term Debt
Line of credit, amount outstanding	290,000,000		90,000,000
Senior Notes due 2021
Long-Term Debt
Debt outstanding	0		550,000,000
Second Lien Notes and Senior Notes
Long-Term Debt
Debt outstanding	400,000,000		400,000,000
Senior Notes due 2026
Long-Term Debt
Debt outstanding	750,000,000		$ 0
5% Holdings' Members | Related Party Debt Transaction | Senior Notes due 2021
Long-Term Debt
Debt outstanding	63,500,000
5% Holdings' Members | Related Party Debt Transaction | Senior Notes due 2024
Long-Term Debt
Debt outstanding	54,900,000
5% Holdings' Members | Related Party Debt Transaction | Senior Notes due 2026
Long-Term Debt
Debt outstanding	$ 56,200,000

Long Term Debt - Credit Facilit

Long Term Debt - Credit Facility (Details)	9 Months Ended
	Sep. 30, 2018USD ($)factorperiod	Aug. 07, 2018USD ($)	Jan. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Long-Term Debt
Total commitments	$ 1,500,000,000
Line of Credit Facility, Maximum Borrowing Capacity	800,000,000		$ 700,000,000
Borrowing base	650,000,000
Line of credit, amount outstanding	290,000,000	$ 240,000,000		$ 90,000,000
Available credit under the facility	$ 360,000,000
Variable interest rate terms and debt covenant ratios
Number of quarters used for calculation of Net Debt to EBITDAX | period	4
Minimum
Variable interest rate terms and debt covenant ratios
Commitment fee, percent	0.375%
Debt Covenant, Current ratio	1
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
Borrowing Base, Utilization Level 1
Variable interest rate terms and debt covenant ratios
Borrowing base utilization percentage, maximum	25.00%
Borrowing Base, Utilization Level 2
Variable interest rate terms and debt covenant ratios
Borrowing base utilization percentage, minimum	25.00%
Borrowing base utilization percentage, maximum	50.00%
Borrowing Base, Utilization Level 3
Variable interest rate terms and debt covenant ratios
Borrowing base utilization percentage, minimum	50.00%
Borrowing base utilization percentage, maximum	75.00%
Borrowing Base, Utilization Level 4
Variable interest rate terms and debt covenant ratios
Borrowing base utilization percentage, minimum	75.00%
Borrowing base utilization percentage, maximum	90.00%
Borrowing Base, Utilization Level 5
Variable interest rate terms and debt covenant ratios
Borrowing base utilization percentage, maximum	90.00%
Quarter ending March 31, 2018
Variable interest rate terms and debt covenant ratios
Annualized EBITDAX multiplier | factor	1.333
Revolving Credit Facility [Member]
Long-Term Debt
Line of Credit Facility, Maximum Borrowing Capacity			750,000,000	525,000,000
Standby Letters of Credit
Long-Term Debt
Letters of credit outstanding	$ 35,700,000			25,700,000
Credit Facility
Long-Term Debt
Line of credit, amount outstanding	$ 290,000,000			90,000,000
Credit Facility | Borrowing Base, Utilization Level 1
Variable interest rate terms and debt covenant ratios
Commitment fee, percent	0.375%
Credit Facility | Borrowing Base, Utilization Level 2
Variable interest rate terms and debt covenant ratios
Commitment fee, percent	0.375%
Credit Facility | Borrowing Base, Utilization Level 3
Variable interest rate terms and debt covenant ratios
Commitment fee, percent	0.50%
Credit Facility | Borrowing Base, Utilization Level 4
Variable interest rate terms and debt covenant ratios
Commitment fee, percent	0.50%
Credit Facility | Borrowing Base, Utilization Level 5
Variable interest rate terms and debt covenant ratios
Commitment fee, percent	0.50%
Credit Facility | LIBOR | Borrowing Base, Utilization Level 1
Variable interest rate terms and debt covenant ratios
Margin rate, percent	1.50%
Credit Facility | LIBOR | Borrowing Base, Utilization Level 2
Variable interest rate terms and debt covenant ratios
Margin rate, percent	1.75%
Credit Facility | LIBOR | Borrowing Base, Utilization Level 3
Variable interest rate terms and debt covenant ratios
Margin rate, percent	2.00%
Credit Facility | LIBOR | Borrowing Base, Utilization Level 4
Variable interest rate terms and debt covenant ratios
Margin rate, percent	2.25%
Credit Facility | LIBOR | Borrowing Base, Utilization Level 5
Variable interest rate terms and debt covenant ratios
Margin rate, percent	2.50%
Credit Facility | Base Rate | Borrowing Base, Utilization Level 1
Variable interest rate terms and debt covenant ratios
Margin rate, percent	0.50%
Credit Facility | Base Rate | Borrowing Base, Utilization Level 2
Variable interest rate terms and debt covenant ratios
Margin rate, percent	0.75%
Credit Facility | Base Rate | Borrowing Base, Utilization Level 3
Variable interest rate terms and debt covenant ratios
Margin rate, percent	1.00%
Credit Facility | Base Rate | Borrowing Base, Utilization Level 4
Variable interest rate terms and debt covenant ratios
Margin rate, percent	1.25%
Credit Facility | Base Rate | Borrowing Base, Utilization Level 5
Variable interest rate terms and debt covenant ratios
Margin rate, percent	1.50%
Letter of Credit [Member] | Revolving Credit Facility [Member]
Long-Term Debt
Line of Credit Facility, Maximum Borrowing Capacity			$ 35,000,000	$ 25,000,000

Long Term Debt - Senior Notes (

Long Term Debt - Senior Notes (Details) - USD ($)	Feb. 17, 2018	Jan. 25, 2018	Jan. 31, 2018	Oct. 31, 2017	Jul. 31, 2016	Mar. 31, 2018	Sep. 30, 2018
Long-Term Debt
Face amount of debt							$ 750,000,000
Senior Notes due 2021
Long-Term Debt
Face amount of debt					$ 550,000,000		550,000,000
Interest rate percentage					7.875%
Proceeds from debt, net of discounts and issuance costs					$ 537,200,000
Repayments of Debt, Principal		$ 500,600,000
Repayments of Debt	$ 52,700,000	534,200,000
Debt Instrument, Make Whole Provision	3,000,000	32,600,000				$ 35,600,000
Interest Expense, Debt	300,000	$ 1,000,000
Debt Instrument, Redemption Amount	$ 49,400,000
Senior Notes due 2024
Long-Term Debt
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%
Senior Notes due 2026
Long-Term Debt
Face amount of debt			$ 750,000,000
Interest rate percentage			5.625%
Proceeds from debt, net of discounts and issuance costs			$ 737,900,000

Long Term Debt - Debt Discount,

Long Term Debt - Debt Discount, Issuance Costs, Interest (Details) - USD ($)	Feb. 17, 2018	Jan. 25, 2018	Sep. 30, 2018	Mar. 31, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Long-Term Debt
Amortization of debt issuance costs			$ 0			$ 0
Interest Incurred On Long Term Debt
Interest expense			21,500,000		$ 16,500,000	61,600,000	$ 39,200,000
Interest costs capitalized			1,700,000		2,900,000	6,300,000	8,600,000
Payment for Debt Extinguishment or Debt Prepayment Cost						35,329,000	0
Credit Facility | Other non-current assets
Long-Term Debt
Accumulated amortization, debt issuance costs			3,700,000			3,700,000
Debt issuance costs			17,900,000			17,900,000
Senior Notes due 2021
Long-Term Debt
Amortization of Debt Issuance Costs, Accelerated Amount						9,400,000
Interest Incurred On Long Term Debt
Debt Instrument, Make Whole Provision	$ 3,000,000	$ 32,600,000		$ 35,600,000
Second Lien Notes
Long-Term Debt
Amortization of debt discount			$ 900,000		$ 1,500,000	$ 12,300,000	$ 3,200,000

Commodity Derivative Instrume_3

Commodity Derivative Instruments - Summary of Contracts (Details)	9 Months Ended
	Sep. 30, 2018USD ($)MMBTUcontract$ / bbl$ / MMBTUbbl
Commodity derivative contracts
Number of counterparties | contract	12
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	1,050,000
Weighted average fixed price, Swaps (in $/Bbl or$/MMBtu) | $ / bbl	52.91
Crude | Swap, 2019
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	0
Weighted average fixed price, Swaps (in $/Bbl or$/MMBtu) | $ / bbl	0
Crude | Calls, 2018 | Sold
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	2,250,000
Weighted average fixed price, Calls (in $/BBl or $/MMBtu) | $ / bbl	49.81
Crude | Calls, 2019 | Sold
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	9,300,000
Weighted average fixed price, Calls (in $/BBl or $/MMBtu) | $ / bbl	51.44
Crude | Puts, 2018 | Purchased
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	2,250,000
Weighted average put price (in $/Bbl or $/MMBtu) | $ / bbl	58.33
Crude | Put Option2019 [Member] | Purchased
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	9,300,000
Weighted average put price (in $/Bbl or $/MMBtu) | $ / bbl	64.78
Natural Gas | Swaps, 2018
Summary of commodity derivative contracts
Notional volume (in MMBtu)	3,300,000
Weighted average fixed price, Swaps (in $/Bbl or$/MMBtu) | $ / bbl	40
Natural Gas | Swaps, 2018 | Purchased
Summary of commodity derivative contracts
Notional volume (in MMBtu)	9,900,000
Weighted average fixed price, Swaps (in $/Bbl or$/MMBtu) | $ / MMBTU	3.02
Natural Gas | Swap, 2019
Summary of commodity derivative contracts
Notional volume (in MMBtu)	8,700,000
Weighted average fixed price, Swaps (in $/Bbl or$/MMBtu) | $ / bbl	41.69
Natural Gas | Swap, 2019 | Purchased
Summary of commodity derivative contracts
Notional volume (in MMBtu)	25,800,000
Weighted average fixed price, Swaps (in $/Bbl or$/MMBtu) | $ / MMBTU	2.77
Natural Gas | Calls, 2018 | Sold
Summary of commodity derivative contracts
Notional volume (in MMBtu)	600,000
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)	3,000,000
Weighted average fixed price, Calls (in $/BBl or $/MMBtu) | $ / MMBTU	3.36
Natural Gas | Puts, 2018 | Sold
Summary of commodity derivative contracts
Notional volume (in 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)	600,000
Weighted average fixed price, Calls (in $/BBl or $/MMBtu) | $ / MMBTU	3
Natural Gas | Put Option2019 [Member] | Sold
Summary of commodity derivative contracts
Notional volume (in MMBtu)	3,000,000
Weighted average fixed price, Calls (in $/BBl or $/MMBtu) | $ / MMBTU	2.50
Natural Gas | Put Option2019 [Member] | Purchased
Summary of commodity derivative contracts
Notional volume (in MMBtu)	3,000,000
Weighted average fixed price, Calls (in $/BBl or $/MMBtu) | $ / MMBTU	2.99
Natural Gas | Basis Swaps, 2018
Summary of commodity derivative contracts
Notional volume (in MMBtu)	11,040,000
Weighted average fixed basis price ($/MMBtu) | $ / MMBTU	(0.68)
Natural Gas | Basis Swap, 2019
Summary of commodity derivative contracts
Notional volume (in MMBtu)	31,200,000
Weighted average fixed basis price ($/MMBtu) | $ / MMBTU	(0.75)

Commodity Derivative Instrume_4

Commodity Derivative Instruments - Gross and Net Fair Value (Details) - USD ($)	Sep. 30, 2018	Dec. 31, 2017
Current assets
Gross amounts and adjustments made for net derivative assets
Gross Amounts of Recognized Assets	$ 92,161,000	$ 22,118,000
Gross Amounts Offset in the Balance Sheet	(78,935,000)	(17,986,000)
Net Amounts of Assets Presented in the Balance Sheet	13,226,000	4,132,000
Gross Amounts not Offset in the Balance Sheet	(2,145,000)	0
Net Amounts	11,081,000	4,132,000
Non-current assets
Gross amounts and adjustments made for net derivative assets
Gross Amounts of Recognized Assets	7,085,000	13,686,000
Gross Amounts Offset in the Balance Sheet	(7,085,000)	(13,686,000)
Net Amounts of Assets Presented in the Balance Sheet	0	0
Gross Amounts not Offset in the Balance Sheet	0	0
Net Amounts	0	0
Financial collateral
Financial collateral received	0	0
Financial collateral pledged	0	0
Current liabilities
Gross amounts and adjustments made for net derivative liabilities
Gross Amounts of Recognized Liabilities	(222,511,000)	(85,414,000)
Gross Amounts Offset in the Balance Sheet	78,935,000	17,986,000
Net Amounts of Liabilities Presented in the Balance Sheet	(143,576,000)	(67,428,000)
Gross Amounts not Offset in the Balance Sheet	2,145,000	0
Net Amounts	(150,217,000)	(84,702,000)
Non-current liabilities
Gross amounts and adjustments made for net derivative liabilities
Gross Amounts of Recognized Liabilities	(15,871,000)	(30,960,000)
Gross Amounts Offset in the Balance Sheet	7,085,000	13,686,000
Net Amounts of Liabilities Presented in the Balance Sheet	(8,786,000)	(17,274,000)
Gross Amounts not Offset in the Balance Sheet	0	0
Net Amounts	$ 0	$ 0

Commodity Derivative Instrume_5

Commodity Derivative Instruments - Gain (Loss) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income (loss) on derivatives
Commodity derivatives gain (loss)	$ (35,913)	$ (37,875)	$ (175,752)	$ 46,423
Other income (expense)
Income (loss) on derivatives
Gain (Loss) on Price Risk Derivatives, Net	$ (35,913)	$ (37,875)	$ (175,752)	$ 46,423

Asset Retirement Obligations -

Asset Retirement Obligations - Summary (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2016
Asset retirement obligations
Balance beginning of period	$ 69,540
Liabilities incurred or acquired	1,705	$ 9,802
Liabilities settled	(9,581)	(4,169)
Revisions in estimated cash flows	3,698	2,630
Accretion expense	3,989	5,169
Balance end of period	$ 69,351	$ 56,108

Fair Value Measurements - Recur

Fair Value Measurements - Recurring Basis (Details) - USD ($)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2016	Dec. 31, 2017
Fair Value Measurements
Impairment of Oil and Gas Properties	$ 0	$ 0	$ 16,200,000	$ 0
Asset transfers out of Level 2 into Level 1	0		0			$ 0
Asset transfers into (out of) Level 3			0		$ 0
Liability transfers out of Level 1 into Level 2	0		0			0
Liability transfers out of Level 2 into Level 1	0		0			0
Liability transfers into (out of) Level 3			0		$ 0
Recurring
Financial Assets:
Commodity derivative assets	13,226,000		13,226,000			4,132,000
Financial Liabilities:
Commodity derivative liabilities	152,362,000		152,362,000			84,702,000
Recurring | Level 1
Financial Assets:
Commodity derivative assets	0		0			0
Financial Liabilities:
Commodity derivative liabilities	0		0			0
Recurring | Level 2
Financial Assets:
Commodity derivative assets	13,226,000		13,226,000			4,132,000
Financial Liabilities:
Commodity derivative liabilities	152,362,000		152,362,000			84,702,000
Recurring | Level 3
Financial Assets:
Commodity derivative assets	0		0			0
Financial Liabilities:
Commodity derivative liabilities	$ 0		$ 0			$ 0

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Fair Value of Financial Instruments
Unamortized debt discount and debt issuance costs	$ 17,885	$ 16,639
Carrying Amount | Senior Notes due 2021
Fair Value of Financial Instruments
Long-term debt	0	540,382
Unamortized debt discount and debt issuance costs	0	9,600
Carrying Amount | Senior Notes due 2024
Fair Value of Financial Instruments
Long-term debt	393,638	392,979
Unamortized debt discount and debt issuance costs	6,400	7,000
Carrying Amount | Senior Notes due 2026
Fair Value of Financial Instruments
Long-term debt	738,477	0
Unamortized debt discount and debt issuance costs	11,500	0
Fair value | Level 2 | Senior Notes due 2021
Fair Value of Financial Instruments
Long-term debt	0	583,000
Fair value | Level 2 | Senior Notes due 2024
Fair Value of Financial Instruments
Long-term debt	393,520	427,000
Fair value | Level 2 | Senior Notes due 2026
Fair Value of Financial Instruments
Long-term debt	667,500	0
Line of Credit | Carrying Amount
Fair Value of Financial Instruments
Long-term debt	290,000	90,000
Line of Credit | Fair value | Level 2
Fair Value of Financial Instruments
Long-term debt	$ 290,000	$ 90,000

Fair Value Measurements - Nonre

Fair Value Measurements - Nonrecurring (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Impairment of Oil and Gas Properties	$ 0	$ 0	$ 16,200,000	$ 0

Income Taxes - Effective Tax Ra

Income Taxes - Effective Tax Rate (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Taxes
Effective combined U.S. federal and state income tax rate			35.90%
Income tax expense (in dollars)	$ 22,200	$ (17,106)	$ 12,300	$ (7,556)
Statutory U.S. federal income tax rate			21.00%

Unit and Stock-Based Compensa_3

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 Compensa_4

Unit and Stock-Based Compensation - Long Term Incentive Plan Options (Details) - 2016 Long Term Incentive Plan - Stock Options - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Assumptions used for the Black-Scholes valuation model
Dividend yield (as a percent)			0.00%
Forfeiture rate (as a percent)			0.00%
Vesting period, in years			3 years
Compensation costs
Share-based compensation expense	$ 3.8	$ 3.3	$ 11.3	$ 9.9
Unrecognized compensation costs	$ 15.9		$ 15.9
Weighted-average period for recognition, unvested awards			1 year 1 month 6 days
Number of Shares
Granted (in shares)			0
Forfeited (in shares)			0
Vested (in shares)			0
Non-vested Stock Options at end of period (in shares)	3,496,290		3,496,290
Weighted Average Exercise Price (in dollars per share)
Granted (in dollars per share)			$ 0
Forfeited (in dollars per share)			0
Vested (in dollars per share)			0
Non-vested Stock Options at end of period (in dollars per share)	$ 18.50		$ 18.50

Unit and Stock-Based Compensa_5

Unit and Stock-Based Compensation - Long Term Incentive Plan RSUs (Details) - 2016 Long Term Incentive Plan - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Stock Options
Restricted Stock Units ("RSUs")
Vesting period, in years			3 years
Forfeiture rate (as a percent)			0.00%
Compensation costs
Share-based compensation expense	$ 3.8	$ 3.3	$ 11.3	$ 9.9
Weighted-average period for recognition, unvested awards			1 year 1 month 6 days
RSUs
Restricted Stock Units ("RSUs")
Forfeiture rate (as a percent)			0.00%
Compensation costs
Share-based compensation expense	7.1	$ 3.3	$ 20.7	$ 9.9
Unrecognized compensation cost	$ 38.7		$ 38.7
Weighted-average period for recognition, unvested awards			1 year 7 months 6 days
RSUs - One Year Vesting
Restricted Stock Units ("RSUs")
Vesting period, in years			1 year
Vesting Period One | RSUs - One Year Vesting
Restricted Stock Units ("RSUs")
Vesting percentage			100.00%
Vesting Period One | RSUs - Three Year Vesting
Restricted Stock Units ("RSUs")
Vesting period, in years			1 year
Vesting percentage			25.00%
Vesting Period Two | RSUs - Three Year Vesting
Restricted Stock Units ("RSUs")
Vesting period, in years			2 years
Vesting percentage			25.00%
Vesting Period Three | RSUs - Three Year Vesting
Restricted Stock Units ("RSUs")
Vesting period, in years			3 years
Vesting percentage			50.00%

Unit and Stock-Based Compensa_6

Unit and Stock-Based Compensation - Long Term Incentive Plan RSUs Rollforward (Details) - 2016 Long Term Incentive Plan	9 Months Ended
	Sep. 30, 2018$ / sharesshares
RSUs
Number of Shares
Non-vested units at beginning of period (in shares) | shares	2,906,473
Granted (in shares) | shares	1,121,768
Forfeited (in shares) | shares	(45,150)
Vested (in shares) | shares	(317,161)
Non-vested units at end of period (in shares) | shares	3,665,930
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per share) | $ / shares	$ 19.51
Granted (in dollars per share) | $ / shares	12.82
Forfeited (in dollars per share) | $ / shares	15.91
Vested (in dollars per share) | $ / shares	15.90
Non-vested units at end of period (in dollars per share) | $ / shares	$ 17.80
Performance Stock Awards
Number of Shares
Non-vested units at beginning of period (in shares) | shares	832,163
Granted (in shares) | shares	1,961,920
Forfeited (in shares) | shares	0
Vested (in shares) | shares	0
Non-vested units at end of period (in shares) | shares	2,794,083
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per share) | $ / shares	$ 8.85
Granted (in dollars per share) | $ / shares	9.06
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	$ 9

Unit and Stock-Based Compensa_7

Unit and Stock-Based Compensation - Incentive Restricted Stock Units (Details) - USD ($) $ in Thousands, shares in Millions	Jul. 17, 2017	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Compensation costs
Unit-based compensation				$ 50,883	$ 46,707
Employee Incentive | Incentive RSUs | Vesting Period One
Incentive Units
Service vesting period, in years				3 years
Vesting percentage	25.00%			25.00%
Employee Incentive | Incentive RSUs | Vesting Period Two
Incentive Units
Vesting percentage	25.00%			25.00%
Employee Incentive | Incentive RSUs | Vesting Period Three
Incentive Units
Vesting percentage	25.00%			50.00%
Employee Incentive | Incentive RSUs | Vesting Period Four
Incentive Units
Vesting percentage	25.00%
Employee Incentive | Incentive RSUs
Compensation costs
Unit-based compensation		$ 4,900	$ 5,900	$ 14,700	$ 12,200
Unrecognized compensation cost		5,700		$ 5,700
Weighted-average period for recognition, unvested awards				3 months 18 days
Employee Incentive | Incentive RSUs | Vesting Period One
Incentive Units
Vesting period, in years				1 year
Employee Incentive | Incentive RSUs | Vesting Period Two
Incentive Units
Vesting period, in years	6 months			2 years
Employee Incentive | Incentive RSUs | Vesting Period Three
Incentive Units
Vesting period, in years	12 months			3 years
Employee Incentive | Incentive RSUs | Vesting Period Four
Incentive Units
Vesting period, in years	18 months
Officers | Employee Incentive | Employee Incentive | Common Stock
Incentive Units
Shares contributed to Extraction Employee Incentive, LLC				2.7
2016 Long Term Incentive Plan | RSUs
Incentive Units
Forfeiture rate (as a percent)				0.00%
Compensation costs
Unrecognized compensation cost		$ 38,700		$ 38,700
Weighted-average period for recognition, unvested awards				1 year 7 months 6 days

Unit and Stock-Based Compensa_8

Unit and Stock-Based Compensation - Incentive Restricted Stock Units Rollforward (Details) - Incentive RSUs	9 Months Ended
	Sep. 30, 2018$ / sharesshares
Number of Shares
Non-vested units at beginning of period (in shares) | shares	1,496,175
Granted (in shares) | shares	0
Forfeited (in shares) | shares	(41,400)
Vested (in shares) | shares	(978,775)
Non-vested units at end of period (in shares) | shares	476,000
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per share) | $ / shares	$ 20.45
Granted (in dollars per share) | $ / shares	0
Forfeited (in dollars per share) | $ / shares	20.45
Vested (in dollars per share) | $ / shares	20.45
Non-vested units at end of period (in dollars per share) | $ / shares	$ 20.45

Unit and Stock-Based Compensa_9

Unit and Stock-Based Compensation Unit and Stock-Based Compensation - Performance Stock Awards (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2018	Sep. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation		$ 50,883	$ 46,707
Performance Stock Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation	$ 1,600	4,200
Unrecognized compensation cost	$ 10,700	$ 10,700
Weighted-average period for recognition, unvested awards		2 years

Earnings (Loss) Per Share - Com

Earnings (Loss) Per Share - Components (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Basic and Diluted EPS (in thousands, except per share data)
Net loss	$ 65,150	$ (29,796)	$ 22,003	$ (13,840)
Net Income (Loss) Attributable to Noncontrolling Interest	(3,305)	0	(3,305)	0
Less: Adjustment to reflect Series A Preferred Stock dividends	(2,721)	(2,721)	(8,164)	(8,164)
Less: Adjustment to reflect Series A Preferred Stock dividends	(1,515)	(1,365)	(4,429)	(3,992)
Adjusted net income (loss) available to common shareholders, basic and diluted	$ 57,609	$ (33,882)	$ 6,105	$ (25,996)
Denominator
Weighted average common shares outstanding, basic and diluted	175,814,000	171,845,000	175,269,000	171,838,000
Earnings Per Common Share
Basic and diluted (in dollars per share)	$ 0.33	$ (0.20)	$ 0.03	$ (0.15)

Earnings (Loss) Per Share - Exc

Earnings (Loss) Per Share - Excluded and Antidilutive Securities (Details) - shares	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Out-of-the-money stock options
Antidilutive Securities Excluded from Computation of Earnings Per Share
Securities excluded from diluted EPS calculation (in shares)	5,244,428			4,500,000
RSUs
Antidilutive Securities Excluded from Computation of Earnings Per Share
Securities excluded from diluted EPS calculation (in shares)	347,343
Series A Convertible Preferred Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share
Securities excluded from diluted EPS calculation (in shares)	11,472,445		11,472,445	11,472,445
Stock Compensation Plan [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share
Securities excluded from diluted EPS calculation (in shares)		8,552,814

Commitments and Contingencies -

Commitments and Contingencies - Leases (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018USD ($)office	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)office	Sep. 30, 2017USD ($)	Jun. 04, 2015office
Office Space Leases
Future minimum lease payments
Total rental commitments under non cancelable leases	$ 33.6		$ 33.6
2,017	0.8		0.8
2,018	3.5		3.5
2,019	3.4		3.4
2,020	3.4		3.4
2,021	3.4		3.4
Thereafter	19.1		19.1
Rent expense	$ 1	$ 0.5	$ 2.7	$ 1.7
Office Space Leases | Denver, Colorado
Leases
Number of office spaces under lease | office	2		2
Office Space Leases | Greeley, Colorado
Leases
Number of office spaces under lease | office	2		2
Office Space Leases | Houston, Texas
Leases
Number of office spaces under lease | office	1		1
Subleases | Denver, Colorado
Leases
Number of office spaces under lease | office					1
Future minimum lease payments
Sublease rental, future lease payments	$ 0.4		$ 0.4

Commitments and Contingencies_2

Commitments and Contingencies - Drilling Rigs (Details) - Drilling Rig Commitments $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)well
Drilling Rigs
Number of drilling rigs | well	3
Early termination obligation | $	$ 7.3

Commitments and Contingencies_3

Commitments and Contingencies - Commitments (Details) $ in Millions	Jul. 07, 2017MMcf	Dec. 15, 2016MMcf	Sep. 30, 2018USD ($)bbl / dcontract	Aug. 07, 2017processing_plant
Delivery and Gathering commitments
Aggregate estimated payments due | $			$ 967.5
Long Term Crude Oil Delivery Commitment, November 2016, Ten Year Term | Minimum
Delivery and Gathering 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 Commitment
Delivery and Gathering commitments
Term of commitment			10 years
Number of commitments | contract			2
Long Term Crude Oil Gathering Commitment | Average
Delivery and Gathering commitments
Gathering commitment, in barrels per day (Bpd), year one			9,167
Gathering commitment, in barrels per day (Bpd), year two			17,967
Gathering commitment, in barrels per day (Bpd), years three through five			18,800
Gathering commitment, in barrels per day (Bpd), years six through ten			10,000
Long Term Crude Oil Gathering Commitment Two
Delivery and Gathering commitments
Term of commitment			10 years
Long Term Crude Oil Gathering Commitment Two | Average
Delivery and Gathering commitments
Gathering commitment, in barrels per day (Bpd), year one			8,000
Gathering commitment, in barrels per day (Bpd), year two			20,000
Gathering commitment, in barrels per day (Bpd), year three			35,000
Gathering commitment, in barrels per day (Bpd), year four through eight			40,000
Gathering commitment, in barrels per day (Bpd), year nine			30,000
Gathering commitment, in barrels per day (Bpd), year ten			25,000
Natural Gas Gathering and Processing Expansion Commitment
Delivery and Gathering commitments
Term of commitment			7 years
Processing Plant, Number | processing_plant				2
Delivery commitment, daily | MMcf	20.6	51.5
Target profit margin period, in years			3 years

Commitments and Contingencies_4

Commitments and Contingencies - Acquisition of Undeveloped Leasehold (Details) - Acquisition of Undeveloped Leasehold Acreage Commitments $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)a
Acquisition of Undeveloped Leasehold Acreage Commitments
Payments for other commitments | $	$ 247.6
Net acres of undeveloped leasehold | a	38,800

Related Party Transactions - Du

Related Party Transactions - Due From Related Parties (Details)	1 Months Ended
	Apr. 30, 2016USD ($)
Board member | Star Peak Capital Office Lease
Office Lease with Related Affiliate
Monthly rent	$ 1,400

Related Party Transactions - _2

Related Party Transactions - Due to Related Parties (Details)	9 Months Ended
	Sep. 30, 2018USD ($)bbl / d	Jan. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Jul. 31, 2016USD ($)
Due to Related Party
Face amount of debt	$ 750,000,000
Aggregate estimated payments due	$ 967,500,000
Long Term Crude Oil Gathering Commitment
Due to Related Party
Term of commitment	10 years
Long Term Crude Oil Gathering Commitment | Average
Due to Related Party
Gathering commitment, in barrels per day (Bpd), year one | bbl / d	9,167
Gathering commitment, in barrels per day (Bpd), year two | bbl / d	17,967
Gathering commitment, in barrels per day (Bpd), years three through five | bbl / d	18,800
Gathering commitment, in barrels per day (Bpd), years six through ten | bbl / d	10,000
Unconsolidated affiliate | Long Term Crude Oil Delivery Commitment, November 2016, Ten Year Term
Due to Related Party
Term of commitment	10 years
Senior Notes due 2021
Due to Related Party
Face amount of debt	$ 550,000,000			$ 550,000,000
Debt outstanding	0		$ 550,000,000
Senior Notes due 2021 | Related Party Debt Transaction | 5% Holdings' Members
Due to Related Party
Debt outstanding	63,500,000
Senior Notes due 2024
Due to Related Party
Face amount of debt	400,000,000
Senior Notes due 2024 | Related Party Debt Transaction | 5% Holdings' Members
Due to Related Party
Debt outstanding	54,900,000
Senior Notes due 2026
Due to Related Party
Face amount of debt		$ 750,000,000
Debt outstanding	750,000,000		$ 0
Senior Notes due 2026 | Related Party Debt Transaction | 5% Holdings' Members
Due to Related Party
Debt outstanding	$ 56,200,000