Extraction Oil & Gas (XOG) 10-Q 7 Nov 17 2017 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Nov. 03, 2017
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	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2,017
Entity Current Reporting Status	Yes
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		172,047,061

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Current Assets:
Cash and cash equivalents	$ 114,139	$ 588,736
Accounts receivable
Trade	52,638	23,154
Oil, natural gas and NGL sales	70,425	34,066
Inventory and prepaid expenses	13,262	7,722
Commodity derivative asset	986	0
Total Current Assets	251,450	653,678
Property and Equipment (successful efforts method), at cost:
Proved oil and gas properties	2,683,062	1,851,052
Unproved oil and gas properties	639,867	452,577
Wells in progress	130,668	98,747
Less: accumulated depletion, depreciation and amortization	(610,390)	(402,912)
Net oil and gas properties	2,843,207	1,999,464
Other property and equipment, net of accumulated depreciation	26,866	32,721
Net Property and Equipment	2,870,073	2,032,185
Non-Current Assets:
Cash held in escrow	0	42,200
Goodwill and other intangible assets, net of accumulated amortization	54,966	54,489
Other non-current assets	11,611	2,224
Total Non-Current Assets	66,577	98,913
Total Assets	3,188,100	2,784,776
Current Liabilities:
Accounts payable and accrued liabilities	151,940	131,134
Revenue payable	41,209	35,162
Production taxes payable	39,556	27,327
Commodity derivative liability	8,259	56,003
Accrued interest payable	14,068	19,621
Asset retirement obligations	4,998	5,300
Total Current Liabilities	260,030	274,547
Non-Current Liabilities:
Senior Notes, net of unamortized debt issuance costs	932,570	538,141
Production taxes payable	37,138	35,838
Commodity derivative liability	3,025	6,738
Other non-current liabilities	6,038	3,466
Asset retirement obligations	60,193	50,808
Deferred tax liability	98,470	106,026
Total Non-Current Liabilities	1,137,434	741,017
Total Liabilities	1,397,464	1,015,564
Commitments and Contingencies—Note 11
Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized; 185,280 issued and outstanding	156,995	153,139
Stockholders' Equity:
Common stock, $0.01 par value; 900,000,000 shares authorized; 171,893,157 and 171,834,605 issued and outstanding	1,718	1,718
Additional paid-in capital	2,101,103	2,067,590
Treasury stock, at cost, 165,385 and 0 shares	2,105	0
Accumulated deficit	(467,075)	(453,235)
Total Stockholders' Equity	1,633,641	1,616,073
Total Liabilities and Stockholders' Equity	$ 3,188,100	$ 2,784,776

CONDENSED CONSOLIDATED BALANCE3

CONDENSED CONSOLIDATED BALANCE SHEETS (Parentheticals) - $ / shares	Sep. 30, 2017	Dec. 31, 2016
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, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenues:
Oil sales	$ 132,075	$ 51,760	$ 269,597	$ 135,896
Natural gas sales	24,672	12,792	63,095	27,730
NGL sales	24,114	8,350	57,574	19,773
Total Revenues	180,861	72,902	390,266	183,399
Operating Expenses:
Lease operating expenses	29,267	15,480	75,755	40,819
Production taxes	16,290	6,186	33,254	16,935
Exploration expenses	7,181	5,985	24,431	14,735
Depletion, depreciation, amortization and accretion	94,220	46,680	213,483	141,317
Impairment of long lived assets	0	467	675	23,350
Other operating expenses	0	0	451	891
Acquisition transaction expenses	0	345	68	345
General and administrative expenses	28,741	20,071	77,916	35,189
Total Operating Expenses	175,699	95,214	426,033	273,581
Operating Income (Loss)	5,162	(22,312)	(35,767)	(90,182)
Other Income (Expense):
Commodity derivatives gain (loss)	(37,875)	16,225	46,423	(62,424)
Interest expense	(15,080)	(31,216)	(33,761)	(57,914)
Other income	891	36	1,709	120
Total Other Income (Expense)	(52,064)	(14,955)	14,371	(120,218)
Loss Before Income Taxes	(46,902)	(37,267)	(21,396)	(210,400)
Income tax benefit	(17,106)	0	(7,556)	0
Net Loss	$ (29,796)	$ (37,267)	$ (13,840)	$ (210,400)
Earnings Per Common Share
Basic and diluted (in dollars per share)	$ (0.20)		$ (0.15)
Weighted Average Common Shares Outstanding
Basic and diluted (in shares)	171,845,000		171,838,000

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS' AND STOCKHOLDERS' EQUITY - 9 months ended Sep. 30, 2017 - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Additional Paid in Capital	Retained Deficit	Treasury Stock, Common [Member]
Balance at beginning of period (in units or shares) at Dec. 31, 2016		171,835			0
Balance at beginning of period at Dec. 31, 2016	$ 1,616,073	$ 1,718	$ 2,067,590	$ (453,235)	$ 0
CHANGES IN MEMBERS' AND STOCKHOLDERS' EQUITY
Common stock issuance costs	(311)		(311)
Stock-based compensation	46,707		46,707
Series A Preferred Stock dividends	(8,164)		(8,164)
Accretion of beneficial conversion feature on Series A Preferred Stock	$ (3,992)		(3,992)
Treasury Stock, Shares, Acquired					165
Treasury Stock, Value, Acquired, Cost Method					$ (2,105)
Restricted Stock, Shares Issued Net of Shares for Tax Withholdings	58
Payments Related to Tax Withholding for Share-based Compensation	$ (727)
Net loss	(13,840)			(13,840)
Balance at end of period (in units or shares) at Sep. 30, 2017		171,893			165
Balance at end of period at Sep. 30, 2017	$ 1,633,641	$ 1,718	$ 2,101,103	$ (467,075)	$ (2,105)

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Cash flows from operating activities:
Net loss	$ (13,840)	$ (210,400)
Reconciliation of net loss to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	213,483	141,317
Abandonment and impairment of unproved properties	5,684	3,331
Impairment of long lived assets	675	23,350
Loss on sale of property and equipment	451	0
Amortization of debt issuance costs and debt discount	3,181	18,330
Deferred rent	(229)	600
Commodity derivatives (gain) loss	(46,423)	62,424
Settlements on commodity derivatives	(8,893)	43,015
Premiums paid on commodity derivatives	0	(611)
Deferred income tax expense	(7,556)	0
Unit and stock-based compensation	46,707	14,922
Equity in earnings of unconsolidated affiliate	(256)	0
Proceeds from Equity Method Investment, Dividends or Distributions	131	0
Changes in current assets and liabilities:
Accounts receivable—trade	(29,099)	3,889
Accounts receivable—oil, natural gas and NGL sales	(36,359)	(8,506)
Inventory and prepaid expenses	(180)	(273)
Accounts payable and accrued liabilities	1,653	(18,242)
Revenue payable	6,047	10,228
Production taxes payable	13,520	6,219
Accrued interest payable	(5,553)	8,342
Asset retirement expenditures	(1,408)	(372)
Net cash provided by operating activities	141,736	97,563
Cash flows from investing activities:
Oil and gas property additions	(1,015,700)	(223,684)
Acquired oil and gas properties	(17,225)	(13,674)
Sale of property and equipment	5,155	2,148
Other property and equipment additions	(9,608)	(3,336)
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	116	0
Cash held in escrow	42,200	(42,000)
Net cash used in investing activities	(995,062)	(280,546)
Cash flows from financing activities:
Borrowings under credit facility	250,000	60,000
Repayments of Lines of Credit	(250,000)	(196,000)
Proceeds from Issuance of Senior Long-term Debt	394,000	550,000
Proceeds from the issuance of units	0	121,370
Treasury Stock, Value, Acquired, Cost Method	0	(2,867)
Payments Related to Tax Withholding for Share-based Compensation	(2,832)	0
Dividends on Series A Preferred Stock	(7,680)	0
Early Repayment of Subordinated Debt	0	430,000
Debt issuance costs	(3,273)	(13,189)
Equity issuance costs	(1,486)	(2,051)
Net cash provided by financing activities	378,729	87,263
Decrease in cash and cash equivalents	(474,597)	(95,720)
Cash and cash equivalents at beginning of period	588,736	97,106
Cash and cash equivalents at end of the period	114,139	1,386
Supplemental cash flow information:
Property and equipment included in accounts payable and accrued liabilities	130,022	53,371
Cash paid for interest	44,703	30,531
Payments of Debt Extinguishment Costs	0	4,300
Promissory Notes Issued to Officers	0	5,562
Accretion of beneficial conversion feature of Series A Preferred Stock	3,992	0
Noncash or Part Noncash Acquisition, Investments Acquired	8,307	0
Increase in dividends payable	$ 484	$ 0

Business and Organization

Business and Organization	9 Months Ended
	Sep. 30, 2017
Limited Liability Company or Limited Partnership, Business Organization and Operations [Abstract]
Business and Organization	Business and Organization Extraction Oil & Gas, Inc. (the “Company” or “Extraction”) is an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin (the “DJ Basin”) of Colorado. The Company and its subsidiaries are focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Rocky Mountain region, as well as the design and support of midstream assets to gather and process crude oil and gas production focused in the DJ Basin of Colorado. Extraction is a public company listed for trading on the NASDAQ Global Select Market under the symbol “XOG”. The condensed consolidated financial statements for the three and nine months ended September 30, 2016 are based on the financial statements of the Company’s accounting predecessor, Extraction Oil & Gas Holdings, LLC, prior to the corporate reorganization (the “Corporate Reorganization”), pursuant to which, in connection with the initial public offering of the Company (the "IPO"), (i) on October 11, 2016, a former subsidiary of Extraction Oil & Gas Holdings, LLC, Extraction Oil & Gas, LLC, converted into the Company, and (ii) on October 17, 2016, Holdings merged with and into the Company with the Company as the surviving entity. For further information on the Corporate Reorganization please refer to the Company’s Annual Report.

Basis of Presentation, Signific

Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements	9 Months Ended
	Sep. 30, 2017
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 May 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-09, which provides clarification and reduces both (1) diversity in practice and (2) cost and complexity when applying the guidance in Topic 718 Compensation - Stock Compensation, to a change to the terms or conditions of a share-based payment award. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that reporting period. Early adoption is permitted for fiscal years beginning after December 15, 2016, including the interim reporting periods within that fiscal year. The Company is currently evaluating the impact of adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements. In February 2017, the FASB issued ASU No. 2017-05, which provided clarification regarding the guidance on accounting for the derecognition of nonfinancial assets. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that fiscal year. The Company is currently evaluating this new standard to determine the potential impact to its 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 this ASU and believes it could have a material impact to its financial statements and related disclosures. In January 2017, the FASB issued ASU No. 2017-01, which clarifies the definition of a business when evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted for transactions for which the acquisition date occurs before the issuance date or effective date of the amendments, only when the transaction has not been reported in the financial statements that have been issued. The Company is currently evaluating this ASU and believes it could have a material impact to its financial statements and related disclosures. In November 2016, the FASB issued ASU No. 2016-18, which intends to clarify how entities should present restricted cash and restricted cash equivalents in the statement of cash flows. This amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company is currently evaluating the impact of adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements. In August 2016, the FASB issued ASU No. 2016-15, which addresses eight specific cash flow issues, including presentation of debt prepayments or debt extinguishment costs, with the objective of reducing the existing diversity in practice. In addition, in November 2016, the FASB issued ASU No. 2016-18, which requires that amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company is currently evaluating this ASU to determine the potential impact to its financial statements and related disclosures. In March 2016, the FASB issued ASU No. 2016-06, which clarifies the requirements to assess whether an embedded put or call option is clearly and closely related to the debt host, solely in accordance with the four step decision sequence in FASB ASB Topic 815, Derivatives and Hedging, as amended by this ASU. This standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and should be applied using a modified retrospective approach. The Company adopted this ASU in the first quarter of 2017 and the adoption of this ASU did not have a material impact on the its consolidated financial statements. 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. In September 2017, the FASB issued ASU No. 2017-13, which provided additional implementation guidance. The Company is currently evaluating the impact this ASU will have on its financial statements and related disclosures and developing a strategy for implementation. In May 2014, the FASB issued ASU No. 2014-09, which establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The ASU allows for the use of either the full or modified retrospective transition method. In August 2015, the FASB issued ASU No. 2015-14, which deferred ASU No. 2014-09 for one year, and is effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of reporting periods beginning after December 15, 2016. The FASB subsequently issued ASU No. 2016-08, ASU No. 2016-10, ASU No. 2016-11, ASU No. 2016-12, ASU No. 2016-20, and ASU No. 2017-13, which provided additional implementation guidance. The Company is in the final stages of its review of contracts in each of its revenue streams and has developed accounting policies to address the provisions of this ASU. While the Company does not expect operating income (loss) to be materially impacted, the Company does expect total revenues and total expenses to change as a result of certain percentage of proceeds contracts. Further, the Company has begun evaluating the design of its pre-adoption and adoption controls and expects new or modification of certain controls to address risks associated with recognizing revenue under the new standard as we continue the implementation process. The Company will continue to evaluate the impact of this and other provisions of the ASU on its accounting policies, internal controls, and consolidated financial statements and related disclosures and has not finalized any estimates of the potential impacts. The Company will adopt this new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings. 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 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, 2017
Business Combinations [Abstract]
Acquisitions	Acquisitions 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 provides new development opportunities in the 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 $ 1.5 million and $2.2 million of revenue and $1.1 million and $1.7 million of earnings, respectively, for three and nine months ended September 30, 2017 . The acquired producing properties contributed de minimis revenue and earnings for the three and nine months ended September 30, 2016. No significant transaction costs related to the acquisition were incurred for the three and nine months ended September 30, 2017 and 2016 . The June 2017 Acquisition was accounted for using the acquisition method under ASC 805, Business Combinations , which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of June 8, 2017. In August 2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands): Purchase Price June 8, 2017 Consideration given Cash $ 13,395 Total consideration given $ 13,395 Allocation of Purchase Price Proved oil and gas properties $ 13,495 Total fair value of oil and gas properties acquired $ 13,495 Asset retirement obligations $ (100 ) Fair value of net assets acquired $ 13,395 November 2016 Acquisition On November 22, 2016, the Company acquired an unaffiliated oil and gas company’s interest in approximately 9,200 net acres of unproved leaseholds located in the DJ Basin for approximately $120.0 million , including customary closing adjustments (the “November 2016 Acquisition”). This transaction has been accounted for as an asset acquisition. The Company also made a $41.1 million deposit in November 2016 in conjunction with November 2016 Acquisition, which has been reflected in the December 31, 2016 consolidated balance sheet within the cash held in escrow line item. The deposit was made for two additional closings of leaseholds located in the DJ Basin. The first closing occurred in January 2017 and added approximately 5,300 net acres for approximately $26.8 million . The second closing occurred in July 2017 and added approximately 640 net acres for approximately $10.9 million . October 2016 Acquisition On October 3, 2016, the Company acquired an unaffiliated oil and gas company’s interests in approximately 6,400 net acres of leasehold, and related producing and non‑producing properties located primarily in Weld County, Colorado, along with various other related rights, permits, contracts, equipment, rights of way, gathering systems and other assets (the “October 2016 Acquisition” or the “Bayswater Acquisition”). The seller received aggregate consideration of approximately $405.3 million in cash. The effective date for the acquisition was July 1, 2016, with purchase price adjustments calculated as of the closing date on October 3, 2016. The acquisition provides new development opportunities in the DJ Basin as well as increases the Company’s existing working interest, as the majority of the locations are located on acreage in which the Company already owns a majority working interest and operates. The Company incurred $2.6 million of transaction costs related to the acquisition. These transaction costs were recorded in the condensed consolidated statements of operations within the acquisition transaction expenses line item, $0.3 million in transaction costs related to the acquisition were incurred for the three and nine months ended September 30, 2016 . No transaction costs related to the acquisition were incurred for the three and nine months ended September 30, 2017 . The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations , which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of October 3, 2016. In February 2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands): Purchase Price October 3, 2016 Consideration given Cash $ 405,335 Total consideration given $ 405,335 Allocation of Purchase Price Proved oil and gas properties $ 252,522 Unproved oil and gas properties 109,800 Total fair value of oil and gas properties acquired $ 362,322 Goodwill (1) $ 54,220 Working capital (7,185 ) Asset retirement obligations (4,022 ) Fair value of net assets acquired $ 405,335 Working capital acquired was estimated as follows: Accounts receivable $ 955 Revenue payable (3,012 ) Production taxes payable (4,244 ) Accrued liabilities (884 ) Total working capital $ (7,185 ) (1) Goodwill is primarily attributable to a decrease in commodity prices from the time the acquisition was negotiated to commodity prices on October 3, 2016 and the operational and financial synergies expected to be realized from the acquisition. Goodwill recognized as a result of the Bayswater Acquisition is not deductible for income tax purposes. August 2016 Acquisition On August 23, 2016, the Company acquired an unaffiliated oil and gas company’s interests in approximately 1,400 net acres of leasehold located primarily in Weld County, Colorado, along with various other related rights, permits, contracts, equipment, rights of way and other assets (the “August 2016 Acquisition”). The seller received aggregate consideration of approximately $17.5 million in cash. The effective date for the acquisition was August 31, 2016, with purchase price adjustments calculated as of the closing date of August 23, 2016. The acquisition provided new development opportunities in the DJ Basin as well as additions adjacent to the Company’s core project area. The Company incurred $0.1 million of transaction costs related to the acquisition. These transaction costs were recorded in the condensed consolidated statements of operations within the acquisition transaction expenses line item in the third quarter of 2016. The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations , which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of August 23, 2016. In March 2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands): Purchase Price August 23, 2016 Consideration given Cash $ 17,504 Total consideration given $ 17,504 Allocation of Purchase Price Proved oil and gas properties $ 12,362 Unproved oil and gas properties 8,566 Total fair value of oil and gas properties acquired $ 20,928 Working capital $ (9 ) Asset retirement obligations (3,415 ) Fair value of net assets acquired $ 17,504 Working capital acquired was estimated as follows: Production taxes payable $ (9 ) Total working capital $ (9 ) Pro Forma Financial Information (Unaudited) For the three and nine months ended September 30, 2016 , the following pro forma financial information represents the combined results for the Company and the properties acquired in October 2016 as if the acquisition and related financing had occurred on January 1, 2016. For purposes of the pro forma financial information, it was assumed that the October 2016 Acquisition was funded through the issuance of $260.3 million in convertible preferred securities and borrowings under the revolving credit facility. The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion ("DD&A") expense of $9.0 million and $23.1 million for the three and nine months ended September 30, 2016 , respectively. No pro forma adjustments were made for the effect of income taxes for the three and nine months ended September 30, 2016 as the acquisitions occurred before the Corporate Reorganization. The October 2016 Acquisition was included in the historical results of the Company for the three and nine months ended September 30, 2017 , therefore this acquisition has no impact on the pro forma financial information for the three and nine months ended September 30, 2017 . Additionally, the pro forma financial information excludes the effects the August 2016 Acquisition as these pro forma adjustments were de minimis. 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, 2016. The June 2017 Acquisition has no impact on the historical results of the Company for the three and nine months ended September 30, 2016 . For purposes of pro forma financial information, it was assumed that the June 2017 Acquisition was funded through cash. The pro forma financial information had no adjustments for DD&A expense and no adjustments for income tax expense for the three months ended September 30, 2017 as this was included in the condensed consolidated financial results. For the nine months ended September 30, 2017 , the pro forma financial information includes effects of adjustments for DD&A expense of $1.6 million . The pro forma financial information also includes the effects of adjustments for income tax expense of $0.6 million for the nine months ended September 30, 2017 . 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. Net loss per common share is not applicable for the period prior to the Corporate Reorganization. For the Three Months Ended September 30, For the Nine Months Ended September 30, 2017 2016 2017 2016 Revenues $ 180,861 $ 92,476 $ 392,430 $ 230,665 Operating expenses $ 175,699 $ 106,765 $ 427,912 $ 304,677 Net loss $ (29,796 ) $ (30,268 ) $ (13,663 ) $ (197,254 ) Loss per common share, basic and diluted $ (0.20 ) $ (0.15 )

Long Term Debt

Long Term Debt	9 Months Ended
	Sep. 30, 2017
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) $ — $ — 2021 Senior Notes due July 15, 2021 550,000 550,000 2024 Senior Notes due May 15, 2024 400,000 — Unamortized debt issuance costs on Senior Notes (17,430 ) (11,859 ) Total long-term debt 932,570 538,141 Less: current portion of long-term debt — — Total long-term debt, net of current portion $ 932,570 $ 538,141 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) January 15, 2021 if (and only if) the Company's 2021 Senior Notes (as defined below) have not been refinanced or repaid in full on or prior to January 15, 2021, (c) April 15, 2021, if (and only if) (i) the Series A Preferred Stock of the Company (the "Series A Preferred Stock") have not been converted into common equity or redeemed prior to April 15, 2021, and (ii) prior to April 15, 2021, the maturity date of the Series A Preferred Stock has not been extended to a date that is no earlier than six months after August 16, 2022 or (d) the earlier termination in whole of the commitments. As of September 30, 2017 , the credit facility was subject to a borrowing base of $375.0 million . As of September 30, 2017 and, with respect to the Prior Credit Facility, December 31, 2016 , the Company had no outstanding borrowings. As of September 30, 2017 and, with respect to the Prior Credit Facility, December 31, 2016 , the Company had standby letters of credit of $25.7 million and $0.6 million , respectively. At September 30, 2017 , the undrawn balance under the credit facility was $375.0 million . As of the date of this filing, the Company had no borrowings outstanding under the credit facility. Redetermination of the borrowing base was scheduled on August 1, 2017 and semiannually on May 1 and November 1, thereafter. The Company and the administrative agent under the credit facility may each elect a redetermination of the borrowing base between any two scheduled redeterminations. The scheduled August 1, 2017 redetermination closed in October 2017, resulting in a borrowing base increase to $525.0 million . Interest on the credit facility is payable at one of the following two variable rates as selected by the Company: a base rate based on the Prime Rate or the Eurodollar rate, based on LIBOR. Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the facility as outlined in the pricing grid 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% 2.00% 1.00% 0.375% Level 2 ≥ 25% < 50% 2.25% 1.25% 0.375% Level 3 ≥ 50% < 75% 2.50% 1.50% 0.500% Level 4 ≥ 75% < 90% 2.75% 1.75% 0.500% Level 5 ≥ 90% 3.00% 2.00% 0.500% The credit facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on dividends, distributions, redemptions and restricted payments covenants; (iii) limitations on investments, loans and advances covenants; (iv) limitations on the sale of property, mergers, consolidations and other similar transactions covenants; and (v) holding cash balances in excess of certain thresholds while carrying a balance on the credit facility. 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 . For the quarter ending September 30, 2017, consolidated EBITDAX will be based on the last six months ’ consolidated EBITDAX multiplied by 2 ; and for the quarter ending December 31, 2017, consolidated EBITDAX will be based on the last nine months ’ consolidated EBITDAX multiplied by 4/3. For the quarters ending on or after March 31, 2018, consolidated EBITDAX will be based on the last twelve months ’ consolidated EBITDAX. The Company was in compliance with all financial covenants under the credit facility as of September 30, 2017 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 its subsidiaries, including oil and gas properties, personal property and the equity interests of the subsidiaries of the Company. The Company has entered into oil and natural gas hedging transactions with several counterparties that are also lenders under the credit facility. The Company’s obligations under these hedging contracts are secured by the collateral securing the credit facility. 2021 Senior Notes In July 2016, the Company issued at par $550.0 million principal amount of 7.875% Senior Notes due July 15, 2021 (the “2021 Senior Notes” and the offering, the “2021 Senior Notes Offering”). The 2021 Senior Notes bear an annual interest rate of 7.875% . The interest on the 2021 Senior Notes is payable on January 15 and July 15 of each year commencing on January 15, 2017. The Company received net proceeds of approximately $537.2 million after deducting discounts and fees. The 2021 Senior Notes are the Company's 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 2021 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of the Company's current and future restricted subsidiaries (other than Extraction Finance Corp., the co-issuer of the 2021 Senior Notes) that guarantees its indebtedness under a credit facility (the “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 future subsidiaries that do not guarantee the notes. The 2021 Senior Notes also contain affirmative and negative covenants that, among other things, limit the Company's and the Guarantors' ability to make investments; declare or pay any dividend or make any other payment to holders of the Company’s or any of its Guarantors’ equity interests; repurchase or redeem any equity interests of the Company; repurchase or redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company's affiliates; engage in any business other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2021 Senior Notes (the “2021 Senior Notes Indenture”) also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2021 Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the 2021 Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2021 Senior Notes may declare all outstanding 2021 Senior Notes to be due and payable immediately. The Company was in compliance with all financial covenants under the 2021 Senior Notes Indenture as of September 30, 2017 , and through the filing of this report. 2024 Senior Notes In August 2017, the Company issued at par $400.0 million principal amount of 7.375% Senior Notes due May 15, 2024 (the “2024 Senior Notes” and the offering, the “2024 Senior Notes Offering”). The 2024 Senior Notes bear an annual interest rate of 7.375% . The interest on the 2024 Senior Notes is payable on May 15 and November 15 of each year commencing on November 15, 2017. The Company received net proceeds of approximately $392.6 million after deducting discounts and fees. The Company's 2024 Senior Notes are its senior unsecured obligations and rank equally in right of payment with all of its other senior indebtedness and senior to any of its subordinated indebtedness. The Company's 2024 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of its current subsidiaries and by certain future restricted subsidiaries that guarantees its indebtedness under a credit facility (the “2024 Senior Note Guarantors”). The 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. The Company was in compliance with all financial covenants under the 2024 Senior Notes Indenture through the filing of this report. Debt Issuance Costs As of September 30, 2017 , the Company had debt issuance costs, net of accumulated amortization, of $3.1 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, 2017 , the Company had debt issuance costs, net of accumulated amortization, of $17.4 million related to its 2021 and 2024 Senior Notes (collectively, the "Senior Notes") which has been reflected on the Company's condensed 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, 2021 Senior Notes and 2024 Senior Notes. For the three and nine months ended September 30, 2017 , the Company recorded amortization expense related to debt issuance costs of $1.5 million and $3.2 million , respectively as compared to $11.6 million and $13.5 million for the three and nine months ended September 30, 2016 , respectively. Debt issuance costs for the three and nine months ended September 30, 2016 include $10.8 million of acceleration of amortization expense upon the repayment of the Company's Second Lien Notes. For additional information regarding amortization expense on Second Lien Notes, see the Company's Annual Report. Debt Discount Costs on Second Lien Notes For the three and nine months ended September 30, 2016 , the Company recorded amortization expense related to the debt discount on its Second Lien Notes of $4.3 million and $4.8 million , respectively. The Company recorded no amortization expense related to the debt discount on its Second Lien Notes for the three and nine months ended September 30, 2017 . For additional information regarding debt discount costs on Second Lien Notes, see the Company’s Annual Report. Interest Incurred on Long‑Term Debt For the three and nine months ended September 30, 2017 , the Company incurred interest expense on long‑term debt of $16.5 million and $39.2 million , respectively, as compared to $12.2 million and $38.9 million for the three and nine months ended September 30, 2016 , respectively. For the three and six months ended September 30, 2017 , the Company capitalized interest expense on long term debt of $2.9 million and $8.6 million , respectively, as compared to $1.2 million and $3.6 million for the three and nine months ended September 30, 2016 , respectively, which has been reflected in the Company’s condensed consolidated financial statements. Also included in interest expense for the three and nine months ended September 30, 2016 is a prepayment penalty of $4.3 million related to the Company's repayment of its Second Lien Notes in July 2016.

Commodity Derivative Instrument

Commodity Derivative Instruments	9 Months Ended
	Sep. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivative Instruments	Commodity Derivative Instruments The Company has entered into commodity derivative instruments, as described below. The Company has utilized swaps, put options and call options to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production. A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. A put option has an established floor price. The buyer of the put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless. Some of the Company’s purchased put options have deferred premiums. For the deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement. A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless. The Company combines swaps, purchased put options, purchased call options, sold put options and sold call options in order to achieve various hedging strategies. Some examples of the Company’s hedging strategies are collars which include purchased put options and sold call options, three-way collars which include purchased put options, sold put options and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap. The objective of the Company’s use of commodity derivative instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these commodity derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes. The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with six 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, 2017 are summarized below: 2017 2018 2019 NYMEX WTI (1) Crude Swaps: Notional volume (Bbl) 1,850,000 5,100,000 — Weighted average fixed price ($/Bbl) $ 50.64 $ 51.61 NYMEX WTI (1) Crude Sold Calls: Notional volume (Bbl) 1,200,000 6,190,000 3,000,000 Weighted average sold call price ($/Bbl) $ 53.04 $ 55.75 $ 55.10 NYMEX WTI (1) Crude Sold Puts: Notional volume (Bbl) 3,225,000 11,338,800 3,000,000 Weighted average sold put price ($/Bbl) $ 37.19 $ 38.93 $ 39.70 NYMEX WTI (1) Crude Purchased Puts: Notional volume (Bbl) 1,800,000 6,838,800 3,000,000 Weighted average purchased put price ($/Bbl) $ 42.13 $ 47.35 $ 49.37 NYMEX HH (2) Natural Gas Swaps: Notional volume (MMBtu) 7,420,000 37,200,000 — Weighted average fixed price ($/MMBtu) $ 3.06 $ 3.10 NYMEX HH (2) Natural Gas Purchased Puts: Notional volume (MMBtu) — 2,400,000 — Weighted average purchased put price ($/MMBtu) $ 3.00 NYMEX HH (2) Natural Gas Sold Calls: Notional volume (MMBtu) — 2,400,000 — Weighted average sold call price ($/MMBtu) $ 3.15 CIG (3) Basis Gas Swaps: Notional volume (MMBtu) 5,215,000 6,300,000 — Weighted average fixed basis price ($/MMBtu) $ (0.31 ) $ (0.31 ) (1) NYMEX WTI refers to West Texas Intermediate crude oil price on the New York Mercantile Exchange. (2) NYMEX HH refers to the Henry Hub natural gas price on the New York Mercantile Exchange. (3) CIG refers to the NYMEX HH settlement price less the fixed basis price, the Rocky Mountains (CIGC) settlement price. 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, 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 $ 25,250 $ (24,264 ) $ 986 $ (146 ) $ 840 Non-current assets $ 25,141 $ (25,141 ) $ — $ — $ — Current liabilities $ (32,523 ) $ 24,264 $ (8,259 ) $ 146 $ (11,138 ) Non-current liabilities $ (28,166 ) $ 25,141 $ (3,025 ) $ — $ — As of December 31, 2016 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 $ 12,620 $ (12,620 ) $ — $ — $ — Non-current assets $ 14,993 $ (14,993 ) $ — $ — $ — Current liabilities $ (68,623 ) $ 12,620 $ (56,003 ) $ — $ (62,741 ) Non-current liabilities $ (21,731 ) $ 14,993 $ (6,738 ) $ — $ — (1) Agreements are in place with all of the Company’s financial trading counterparties that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. (2) Netting for balance sheet presentation is performed by current and non‑current classification. This adjustment represents amounts subject to an enforceable master netting arrangement, which are not netted on the 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, 2017 and 2016 (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, 2017 2016 2017 2016 Commodity derivatives gain (loss) $ (37,875 ) $ 16,225 $ 46,423 $ (62,424 )

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The Company follows accounting for asset retirement obligations in accordance with ASC 410, Asset Retirement and Environmental Obligations , which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The Company’s asset retirement obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut-in wells at the end of their productive lives in accordance with applicable local, state and federal laws and applicable lease terms. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement costs are depleted with proved oil and gas properties using the unit-of-production method. The following table summarizes the activities of the Company’s asset retirement obligations for the period indicated (in thousands): For the Nine Months Ended September 30, 2017 For the Year Ended December 31, 2016 Balance beginning of period $ 56,108 $ 44,367 Liabilities incurred or acquired 6,644 8,945 Liabilities settled (1,408 ) (1,155 ) Revisions in estimated cash flows — (1,695 ) Accretion expense 3,847 5,646 Balance end of period $ 65,191 $ 56,108

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements ASC 820, Fair Value Measurement and Disclosure , establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows: • Level 1: Quoted prices are available in active markets for identical assets or liabilities; • Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; • Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations. The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between levels during any periods presented below. The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2017 and December 31, 2016 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 $ — $ 986 $ — $ 986 Financial Liabilities: Commodity derivative liabilities $ — $ 11,284 $ — $ 11,284 Fair Value Measurements at Level 1 Level 2 Level 3 Total Financial Assets: Commodity derivative assets $ — $ — $ — $ — Financial Liabilities: Commodity derivative liabilities $ — $ 62,741 $ — $ 62,741 The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above: Commodity Derivative Instruments The Company determines its estimate of the fair value of derivative instruments using a market based approach that takes into account several factors, including quoted market prices in active markets, implied market volatility factors, quotes from third parties, the credit rating of each counterparty and the Company’s own credit rating. In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. Derivative instruments utilized by the Company consist of swaps, put options and call options. The oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are valued using public indices, the instruments themselves are traded with third party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2. Fair Value of Financial Instruments The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and long-term debt. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company’s credit facility approximated fair value as it bears interest at variable rates over the term of the loan. The fair value of the 2021 Senior Notes and 2024 Senior Notes were derived from available market data. As such, the Company has classified the 2021 Senior Notes and 2024 Senior Notes as Level 2. Please refer to Note 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, 2017 At December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value 2021 Senior Notes (1) $ 539,804 $ 580,250 $ 538,141 $ 588,500 2024 Senior Notes (2) $ 392,766 $ 419,000 $ — $ — (1) The carrying amount of the 2021 Senior Notes includes unamortized debt issuance costs of $10.2 million and $11.9 million as of September 30, 2017 and December 31, 2016 , respectively. (2) The carrying amount of the 2024 Senior Notes includes unamortized debt issuance costs of $7.2 million as of September 30, 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 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). No impairment expense was recognized for the three and nine months ended September 30, 2017 and the three months ended September 30, 2016 on proved oil and gas properties. For the nine months ended September 30, 2016 , the Company recognized $22.4 million in impairment expense on its proved oil and gas properties related to impairment of assets in its northern field. The future undiscounted cash flows did not exceed the Company’s carrying amount associated with its proved oil and gas properties in its northern field and it was determined that the proved oil and gas properties had no remaining fair value. Therefore, the full net book value of these proved oil and gas properties was impaired at September 30, 2016 . The Company applies the provisions of ASC 350, Intangibles-Goodwill and Other . Goodwill represents the excess of the purchase price over the estimated value of the net assets acquired in business combinations. The Company tests goodwill for impairment annually on September 30, or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. The goodwill test is performed at the reporting unit level, which represents the Company’s oil and gas operations in its core DJ Basin field. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. Any sharp prolonged decreases in the prices of oil and natural gas as well as continued declines in the quoted market price of the Company’s common shares could change the estimates of the fair value of the reporting unit and could result in an impairment charge. The Company performed an assessment as of September 30, 2017 , which concluded the fair value of the reporting unit was greater than its carrying amount. The Company’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 . 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, 2017
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 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, 2017 was 35.3% . During the nine months ended September 30, 2017 , the Company recognized income tax benefit of $7.6 million . The effective rate for the nine months ended September 30, 2017 differs from the statutory U.S. federal income tax rate of 35% primarily due to state income taxes and estimated permanent differences. Included as a discrete item during the three months ended September 30, 2017 is the tax deficiency related to equity compensation in excess of compensation recognized for financial reporting. 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. The Company’s accounting predecessor was a limited liability company that was not subject to U.S. federal income tax during the first nine months of 2016. The Company adopted ASU No. 2016-09 on January 1, 2017. There was no tax effect upon adoption as the Company did not have an accumulated windfall pool as of December 31, 2016.

Unit and Stock-Based Compensati

Unit and Stock-Based Compensation	9 Months Ended
	Sep. 30, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Unit and Stock-Based Compensation	Unit and Stock‑Based Compensation Extraction Long Term Incentive Plan In October 2016, the 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. 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 were measured at the grant date using the Black-Scholes valuation model. The Company utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited historical exercise data available in estimating the expected term of the stock options. Expected volatility is based on the volatility of the historical stock prices of the Company’s peer group. The risk-free rates are based on the yields of U.S. Treasury instruments with comparable terms. A dividend yield and forfeiture rate of zero were assumed. Stock options granted under the LTIP vest ratably over three years and are exercisable immediately upon vesting through the tenth anniversary of the grant date. To fulfill options exercised, the Company will issue new shares. The Company recorded $3.3 million and $9.9 million of stock-based compensation costs related to the stock options 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. The Company did not record any stock-based compensation expense related to stock options for the three and nine months ended September 30, 2016 . As of September 30, 2017 , there was $26.6 million of unrecognized compensation cost related to the stock options that is expected to be recognized over a weighted average period of 2.0 years . The following table summarizes the stock option activity from January 1, 2017 through September 30, 2017 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, 2017 4,500,000 $ 19.00 Granted — $ — Forfeited — $ — Vested — $ — Non-vested Stock Options at September 30, 2017 4,500,000 $ 19.00 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 $8.9 million and $24.6 million of stock-based compensation costs related to RSUs for the three and nine months ended September 30, 2017 , respectively. The Company did not record any stock-based compensation costs related to RSUs for the three and nine months ended September 30, 2016 . These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of September 30, 2017 , there was $52.7 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 1.9 years . The following table summarizes the RSU activity from January 1, 2017 through September 30, 2017 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, 2017 3,237,500 $ 21.41 Granted 1,305,033 $ 16.43 Forfeited (403,725) $ 19.72 Vested (85,994) $ 16.82 Non-vested RSUs at September 30, 2017 4,052,814 $ 20.07 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 will to 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 $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 , respectively. The Company did not record any stock-based compensation costs related to Incentive RSUs for the three and nine months ended September 30, 2016 . These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of September 30, 2017 , there was $26.5 million of total unrecognized compensation cost related to the unvested Incentive RSUs granted to certain employees that is expected to be recognized over a weighted average period of 1.3 years . The following table summarizes the Incentive RSU activity from January 1, 2017 through September 30, 2017 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, 2017 2,714,368 $ 20.45 Granted — $ — Forfeited (703,868) $ 20.45 Vested (507,200) $ 20.45 Non-vested Incentive RSUs at September 30, 2017 1,503,300 $ 20.45 Unit-Based Compensation The Company recorded $12.3 million and $14.9 million of unit-based compensation costs related to restricted unit awards for the three and nine months ended September 30, 2016 , respectively. There was no unrecognized compensation costs related to these restricted unit awards as of September 30, 2017 . For additional disclosure regarding these restricted unit awards, see the Company’s Annual Report.

Earnings (Loss) Per Share

Earnings (Loss) Per Share	9 Months Ended
	Sep. 30, 2017
Earnings Per Share [Abstract]
Earnings (Loss) per Share	Earnings (Loss) Per Share Basic earnings per share (“EPS”) includes no dilution and is computed by dividing net income (loss) 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, 2017 . EPS information is not applicable for the three and nine months ended September 30, 2016 . The components of basic and diluted EPS were as follows (in thousands, except per share data): For the Three Months Ended September 30, 2017 For the Nine Months Ended September 30, 2017 Basic and Diluted Loss Per Share Net Loss $ (29,796 ) $ (13,840 ) Less: Adjustment to reflect Series A Preferred Stock dividend (2,721 ) (8,164 ) Less: Adjustment to reflect accretion of Series A Preferred Stock discount (1,365 ) (3,992 ) Adjusted net loss available to common shareholders, basic and diluted $ (33,882 ) $ (25,996 ) Denominator: Weighted average common shares outstanding, basic and diluted (1) 171,845 171,838 Loss Per Common Share Basic and diluted $ (0.20 ) $ (0.15 ) (1) For the three and nine months ended September 30, 2017 , the diluted EPS calculation excludes the anti-dilutive effect of 4,500,000 common shares for stock options that were out-of-the-money, 4,052,814 RSUs and 11,472,445 common shares issuable for Series A Preferred Stock under the if-converted method.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Leases The Company leases two office spaces in Denver, Colorado, one office space in Greeley, Colorado and one office space in Houston, Texas under separate operating lease agreements. The Denver, Colorado leases expire on February 29, 2020 and May 31, 2026, respectively. The Greeley and Houston leases expire on August 31, 2019 and October 31, 2017, respectively. Total rental commitments under non‑cancelable leases for office space were $19.6 million at September 30, 2017 . The future minimum lease payments under these non‑cancelable leases are as follows: $0.6 million in 2017 , $2.6 million in 2018 , $2.5 million in 2019 , $2.2 million in 2020 , $2.2 million in 2021 and $9.5 million thereafter. Rent expense was $0.5 million and $1.7 million for the three and nine months ended September 30, 2017 , respectively, as compared to $0.6 million and $1.3 million for the three and nine months ended September 30, 2016 , 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 $0.6 million . Drilling Rigs As of September 30, 2017 , the Company was subject to commitments on four drilling rigs. In the event of early termination of these contracts, the Company would be obligated to pay an aggregate amount of approximately $12.1 million as of September 30, 2017 , as required under the terms of the contracts. The fourth rig is expected to be placed in service during the fourth quarter of 2017 and will replace a rig currently under contract. Delivery Commitments As of September 30, 2017 , 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. 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. The Company evaluates its contracts for loss contingencies and accrues for such losses, if the loss can be reasonably estimated and deemed probable. The Company also has one long-term crude oil gathering commitment with an unconsolidated affiliate. It 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 aggregate amount of estimated payments under these agreements is $1.0 billion . In collaboration with several other producers and a midstream provider, on December 15, 2016 and August 7, 2017, the Company agreed to participate in expansions of natural gas gathering and processing capacity in the DJ Basin. The plan includes two new processing plants as well as the expansion of related gathering systems, which are currently expected to be completed by late 2018 and mid-2019, respectively, although the 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 date 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. None of the Company’s reserves are subject to any priorities or curtailments that may affect quantities delivered to its customers. The Company believes that its future production is adequate to meet its commitments. If for some reason the Company’s production is not sufficient to satisfy its commitments, the Company expects to be able to purchase volumes in the market or make other arrangements to satisfy its commitments. Acquisition of Undeveloped Leasehold Acreage As of September 30, 2017 , the Company is party to an agreement with an unrelated third party for which it has paid $77.5 million and may be required to pay up to an additional $116.5 million , subject to certain customary conditions, to lease up to a total of approximately 30,000 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 connect wells to gathering and transportation services and reserve or earn certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost or the Company may be required to pay damages if certain performance conditions are not met. Legal Matters In the ordinary course of business, the Company may at times be subject to claims and legal actions. Management believes it is remote that the impact of such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows. Management is unaware of any pending litigation brought against the Company requiring the reserve of a contingent liability as of the date of this filing. The Company is currently in discussions with the Colorado Department of Public Health and Environment (“CDPHE”) regarding a Compliance Advisory issued to the Company in July 2015, which alleged air quality violations at three Company facilities regarding leakages of volatile organic compounds from storage tanks, all of which were promptly addressed. The Company continues to work with the CDPHE on its investigation into the Company's facilities and it intends to seek a field-wide administrative settlement of these issues. At this time, we anticipate the remediation and compliance costs that this matter may impose upon us to be an immaterial amount.

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2017
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Office Lease with Related Affiliate In April 2016, the Company subleased office space to Star Peak Capital, LLC, of which a member of the board of directors is an owner, for $1,400 per month. The sublease commenced on May 1, 2016 and expires on February 28, 2020. 2021 Senior Notes Several lenders of the 2021 Senior Notes are also 5% stockholders of the Company. 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 lenders of the 2024 Senior Notes are also 5% stockholders of the Company. As of the initial issuance in August 2017 of the $400.0 million principal amount on the 2024 Senior Notes, such stockholders held $54.9 million . Series A Preferred Stock Several holders of the Series A Preferred Stock are also 5% stockholders of the Company. As of the initial issuance in October 2016 of the $185.3 million of Series A Preferred Stock, such stockholders held $105.0 million . Long-Term Crude Oil Gathering Commitment The Company has a long-term crude oil gathering commitment with an unconsolidated affiliate. It 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 in years three through five and 10,000 Bbl/d in years six through ten. The aggregate amount of estimate payments under this agreement is $71.9 million .

Basis of Presentation, Signif19

Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements (Policies)	9 Months Ended
	Sep. 30, 2017
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 May 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-09, which provides clarification and reduces both (1) diversity in practice and (2) cost and complexity when applying the guidance in Topic 718 Compensation - Stock Compensation, to a change to the terms or conditions of a share-based payment award. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that reporting period. Early adoption is permitted for fiscal years beginning after December 15, 2016, including the interim reporting periods within that fiscal year. The Company is currently evaluating the impact of adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements. In February 2017, the FASB issued ASU No. 2017-05, which provided clarification regarding the guidance on accounting for the derecognition of nonfinancial assets. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that fiscal year. The Company is currently evaluating this new standard to determine the potential impact to its 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 this ASU and believes it could have a material impact to its financial statements and related disclosures. In January 2017, the FASB issued ASU No. 2017-01, which clarifies the definition of a business when evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted for transactions for which the acquisition date occurs before the issuance date or effective date of the amendments, only when the transaction has not been reported in the financial statements that have been issued. The Company is currently evaluating this ASU and believes it could have a material impact to its financial statements and related disclosures. In November 2016, the FASB issued ASU No. 2016-18, which intends to clarify how entities should present restricted cash and restricted cash equivalents in the statement of cash flows. This amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company is currently evaluating the impact of adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements. In August 2016, the FASB issued ASU No. 2016-15, which addresses eight specific cash flow issues, including presentation of debt prepayments or debt extinguishment costs, with the objective of reducing the existing diversity in practice. In addition, in November 2016, the FASB issued ASU No. 2016-18, which requires that amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company is currently evaluating this ASU to determine the potential impact to its financial statements and related disclosures. In March 2016, the FASB issued ASU No. 2016-06, which clarifies the requirements to assess whether an embedded put or call option is clearly and closely related to the debt host, solely in accordance with the four step decision sequence in FASB ASB Topic 815, Derivatives and Hedging, as amended by this ASU. This standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and should be applied using a modified retrospective approach. The Company adopted this ASU in the first quarter of 2017 and the adoption of this ASU did not have a material impact on the its consolidated financial statements. 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. In September 2017, the FASB issued ASU No. 2017-13, which provided additional implementation guidance. The Company is currently evaluating the impact this ASU will have on its financial statements and related disclosures and developing a strategy for implementation. In May 2014, the FASB issued ASU No. 2014-09, which establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The ASU allows for the use of either the full or modified retrospective transition method. In August 2015, the FASB issued ASU No. 2015-14, which deferred ASU No. 2014-09 for one year, and is effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of reporting periods beginning after December 15, 2016. The FASB subsequently issued ASU No. 2016-08, ASU No. 2016-10, ASU No. 2016-11, ASU No. 2016-12, ASU No. 2016-20, and ASU No. 2017-13, which provided additional implementation guidance. The Company is in the final stages of its review of contracts in each of its revenue streams and has developed accounting policies to address the provisions of this ASU. While the Company does not expect operating income (loss) to be materially impacted, the Company does expect total revenues and total expenses to change as a result of certain percentage of proceeds contracts. Further, the Company has begun evaluating the design of its pre-adoption and adoption controls and expects new or modification of certain controls to address risks associated with recognizing revenue under the new standard as we continue the implementation process. The Company will continue to evaluate the impact of this and other provisions of the ASU on its accounting policies, internal controls, and consolidated financial statements and related disclosures and has not finalized any estimates of the potential impacts. The Company will adopt this new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings. 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 financial statements and related disclosures that have been issued but not yet adopted by the Company through the date of this filing.

Acquisitions (Tables)

Acquisitions (Tables)	9 Months Ended
	Sep. 30, 2017
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. Net loss per common share is not applicable for the period prior to the Corporate Reorganization. For the Three Months Ended September 30, For the Nine Months Ended September 30, 2017 2016 2017 2016 Revenues $ 180,861 $ 92,476 $ 392,430 $ 230,665 Operating expenses $ 175,699 $ 106,765 $ 427,912 $ 304,677 Net loss $ (29,796 ) $ (30,268 ) $ (13,663 ) $ (197,254 ) Loss per common share, basic and diluted $ (0.20 ) $ (0.15 )
October 2016 Acquisition
Acquisitions
Schedule summarizing the purchase price and allocation of fair value of assets acquired and liabilities assumed	The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands): Purchase Price October 3, 2016 Consideration given Cash $ 405,335 Total consideration given $ 405,335 Allocation of Purchase Price Proved oil and gas properties $ 252,522 Unproved oil and gas properties 109,800 Total fair value of oil and gas properties acquired $ 362,322 Goodwill (1) $ 54,220 Working capital (7,185 ) Asset retirement obligations (4,022 ) Fair value of net assets acquired $ 405,335 Working capital acquired was estimated as follows: Accounts receivable $ 955 Revenue payable (3,012 ) Production taxes payable (4,244 ) Accrued liabilities (884 ) Total working capital $ (7,185 ) (1) Goodwill is primarily attributable to a decrease in commodity prices from the time the acquisition was negotiated to commodity prices on October 3, 2016 and the operational and financial synergies expected to be realized from the acquisition. Goodwill recognized as a result of the Bayswater Acquisition is not deductible for income tax purposes.
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
August 2016 Acquisition
Acquisitions
Schedule summarizing the purchase price and allocation of fair value of assets acquired and liabilities assumed	The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands): Purchase Price August 23, 2016 Consideration given Cash $ 17,504 Total consideration given $ 17,504 Allocation of Purchase Price Proved oil and gas properties $ 12,362 Unproved oil and gas properties 8,566 Total fair value of oil and gas properties acquired $ 20,928 Working capital $ (9 ) Asset retirement obligations (3,415 ) Fair value of net assets acquired $ 17,504 Working capital acquired was estimated as follows: Production taxes payable $ (9 ) Total working capital $ (9 )

Long Term Debt (Tables)

Long Term Debt (Tables)	9 Months Ended
	Sep. 30, 2017
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) $ — $ — 2021 Senior Notes due July 15, 2021 550,000 550,000 2024 Senior Notes due May 15, 2024 400,000 — Unamortized debt issuance costs on Senior Notes (17,430 ) (11,859 ) Total long-term debt 932,570 538,141 Less: current portion of long-term debt — — Total long-term debt, net of current portion $ 932,570 $ 538,141
Schedule of Borrowing Base Utilization Grid	The grid below shows the Base Rate Margin and Eurodollar Margin depending on the applicable Borrowing Base Utilization Percentage (as defined in the credit facility) as of the date of this filing: Borrowing Base Utilization Grid Borrowing Base Utilization Percentage Utilization Eurodollar Margin Base Rate Margin Commitment Fee Rate Level 1 < 25% 2.00% 1.00% 0.375% Level 2 ≥ 25% < 50% 2.25% 1.25% 0.375% Level 3 ≥ 50% < 75% 2.50% 1.50% 0.500% Level 4 ≥ 75% < 90% 2.75% 1.75% 0.500% Level 5 ≥ 90% 3.00% 2.00% 0.500%

Commodity Derivative Instrume22

Commodity Derivative Instruments (Tables)	9 Months Ended
	Sep. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of commodity derivative contracts	The Company’s commodity derivative contracts as of September 30, 2017 are summarized below: 2017 2018 2019 NYMEX WTI (1) Crude Swaps: Notional volume (Bbl) 1,850,000 5,100,000 — Weighted average fixed price ($/Bbl) $ 50.64 $ 51.61 NYMEX WTI (1) Crude Sold Calls: Notional volume (Bbl) 1,200,000 6,190,000 3,000,000 Weighted average sold call price ($/Bbl) $ 53.04 $ 55.75 $ 55.10 NYMEX WTI (1) Crude Sold Puts: Notional volume (Bbl) 3,225,000 11,338,800 3,000,000 Weighted average sold put price ($/Bbl) $ 37.19 $ 38.93 $ 39.70 NYMEX WTI (1) Crude Purchased Puts: Notional volume (Bbl) 1,800,000 6,838,800 3,000,000 Weighted average purchased put price ($/Bbl) $ 42.13 $ 47.35 $ 49.37 NYMEX HH (2) Natural Gas Swaps: Notional volume (MMBtu) 7,420,000 37,200,000 — Weighted average fixed price ($/MMBtu) $ 3.06 $ 3.10 NYMEX HH (2) Natural Gas Purchased Puts: Notional volume (MMBtu) — 2,400,000 — Weighted average purchased put price ($/MMBtu) $ 3.00 NYMEX HH (2) Natural Gas Sold Calls: Notional volume (MMBtu) — 2,400,000 — Weighted average sold call price ($/MMBtu) $ 3.15 CIG (3) Basis Gas Swaps: Notional volume (MMBtu) 5,215,000 6,300,000 — Weighted average fixed basis price ($/MMBtu) $ (0.31 ) $ (0.31 ) (1) NYMEX WTI refers to West Texas Intermediate crude oil price on the New York Mercantile Exchange. (2) NYMEX HH refers to the Henry Hub natural gas price on the New York Mercantile Exchange. (3) CIG refers to the NYMEX HH settlement price less the fixed basis price, the Rocky Mountains (CIGC) settlement price
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, 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 $ 25,250 $ (24,264 ) $ 986 $ (146 ) $ 840 Non-current assets $ 25,141 $ (25,141 ) $ — $ — $ — Current liabilities $ (32,523 ) $ 24,264 $ (8,259 ) $ 146 $ (11,138 ) Non-current liabilities $ (28,166 ) $ 25,141 $ (3,025 ) $ — $ — As of December 31, 2016 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 $ 12,620 $ (12,620 ) $ — $ — $ — Non-current assets $ 14,993 $ (14,993 ) $ — $ — $ — Current liabilities $ (68,623 ) $ 12,620 $ (56,003 ) $ — $ (62,741 ) Non-current liabilities $ (21,731 ) $ 14,993 $ (6,738 ) $ — $ — (1) Agreements are in place with all of the Company’s financial trading counterparties that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. (2) Netting for balance sheet presentation is performed by current and non‑current classification. This adjustment represents amounts subject to an enforceable master netting arrangement, which are not netted on the 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, 2017 and 2016 (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, 2017 2016 2017 2016 Commodity derivatives gain (loss) $ (37,875 ) $ 16,225 $ 46,423 $ (62,424 )

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2017
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, 2017 For the Year Ended December 31, 2016 Balance beginning of period $ 56,108 $ 44,367 Liabilities incurred or acquired 6,644 8,945 Liabilities settled (1,408 ) (1,155 ) Revisions in estimated cash flows — (1,695 ) Accretion expense 3,847 5,646 Balance end of period $ 65,191 $ 56,108

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Schedule of financial assets and liabilities accounted for at fair value on a recurring basis	The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2017 and December 31, 2016 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 $ — $ 986 $ — $ 986 Financial Liabilities: Commodity derivative liabilities $ — $ 11,284 $ — $ 11,284 Fair Value Measurements at Level 1 Level 2 Level 3 Total Financial Assets: Commodity derivative assets $ — $ — $ — $ — Financial Liabilities: Commodity derivative liabilities $ — $ 62,741 $ — $ 62,741
Schedule of fair value of financial instruments	This disclosure (in thousands) does not impact the Company’s financial position, results of operations or cash flows. At September 30, 2017 At December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value 2021 Senior Notes (1) $ 539,804 $ 580,250 $ 538,141 $ 588,500 2024 Senior Notes (2) $ 392,766 $ 419,000 $ — $ — (1) The carrying amount of the 2021 Senior Notes includes unamortized debt issuance costs of $10.2 million and $11.9 million as of September 30, 2017 and December 31, 2016 , respectively.

Unit and Stock-Based Compensa25

Unit and Stock-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2017
Unit and Stock-Based Compensation
Schedule summarizing stock option activity	The following table summarizes the stock option activity from January 1, 2017 through September 30, 2017 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, 2017 4,500,000 $ 19.00 Granted — $ — Forfeited — $ — Vested — $ — Non-vested Stock Options at September 30, 2017 4,500,000 $ 19.00
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, 2017 through September 30, 2017 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, 2017 2,714,368 $ 20.45 Granted — $ — Forfeited (703,868) $ 20.45 Vested (507,200) $ 20.45 Non-vested Incentive RSUs at September 30, 2017 1,503,300 $ 20.45
2016 Long Term Incentive Plan | RSUs
Unit and Stock-Based Compensation
Schedule of non-vested restricted award activity	The following table summarizes the RSU activity from January 1, 2017 through September 30, 2017 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, 2017 3,237,500 $ 21.41 Granted 1,305,033 $ 16.43 Forfeited (403,725) $ 19.72 Vested (85,994) $ 16.82 Non-vested RSUs at September 30, 2017 4,052,814 $ 20.07

Earnings (Loss) Per Share (Tabl

Earnings (Loss) Per Share (Tables)	9 Months Ended
	Sep. 30, 2017
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 September 30, 2017 For the Nine Months Ended September 30, 2017 Basic and Diluted Loss Per Share Net Loss $ (29,796 ) $ (13,840 ) Less: Adjustment to reflect Series A Preferred Stock dividend (2,721 ) (8,164 ) Less: Adjustment to reflect accretion of Series A Preferred Stock discount (1,365 ) (3,992 ) Adjusted net loss available to common shareholders, basic and diluted $ (33,882 ) $ (25,996 ) Denominator: Weighted average common shares outstanding, basic and diluted (1) 171,845 171,838 Loss Per Common Share Basic and diluted $ (0.20 ) $ (0.15 ) (1) For the three and nine months ended September 30, 2017 , the diluted EPS calculation excludes the anti-dilutive effect of 4,500,000 common shares for stock options that were out-of-the-money, 4,052,814 RSUs and 11,472,445 common shares issuable for Series A Preferred Stock under the if-converted method.

Acquisitions - July 2017 Acquis

Acquisitions - July 2017 Acquisition (Details) $ in Thousands	Jul. 07, 2017USD ($)a	Sep. 30, 2017USD ($)	Dec. 31, 2016USD ($)
Acquisitions
Deposit		$ 0	$ 42,200
July 2017 Acquisition
Acquisitions
Acres acquired or to be acquired | a	12,500
Purchase price	$ 84,000

Acquisitions - June 2017 Acquis

Acquisitions - June 2017 Acquisition (Details) a in Thousands	Jun. 08, 2017USD ($)a	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)
Acquisitions
Earnings		$ (29,796,000)	$ (37,267,000)	$ (13,840,000)	$ (210,400,000)
Acquisition transaction expenses		0	345,000	68,000	345,000
June 2017 Acquisition
Acquisitions
Acres acquired | a	0
Total consideration given	$ 13,395,000
Cash	13,395,000
Revenues		1,500,000		2,200,000
Earnings		1,100,000		1,700,000
Proved oil and gas properties	13,495,000
Total fair value of oil and gas properties acquired	13,495,000
Asset retirement obligations	(100,000)
Fair value of net assets acquired	$ 13,395,000
Acquisition transaction expenses		$ 0	$ 0	$ 0	$ 0

Acquisitions - November 2016 Ac

Acquisitions - November 2016 Acquisition (Details) $ in Thousands	Nov. 22, 2016USD ($)acontract	Jul. 31, 2017USD ($)a	Jan. 31, 2017USD ($)a	Sep. 30, 2017USD ($)	Dec. 31, 2016USD ($)
Acquisitions
Deposit				$ 0	$ 42,200
November 2016 Acquisition
Acquisitions
Acres acquired | a	9,200	640	5,300
Purchase price	$ 120,000	$ 10,900	$ 26,800
November 2016 Acquisition | Cash Held in Escrow
Acquisitions
Deposit	$ 41,100
Number of additional closings | contract	2

Acquisitions - October 2016 Acq

Acquisitions - October 2016 Acquisition (Details)	Oct. 03, 2016USD ($)a	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Nov. 03, 2017USD ($)	Dec. 31, 2016USD ($)
Acquisitions
Acquisition transaction expenses		$ 0	$ 345,000	$ 68,000	$ 345,000
Other information
Long-term Line of Credit, Noncurrent		0		0		$ 0	$ 0
October 2016 Acquisition
Acquisitions
Acres acquired | a	6,400
Acquisition transaction expenses	$ 2,600,000	300,000	$ 0	0	$ 300,000
Consideration given
Cash	405,335,000
Total consideration given	405,335,000
Allocation of Purchase Price
Proved oil and gas properties	252,522,000
Unproved oil and gas properties	109,800,000
Total fair value of oil and gas properties acquired	362,322,000
Goodwill	54,220,000
Working capital	(7,185,000)
Asset retirement obligations	(4,022,000)
Fair value of net assets acquired	405,335,000
Working capital acquired was estimated as follows:
Accounts receivable	955,000
Revenue payable	(3,012,000)
Production taxes payable	(4,244,000)
Accrued liabilities	(884,000)
Total working capital	7,185,000
Other information
Goodwill recognized, deductible for tax purposes	$ 0
Credit Facility
Other information
Long-term Line of Credit, Noncurrent		$ 0		$ 0			$ 0

Acquisitions - August 2016 Acqu

Acquisitions - August 2016 Acquisition (Details)	Aug. 23, 2016USD ($)a	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)
Acquisitions
Acquisition transaction expenses		$ 0	$ 345,000	$ 68,000	$ 345,000
August 2016 Acquisition
Acquisitions
Acres acquired | a	1,400
Acquisition transaction expenses	$ 100,000		$ 0	$ 0	$ 0
Consideration given
Cash	17,504,000
Total consideration given	17,504,000
Allocation of Purchase Price
Proved oil and gas properties	12,362,000
Unproved oil and gas properties	8,566,000
Total fair value of oil and gas properties acquired	20,928,000
Asset retirement obligations	(3,415,000)
Fair value of net assets acquired	17,504,000
Working capital acquired was estimated as follows:
Production taxes payable	(9,000)
Working capital	$ (9,000)

Acquisitions - Pro Forma Inform

Acquisitions - Pro Forma Information (Details) - USD ($)	1 Months Ended	3 Months Ended		9 Months Ended
	Oct. 31, 2016	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Pro Forma Financial Information
Depletion, depreciation, amortization and accretion		$ 94,220,000	$ 46,680,000	$ 213,483,000	$ 141,317,000
Income tax expense (in dollars)		(17,106,000)	0	(7,556,000)	0
October 2016 Acquisition
Pro Forma Financial Information
Funding provided through issuance of convertible preferred securities and borrowings under revolving credit facility	$ 260,300,000
Revenues		180,861,000	92,476,000	392,430,000	230,665,000
Operating expenses		175,699,000	106,765,000	427,912,000	304,677,000
Net loss		$ (29,796,000)	(30,268,000)	$ (13,663,000)	(197,254,000)
Earnings per common share, basic and diluted (usd per share)		$ (0.20)		$ (0.15)
October 2016 Acquisition | Adjustment To Depletion Depreciation Amortization And Accretion Expense [Member]
Pro Forma Financial Information
Depletion, depreciation, amortization and accretion		$ 0	9,000,000	$ 1,600,000	23,100,000
October 2016 Acquisition | Adjustment for effect of income taxes
Pro Forma Financial Information
Income tax expense (in dollars)		$ 0	$ 0	$ 600,000	$ 0

Long Term Debt - Components (De

Long Term Debt - Components (Details) - USD ($)	Nov. 03, 2017	Sep. 30, 2017	Dec. 31, 2016
Long-Term Debt
Line of credit, amount outstanding	$ 0	$ 0	$ 0
Unamortized debt issuance costs on Senior Notes		(17,430,000)	(11,859,000)
Total long-term debt		932,570,000	538,141,000
Less: current portion of long-term debt		0	0
Total long-term debt, net of current portion		932,570,000	538,141,000
Credit Facility
Long-Term Debt
Line of credit, amount outstanding		0	0
Senior Notes due 2021
Long-Term Debt
Debt outstanding		550,000,000	550,000,000
Second Lien Notes and Senior Notes
Long-Term Debt
Debt outstanding		$ 400,000,000	$ 0

Long Term Debt - Credit Facilit

Long Term Debt - Credit Facility (Details)	9 Months Ended
	Sep. 30, 2017USD ($)factorDerivativeNumberOfCounterpartiesperiod	Nov. 03, 2017USD ($)	Oct. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Long-Term Debt
Total commitments	$ 1,500,000,000
Borrowing base	375,000,000
Line of credit, amount outstanding	0	$ 0		$ 0
Available credit under the facility	$ 375,000,000
Number of variable rates available | DerivativeNumberOfCounterparties	2
Variable interest rate terms and debt covenant ratios
Number of quarters used for calculation of Net Debt to EBITDAX | period	4
Period used for calculation of Net debt to EBITDAX ratio	6 months
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%
LIBOR | Borrowing Base, Utilization Level 1
Variable interest rate terms and debt covenant ratios
Margin rate, percent	2.00%
LIBOR | Borrowing Base, Utilization Level 2
Variable interest rate terms and debt covenant ratios
Margin rate, percent	2.25%
LIBOR | Borrowing Base, Utilization Level 3
Variable interest rate terms and debt covenant ratios
Margin rate, percent	2.50%
LIBOR | Borrowing Base, Utilization Level 4
Variable interest rate terms and debt covenant ratios
Margin rate, percent	2.75%
LIBOR | Borrowing Base, Utilization Level 5
Variable interest rate terms and debt covenant ratios
Margin rate, percent	3.00%
Base Rate | Borrowing Base, Utilization Level 1
Variable interest rate terms and debt covenant ratios
Commitment fee, percent	0.375%
Margin rate, percent	1.00%
Base Rate | Borrowing Base, Utilization Level 2
Variable interest rate terms and debt covenant ratios
Commitment fee, percent	0.375%
Margin rate, percent	1.25%
Base Rate | Borrowing Base, Utilization Level 3
Variable interest rate terms and debt covenant ratios
Commitment fee, percent	0.50%
Margin rate, percent	1.50%
Base Rate | Borrowing Base, Utilization Level 4
Variable interest rate terms and debt covenant ratios
Commitment fee, percent	0.50%
Margin rate, percent	1.75%
Base Rate | Borrowing Base, Utilization Level 5
Variable interest rate terms and debt covenant ratios
Commitment fee, percent	0.50%
Margin rate, percent	2.00%
Quarters ending December 31, 2016 through December 31, 2017
Variable interest rate terms and debt covenant ratios
Annualized EBITDAX multiplier | factor	2
Quarter ending March 31, 2018
Variable interest rate terms and debt covenant ratios
Period used for calculation of Net debt to EBITDAX ratio	9 months
Annualized EBITDAX multiplier | factor	1.333
Quarters ending on or after June 30, 2018
Variable interest rate terms and debt covenant ratios
Period used for calculation of Net debt to EBITDAX ratio	12 months
Standby Letters of Credit
Long-Term Debt
Letters of credit outstanding	$ 25,700,000			600,000
Credit Facility
Long-Term Debt
Line of credit, amount outstanding	$ 0			$ 0
Subsequent Event
Long-Term Debt
Borrowing base			$ 525,000,000

Long Term Debt - Senior Notes (

Long Term Debt - Senior Notes (Details) - USD ($)	1 Months Ended		9 Months Ended
	Oct. 31, 2017	Jul. 31, 2016	Sep. 30, 2017	Aug. 31, 2017
Long-Term Debt
Immediate Due and Payable clause, percentage of holdings			25.00%
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
Senior Notes due 2024
Long-Term Debt
Face amount of debt				$ 400,000,000
Senior Notes due 2024 | Scenario, Forecast
Long-Term Debt
Interest rate percentage	7.375%
Proceeds from debt, net of discounts and issuance costs	$ 392,600,000
Immediate Due and Payable clause, percentage of holdings	25.00%

Long Term Debt - Debt Discount,

Long Term Debt - Debt Discount, Issuance Costs, Interest (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Long-Term Debt
Amortization of debt issuance costs	$ 0	$ 4,300,000	$ 0	$ 4,800,000
Interest Incurred On Long Term Debt
Interest expense	16,500,000	12,200,000	39,200,000	38,900,000
Interest costs capitalized	2,900,000	1,200,000	8,600,000	3,600,000
Payments of Debt Extinguishment Costs			0	4,300,000
Credit Facility | Other non-current assets
Long-Term Debt
Accumulated amortization, debt issuance costs	3,100,000		3,100,000
Debt issuance costs	17,400,000		17,400,000
Second Lien Notes
Long-Term Debt
Amortization of debt discount	1,500,000	$ 11,600,000	3,200,000	$ 13,500,000
Interest Incurred On Long Term Debt
Payments of Debt Extinguishment Costs	$ 4,300,000		$ 4,300,000

Commodity Derivative Instrume37

Commodity Derivative Instruments - Summary of Contracts (Details)	9 Months Ended
	Sep. 30, 2017USD ($)$ / MMBTUMMBTUcontract$ / bblbbl
Commodity derivative contracts
Number of counterparties | contract	6
Derivative instruments in a net liability position with credit-risk-related contingent features | $	$ 0
Crude | Swaps, 2017
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	1,850,000
Weighted average fixed price, Swaps (in $/Bbl or$/MMBtu) | $ / bbl	50.64
Crude | Swaps, 2018
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	5,100,000
Weighted average fixed price, Swaps (in $/Bbl or$/MMBtu) | $ / bbl	51.61
Crude | Swap, 2019
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	0
Crude | Calls, 2017 | Sold
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	1,200,000
Weighted average fixed price, Calls (in $/BBl or $/MMBtu) | $ / bbl	53.04
Crude | Calls, 2018 | Sold
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	6,190,000
Weighted average fixed price, Calls (in $/BBl or $/MMBtu) | $ / bbl	55.75
Crude | Calls, 2019 | Sold
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	3,000,000
Weighted average fixed price, Calls (in $/BBl or $/MMBtu) | $ / bbl	55.10
Crude | Puts, 2017 | Sold
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	3,225,000
Weighted average fixed price, Puts (in $/BBl or $/MMBtu) | $ / bbl	37.19
Crude | Puts, 2017 | Purchased
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	1,800,000
Weighted average put price (in $/Bbl or $/MMBtu) | $ / bbl	42.13
Crude | Puts, 2018 | Sold
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	11,338,800
Weighted average fixed price, Puts (in $/BBl or $/MMBtu) | $ / bbl	38.93
Crude | Puts, 2018 | Purchased
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	6,838,800
Weighted average put price (in $/Bbl or $/MMBtu) | $ / bbl	47.35
Crude | Put Option 2019 [Member] | Sold
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	3,000,000
Weighted average fixed price, Puts (in $/BBl or $/MMBtu) | $ / bbl	39.70
Crude | Put Option 2019 [Member] | Purchased
Summary of commodity derivative contracts
Notional volume (in barrels) | bbl	3,000,000
Weighted average put price (in $/Bbl or $/MMBtu) | $ / bbl	49.37
Natural Gas | Swaps, 2017
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	7,420,000
Weighted average fixed price, Swaps (in $/Bbl or$/MMBtu) | $ / MMBTU	3.06
Natural Gas | Swaps, 2018
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	37,200,000
Weighted average fixed price, Swaps (in $/Bbl or$/MMBtu) | $ / MMBTU	3.10
Natural Gas | Swap, 2019
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	0
Natural Gas | Calls, 2017 | Sold
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	0
Natural Gas | Calls, 2018 | Sold
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	2,400,000
Weighted average fixed price, Calls (in $/BBl or $/MMBtu) | $ / MMBTU	3.15
Natural Gas | Calls, 2019 | Sold
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	0
Natural Gas | Puts, 2017 | Purchased
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	0
Natural Gas | Puts, 2018 | Purchased
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	2,400,000
Weighted average fixed price, Swaps (in $/Bbl or$/MMBtu) | $ / MMBTU	3
Natural Gas | Put Option 2019 [Member] | Purchased
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	0
Natural Gas | Basis Swaps, 2017
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	5,215,000
Weighted average fixed basis price ($/MMBtu) | $ / MMBTU	(0.31)
Natural Gas | Basis Swaps, 2018
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	6,300,000
Weighted average fixed basis price ($/MMBtu) | $ / MMBTU	(0.31)
Natural Gas | Basis Swap, 2019
Summary of commodity derivative contracts
Notional volume (in MMBtu) | MMBTU	0

Commodity Derivative Instrume38

Commodity Derivative Instruments - Gross and Net Fair Value (Details) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Current assets
Gross amounts and adjustments made for net derivative assets
Gross Amounts of Recognized Assets	$ 25,250,000	$ 12,620,000
Gross Amounts Offset in the Balance Sheet	(24,264,000)	(12,620,000)
Net Amounts of Assets Presented in the Balance Sheet	986,000	0
Gross Amounts not Offset in the Balance Sheet	(146,000)	0
Net Amounts	840,000	0
Non-current assets
Gross amounts and adjustments made for net derivative assets
Gross Amounts of Recognized Assets	25,141,000	14,993,000
Gross Amounts Offset in the Balance Sheet	(25,141,000)	(14,993,000)
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	(32,523,000)	(68,623,000)
Gross Amounts Offset in the Balance Sheet	24,264,000	12,620,000
Net Amounts of Liabilities Presented in the Balance Sheet	(8,259,000)	(56,003,000)
Gross Amounts not Offset in the Balance Sheet	146,000	0
Net Amounts	(11,138,000)	(62,741,000)
Non-current liabilities
Gross amounts and adjustments made for net derivative liabilities
Gross Amounts of Recognized Liabilities	(28,166,000)	(21,731,000)
Gross Amounts Offset in the Balance Sheet	25,141,000	14,993,000
Net Amounts of Liabilities Presented in the Balance Sheet	(3,025,000)	(6,738,000)
Gross Amounts not Offset in the Balance Sheet	0	0
Net Amounts	$ 0	$ 0

Commodity Derivative Instrume39

Commodity Derivative Instruments - Gain (Loss) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income (loss) on derivatives
Commodity derivatives gain (loss)	$ (37,875)	$ 16,225	$ 46,423	$ (62,424)
Other income (expense)
Income (loss) on derivatives
Gain (Loss) on Price Risk Derivatives, Net	$ (37,875)	$ 16,225	$ 46,423	$ (62,424)

Asset Retirement Obligations -

Asset Retirement Obligations - Summary (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Asset retirement obligations
Balance beginning of period	$ 56,108	$ 44,367
Liabilities incurred or acquired	6,644	8,945
Liabilities settled	(1,408)	(1,155)
Revisions in estimated cash flows	0	(1,695)
Accretion expense	3,847	5,646
Balance end of period	$ 65,191	$ 56,108

Fair Value Measurements - Recur

Fair Value Measurements - Recurring Basis (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Fair Value Measurements
Asset transfers out of Level 2 into Level 1	$ 0	$ 0
Asset transfers into (out of) Level 3	0	0
Liability transfers out of Level 1 into Level 2	0	0
Liability transfers out of Level 2 into Level 1	0	0
Liability transfers into (out of) Level 3	0	0
Recurring
Financial Assets:
Commodity derivative assets	986	0
Financial Liabilities:
Commodity derivative liabilities	11,284	62,741
Recurring | Level 1
Financial Assets:
Commodity derivative assets	0	0
Financial Liabilities:
Commodity derivative liabilities	0	0
Recurring | Level 2
Financial Assets:
Commodity derivative assets	986	0
Financial Liabilities:
Commodity derivative liabilities	11,284	62,741
Recurring | Level 3
Financial Assets:
Commodity derivative assets	0	0
Financial Liabilities:
Commodity derivative liabilities	$ 0	$ 0

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Fair Value of Financial Instruments
Unamortized debt discount and debt issuance costs	$ 17,430	$ 11,859
Carrying Amount
Fair Value of Financial Instruments
Unamortized debt discount and debt issuance costs	10,200	11,900
Carrying Amount | Senior Notes due 2021
Fair Value of Financial Instruments
Long-term debt	539,804	538,141
Carrying Amount | Senior Notes due 2024
Fair Value of Financial Instruments
Long-term debt	392,766	0
Unamortized debt discount and debt issuance costs	7,200
Fair value | Level 2 | Senior Notes due 2021
Fair Value of Financial Instruments
Long-term debt	580,250	588,500
Fair value | Level 2 | Senior Notes due 2024
Fair Value of Financial Instruments
Long-term debt	$ 419,000	$ 0

Fair Value Measurements - Nonre

Fair Value Measurements - Nonrecurring (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Fair Value Disclosures [Abstract]
Impairment of proved properties	$ 0	$ 0	$ 0	$ 22,400,000

Income Taxes - Effective Tax Ra

Income Taxes - Effective Tax Rate (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Taxes
Effective combined U.S. federal and state income tax rate			35.30%
Income tax expense (in dollars)	$ (17,106)	$ 0	$ (7,556)	$ 0
Statutory U.S. federal income tax rate			35.00%

Unit and Stock-Based Compensa45

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 Compensa46

Unit and Stock-Based Compensation - Long Term Incentive Plan Options (Details) - 2016 Long Term Incentive Plan - Stock Options $ / shares in Units, $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2017USD ($)$ / sharesshares	Sep. 30, 2017USD ($)$ / sharesshares
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 | $	$ 3.3	$ 9.9
Unrecognized compensation costs | $	$ 26.6	$ 26.6
Weighted-average period for recognition, unvested awards		2 years
Number of Shares
Granted (in shares) | shares		0
Forfeited (in shares) | shares		0
Vested (in shares) | shares		0
Non-vested Stock Options at end of period (in shares) | shares	4,500,000	4,500,000
Weighted Average Exercise Price (in dollars per share)
Granted (in dollars per share) | $ / shares		$ 0
Forfeited (in dollars per share) | $ / shares		0
Vested (in dollars per share) | $ / shares		0
Non-vested Stock Options at end of period (in dollars per share) | $ / shares	$ 19	$ 19

Unit and Stock-Based Compensa47

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, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
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	$ 3.3		$ 9.9
Weighted-average period for recognition, unvested awards			2 years
RSUs
Restricted Stock Units ("RSUs")
Forfeiture rate (as a percent)			0.00%
Compensation costs
Share-based compensation expense	8.9	$ 0	$ 24.6	$ 0
Unrecognized compensation cost	$ 52.7		$ 52.7
Weighted-average period for recognition, unvested awards			1 year 10 months 24 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 Compensa48

Unit and Stock-Based Compensation - Long Term Incentive Plan RSUs Rollforward (Details) - 2016 Long Term Incentive Plan - RSUs	9 Months Ended
	Sep. 30, 2017$ / sharesshares
Number of Shares
Non-vested units at beginning of period (in shares) | shares	3,237,500
Granted (in shares) | shares	1,305,033
Forfeited (in shares) | shares	(403,725)
Vested (in shares) | shares	(85,994)
Non-vested units at end of period (in shares) | shares	4,052,814
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per share) | $ / shares	$ 21.41
Granted (in dollars per share) | $ / shares	16.43
Forfeited (in dollars per share) | $ / shares	19.72
Vested (in dollars per share) | $ / shares	16.82
Non-vested units at end of period (in dollars per share) | $ / shares	$ 20.07

Unit and Stock-Based Compensa49

Unit and Stock-Based Compensation - Incentive Restricted Stock Units (Details) - USD ($) $ in Thousands, shares in Millions	Jul. 17, 2017	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Compensation costs
Unit-based compensation				$ 46,707	$ 14,922
RUAs
Compensation costs
Unrecognized compensation cost		$ 0		$ 0
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		5,900	$ 0	$ 12,200	$ 0
Unrecognized compensation cost		26,500		$ 26,500
Weighted-average period for recognition, unvested awards				1 year 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		$ 52,700		$ 52,700
Weighted-average period for recognition, unvested awards				1 year 10 months 24 days

Unit and Stock-Based Compensa50

Unit and Stock-Based Compensation - Incentive Restricted Stock Units Rollforward (Details) - Incentive RSUs	9 Months Ended
	Sep. 30, 2017$ / sharesshares
Number of Shares
Non-vested units at beginning of period (in shares) | shares	2,714,368
Granted (in shares) | shares	0
Forfeited (in shares) | shares	(703,868)
Vested (in shares) | shares	(507,200)
Non-vested units at end of period (in shares) | shares	1,503,300
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 Compensa51

Unit and Stock-Based Compensation - RUAs (Details) - RUAs - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2017
Compensation costs
Unit-based compensation costs	$ 12.3	$ 14.9
Unrecognized compensation cost			$ 0

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, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Basic and Diluted EPS (in thousands, except per share data)
Net loss	$ (29,796)	$ (37,267)	$ (13,840)	$ (210,400)
Less: Adjustment to reflect Series A Preferred Stock dividend	(2,721)		(8,164)
Less: Adjustment to reflect Series A Preferred Stock dividend	(1,365)		(3,992)
Adjusted net loss available to common shareholders, basic and diluted	$ (33,882)		$ (25,996)
Denominator
Weighted average common shares outstanding, basic and diluted	171,845,000		171,838,000
Earnings Per Common Share
Basic and diluted (in dollars per share)	$ (0.20)		$ (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, 2017	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)	4,500,000	4,500,000
RSUs
Antidilutive Securities Excluded from Computation of Earnings Per Share
Securities excluded from diluted EPS calculation (in shares)	4,071,683	4,052,814
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

Commitments and Contingencies -

Commitments and Contingencies - Leases (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017USD ($)lease	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)lease	Sep. 30, 2016USD ($)	Jun. 04, 2015lease
Office Space Leases
Future minimum lease payments
Total rental commitments under non cancelable leases	$ 19.6		$ 19.6
2,017	0.6		0.6
2,018	2.6		2.6
2,019	2.5		2.5
2,020	2.2		2.2
2,021	2.2		2.2
Thereafter	9.5		9.5
Rent expense	$ 0.5	$ 0.6	$ 1.7	$ 1.3
Office Space Leases | Denver, Colorado
Leases
Number of office spaces under lease | lease	2		2
Office Space Leases | Greeley, Colorado
Leases
Number of office spaces under lease | lease	1		1
Office Space Leases | Houston, Texas
Leases
Number of office spaces under lease | lease	1		1
Subleases | Denver, Colorado
Leases
Number of office spaces under lease | lease					1
Future minimum lease payments
Sublease rental, future lease payments	$ 0.6		$ 0.6

Commitments and Contingencies55

Commitments and Contingencies - Drilling Rigs (Details) - Drilling Rig Commitments $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)property
Drilling Rigs
Number of drilling rigs | property	4
Early termination obligation | $	$ 12.1

Commitments and Contingencies56

Commitments and Contingencies - Commitments (Details) $ in Billions	Jul. 07, 2017MMcf	Dec. 15, 2016MMcf	Sep. 30, 2017USD ($)bbl / dcontract	Aug. 07, 2017processing_plant
Delivery and Gathering commitments
Aggregate estimated payments due | $			$ 1
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			1
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
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 Contingencies57

Commitments and Contingencies - Acquisition of Undeveloped Leasehold (Details) - Acquisition of Undeveloped Leasehold Acreage Commitments $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)a
Acquisition of Undeveloped Leasehold Acreage Commitments
Payments for other commitments	$ 77.5
Commitments	$ 116.5
Net acres of undeveloped leasehold | a	30,000

Commitments and Contingencies58

Commitments and Contingencies - Legal Matters (Details)	9 Months Ended
	Sep. 30, 2017facility
CDPHE Compliance Advisory
Legal Matters
Number of facilities with alleged air quality violations	3

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 - 60

Related Party Transactions - Due to Related Parties (Details)	Oct. 17, 2016USD ($)	Sep. 30, 2017USD ($)bbl / d	Aug. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Jul. 31, 2016USD ($)
Due to Related Party
Aggregate estimated payments due		$ 1,000,000,000
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
Unconsolidated affiliate | Long Term Crude Oil Gathering Commitment
Due to Related Party
Aggregate estimated payments due		$ 71,900,000
Unconsolidated affiliate | 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
Series A Convertible Preferred Stock
Due to Related Party
Issuance of stock	$ 185,300,000
Series A Convertible Preferred Stock | Related Party Debt Transaction | 5% Holdings' Members
Due to Related Party
Debt outstanding		$ 105,000,000
Senior Notes due 2021
Due to Related Party
Face amount of debt		550,000,000			$ 550,000,000
Debt outstanding		550,000,000		$ 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