Ranger Oil (ROCC) 10-Q 9 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 Documentand Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3
Trading Symbol	PVAC
Entity Registrant Name	PENN VIRGINIA CORP
Entity Central Index Key	77,159
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		15,004,270

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 12, 2016	Sep. 30, 2017	Sep. 12, 2016		Sep. 30, 2017
Other income (expense)
Income tax benefit (expense)			$ 0			$ 0
Net income (loss)						43,463
Successor [Member]
Revenues
Crude oil	$ 5,508		29,963			92,387
Natural gas liquids	333		2,393			6,738
Natural gas	475		1,977			6,200
Gain on sales of assets, net	0		9			(60)
Other, net	33		117			462
Total revenues	6,349		34,459			105,727
Operating expenses
Lease operating	756		5,254			15,540
Gathering, processing and transportation	576		2,399			7,505
Production and ad valorem taxes	375		1,668			5,766
General and administrative	1,476		6,952			14,800
Exploration	0		0			0
Depreciation, depletion and amortization	2,029		10,659			31,545
Total operating expenses	5,212		26,932			75,156
Operating income (loss)	1,137		7,527			30,571
Other income (expense)
Interest expense	(218)		(1,202)			(3,014)
Derivatives	(4,369)		(12,275)			15,802
Other, net	9		3			104
Reorganization items, net	0		0			0
Income (loss) before income taxes	(3,441)		(5,947)			43,463
Income tax benefit (expense)	0
Net income (loss)	(3,441)		(5,947)			43,463
Preferred stock dividends	0		0			0
Net income (loss) attributable to common shareholders	$ (3,441)		$ (5,947)			$ 43,463
Net income (loss) per share:
Basic (in dollars per share)	$ (0.23)		$ (0.40)			$ 2.90
Diluted (in dollars per share)	$ (0.23)		$ (0.40)			$ 2.89
Weighted average shares outstanding – basic (in shares)	14,992		14,994			14,993
Weighted average shares outstanding – diluted (in shares)	14,992		14,994			15,062
Predecessor [Member]
Revenues
Crude oil		$ 23,392		$ 81,377
Natural gas liquids		1,680		6,064
Natural gas		1,889		6,208
Gain on sales of assets, net		504		1,261
Other, net		(804)		(600)
Total revenues		26,661		94,310
Operating expenses
Lease operating		4,209		15,626
Gathering, processing and transportation		4,767		13,235
Production and ad valorem taxes		574		3,490
General and administrative		6,895		38,945
Exploration		4,641		10,288
Depreciation, depletion and amortization		8,024		33,582
Total operating expenses		29,110		115,166
Operating income (loss)		(2,449)		(20,856)
Other income (expense)
Interest expense		(1,363)		(58,018)
Derivatives		8,934		(8,333)
Other, net		(2,154)		(3,184)
Reorganization items, net		1,152,373		1,144,993
Income (loss) before income taxes		1,155,341		1,054,602
Income tax benefit (expense)		0		0
Net income (loss)		1,155,341		1,054,602
Preferred stock dividends		0		(5,972)	[1]
Net income (loss) attributable to common shareholders		$ 1,155,341		$ 1,048,630
Net income (loss) per share:
Basic (in dollars per share)		$ 12.94		$ 11.91
Diluted (in dollars per share)		$ 10.37		$ 8.50
Weighted average shares outstanding – basic (in shares)		89,292		88,013
Weighted average shares outstanding – diluted (in shares)		111,458		124,087
[1]	1 Dividends attributable to our Series A 6% Convertible Perpetual Preferred Stock and Series B 6% Convertible Perpetual Preferred Stock (together, the “Series A and B Preferred Stock”) were excluded from the computation of diluted loss per share for the period from January 1, 2016 through September 12, 2016, as their assumed conversion would have been anti-dilutive.

CONDENSED CONSOLIDATED STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 12, 2016	Sep. 30, 2017	Sep. 12, 2016	Sep. 30, 2017
Net income (loss)					$ 43,463
Successor [Member]
Net income (loss)	$ (3,441)		$ (5,947)		43,463
Other comprehensive loss:
Change in pension and postretirement obligations, net of tax of $0 and $0 in 2016	0		0		0
Total Other Comprehensive Income (Loss), Net of Tax	0		0		0
Comprehensive income (loss)	$ (3,441)		$ (5,947)		$ 43,463
Predecessor [Member]
Net income (loss)		$ 1,155,341		$ 1,054,602
Other comprehensive loss:
Change in pension and postretirement obligations, net of tax of $0 and $0 in 2016		(383)		(421)
Total Other Comprehensive Income (Loss), Net of Tax		(383)		(421)
Comprehensive income (loss)		$ 1,154,958		$ 1,054,181

CONDENSED CONSOLIDATED STATEME4

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 12, 2016	Sep. 30, 2017	Sep. 12, 2016	Sep. 30, 2017
Successor [Member]
Change in pension and postretirement obligations, net of tax	$ 0		$ 0		$ 0
Predecessor [Member]
Change in pension and postretirement obligations, net of tax		$ 0		$ 0

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	$ 7,487	$ 6,761
Accounts receivable, net of allowance for doubtful accounts	48,096	29,095
Derivative assets	6,140	0
Other current assets	3,115	3,028
Total current assets	64,838	38,884
Property and equipment, net (full cost method)	486,060	247,473
Derivative assets	2,520	0
Other assets	8,823	5,329
Total assets	562,241	291,686
Current liabilities
Accounts payable and accrued liabilities	62,236	49,697
Derivative liabilities	13,634	12,932
Total current liabilities	75,870	62,629
Other liabilities	4,631	4,072
Derivative liabilities	4,923	14,437
Long-term debt, net	245,055	25,000
Commitments and contingencies (Note 13)
Shareholders’ equity:
Preferred stock of $0.01 par value – 5,000,000 shares authorized; none issued	0	0
Common stock of $0.01 par value – 45,000,000 shares authorized; 15,004,270 and 14,992,018 shares issued as of September 30, 2017 and December 31, 2016, respectively	150	150
Paid-in capital	193,372	190,621
Retained earnings (accumulated deficit)	38,167	(5,296)
Accumulated other comprehensive income	73	73
Total shareholders’ equity	231,762	185,548
Total liabilities and shareholders’ equity	$ 562,241	$ 291,686

CONDENSED CONSOLIDATED BALANCE6

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Sep. 30, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Preferred stock, par value	$ 0.01	$ 100
Preferred stock, shares authorized	5,000,000	5,000,000
Schedule of Stockholders' Equity [Line Items]
Preferred stock, redemption value per share (in dollars per share)	$ 0	$ 0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	45,000,000	45,000,000
Common stock, shares issued	15,004,270	14,992,018
Series A Preferred Stock
Schedule of Stockholders' Equity [Line Items]
Preferred stock, issued	0	0
Series B Preferred Stock
Schedule of Stockholders' Equity [Line Items]
Preferred stock, issued	0	0

CONDENSED CONSOLIDATED STATEME7

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 12, 2016	Sep. 30, 2017	Sep. 12, 2016	Sep. 30, 2017	Sep. 30, 2016
Cash flows from operating activities
Net income (loss)					$ 43,463
Derivative contracts:
Share-based compensation (equity-classified)					2,700
Cash flows from financing activities
Proceeds received from rights offering, net					100
Cash and cash equivalents – beginning of period					6,761
Cash and cash equivalents – end of period			$ 7,487		7,487
Successor [Member]
Cash flows from operating activities
Net income (loss)	$ (3,441)		(5,947)		43,463
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Non-cash reorganization items	0				0
Depreciation, depletion and amortization	2,029		10,659		31,545
Accretion of firm transportation obligation	0				0
Derivative contracts:
Net (gains) losses	4,369				(15,802)
Cash settlements, net	0				(1,670)
Loss (gain) on sales of assets, net	0				60
Non-cash exploration expense	0				0
Non-cash interest expense	38				1,362
Share-based compensation (equity-classified)	0				2,707
Other, net	0				59
Changes in operating assets and liabilities, net	585				(11,430)
Net cash provided by operating activities	3,580				50,294
Cash flows from investing activities
Acquisition, net	0				(200,162)
Capital expenditures	0				(67,844)
Proceeds from sales of assets, net	0				0
Other, net	0				0
Net cash used in investing activities	0				(268,006)
Cash flows from financing activities
Proceeds from credit facility borrowings	0				39,000
Repayment of credit facility borrowings	(21,000)				(7,000)
Proceeds from second lien facility, net	0				196,000
Debt issuance costs paid	0				(9,562)
Proceeds received from rights offering, net	0				55
Other, net	0				(55)
Net cash provided by (used in) financing activities	(21,000)				218,438
Net increase (decrease) in cash and cash equivalents	(17,420)				726
Cash and cash equivalents – beginning of period					6,761
Cash and cash equivalents – end of period	13,994		$ 7,487		7,487	$ 13,994
Cash paid for:
Interest, net of amounts capitalized	0				1,596
Income taxes, net of (refunds)	0				0
Reorganization items, net	0				1,098
Non-cash investing and financing activities:
Common stock issued in exchange for liabilities	0				0
Changes in accrued liabilities related to capital expenditures	0				8,140
Derivatives settled to reduce outstanding debt	0				$ 0
Predecessor [Member]
Cash flows from operating activities
Net income (loss)		$ 1,155,341		$ 1,054,602
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Non-cash reorganization items				(1,178,302)
Depreciation, depletion and amortization		8,024		33,582
Accretion of firm transportation obligation				317		300
Derivative contracts:
Net (gains) losses				8,333
Cash settlements, net				48,008
Loss (gain) on sales of assets, net				(1,261)
Non-cash exploration expense				6,038
Non-cash interest expense				22,188
Share-based compensation (equity-classified)				1,511
Other, net				(13)
Changes in operating assets and liabilities, net				35,244
Net cash provided by operating activities				30,247
Cash flows from investing activities
Acquisition, net				0
Capital expenditures				(15,359)
Proceeds from sales of assets, net				224
Other, net				1,186
Net cash used in investing activities				(13,949)
Cash flows from financing activities
Proceeds from credit facility borrowings				75,350
Repayment of credit facility borrowings				(119,121)
Proceeds from second lien facility, net				0
Debt issuance costs paid				(3,011)
Proceeds received from rights offering, net				49,943
Other, net				0
Net cash provided by (used in) financing activities				3,161
Net increase (decrease) in cash and cash equivalents				19,459
Cash and cash equivalents – beginning of period	$ 31,414			11,955		11,955
Cash and cash equivalents – end of period		$ 31,414		31,414
Cash paid for:
Interest, net of amounts capitalized				4,331
Income taxes, net of (refunds)				(35)
Reorganization items, net				30,990
Non-cash investing and financing activities:
Common stock issued in exchange for liabilities				140,952
Changes in accrued liabilities related to capital expenditures				(11,301)
Derivatives settled to reduce outstanding debt				$ 51,979		$ 52,000

Nature of Operations

Nature of Operations	9 Months Ended
	Sep. 30, 2017
Accounting Policies [Abstract]
Nature of Operations	Nature of Operations Penn Virginia Corporation (together with its consolidated subsidiaries, unless the context otherwise requires, “Penn Virginia,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company engaged in the onshore exploration, development and production of oil, natural gas liquids (“NGLs”) and natural gas. Our current operations consist primarily of drilling unconventional horizontal development wells and operating our producing wells in the Eagle Ford Shale (the “Eagle Ford”) in South Texas. Our operations are substantially concentrated with over 90 percent of our production, revenues and capital expenditures attributable to this region. We also have less significant operations in Oklahoma, primarily consisting of non-operated properties in the Granite Wash. In late August 2017, southeast Texas was adversely impacted by Category 4 Hurricane Harvey. While we experienced no long-term damage to our producing assets or facilities in that region, our production, drilling and completion operations were all curtailed for several days at the end of August 2017. Sales of production were initially curtailed to approximately 50 percent of full potential due to compression availability and localized flooding and were brought back online to full potential in early September 2017.

Basis of Presentation

Basis of Presentation	9 Months Ended
	Sep. 30, 2017
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Our unaudited Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of our subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our Condensed Consolidated Financial Statements have been included. Our Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Annual Report on Form 10-K for the year ended December 31, 2016 . Operating results for the nine months ended September 30, 2017 , are not necessarily indicative of the results that may be expected for the year ending December 31, 2017 . Comparability of Financial Statements to Prior Periods We adopted and began applying the relevant guidance provided in GAAP with respect to the accounting and financial statement disclosures for entities that have emerged from bankruptcy proceedings (“Fresh Start Accounting”) on September 12, 2016. Accordingly, our Condensed Consolidated Financial Statements and Notes after September 12, 2016, are not comparable to the Condensed Consolidated Financial Statements and Notes through that date. To facilitate our financial statement presentations, we refer to the reorganized company in these Condensed Consolidated Financial Statements and Notes as the “Successor,” which is effectively a new reporting entity for financial reporting purposes, for periods subsequent to September 12, 2016, and the “Predecessor” for periods prior to September 13, 2016. In connection with our reorganization, we experienced a change in control as the outstanding common and preferred shares of the Predecessor were canceled and substantially all of the Successor’s new common stock was issued to the Predecessor’s creditors. Furthermore, our Condensed Consolidated Financial Statements and Notes have been presented with a “black line” division to delineate, where applicable, the lack of comparability between the Predecessor and Successor. In addition, we adopted the full cost method of accounting for our oil and gas properties effective with our adoption of Fresh Start Accounting. Accordingly, our results of operations, financial position and cash flows for the Successor periods will be substantially different from our historic trends. We have recasted amounts for equity-classified share-based compensation recognized as a component of “General and administrative” expenses from the amounts originally reported for the Predecessor period from July 1, 2016 through September 12, 2016 to correct for an immaterial error identified by management and disclosed in our Quarterly Report on Form 10-Q for the period ended September 30, 2016. Previously reported expense associated with this matter was decreased by $5.3 million for the period from July 1, 2016 through September 12, 2016. Our Predecessor net income for the period from July 1, 2016 through September 12, 2016 increased by an identical amount and our net income per basic and diluted share increased by $0.06 and $0.05 . The Predecessor net income and earnings per share measures were unchanged for the period from January 1, 2016 through September 12, 2016. Going Concern Presumption Our unaudited Condensed Consolidated Financial Statements for the Successor periods have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. Subsequent Events Management has evaluated all of our activities through the issuance date of our Condensed Consolidated Financial Statements and has concluded that, other than certain events described in Notes 3 and 6, no subsequent events have occurred that would require recognition in our Condensed Consolidated Financial Statements or disclosure in the Notes thereto. Recently Issued Accounting Pronouncements In March 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017–07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017–07”) which provides guidance to improve the reporting of net benefit cost in financial statements. The guidance requires employers to disaggregate the service cost component from the other components of net benefit cost. The service cost component of net periodic benefit cost shall be reported in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period, except for amounts capitalized. All other components of net benefit cost shall be presented outside of a subtotal for income from operations. The line item used to present the components other than the service cost shall be disclosed if the other components are not presented in a separate line item or items. ASU 2017–07 is effective January 1, 2018 and is required to be applied retrospectively. ASU 2017–07 will be applicable to our legacy retiree benefit plans which cover a limited population of former employees. There is no service cost associated with these plans as they are not applicable to current employees, but rather interest and other costs associated with the legacy obligations. Upon the adoption of ASU 2017–07, the entirety of the expense associated with these plans will be presented as a component of the “Other income (expense)” caption in our Condensed Consolidated Statement of Operations. These costs are currently recognized as a component of “General and administrative” expenses. The total cost associated with these plans is generally less than $ 0.1 million on an annual basis and is therefore not material. We will adopt ASU 2017–07 in January 2018. In June 2016, the FASB issued ASU 2016–13, Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”), which changes the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities, among others. ASU 2016–13 is required to be adopted using the modified retrospective method by January 1, 2020, with early adoption permitted for fiscal periods beginning after December 15, 2018. In contrast to current guidance, which considers current information and events and utilizes a probable threshold, (an “incurred loss” model), ASU 2016–13 mandates an “expected loss” model. The expected loss model: (i) estimates the risk of loss even when risk is remote, (ii) estimates losses over the contractual life, (iii) considers past events, current conditions and reasonable supported forecasts and (iv) has no recognition threshold. ASU 2016–13 will have applicability to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners which have a higher credit risk than those associated with our traditional customer receivables. At this time, we do not anticipate that the adoption of ASU 2016–13 will have a significant impact on our Consolidated Financial Statements and related disclosures; however, we are continuing to evaluate the requirements and the period for which we will adopt the standard as well as monitoring developments regarding ASU 2016–13 that are unique to our industry. In February 2016, the FASB issued ASU 2016–02, Leases (“ASU 2016–02”), which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases with terms of more than twelve months. Consistent with current GAAP, the recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease. ASU 2016–02 also will require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ASU 2016–02 is January 1, 2019, with early adoption permitted. We believe that ASU 2016–02 will likely be applicable to our oil and natural gas gathering commitment arrangements as described in Note 13, our existing leases for office facilities and certain office equipment, land easements and similar arrangements for rights-of-way and potentially to certain drilling rig and completion contracts with terms in excess of twelve months to the extent we may have such contracts in the future. Our oil and natural gas gathering arrangements are fairly complex and involve multiple elements that could be construed as leases. Accordingly, we are continuing to evaluate the effect that ASU 2016–02 will have on our Consolidated Financial Statements and related disclosures as well as the period for which we will adopt the standard, however, at this time, we believe that we will likely adopt ASU 2016–02 in 2019. We are also continuing to monitor developments regarding ASU 2016–02 that are unique to our industry. In May 2014, the FASB issued ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014–09 will replace most existing revenue recognition guidance in GAAP when it becomes effective on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. While traditional commodity sales transactions, property conveyances and joint interest arrangements in the oil and gas industry are not expected to be significantly impacted by ASU 2014–09, the terms of the individual commodity purchase, joint operating agreements and other contracts underlying these types of transactions will determine the appropriate recognition, measurement and disclosure once ASU 2014–09 has been adopted. Also, to the extent applicable, we are considering our participation in certain of these transactions as either a principal or agent. In addition, the recognition, measurement and disclosure of producer imbalances and other non-product revenues, including our ancillary marketing, gathering and transportation and water disposal revenues, while not significant, could be impacted to some degree. Our non-product revenues are projected to represent less than $1 million of our total revenues on an annualized basis; however, that level could rise in future periods based on the potential expansion and growth of our operations. In summary, with the exception of more expansive disclosures, we have not identified any potentially material impact attributable to ASU 2014–09. While we are continuing to evaluate the overall effect that ASU 2014–09 will have on our Consolidated Financial Statements and related disclosures, our remaining efforts are primarily focused on developing controls and procedures to facilitate the ongoing process of analysis of future contracts and their terms in order to support the appropriate accounting and disclosure. We are also continuing to monitor developments regarding ASU 2014–09 that are unique to our industry. We will adopt ASU 2014–09 in January 2018 using the cumulative effect transition method.

Acquisitions (Notes)

Acquisitions (Notes)	9 Months Ended
	Sep. 30, 2017
Acquisitions [Abstract]
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	Acquisitions Eagle Ford Acquisition On July 30, 2017, we entered into a purchase and sale agreement (the “Purchase Agreement”) with Devon Energy Corporation (“Devon”) to acquire all of Devon’s right, title and interest in and to certain oil and gas assets (the “Devon Properties”), including oil and gas leases covering approximately 19,600 net acres located primarily in Lavaca County, Texas for aggregate consideration of $205.0 million in cash, subject to customary purchase price adjustments (the “Acquisition”). Upon execution of the Purchase Agreement, we deposited $10.3 million as earnest money into an escrow account (the “Escrow Account”). The Acquisition has an effective date of March 1, 2017 (the “Effective Date”) and closed on September 29, 2017 (the “Date of Acquisition”), at which time we paid cash consideration of $189.9 million and $7.1 million was released from the Escrow Account to Devon. On the Date of Acquisition we also identified and applied $3.2 million of preliminary purchase price adjustments to net working capital items attributable to the period from the Effective Date through the Date of Acquisition (the “Post-Effective Period”). The $3.2 million remaining in the Escrow Account as of September 30, 2017, which is included as a component of noncurrent “Other assets” on our Condensed Consolidated Balance Sheet, is attributable to certain properties for which title defects have been identified. To the extent that Devon is successful in curing these title defects, funds will be transferred from the Escrow Account to Devon and we will reclassify corresponding amounts from Other assets to Property and equipment, net on our Condensed Consolidated Balance Sheet. On November 1, 2017, we acquired additional working interests in the Devon Properties for $0.7 million from parties that had tag-along rights to sell their interests under the Purchase Agreement. The Acquisition was financed with the net proceeds received from borrowings under a new $200 million second lien credit agreement (the “Second Lien Facility”) (see Note 8 for terms of the Second Lien Facility) and incremental borrowings under our credit agreement (the “Credit Facility”). We incurred $1.5 million of transaction costs associated with the Acquisition, including advisory, legal, due diligence and other professional fees. These costs have been recognized as a component of our “General and administrative” expenses. We accounted for the Acquisition by applying the acquisition method of accounting as of the Date of Acquisition. In accordance with the Purchase Agreement, the Acquisition is deemed to have occurred on September 30, 2017. Accordingly, no production, revenues and expenses attributable to the Devon Properties have been included in our results of operations for the periods ended September 30, 2017. The initial accounting for the Acquisition as presented below is based upon preliminary information available to us and was not complete as of the date our Condensed Consolidated Financial Statements were issued. The final purchase price will be subject to additional post-closing adjustments for the Post-Effective Period to be identified by Devon and agreed to by us in a final settlement. The following table represents the preliminary fair values assigned to the net assets acquired as of the Date of Acquisition and the consideration transferred: Assets Oil and gas properties - proved $ 42,795 Oil and gas properties - unproved 142,817 Other property and equipment 8,642 Liabilities Asset retirement obligations (“AROs”) 491 Net assets acquired $ 193,763 Cash consideration paid to Devon on the Date of Acquisition $ 189,911 Amount transferred to Devon from the Escrow Account 7,049 Application of working capital adjustments, net (3,197 ) Preliminary purchase price $ 193,763 The fair values of the oil and gas properties acquired were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) future cash flows and (v) a market-based weighted-average cost of capital. The fair value of the other property and equipment acquired was measured primarily with reference to replacement costs for similar assets adjusted for the age and normal use of the underlying assets. Because many of these inputs are not observable, we have classified the initial fair value estimates as Level 3 inputs as that term is defined in GAAP. The following table presents unaudited summary pro forma financial information for the periods presented assuming the Acquisition and the related entry into the Second Lien Facility occurred as of January 1, 2017. The pro forma financial information does not purport to represent what our actual results of operations would have been if the Acquisition and the entry into the Second Lien Facility had occurred as of this date, or the results of operations for any future periods. We have excluded any pro forma presentations for the Predecessor periods as they are not comparable. Three Months Nine Months Ended Ended September 30, September 30, 2017 2017 Total revenues $ 41,865 $ 130,504 Net income (loss) attributable to common shareholders $ (8,657 ) $ 38,947 Net income (loss) per share - basic $ (0.58 ) $ 2.60 Net income (loss) per share - diluted $ (0.58 ) $ 2.58

Bankruptcy Proceeding Bankruptc

Bankruptcy Proceeding Bankruptcy Proceedings	9 Months Ended
	Sep. 30, 2017
Reorganizations [Abstract]
Reorganization under Chapter 11 of US Bankruptcy Code Disclosure [Text Block]	Bankruptcy Proceedings and Emergence On May 12, 2016 (the “Petition Date”), we and eight of our subsidiaries filed voluntary petitions ( In re Penn Virginia Corporation, et al., Case No. 16-32395 ) seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Virginia (the “Bankruptcy Court”). On August 11, 2016 (the “Confirmation Date”), the Bankruptcy Court confirmed our Second Amended Joint Chapter 11 Plan of Reorganization of Penn Virginia Corporation and its Debtor Affiliates (the “Plan”), and we subsequently emerged from bankruptcy on September 12, 2016 (the “Emergence Date”). While our emergence from bankruptcy is effectively complete, certain administrative and claims resolution activities will continue under the authority of the Bankruptcy Court until they have been appropriately discharged. As of November 3, 2017, certain claims were still in the process of resolution. While most of these matters are unsecured claims for which shares of Successor common stock have been allocated, certain of these matters must be settled with cash payments. As of September 30, 2017 , we had $ 3.9 million reserved for outstanding claims to be potentially settled in cash. This reserve is included as a component of “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet.

Accounts Receivable and Major C

Accounts Receivable and Major Customers	9 Months Ended
	Sep. 30, 2017
Receivables [Abstract]
Accounts Receivable and Major Customers	Accounts Receivable and Major Customers The following table summarizes our accounts receivable by type as of the dates presented: September 30, December 31, 2017 2016 Customers $ 30,852 $ 20,489 Joint interest partners 18,938 7,238 Other 668 3,789 50,458 31,516 Less: Allowance for doubtful accounts (2,362 ) (2,421 ) $ 48,096 $ 29,095 For the nine months ended September 30, 2017 , two customers accounted for $85.9 million , or approximately 82% , of our consolidated product revenues. The revenues generated from these customers during the nine months ended September 30, 2017 were $72.6 million and $13.3 million , or 69% and 13% of the consolidated total, respectively. As of September 30, 2017 , $14.6 million , or approximately 47% , of our consolidated accounts receivable from customers was related to these customers. For the nine months ended September 30, 2016 , or combined Predecessor and Successor periods, three customers accounted for $93.5 million , or approximately 94% , of our consolidated product revenues. The revenues generated from these customers during the nine months ended September 30, 2016 were $64.1 million , $15.8 million and $13.6 million , or approximately 64% , 16% and 14% of the consolidated total, respectively. As of December 31, 2016 , $16.7 million , or approximately 81% , of our consolidated accounts receivable from customers was related to these customers. No significant uncertainties exist related to the collectability of amounts owed to us by any of these customers.

Derivative Instruments

Derivative Instruments	9 Months Ended
	Sep. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments We utilize derivative instruments to mitigate our financial exposure to commodity price volatility. Our derivative instruments are not formally designated as hedges in the context of GAAP. We typically utilize collars and swaps, which are placed with financial institutions that we believe are acceptable credit risks, to hedge against the variability in cash flows associated with anticipated sales of our future commodity production. At times, we also utilize option contracts. While the use of derivative instruments limits the risk of adverse price movements, such use may also limit future revenues from favorable price movements. The counterparty to a collar or swap contract is required to make a payment to us if the settlement price for any settlement period is below the floor or swap price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling or swap price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract. We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for West Texas Intermediate (“WTI”) crude oil , and Louisiana Light Sweet (“LLS”) and New York Mercantile Exchange (“NYMEX”) Henry Hub gas and closing prices as of the end of the reporting period. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position and our own credit risk if the derivative is in a liability position. We terminated all of our pre-petition derivative contracts from March 2016 through May 2016 for $63.0 million and reduced amounts outstanding under the pre-petition credit agreement (the “RBL”) by $52.0 million . In connection with these transactions, the counterparties to the derivative contracts, which were also affiliates of lenders under the RBL, transferred the cash proceeds that were used for RBL repayments directly to the administrative agent under the RBL. Accordingly, all of these RBL repayments have been presented as non-cash financing activities on our Condensed Consolidated Statement of Cash Flows for the Predecessor period from January 1, 2016 through the Petition Date. Subsequent to the Petition Date, we entered into a series of new commodity derivative contracts. Accordingly, we hedged a substantial portion of our estimated future crude oil production through the end of 2019. We are currently unhedged with respect to NGL and natural gas production. In August 2017, in anticipation of the closing of the Acquisition, we bought a series of put option contracts for 4,000 barrels of oil per day (“BOPD”) for each of the quarterly periods ending in 2018 with a strike price of $55.00 per barrel. We incurred premiums ranging from $8.00 to $9.50 per barrel which were deferred. In early October and subsequent to the closing of the Acquisition, we sold the underlying put options and converted the contracts to fixed price swaps with 1,000 BOPD for each of the quarterly periods ending in 2018 for a weighted-average WTI-based swap price of $49.00 per barrel, 1,000 BOPD for each of the quarterly periods ending in 2018 for a weighted-average swap price based on the LLS index of $50.83 per barrel and 2,000 BOPD for each of the quarterly periods in 2019 for a weighted-average swap price based on the LLS index of $50.86 per barrel. Premiums that were due upon the sale of the put option contracts were settled via a reduction in the strike price of the resulting swap contracts. We also entered into additional hedge contracts in October 2017 (see below). The following table sets forth our commodity derivative positions, presented on a net basis by period of maturity, as of September 30, 2017 : Average Weighted Volume Per Average Fair Value Instrument Day Price Asset Liability Crude Oil: (barrels) ($/barrel) Fourth quarter 2017 Swaps 4,381 $ 48.59 $ — $ 1,361 First quarter 2018 Swaps/Put option 1 8,513 $ 47.98 — 2,427 Second quarter 2018 Swaps/Put option 1 8,484 $ 47.98 — 1,971 Third quarter 2018 Swaps/Put option 1 8,455 $ 47.98 — 1,563 Fourth quarter 2018 Swaps/Put option 1 8,455 $ 47.98 — 1,251 First quarter 2019 Swaps 2,946 $ 49.87 — 356 Second quarter 2019 Swaps 2,921 $ 49.87 — 307 Third quarter 2019 Swaps 2,897 $ 49.87 — 258 Fourth quarter 2019 Swaps 2,898 $ 49.87 — 231 Settlements to be paid in subsequent period 172 _______________________ 1 As discussed above, the put option contracts were unwound and converted to fixed price swaps in early October 2017. Including the effect of these transactions as well as additional hedge contracts entered into in October 2017, we have hedged our crude oil production as follows: remainder of 2017 - 4,381 BOPD at a weighted-average WTI-based price of $48.59 per barrel and 663 BOPD at a weighted-average LLS-based price of $56.18 per barrel, 2018 - 5,477 BOPD at a weighted-average WTI-based price of $49.30 per barrel and 1,500 BOPD at a weighted-average LLS-based price of $51.97 per barrel, 2019 - 2,915 BOPD at a weighted-average WTI-based price of $49.87 per barrel and 2,500 BOPD at a weighted-average LLS-based price of $51.30 per barrel and 2020 - 1,000 BOPD at a weighted-average WTI-based price of $50.35 per barrel. Financial Statement Impact of Derivatives The impact of our derivative activities on income is included in “Derivatives” in our Condensed Consolidated Statements of Operations. The following table summarizes the effects of our derivative activities for the periods presented: Successor Predecessor Three Months Ended Period from September 13, 2016 Period from July 1, 2016 September 30, 2017 Through September 30, 2106 Through September 12, 2016 Derivative gains (losses) $ (12,275 ) $ (4,369 ) $ 8,934 Successor Predecessor Nine Months Ended Period from September 13, 2016 Period from January 1, 2016 September 30, 2017 Through September 30, 2106 Through September 12, 2016 Derivative gains (losses) $ 15,802 $ (4,369 ) $ (8,333 ) The effects of derivative gains and (losses) and cash settlements (except for those cash settlements attributable to the aforementioned termination transactions) are reported as adjustments to reconcile net income (loss) to net cash provided by operating activities. These items are recorded in the “Derivative contracts” section of our Condensed Consolidated Statements of Cash Flows under “Net (gains) losses” and “Cash settlements, net.” The following table summarizes the fair values of our derivative instruments presented on a gross basis, as well as the locations of these instruments on our Condensed Consolidated Balance Sheets as of the dates presented: September 30, 2017 December 31, 2016 Derivative Derivative Derivative Derivative Type Balance Sheet Location Assets Liabilities Assets Liabilities Commodity contracts Derivative assets/liabilities – current $ 6,140 $ 13,634 $ — $ 12,932 Commodity contracts Derivative assets/liabilities – noncurrent 2,520 4,923 — 14,437 $ 8,660 $ 18,557 $ — $ 27,369 As of September 30, 2017 , we reported total commodity derivative assets of $8.7 million . The contracts associated with this position are with three counterparties, all of which are investment grade financial institutions. This concentration may impact our overall credit risk in that these counterparties may be similarly affected by changes in economic or other conditions. We have neither paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions. Furthermore, our derivative contracts are not subject to margin calls or similar accelerations. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.

Property and Equipment

Property and Equipment	9 Months Ended
	Sep. 30, 2017
Property, Plant and Equipment [Abstract]
Property and Equipment	Property and Equipment The following table summarizes our property and equipment as of the dates presented: September 30, December 31, 2017 2016 Oil and gas properties: Proved $ 369,384 $ 251,083 Unproved 147,594 4,719 Total oil and gas properties 516,978 255,802 Other property and equipment 12,484 3,575 Total properties and equipment 529,462 259,377 Accumulated depreciation, depletion and amortization (43,402 ) (11,904 ) $ 486,060 $ 247,473 Unproved property costs of $ 147.6 million and $ 4.7 million have been excluded from amortization as of September 30, 2017 and December 31, 2016 , respectively. We transferred $ 1.9 million of undeveloped leasehold costs associated with acreage unlikely to be drilled or associated with proved undeveloped reserves, including capitalized interest, from unproved properties to the full cost pool during the nine months ended September 30, 2017 . We capitalized internal costs of $ 1.6 million and interest of $ 0.1 million during the nine months ended September 30, 2017 in accordance with our accounting policies. Average depreciation, depletion and amortization (“DD&A”) per barrel of oil equivalent of proved oil and gas properties was $11.93 for the nine months ended September 30, 2017 , $10.04 for the Predecessor period from January 1, 2016 through September 12, 2016 and $11.09 for the Successor period from September 13, 2016 through September 30, 2016. The DD&A rate for the Predecessor period was determined under the successful efforts method while the Successor periods subsequent to September 12, 2016 were determined under the full cost method (see Note 2).

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2017
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt The following table summarizes our debt obligations as of the dates presented: September 30, 2017 December 31, 2016 Principal Unamortized Discount and Deferred Issuance Costs 1 Principal Unamortized Discount and Deferred Issuance Costs Credit facility 2 $ 57,000 $ 25,000 Second lien term loans 200,000 $ 11,945 — $ — Totals 257,000 $ 11,945 25,000 $ — Less: Unamortized discount (4,000 ) — Less: Unamortized deferred issuance costs (7,945 ) — Long-term debt, net $ 245,055 $ 25,000 _______________________ 1 Discount and issuance costs of the Second Lien Facility are being amortized over the term of the underlying loan using the effective-interest method. 2 Issuance costs of the Credit Facility, which represent costs attributable to the access to credit over it’s contractual term, have been presented as a component of Other assets (see Note 11) and are being amortized over the term of the Credit Facility using the straight-line method. Credit Facility On the Emergence Date, we entered into the Credit Facility. The Credit Facility currently provides for a $237.5 million revolving commitment and borrowing base and a $5 million sublimit for the issuance of letters of credit. In September 2017, the borrowing base under the Credit Facility was redetermined from $200 million to $237.5 million pursuant to the Master Assignment, Agreement and Amendment No. 3 to the Credit Facility (the “Third Amendment”). In the nine months ended September 30, 2017, we paid and capitalized issue costs of $ 1.7 million in connection with the amendments that increased our borrowing base and wrote-off $ 0.8 million of previously capitalized issue costs due to changes in the composition of financial institutions comprising the Credit Facility bank group associated with the amendments. The availability under the Credit Facility may not exceed the lesser of the aggregate commitments or the borrowing base. The borrowing base under the Credit Facility is generally redetermined semi-annually in April and October of each year. Additionally, the Credit Facility lenders may, at their discretion, initiate a redetermination at any time during the six-month period between scheduled redeterminations. The Credit Facility is available to us to pay expenses associated with our bankruptcy proceedings and for general corporate purposes including working capital. The Credit Facility matures in September 2020. We had $0.8 million in letters of credit outstanding as of September 30, 2017 and December 31, 2016 . The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 2.00% to 3.00% , determined based on the average availability under the Credit Facility or (b) a customary London interbank offered rate (“LIBOR”) plus an applicable margin ranging from 3.00% to 4.00% , determined based on the average availability under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on LIBOR borrowings is payable every one , three or six months, at our election, and is computed on the basis of a year of 360 days. As of September 30, 2017 , the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 4.42% . Unused commitment fees are charged at a rate of 0.50% . The Credit Facility is guaranteed by us and all of our subsidiaries (the “Guarantor Subsidiaries”). The guarantees under the Credit Facility are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. The parent company has no material independent assets or operations. There are no significant restrictions on the ability of the parent company or any of the Guarantor Subsidiaries to obtain funds through dividends, advances or loans. The obligations under the Credit Facility are secured by a first priority lien on substantially all of our assets. The Credit Facility requires us to maintain (1) a minimum interest coverage ratio (adjusted earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses as defined in the Credit Facility (“EBITDAX”) to adjusted interest expense), measured as of the last day of each fiscal quarter, of 3.00 to 1.00, (2) a minimum current ratio (as defined in the Credit Facility, which considers the unused portion of the total commitment as a current asset), measured as of the last day of each fiscal quarter of 1.00 to 1.00, and (3) a maximum leverage ratio (consolidated indebtedness to EBITDAX), measured as of the last day of each fiscal quarter, initially of 4.00 to 1.00, decreasing on December 31, 2017 to 3.75 to 1.00 and on March 31, 2018 and thereafter to 3.50 to 1.00. The Credit Facility also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, merger, consolidation or sale of assets, payment of dividends, and transactions with affiliates and other customary covenants. The Credit Facility contains customary events of default and remedies for credit facilities of this nature. If we do not comply with the financial and other covenants in the Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Credit Facility. As of September 30, 2017, we were in compliance with all of the covenants under the Credit Facility. Second Lien Facility On September 29, 2017, we entered into the $200 million Second Lien Facility. We received net proceeds of $188.1 million from the Second Lien Facility net of an original issue discount (“OID”) of $4.0 million and issue costs of $7.9 million . The proceeds from the Second Lien Facility were used to fund the Acquisition and related fees and expenses. The maturity date under the Second Lien Facility is September 29, 2022. The outstanding borrowings under the Second Lien Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate based on the prime rate plus an applicable margin of 6.00% or (b) a customary LIBOR rate plus an applicable margin of 7.00% . Amounts under the Second Lien Facility were borrowed at a price of 98% with an initial interest rate of 8.34% resulting in an effective interest rate of 9.86% . Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on eurocurrency borrowings is payable every one or three months (including in three month intervals if we select a six month interest period), at our election and is computed on the basis of a 360-day year. We have the right, to the extent permitted under the Credit Facility and an intercreditor agreement between the lenders under the Credit Facility and the lenders under the Second Lien Facility, to prepay loans under the Second Lien Facility at any time, subject to the following prepayment premiums (in addition to customary “breakage” costs with respect to eurocurrency loans): during year one, a customary “make-whole” premium; during year two, 102% of the amount being prepaid; during year three, 101% of the amount being prepaid; and thereafter, no premium. The Second Lien Facility also provides for the following prepayment premiums in the event of a change in control that results in an offer of prepayment that is accepted by the lenders under the Second Lien Facility: during years one and two, 102% of the amount being prepaid; during year three, 101% of the amount being prepaid; and thereafter, no premium. The Second Lien Facility is collateralized by substantially all of the Company’s and its subsidiaries’ assets with lien priority subordinated to the liens securing the Credit Facility. The obligations under the Second Lien Facility are guaranteed by us and the Subsidiary Guarantors. The Second Lien Facility has no financial covenants, but contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, merger, consolidation or sale of assets and transactions with affiliates and other customary covenants. As illustrated in the table above, the OID and issue costs of the Second Lien Facility are presented as reductions to the outstanding term loans. These costs are subject to amortization using the interest method over the five-year term of the Second Lien Facility. As of September 30, 2017, we were in compliance with all of the covenants under the Second Lien Facility.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes We recognized a federal and state income tax expense for the nine months ended September 30, 2017 at the blended rate of 35.52% ; however, the federal and state tax expense was fully offset by an adjustment to the valuation allowance against our net deferred tax assets. We recognized a federal income tax benefit for the nine months ended September 30, 2016 at the statutory rate of 35% which was fully offset by a valuation allowance against our net deferred tax assets. We considered both the positive and negative evidence in determining that it was more likely than not that some portion or all of our deferred tax assets will not be realized, primarily as a result of cumulative losses. We received a state income tax refund of less than $0.1 million during the nine months ended September 30, 2016 . We have evaluated the impact of the reorganization, including the change in control, resulting from our emergence from bankruptcy. From an income tax perspective, the most significant impact is attributable to our carryover tax attributes associated with our net operating losses (“NOLs”). We believe that the Successor will be able to fully absorb the cancellation of debt income realized by the Predecessor in connection with the reorganization with its adjusted NOL carryovers. The amount of the remaining NOL carryovers and the tax basis of our properties will be limited under Section 382 of the Internal Revenue Code due to the change in control that occurred upon our emergence from bankruptcy on the Emergence Date. As the tax basis of our assets, primarily our oil and gas properties, is in excess of the carrying value, as adjusted in the Fresh Start Accounting process, the Successor is in a net deferred tax asset position. We have determined that it is more likely than not that we will not realize future income tax benefits from the additional tax basis and our remaining NOL carryovers. Accordingly, we have provided for a full valuation allowance of the underlying deferred tax assets.

Exit Activities

Exit Activities	9 Months Ended
	Sep. 30, 2017
Restructuring and Related Activities [Abstract]
Exit Activities	Exit Activities Prior to the Emergence Date, the Predecessor committed to a number of actions, or exit activities, the most significant of which are described below. Reductions in Force In connection with efforts to reduce our administrative costs, we took certain actions to reduce our total employee headcount. In 2016, we reduced our total employee headcount by 53 employees. We incurred charges of $ 2.0 million in connection with this action and paid a total of $ 1.9 million in severance and termination benefits during the nine months ended September 30, 2016 . We recognized an immaterial credit adjustment to the remaining obligation of less than $ 0.1 million during the combined Predecessor and Successor periods ended ended September 30, 2017 . There were no payments under these obligations during the nine months ended September 30, 2017 . The costs associated with these reduction-in-force actions are included as a component of our “General and administrative” expenses in our Condensed Consolidated Statements of Operations. The related obligation is included in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet. Drilling Rig Termination In connection with the suspension of our 2016 drilling program in the Eagle Ford, we terminated a drilling rig contract and incurred $ 1.3 million in early termination charges during the Predecessor period prior to the Petition Date. As this obligation represented a pre-petition liability of the Predecessor, it was discharged in connection with our emergence from bankruptcy. The vendor recovered a portion of the amount in the form of Successor common stock. Firm Transportation Obligation We had a contractual obligation for certain firm transportation capacity in the Appalachian region that was scheduled to expire in 2022 and, as a result of the sale of our natural gas assets in that region in 2012, we no longer had production available to satisfy the commitment. We originally recognized a liability in 2012 representing this obligation for the estimated discounted future net cash outflows over the remaining term of the contract. The accretion of the obligation through the Petition Date, net of any recoveries from periodic sales of our contractual capacity, was charged as an offset to Other revenue. During the Predecessor period September 12, 2016, we paid a total of $ 1.1 million and recognized accretion expense of $ 0.3 million attributable to the underlying obligation. In connection with our emergence from bankruptcy, we rejected the underlying contract.

Additional Balance Sheet Detail

Additional Balance Sheet Detail	9 Months Ended
	Sep. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Additional Balance Sheet Detail	Additional Balance Sheet Detail The following table summarizes components of selected balance sheet accounts as of the dates presented: September 30, December 31, 2017 2016 Other current assets: Tubular inventory and well materials $ 2,297 $ 2,125 Prepaid expenses 818 903 $ 3,115 $ 3,028 Other assets: Deferred issuance costs of the Credit Facility $ 3,130 $ 2,785 Deposit in escrow 1 3,205 — Other 2,488 2,544 $ 8,823 $ 5,329 Accounts payable and accrued liabilities: Trade accounts payable $ 7,275 $ 9,825 Drilling costs 10,620 2,479 Royalties and revenue – related 30,184 26,116 Compensation – related 3,135 2,557 Interest 107 55 Reserve for bankruptcy claims 3,922 3,922 Other 6,993 4,743 $ 62,236 $ 49,697 Other liabilities: Asset retirement obligations $ 3,041 $ 2,459 Defined benefit pension obligations 946 1,025 Postretirement health care benefit obligations 544 488 Other 100 100 $ 4,631 $ 4,072 _______________________ 1 Represents amount remaining in the escrow deposit for the Acquisition (see Note 3).

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements We apply the authoritative accounting provisions for measuring the fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date. Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and our Credit Facility and Second Lien Facility borrowings. As of September 30, 2017 , the carrying values of all of these financial instruments approximated fair value. Recurring Fair Value Measurements Certain financial assets and liabilities are measured at fair value on a recurring basis on our Condensed Consolidated Balance Sheets. The following tables summarize the valuation of those assets and (liabilities) as of the dates presented: September 30, 2017 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Assets: Commodity derivative assets – current $ 6,140 $ — $ 6,140 $ — Commodity derivative assets – noncurrent 2,520 — 2,520 — Liabilities: Commodity derivative liabilities – current $ (13,634 ) $ — $ (13,634 ) $ — Commodity derivative liabilities – noncurrent (4,923 ) — (4,923 ) — December 31, 2016 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Liabilities: Commodity derivative liabilities – current $ (12,932 ) $ — $ (12,932 ) $ — Commodity derivative liabilities – noncurrent (14,437 ) — (14,437 ) — Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one level of the fair value hierarchy to another level. In such instances, the transfer is deemed to have occurred at the beginning of the quarterly period in which the event or change in circumstances that caused the transfer occurred. There were no transfers during the periods ended September 30, 2017 and 2016 . We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below: • Commodity derivatives : We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for WTI crude oil and NYMEX Henry Hub gas closing prices as of the end of the reporting periods. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. Each of these is a level 2 input. Non-Recurring Fair Value Measurements In addition to the fair value measurements applied with respect to the Acquisition, as described in Note 3, the most significant non-recurring fair value measurements utilized in the preparation of our Condensed Consolidated Financial Statements are those attributable to the initial determination of AROs associated with the ongoing development of new oil and gas properties. The determination of the fair value of AROs is based upon regional market and facility specific information. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these significant fair value inputs are typically not observable, we have categorized the initial estimates as level 3 inputs. In addition, we utilize non-recurring fair value measurements with respect to the recognition and measurement of asset impairments, particularly during our Predecessor periods during which time we applied the successful efforts method to our oil and gas properties. The factors used to determine fair value for purposes of recognizing and measuring asset impairments while we applied the successful efforts method to our oil and gas properties during our Predecessor periods included, but were not limited to, estimates of proved and risk-adjusted probable reserves, future commodity prices, indicative sales prices for properties, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Because these significant fair value inputs were typically not observable, we have categorized the amounts as level 3 inputs. Under the full cost method, which we have applied since the Emergence Date, we apply a ceiling test determination utilizing prescribed procedures. The full cost method is substantially different from the successful efforts method which relies upon fair value measurements.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Gathering and Intermediate Transportation Commitments We have long-term agreements (the “Amended Agreements”) with Republic Midstream, LLC (“Republic Midstream”) and Republic Midstream Marketing, LLC (“Republic Marketing” and, together with Republic Midstream, collectively, “Republic”) to provide for gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production in the South Texas region as well as volume capacity support for certain downstream interstate pipeline transportation. Republic is obligated to gather and transport our crude oil and condensate from within a dedicated area in the Eagle Ford via a gathering system and intermediate takeaway pipeline connecting to a downstream interstate pipeline operated by a third party through 2041. We have a minimum volume commitment (“MVC”) of 8,000 gross barrels of oil per day to Republic through 2031 under the gathering agreement. Under the marketing agreement, we have a 10 -year commitment to sell 8,000 barrels per day of crude oil to Republic, or any third party, utilizing Republic Marketing’s capacity on a certain downstream interstate pipeline. Excluding the potential impact of the effects of price escalation from commodity price changes, the minimum fee requirements attributable to the MVC under the Amended Agreements are as follows: $ 2.5 million for the remainder of 2017, $ 10.4 million for 2018, $ 11.7 million for 2019, $ 13.0 million for 2020 through 2025, $ 7.4 million for 2026, $ 3.8 million for 2027 through 2030 and $ 2.2 million for 2031. Drilling Commitments We have contractual commitments for three drilling rigs. One rig began operations in September 2017 and is subject to a six-month commitment through March 2018. A second rig began operations in October 2017 and is committed on a limited well pad-basis. A third rig is contracted to enter service in November 2017 and is also subject to a six-month commitment through May 2018. We have approximately $ 6.9 million of obligations associated with these commitments. Legal and Regulatory We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, results of operations or cash flows. As of September 30, 2017 , we continue to maintain a $0.1 million reserve for a litigation matter. As of September 30, 2017 , we also had AROs of approximately $3.0 million attributable to the plugging of abandoned wells.

Shareholders' Equity

Shareholders' Equity	9 Months Ended
	Sep. 30, 2017
Equity [Abstract]
Shareholders' Equity	Shareholders’ Equity The following tables summarize the components of our shareholders ’ equity and the changes therein as of and for nine months ended September 30, 2017 : December 31, All Other September 30, 2016 Net Income Changes 1 2017 Common stock $ 150 $ — $ — $ 150 Paid-in capital 190,621 — 2,751 193,372 Retained earnings (accumulated deficit) (5,296 ) 43,463 — 38,167 Accumulated other comprehensive income 73 — — 73 $ 185,548 $ 43,463 $ 2,751 $ 231,762 _______________________ 1 Includes equity-classified share-based compensation of $ 2.7 million and $ 0.1 million from the receipt in May 2017 of proceeds attributable to the rights offering in 2016 that had been held in escrow, net of costs to register our common stock. During the nine months ended September 30, 2017 , 12,252 shares of common stock were issued in connection with the vesting of certain time-vested restricted stock units (“RSUs“ ), net of shares withheld for income taxes.

Share-Based Compensation and Ot

Share-Based Compensation and Other Benefit Plans	9 Months Ended
	Sep. 30, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-Based Compensation and Other Benefit Plans	Share-Based Compensation and Other Benefit Plans Share-Based Compensation We recognize share-based compensation expense related to our share-based compensation plans as a component of “General and administrative” expense in our Condensed Consolidated Statements of Operations. In the Predecessor periods in 2016 we had outstanding equity-classified awards in the form of stock options, restricted stock units and deferred stock units. All outstanding equity-classified share-based compensation awards were canceled in connection with our emergence from bankruptcy. We reserved 749,600 shares of Successor common Stock for issuance under the Penn Virginia Corporation Management Incentive Plan for future share-based compensation awards. A total of 298,454 RSUs and 98,526 performance restricted stock units (“PRSUs”) have been granted as of September 30, 2017 . The following table summarizes our share-based compensation expense (benefit) recognized for the periods presented: Successor Predecessor Period From Period From Three Months Ended September 13, 2016 Through July 1, 2016 Through September 30, 2017 September 30, 2016 September 12, 2016 Equity-classified awards 1 $ 1,013 $ — $ 147 Liability-classified awards — — — $ 1,013 $ — $ 147 _______________________ 1 Amounts for the period from July 1, 2016 through September 12, 2016 periods have been recasted (see Note 2). Successor Predecessor Period From Period From Nine Months Ended September 13, 2016 Through January 1, 2016 Through September 30, 2017 September 30, 2016 September 12, 2016 Equity-classified awards $ 2,707 $ — $ 1,511 Liability-classified awards — — (19 ) $ 2,707 $ — $ 1,492 In the nine months ended September 30, 2017 , we granted 190,891 RSUs to certain employees with an average grant-date fair value of $ 48.70 per RSU. The RSUs are being charged to expense on a straight-line basis over five years. In the nine months ended September 30, 2017 , we also granted 98,526 PRSUs to members of our management. The PRSUs were issued collectively in two to three separate tranches with individual three -year performance periods beginning in January 2017, 2018 and 2019, respectively. Vesting of the PRSUs can range from zero to 200 percent of the original grant based on the performance of our common stock relative to an industry index. Due to their market condition, the PRSUs are being charged to expense using graded vesting over a maximum of five years. The fair value of each PRSU award was estimated on their grant dates using a Monte Carlo simulation with a range of $47.70 to $65.28 per PRSU. Expected volatilities were based on historical volatilities and range from 59.63% to 62.18% . A risk-free rate of interest with a range of 1.44% to 1.51% was utilized which is equivalent to the yield, as of the measurement date, of the zero-coupon U.S. Treasury bill commensurate with the longest remaining performance measurement period for each tranche. We assumed no payment of dividends during the performance periods. Other Benefit Plans We maintain the Penn Virginia Corporation and Affiliated Companies Employees 401(k) Plan (the “401(k) Plan”), a defined contribution plan, which covers substantially all of our employees. We recognized $0.3 million of expense attributable to the 401(k) Plan for the nine months ended September 30, 2017 , and $0.4 million for the period January 1, 2016 through September 12, 2016, and less than $0.1 million for the period September 13, 2016 through September 30, 2016. We maintain unqualified legacy defined benefit pension and defined benefit postretirement plans that cover a limited number of former employees, all of whom retired prior to 2000. The combined expense recognized with respect to these plans was less than $0.1 million for the nine months ended September 30, 2017 , less than $ 0.1 million for the period January 1, 2016 through September 12, 2016 and less than $ 0.1 million for the period September 13, 2106 through September 30, 2016.

Interest Expense

Interest Expense	9 Months Ended
	Sep. 30, 2017
Banking and Thrift [Abstract]
Interest Expense	The following table summarizes the components of interest expense for the periods presented: Successor Predecessor Three Months Ended Period From September 13, 2016 Period From July 1, 2016 September 30, 2017 Through September 30, 2016 Through September 12, 2016 Interest on borrowings and related fees 1 $ 879 $ 180 $ 1,363 Amortization of debt issuance costs 2 374 38 — Capitalized interest (51 ) — — $ 1,202 $ 218 $ 1,363 ___________________ 1 Absent the bankruptcy proceedings and the corresponding suspension of the accrual of interest on unsecured debt, we would have recorded total contractual interest expense of $ 19.3 million for the period from July 1, 2016 through September 12, 2016, including $ 4.4 million and $ 13.4 million attributable to the 7.25% Senior Notes due 2019 (“2019 Senior Notes”) and the 8.5% Senior Notes due 2020 (“2020 Senior Notes”). 2 The three months ended September 30, 2017 includes a $0.2 million write-off attributable to a change in the composition of financial institutions comprising the Credit Facility’s bank group in connection with the Third Amendment (see Note 8). Successor Predecessor Nine Months Ended Period From September 13, 2016 Period From January 1, 2016 September 30, 2017 Through September 30, 2016 Through September 12, 2016 Interest on borrowings and related fees 1 $ 1,784 $ 180 $ 36,013 Amortization of debt issuance costs 2 1,362 38 22,188 Capitalized interest (132 ) — (183 ) $ 3,014 $ 218 $ 58,018 Successor Predecessor Nine Months Ended Period From September 13, 2016 Period From January 1, 2016 September 30, 2017 Through September 30, 2016 Through September 12, 2016 Interest on borrowings and related fees 1 $ 1,784 $ 180 $ 36,013 Amortization of debt issuance costs 2 1,362 38 22,188 Capitalized interest (132 ) — (183 ) $ 3,014 $ 218 $ 58,018 ___________________ 1 Absent the bankruptcy proceedings and the corresponding suspension of the accrual of interest on unsecured debt, we would have recorded total contractual interest expense of $ 66.1 million for the period from January 1, 2016 through September 12, 2016, including $ 15.3 million and $ 46.3 million attributable to the 2019 Senior Notes and the 2020 Senior Notes, respectively. 2 The nine months ended September 30, 2017 includes a total of $0.8 million of write-offs attributable to changes in the composition of financial institutions comprising the Credit Facility’s bank group in connection with amendments to the Credit Facility (see Note 8). The period from January 1, 2016 through September 12, 2016 includes $20.5 million related to the accelerated write-off of unamortized debt issuance costs associated with the RBL and Senior Notes.

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 The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings (loss) per share for the periods presented: Successor Predecessor Three Months Ended Period From September 13, 2016 Period From July 1, 2016 September 30, 2017 Through September 30, 2016 Through September 12, 2016 Net income (loss) $ (5,947 ) $ (3,441 ) $ 1,155,341 Less: Preferred stock dividends — — — Net income (loss) attributable to common shareholders – basic and diluted $ (5,947 ) $ (3,441 ) $ 1,155,341 Weighted-average shares – basic 14,994 14,992 89,292 Effect of dilutive securities 1 — — 22,166 Weighted-average shares – diluted 14,994 14,992 111,458 _______________________ 1 The number of dilutive securities for the three months ended September 30, 2017 , which is attributable to RSUs and PRSUs, was determined under the “treasury stock” method. For the three months ended September 30, 2017 , approximately 0.1 million of potentially dilutive securities attributable to RSUs had the effect of being anti-dilutive and were excluded from the calculation of diluted loss per common share. Successor Predecessor Predecessor Nine Months Ended Period From September 13, 2016 Period From January 1, 2016 September 30, 2017 Through September 30, 2016 Through September 12, 2016 Net income (loss) $ 43,463 $ (3,441 ) $ 1,054,602 Less: Preferred stock dividends 1 — — (5,972 ) Net income (loss) attributable to common shareholders – basic and diluted $ 43,463 $ (3,441 ) $ 1,048,630 Weighted-average shares – basic 14,993 14,992 88,013 Effect of dilutive securities 2 69 — 36,074 Weighted-average shares – diluted 15,062 14,992 124,087 _______________________ 1 Dividends attributable to our Series A 6% Convertible Perpetual Preferred Stock and Series B 6% Convertible Perpetual Preferred Stock (together, the “Series A and B Preferred Stock”) were excluded from the computation of diluted loss per share for the period from January 1, 2016 through September 12, 2016, as their assumed conversion would have been anti-dilutive. 2 The number of dilutive securities for the three and nine months ended September 30, 2017 , which is attributable to RSUs and PRSUs, was determined under the “treasury stock” method.

Basis of Presentation (Policies

Basis of Presentation (Policies)	9 Months Ended
	Sep. 30, 2017
Schedule of Policies [Line Items]
New Accounting Pronouncements	Recently Issued Accounting Pronouncements In March 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017–07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017–07”) which provides guidance to improve the reporting of net benefit cost in financial statements. The guidance requires employers to disaggregate the service cost component from the other components of net benefit cost. The service cost component of net periodic benefit cost shall be reported in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period, except for amounts capitalized. All other components of net benefit cost shall be presented outside of a subtotal for income from operations. The line item used to present the components other than the service cost shall be disclosed if the other components are not presented in a separate line item or items. ASU 2017–07 is effective January 1, 2018 and is required to be applied retrospectively. ASU 2017–07 will be applicable to our legacy retiree benefit plans which cover a limited population of former employees. There is no service cost associated with these plans as they are not applicable to current employees, but rather interest and other costs associated with the legacy obligations. Upon the adoption of ASU 2017–07, the entirety of the expense associated with these plans will be presented as a component of the “Other income (expense)” caption in our Condensed Consolidated Statement of Operations. These costs are currently recognized as a component of “General and administrative” expenses. The total cost associated with these plans is generally less than $ 0.1 million on an annual basis and is therefore not material. We will adopt ASU 2017–07 in January 2018. In June 2016, the FASB issued ASU 2016–13, Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”), which changes the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities, among others. ASU 2016–13 is required to be adopted using the modified retrospective method by January 1, 2020, with early adoption permitted for fiscal periods beginning after December 15, 2018. In contrast to current guidance, which considers current information and events and utilizes a probable threshold, (an “incurred loss” model), ASU 2016–13 mandates an “expected loss” model. The expected loss model: (i) estimates the risk of loss even when risk is remote, (ii) estimates losses over the contractual life, (iii) considers past events, current conditions and reasonable supported forecasts and (iv) has no recognition threshold. ASU 2016–13 will have applicability to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners which have a higher credit risk than those associated with our traditional customer receivables. At this time, we do not anticipate that the adoption of ASU 2016–13 will have a significant impact on our Consolidated Financial Statements and related disclosures; however, we are continuing to evaluate the requirements and the period for which we will adopt the standard as well as monitoring developments regarding ASU 2016–13 that are unique to our industry. In February 2016, the FASB issued ASU 2016–02, Leases (“ASU 2016–02”), which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases with terms of more than twelve months. Consistent with current GAAP, the recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease. ASU 2016–02 also will require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ASU 2016–02 is January 1, 2019, with early adoption permitted. We believe that ASU 2016–02 will likely be applicable to our oil and natural gas gathering commitment arrangements as described in Note 13, our existing leases for office facilities and certain office equipment, land easements and similar arrangements for rights-of-way and potentially to certain drilling rig and completion contracts with terms in excess of twelve months to the extent we may have such contracts in the future. Our oil and natural gas gathering arrangements are fairly complex and involve multiple elements that could be construed as leases. Accordingly, we are continuing to evaluate the effect that ASU 2016–02 will have on our Consolidated Financial Statements and related disclosures as well as the period for which we will adopt the standard, however, at this time, we believe that we will likely adopt ASU 2016–02 in 2019. We are also continuing to monitor developments regarding ASU 2016–02 that are unique to our industry. In May 2014, the FASB issued ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014–09 will replace most existing revenue recognition guidance in GAAP when it becomes effective on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. While traditional commodity sales transactions, property conveyances and joint interest arrangements in the oil and gas industry are not expected to be significantly impacted by ASU 2014–09, the terms of the individual commodity purchase, joint operating agreements and other contracts underlying these types of transactions will determine the appropriate recognition, measurement and disclosure once ASU 2014–09 has been adopted. Also, to the extent applicable, we are considering our participation in certain of these transactions as either a principal or agent. In addition, the recognition, measurement and disclosure of producer imbalances and other non-product revenues, including our ancillary marketing, gathering and transportation and water disposal revenues, while not significant, could be impacted to some degree. Our non-product revenues are projected to represent less than $1 million of our total revenues on an annualized basis; however, that level could rise in future periods based on the potential expansion and growth of our operations. In summary, with the exception of more expansive disclosures, we have not identified any potentially material impact attributable to ASU 2014–09. While we are continuing to evaluate the overall effect that ASU 2014–09 will have on our Consolidated Financial Statements and related disclosures, our remaining efforts are primarily focused on developing controls and procedures to facilitate the ongoing process of analysis of future contracts and their terms in order to support the appropriate accounting and disclosure. We are also continuing to monitor developments regarding ASU 2014–09 that are unique to our industry. We will adopt ASU 2014–09 in January 2018 using the cumulative effect transition method.
Basis of Presentation	Basis of Presentation Our unaudited Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of our subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our Condensed Consolidated Financial Statements have been included. Our Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Annual Report on Form 10-K for the year ended December 31, 2016 . Operating results for the nine months ended September 30, 2017 , are not necessarily indicative of the results that may be expected for the year ending December 31, 2017 . Comparability of Financial Statements to Prior Periods We adopted and began applying the relevant guidance provided in GAAP with respect to the accounting and financial statement disclosures for entities that have emerged from bankruptcy proceedings (“Fresh Start Accounting”) on September 12, 2016. Accordingly, our Condensed Consolidated Financial Statements and Notes after September 12, 2016, are not comparable to the Condensed Consolidated Financial Statements and Notes through that date. To facilitate our financial statement presentations, we refer to the reorganized company in these Condensed Consolidated Financial Statements and Notes as the “Successor,” which is effectively a new reporting entity for financial reporting purposes, for periods subsequent to September 12, 2016, and the “Predecessor” for periods prior to September 13, 2016. In connection with our reorganization, we experienced a change in control as the outstanding common and preferred shares of the Predecessor were canceled and substantially all of the Successor’s new common stock was issued to the Predecessor’s creditors. Furthermore, our Condensed Consolidated Financial Statements and Notes have been presented with a “black line” division to delineate, where applicable, the lack of comparability between the Predecessor and Successor. In addition, we adopted the full cost method of accounting for our oil and gas properties effective with our adoption of Fresh Start Accounting. Accordingly, our results of operations, financial position and cash flows for the Successor periods will be substantially different from our historic trends. We have recasted amounts for equity-classified share-based compensation recognized as a component of “General and administrative” expenses from the amounts originally reported for the Predecessor period from July 1, 2016 through September 12, 2016 to correct for an immaterial error identified by management and disclosed in our Quarterly Report on Form 10-Q for the period ended September 30, 2016. Previously reported expense associated with this matter was decreased by $5.3 million for the period from July 1, 2016 through September 12, 2016. Our Predecessor net income for the period from July 1, 2016 through September 12, 2016 increased by an identical amount and our net income per basic and diluted share increased by $0.06 and $0.05 . The Predecessor net income and earnings per share measures were unchanged for the period from January 1, 2016 through September 12, 2016. Going Concern Presumption Our unaudited Condensed Consolidated Financial Statements for the Successor periods have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business.
Fair Value Measurements	We apply the authoritative accounting provisions for measuring the fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date.
Fair Value, Measurements, Recurring
Schedule of Policies [Line Items]
Fair Value Measurements	We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below: • Commodity derivatives : We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for WTI crude oil and NYMEX Henry Hub gas closing prices as of the end of the reporting periods. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. Each of these is a level 2 input.
Fair Value, Measurements, Nonrecurring
Schedule of Policies [Line Items]
Fair Value Measurements	Non-Recurring Fair Value Measurements In addition to the fair value measurements applied with respect to the Acquisition, as described in Note 3, the most significant non-recurring fair value measurements utilized in the preparation of our Condensed Consolidated Financial Statements are those attributable to the initial determination of AROs associated with the ongoing development of new oil and gas properties. The determination of the fair value of AROs is based upon regional market and facility specific information. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these significant fair value inputs are typically not observable, we have categorized the initial estimates as level 3 inputs. In addition, we utilize non-recurring fair value measurements with respect to the recognition and measurement of asset impairments, particularly during our Predecessor periods during which time we applied the successful efforts method to our oil and gas properties. The factors used to determine fair value for purposes of recognizing and measuring asset impairments while we applied the successful efforts method to our oil and gas properties during our Predecessor periods included, but were not limited to, estimates of proved and risk-adjusted probable reserves, future commodity prices, indicative sales prices for properties, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Because these significant fair value inputs were typically not observable, we have categorized the amounts as level 3 inputs. Under the full cost method, which we have applied since the Emergence Date, we apply a ceiling test determination utilizing prescribed procedures. The full cost method is substantially different from the successful efforts method which relies upon fair value measurements.

Acquisitions (Tables)

Acquisitions (Tables)	9 Months Ended
	Sep. 30, 2017
Business Acquisition [Line Items]
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	Acquisitions Eagle Ford Acquisition On July 30, 2017, we entered into a purchase and sale agreement (the “Purchase Agreement”) with Devon Energy Corporation (“Devon”) to acquire all of Devon’s right, title and interest in and to certain oil and gas assets (the “Devon Properties”), including oil and gas leases covering approximately 19,600 net acres located primarily in Lavaca County, Texas for aggregate consideration of $205.0 million in cash, subject to customary purchase price adjustments (the “Acquisition”). Upon execution of the Purchase Agreement, we deposited $10.3 million as earnest money into an escrow account (the “Escrow Account”). The Acquisition has an effective date of March 1, 2017 (the “Effective Date”) and closed on September 29, 2017 (the “Date of Acquisition”), at which time we paid cash consideration of $189.9 million and $7.1 million was released from the Escrow Account to Devon. On the Date of Acquisition we also identified and applied $3.2 million of preliminary purchase price adjustments to net working capital items attributable to the period from the Effective Date through the Date of Acquisition (the “Post-Effective Period”). The $3.2 million remaining in the Escrow Account as of September 30, 2017, which is included as a component of noncurrent “Other assets” on our Condensed Consolidated Balance Sheet, is attributable to certain properties for which title defects have been identified. To the extent that Devon is successful in curing these title defects, funds will be transferred from the Escrow Account to Devon and we will reclassify corresponding amounts from Other assets to Property and equipment, net on our Condensed Consolidated Balance Sheet. On November 1, 2017, we acquired additional working interests in the Devon Properties for $0.7 million from parties that had tag-along rights to sell their interests under the Purchase Agreement. The Acquisition was financed with the net proceeds received from borrowings under a new $200 million second lien credit agreement (the “Second Lien Facility”) (see Note 8 for terms of the Second Lien Facility) and incremental borrowings under our credit agreement (the “Credit Facility”). We incurred $1.5 million of transaction costs associated with the Acquisition, including advisory, legal, due diligence and other professional fees. These costs have been recognized as a component of our “General and administrative” expenses. We accounted for the Acquisition by applying the acquisition method of accounting as of the Date of Acquisition. In accordance with the Purchase Agreement, the Acquisition is deemed to have occurred on September 30, 2017. Accordingly, no production, revenues and expenses attributable to the Devon Properties have been included in our results of operations for the periods ended September 30, 2017. The initial accounting for the Acquisition as presented below is based upon preliminary information available to us and was not complete as of the date our Condensed Consolidated Financial Statements were issued. The final purchase price will be subject to additional post-closing adjustments for the Post-Effective Period to be identified by Devon and agreed to by us in a final settlement. The following table represents the preliminary fair values assigned to the net assets acquired as of the Date of Acquisition and the consideration transferred: Assets Oil and gas properties - proved $ 42,795 Oil and gas properties - unproved 142,817 Other property and equipment 8,642 Liabilities Asset retirement obligations (“AROs”) 491 Net assets acquired $ 193,763 Cash consideration paid to Devon on the Date of Acquisition $ 189,911 Amount transferred to Devon from the Escrow Account 7,049 Application of working capital adjustments, net (3,197 ) Preliminary purchase price $ 193,763 The fair values of the oil and gas properties acquired were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) future cash flows and (v) a market-based weighted-average cost of capital. The fair value of the other property and equipment acquired was measured primarily with reference to replacement costs for similar assets adjusted for the age and normal use of the underlying assets. Because many of these inputs are not observable, we have classified the initial fair value estimates as Level 3 inputs as that term is defined in GAAP. The following table presents unaudited summary pro forma financial information for the periods presented assuming the Acquisition and the related entry into the Second Lien Facility occurred as of January 1, 2017. The pro forma financial information does not purport to represent what our actual results of operations would have been if the Acquisition and the entry into the Second Lien Facility had occurred as of this date, or the results of operations for any future periods. We have excluded any pro forma presentations for the Predecessor periods as they are not comparable. Three Months Nine Months Ended Ended September 30, September 30, 2017 2017 Total revenues $ 41,865 $ 130,504 Net income (loss) attributable to common shareholders $ (8,657 ) $ 38,947 Net income (loss) per share - basic $ (0.58 ) $ 2.60 Net income (loss) per share - diluted $ (0.58 ) $ 2.58
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	The following table represents the preliminary fair values assigned to the net assets acquired as of the Date of Acquisition and the consideration transferred: Assets Oil and gas properties - proved $ 42,795 Oil and gas properties - unproved 142,817 Other property and equipment 8,642 Liabilities Asset retirement obligations (“AROs”) 491 Net assets acquired $ 193,763 Cash consideration paid to Devon on the Date of Acquisition $ 189,911 Amount transferred to Devon from the Escrow Account 7,049 Application of working capital adjustments, net (3,197 ) Preliminary purchase price $ 193,763
Business Acquisition, Pro Forma Information [Table Text Block]	The following table presents unaudited summary pro forma financial information for the periods presented assuming the Acquisition and the related entry into the Second Lien Facility occurred as of January 1, 2017. The pro forma financial information does not purport to represent what our actual results of operations would have been if the Acquisition and the entry into the Second Lien Facility had occurred as of this date, or the results of operations for any future periods. We have excluded any pro forma presentations for the Predecessor periods as they are not comparable. Three Months Nine Months Ended Ended September 30, September 30, 2017 2017 Total revenues $ 41,865 $ 130,504 Net income (loss) attributable to common shareholders $ (8,657 ) $ 38,947 Net income (loss) per share - basic $ (0.58 ) $ 2.60 Net income (loss) per share - diluted $ (0.58 ) $ 2.58

Accounts Receivable and Major27

Accounts Receivable and Major Customers (Tables)	9 Months Ended
	Sep. 30, 2017
Receivables [Abstract]
Summary of Accounts Receivable	The following table summarizes our accounts receivable by type as of the dates presented: September 30, December 31, 2017 2016 Customers $ 30,852 $ 20,489 Joint interest partners 18,938 7,238 Other 668 3,789 50,458 31,516 Less: Allowance for doubtful accounts (2,362 ) (2,421 ) $ 48,096 $ 29,095

Derivative Instruments (Tables)

Derivative Instruments (Tables)	9 Months Ended
	Sep. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivative Positions	The following table sets forth our commodity derivative positions, presented on a net basis by period of maturity, as of September 30, 2017 : Average Weighted Volume Per Average Fair Value Instrument Day Price Asset Liability Crude Oil: (barrels) ($/barrel) Fourth quarter 2017 Swaps 4,381 $ 48.59 $ — $ 1,361 First quarter 2018 Swaps/Put option 1 8,513 $ 47.98 — 2,427 Second quarter 2018 Swaps/Put option 1 8,484 $ 47.98 — 1,971 Third quarter 2018 Swaps/Put option 1 8,455 $ 47.98 — 1,563 Fourth quarter 2018 Swaps/Put option 1 8,455 $ 47.98 — 1,251 First quarter 2019 Swaps 2,946 $ 49.87 — 356 Second quarter 2019 Swaps 2,921 $ 49.87 — 307 Third quarter 2019 Swaps 2,897 $ 49.87 — 258 Fourth quarter 2019 Swaps 2,898 $ 49.87 — 231 Settlements to be paid in subsequent period 172
Impact of Derivative Activities on Condensed Consolidated Statements of Income	The impact of our derivative activities on income is included in “Derivatives” in our Condensed Consolidated Statements of Operations. The following table summarizes the effects of our derivative activities for the periods presented: Successor Predecessor Three Months Ended Period from September 13, 2016 Period from July 1, 2016 September 30, 2017 Through September 30, 2106 Through September 12, 2016 Derivative gains (losses) $ (12,275 ) $ (4,369 ) $ 8,934 Successor Predecessor Nine Months Ended Period from September 13, 2016 Period from January 1, 2016 September 30, 2017 Through September 30, 2106 Through September 12, 2016 Derivative gains (losses) $ 15,802 $ (4,369 ) $ (8,333 )
Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets	The following table summarizes the fair values of our derivative instruments presented on a gross basis, as well as the locations of these instruments on our Condensed Consolidated Balance Sheets as of the dates presented: September 30, 2017 December 31, 2016 Derivative Derivative Derivative Derivative Type Balance Sheet Location Assets Liabilities Assets Liabilities Commodity contracts Derivative assets/liabilities – current $ 6,140 $ 13,634 $ — $ 12,932 Commodity contracts Derivative assets/liabilities – noncurrent 2,520 4,923 — 14,437 $ 8,660 $ 18,557 $ — $ 27,369

Property and Equipment (Tables)

Property and Equipment (Tables)	9 Months Ended
	Sep. 30, 2017
Property, Plant and Equipment [Abstract]
Summary of Property and Equipment	The following table summarizes our property and equipment as of the dates presented: September 30, December 31, 2017 2016 Oil and gas properties: Proved $ 369,384 $ 251,083 Unproved 147,594 4,719 Total oil and gas properties 516,978 255,802 Other property and equipment 12,484 3,575 Total properties and equipment 529,462 259,377 Accumulated depreciation, depletion and amortization (43,402 ) (11,904 ) $ 486,060 $ 247,473

Long-Term Debt Long-Term Debt (

Long-Term Debt Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2017
Debt Instrument [Line Items]
Schedule of Long-term Debt Instruments [Table Text Block]	The following table summarizes our debt obligations as of the dates presented: September 30, 2017 December 31, 2016 Principal Unamortized Discount and Deferred Issuance Costs 1 Principal Unamortized Discount and Deferred Issuance Costs Credit facility 2 $ 57,000 $ 25,000 Second lien term loans 200,000 $ 11,945 — $ — Totals 257,000 $ 11,945 25,000 $ — Less: Unamortized discount (4,000 ) — Less: Unamortized deferred issuance costs (7,945 ) — Long-term debt, net $ 245,055 $ 25,000

Additional Balance Sheet Deta31

Additional Balance Sheet Detail (Tables)	9 Months Ended
	Sep. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Components of Selected Balance Sheet Accounts	The following table summarizes components of selected balance sheet accounts as of the dates presented: September 30, December 31, 2017 2016 Other current assets: Tubular inventory and well materials $ 2,297 $ 2,125 Prepaid expenses 818 903 $ 3,115 $ 3,028 Other assets: Deferred issuance costs of the Credit Facility $ 3,130 $ 2,785 Deposit in escrow 1 3,205 — Other 2,488 2,544 $ 8,823 $ 5,329 Accounts payable and accrued liabilities: Trade accounts payable $ 7,275 $ 9,825 Drilling costs 10,620 2,479 Royalties and revenue – related 30,184 26,116 Compensation – related 3,135 2,557 Interest 107 55 Reserve for bankruptcy claims 3,922 3,922 Other 6,993 4,743 $ 62,236 $ 49,697 Other liabilities: Asset retirement obligations $ 3,041 $ 2,459 Defined benefit pension obligations 946 1,025 Postretirement health care benefit obligations 544 488 Other 100 100 $ 4,631 $ 4,072 _______________________ 1 Represents amount remaining in the escrow deposit for the Acquisition (see Note 3).

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following tables summarize the valuation of those assets and (liabilities) as of the dates presented: September 30, 2017 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Assets: Commodity derivative assets – current $ 6,140 $ — $ 6,140 $ — Commodity derivative assets – noncurrent 2,520 — 2,520 — Liabilities: Commodity derivative liabilities – current $ (13,634 ) $ — $ (13,634 ) $ — Commodity derivative liabilities – noncurrent (4,923 ) — (4,923 ) — December 31, 2016 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Liabilities: Commodity derivative liabilities – current $ (12,932 ) $ — $ (12,932 ) $ — Commodity derivative liabilities – noncurrent (14,437 ) — (14,437 ) —

Shareholders' Equity (Tables)

Shareholders' Equity (Tables)	9 Months Ended
	Sep. 30, 2017
Equity [Abstract]
Schedule of Stockholders Equity	The following tables summarize the components of our shareholders ’ equity and the changes therein as of and for nine months ended September 30, 2017 : December 31, All Other September 30, 2016 Net Income Changes 1 2017 Common stock $ 150 $ — $ — $ 150 Paid-in capital 190,621 — 2,751 193,372 Retained earnings (accumulated deficit) (5,296 ) 43,463 — 38,167 Accumulated other comprehensive income 73 — — 73 $ 185,548 $ 43,463 $ 2,751 $ 231,762 _______________________ 1 Includes equity-classified share-based compensation of $ 2.7 million and $ 0.1 million from the receipt in May 2017 of proceeds attributable to the rights offering in 2016 that had been held in escrow, net of costs to register our common stock. During the nine months ended September 30, 2017 , 12,252 shares of common stock were issued in connection with the vesting of certain time-vested restricted stock units (“RSUs“ ), net of shares withheld for income taxes.

Share-Based Compensation (Table

Share-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of Share-Based Compensation Expense	Successor Predecessor Period From Period From Nine Months Ended September 13, 2016 Through January 1, 2016 Through September 30, 2017 September 30, 2016 September 12, 2016 Equity-classified awards $ 2,707 $ — $ 1,511 Liability-classified awards — — (19 ) $ 2,707 $ — $ 1,492 The following table summarizes our share-based compensation expense (benefit) recognized for the periods presented: Successor Predecessor Period From Period From Three Months Ended September 13, 2016 Through July 1, 2016 Through September 30, 2017 September 30, 2016 September 12, 2016 Equity-classified awards 1 $ 1,013 $ — $ 147 Liability-classified awards — — — $ 1,013 $ — $ 147 _______________________ 1 Amounts for the period from July 1, 2016 through September 12, 2016 periods have been recasted (see Note 2).

Interest Expense (Tables)

Interest Expense (Tables)	9 Months Ended
	Sep. 30, 2017
Banking and Thrift [Abstract]
Interest Expense Net Disclosure	Successor Predecessor Nine Months Ended Period From September 13, 2016 Period From January 1, 2016 September 30, 2017 Through September 30, 2016 Through September 12, 2016 Interest on borrowings and related fees 1 $ 1,784 $ 180 $ 36,013 Amortization of debt issuance costs 2 1,362 38 22,188 Capitalized interest (132 ) — (183 ) $ 3,014 $ 218 $ 58,018
Debt Instrument [Line Items]
Interest Expense	The following table summarizes the components of interest expense for the periods presented: Successor Predecessor Three Months Ended Period From September 13, 2016 Period From July 1, 2016 September 30, 2017 Through September 30, 2016 Through September 12, 2016 Interest on borrowings and related fees 1 $ 879 $ 180 $ 1,363 Amortization of debt issuance costs 2 374 38 — Capitalized interest (51 ) — — $ 1,202 $ 218 $ 1,363 ___________________ 1 Absent the bankruptcy proceedings and the corresponding suspension of the accrual of interest on unsecured debt, we would have recorded total contractual interest expense of $ 19.3 million for the period from July 1, 2016 through September 12, 2016, including $ 4.4 million and $ 13.4 million attributable to the 7.25% Senior Notes due 2019 (“2019 Senior Notes”) and the 8.5% Senior Notes due 2020 (“2020 Senior Notes”). 2 The three months ended September 30, 2017 includes a $0.2 million write-off attributable to a change in the composition of financial institutions comprising the Credit Facility’s bank group in connection with the Third Amendment (see Note 8). Successor Predecessor Nine Months Ended Period From September 13, 2016 Period From January 1, 2016 September 30, 2017 Through September 30, 2016 Through September 12, 2016 Interest on borrowings and related fees 1 $ 1,784 $ 180 $ 36,013 Amortization of debt issuance costs 2 1,362 38 22,188 Capitalized interest (132 ) — (183 ) $ 3,014 $ 218 $ 58,018 Successor Predecessor Nine Months Ended Period From September 13, 2016 Period From January 1, 2016 September 30, 2017 Through September 30, 2016 Through September 12, 2016 Interest on borrowings and related fees 1 $ 1,784 $ 180 $ 36,013 Amortization of debt issuance costs 2 1,362 38 22,188 Capitalized interest (132 ) — (183 ) $ 3,014 $ 218 $ 58,018 ___________________ 1 Absent the bankruptcy proceedings and the corresponding suspension of the accrual of interest on unsecured debt, we would have recorded total contractual interest expense of $ 66.1 million for the period from January 1, 2016 through September 12, 2016, including $ 15.3 million and $ 46.3 million attributable to the 2019 Senior Notes and the 2020 Senior Notes, respectively. 2 The nine months ended September 30, 2017 includes a total of $0.8 million of write-offs attributable to changes in the composition of financial institutions comprising the Credit Facility’s bank group in connection with amendments to the Credit Facility (see Note 8). The period from January 1, 2016 through September 12, 2016 includes $20.5 million related to the accelerated write-off of unamortized debt issuance costs associated with the RBL and Senior Notes.

Earnings per Share (Tables)

Earnings per Share (Tables)	9 Months Ended
	Sep. 30, 2017
Earnings Per Share [Abstract]
Components of Calculation of Basic and Diluted Earnings Per Share	Successor Predecessor Predecessor Nine Months Ended Period From September 13, 2016 Period From January 1, 2016 September 30, 2017 Through September 30, 2016 Through September 12, 2016 Net income (loss) $ 43,463 $ (3,441 ) $ 1,054,602 Less: Preferred stock dividends 1 — — (5,972 ) Net income (loss) attributable to common shareholders – basic and diluted $ 43,463 $ (3,441 ) $ 1,048,630 Weighted-average shares – basic 14,993 14,992 88,013 Effect of dilutive securities 2 69 — 36,074 Weighted-average shares – diluted 15,062 14,992 124,087 _______________________ 1 Dividends attributable to our Series A 6% Convertible Perpetual Preferred Stock and Series B 6% Convertible Perpetual Preferred Stock (together, the “Series A and B Preferred Stock”) were excluded from the computation of diluted loss per share for the period from January 1, 2016 through September 12, 2016, as their assumed conversion would have been anti-dilutive. 2 The number of dilutive securities for the three and nine months ended September 30, 2017 , which is attributable to RSUs and PRSUs, was determined under the “treasury stock” method. The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings (loss) per share for the periods presented: Successor Predecessor Three Months Ended Period From September 13, 2016 Period From July 1, 2016 September 30, 2017 Through September 30, 2016 Through September 12, 2016 Net income (loss) $ (5,947 ) $ (3,441 ) $ 1,155,341 Less: Preferred stock dividends — — — Net income (loss) attributable to common shareholders – basic and diluted $ (5,947 ) $ (3,441 ) $ 1,155,341 Weighted-average shares – basic 14,994 14,992 89,292 Effect of dilutive securities 1 — — 22,166 Weighted-average shares – diluted 14,994 14,992 111,458 _______________________ 1 The number of dilutive securities for the three months ended September 30, 2017 , which is attributable to RSUs and PRSUs, was determined under the “treasury stock” method. For the three months ended September 30, 2017 , approximately 0.1 million of potentially dilutive securities attributable to RSUs had the effect of being anti-dilutive and were excluded from the calculation of diluted loss per common share. Successor Predecessor Predecessor Nine Months Ended Period From September 13, 2016 Period From January 1, 2016 September 30, 2017 Through September 30, 2016 Through September 12, 2016 Net income (loss) $ 43,463 $ (3,441 ) $ 1,054,602 Less: Preferred stock dividends 1 — — (5,972 ) Net income (loss) attributable to common shareholders – basic and diluted $ 43,463 $ (3,441 ) $ 1,048,630 Weighted-average shares – basic 14,993 14,992 88,013 Effect of dilutive securities 2 69 — 36,074 Weighted-average shares – diluted 15,062 14,992 124,087 _______________________ 1 Dividends attributable to our Series A 6% Convertible Perpetual Preferred Stock and Series B 6% Convertible Perpetual Preferred Stock (together, the “Series A and B Preferred Stock”) were excluded from the computation of diluted loss per share for the period from January 1, 2016 through September 12, 2016, as their assumed conversion would have been anti-dilutive. 2 The number of dilutive securities for the three and nine months ended September 30, 2017 , which is attributable to RSUs and PRSUs, was determined under the “treasury stock” method.

Nature of Operations Nature of

Nature of Operations Nature of Operations (Details)	9 Months Ended
	Sep. 30, 2017
Concentration Risk [Line Items]
Production Decrease	5000.00%
TEXAS | Eagle Ford Shale
Concentration Risk [Line Items]
Concentration risk, percentage (more than)	90.00%

Basis of Presentation (Details)

Basis of Presentation (Details) - $ / shares	1 Months Ended	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Immaterial Error Correction			5.3
Successor [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Basic (in dollars per share)	$ (0.23)	$ (0.40)		$ 2.90
Diluted (in dollars per share)	$ (0.23)	$ (0.40)		$ 2.89
Increase in Diluted and Basic Earnings Per Share [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Basic (in dollars per share)			$ 0.06
Increase in Diluted Earnings Per Share [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Basic (in dollars per share)			$ 0.05

Acquisitions (Details)

Acquisitions (Details) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017USD ($)$ / shares		Sep. 30, 2017USD ($)$ / shares		Nov. 01, 2017USD ($)	Sep. 29, 2017USD ($)a	Dec. 31, 2016USD ($)
Business Acquisition [Line Items]
Earnest Money Deposits	$ 3,205	[1]	$ 3,205	[1]			$ 0
Business Acquisition, Pro Forma Revenue	41,865		130,504
Capitalized Costs, Proved Properties	1,600		1,600
Property, Plant and Equipment, Gross	529,462		529,462				259,377
Asset Retirement Obligation	3,000		3,000
Amount Transferred from Escrow Account						$ 7,100
Business Acquisition, Pro Forma Income (Loss) from Continuing Operations, Net of Tax	$ (8,657)		$ 38,947
Business Acquisition, Pro Forma Earnings Per Share, Basic | $ / shares	$ (580)		$ 2,600
Business Acquisition, Pro Forma Earnings Per Share, Diluted | $ / shares	$ (580)		$ 2,580
Second Lien Facility	$ 200,000		$ 200,000				$ 0
Devon Acquisition [Member]
Business Acquisition [Line Items]
Acreage, Net | a						19,600
Other Payments to Acquire Businesses			$ 205,000
Escrow Deposit						$ 10,300
Earnest Money Deposits						3,200
Capitalized Costs, Proved Properties						42,795
Capitalized Costs, Unproved Properties						142,817
Property, Plant and Equipment, Gross						8,642
Asset Retirement Obligation						491
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net						193,763
Cash Paid on Date of Acquisition						189,911
Amount Transferred from Escrow Account						7,049
Working Capital Adjustments, Net						(3,197)
Preliminary Purchase Price						193,763
Business Acquisition, Transaction Costs						$ 1,500
Subsequent Event [Member] | Devon Acquisition [Member]
Business Acquisition [Line Items]
Additional working interests					$ 700
[1]	1 Represents amount remaining in the escrow deposit for the Acquisition (see Note 3).

Bankruptcy Proceeding Bankrup40

Bankruptcy Proceeding Bankruptcy Proceeding (Details) $ in Thousands	May 12, 2016subsidiary	Sep. 30, 2017USD ($)	Dec. 31, 2016USD ($)
Reorganizations [Abstract]
Number of Subsidiaries Filing Chapter 11 Bankruptcy | subsidiary	8
Bankruptcy Claims, amount reserved for outstanding claims | $		$ 3,922	$ 3,922

Summary of Accounts Receivable

Summary of Accounts Receivable (Detail) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Receivables [Abstract]
Customers	$ 30,852	$ 20,489
Joint interest partners	18,938	7,238
Other	668	3,789
Accounts Receivable, Gross, Current, Total	50,458	31,516
Less: Allowance for doubtful accounts	(2,362)	(2,421)
Accounts receivable, net of allowance for doubtful accounts	$ 48,096	$ 29,095

Accounts Receivable and Major42

Accounts Receivable and Major Customers - Additional Information (Detail) $ in Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2017USD ($)Customer	Sep. 30, 2016USD ($)Customer	Dec. 31, 2016USD ($)
Sales Revenue | Customer Concentration Risk
Accounts, Notes, Loans and Financing Receivable [Line Items]
Number of major customers | Customer	2	3
Revenues, major customers	$ 85.9	$ 93.5
Concentration risk, percentage	82.00%	94.00%
Sales Revenue | Customer Concentration Risk | Major Customer 1
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers	$ 72.6	$ 64.1
Concentration risk, percentage	69.00%	64.00%
Sales Revenue | Customer Concentration Risk | Major Customer 2
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers	$ 13.3	$ 15.8
Concentration risk, percentage	13.00%	16.00%
Sales Revenue | Customer Concentration Risk | Major Customer 3
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers		$ 13.6
Concentration risk, percentage		14.00%
Accounts Receivable | Credit Concentration Risk
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration risk, percentage	47.00%		81.00%
Accounts receivable, major customers	$ 14.6		$ 16.7

Derivative Instruments - Additi

Derivative Instruments - Additional Information (Detail) $ in Thousands	8 Months Ended	9 Months Ended
	Sep. 12, 2016USD ($)	Sep. 30, 2017USD ($)Entity$ / bblbbl	Sep. 30, 2016USD ($)	Oct. 04, 2017bbl$ / bbl	Dec. 31, 2016USD ($)
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | bbl		4,000
Derivative, Price Risk Option Strike Price		55
Derivative assets | $		$ 18,557			$ 27,369
Derivative, Price Risk Option, Premium, Minimum		8
Derivative, Price Risk Option, Premium, Maximum		9.50
Commodity contracts
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative assets | $		$ 8,700
Number of derivative counterparties | Entity		3
Commodity contracts | Crude Oil
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Third-party quoted forward prices		West Texas Intermediate (“WTI”) crude oil
Commodity contracts | Natural Gas
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Third-party quoted forward prices		(“NYMEX”) Henry Hub gas
Predecessor [Member]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivatives settled to reduce outstanding debt | $	$ 51,979		$ 52,000
Predecessor [Member] | March 2016 [Domain]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivatives Settled | $			$ 63,000
Subsequent Event [Member] | Converted 2018 [Member] | Crude Oil
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Swap Type, Average Fixed Price				49
Notional Volume, per day | bbl				1,000
Subsequent Event [Member] | Converted 2018 [Member] | Louisiana Light Sweet [Member]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Swap Type, Average Fixed Price				50.83
Notional Volume, per day | bbl				1,000
Subsequent Event [Member] | Converted 2019 [Member] | Louisiana Light Sweet [Member]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Swap Type, Average Fixed Price				50.86
Notional Volume, per day | bbl				2,000
Subsequent Event [Member] | 2018 [Member] | Crude Oil
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Swap Type, Average Fixed Price				49.30
Notional Volume, per day | bbl				5,477
Subsequent Event [Member] | 2018 [Member] | Louisiana Light Sweet [Member]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Swap Type, Average Fixed Price				51.97
Notional Volume, per day | bbl				1,500
Subsequent Event [Member] | 2019 [Member] | Crude Oil
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Swap Type, Average Fixed Price				49.87
Notional Volume, per day | bbl				2,915
Subsequent Event [Member] | 2019 [Member] | Louisiana Light Sweet [Member]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Swap Type, Average Fixed Price				51.30
Notional Volume, per day | bbl				2,500
Subsequent Event [Member] | 2020 [Member] | Crude Oil
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Swap Type, Average Fixed Price				50.35
Notional Volume, per day | bbl				1,000
Subsequent Event [Member] | Remainder of 2017 [Member] | Crude Oil
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Swap Type, Average Fixed Price				48.59
Notional Volume, per day | bbl				4,381
Subsequent Event [Member] | Remainder of 2017 [Member] | Louisiana Light Sweet [Member]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Swap Type, Average Fixed Price				56.18
Notional Volume, per day | bbl				663

Commodity Derivative Positions

Commodity Derivative Positions (Detail) $ in Thousands	9 Months Ended
	Sep. 30, 2017USD ($)bbl$ / bbl	Dec. 31, 2016USD ($)
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative Liability	$ 18,557	$ 27,369
Settlement Agreement [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Fair Value Asset
Fair Value Liability	$ 172
Crude Oil | Fourth Quarter 2017 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	4,381
Derivative, Swap Type, Average Fixed Price | $ / bbl	48.59
Fair Value Asset	$ 0
Fair Value Liability	$ 1,361
Crude Oil | First Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps/Put option 1
Notional Volume, per day | bbl	8,513
Derivative, Swap Type, Average Fixed Price | $ / bbl	47.98
Fair Value Asset	$ 0
Fair Value Liability	$ 2,427
Crude Oil | Second Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps/Put option 1
Notional Volume, per day | bbl	8,484
Derivative, Swap Type, Average Fixed Price | $ / bbl	47.98
Fair Value Asset	$ 0
Fair Value Liability	$ 1,971
Crude Oil | Third Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps/Put option 1
Notional Volume, per day | bbl	8,455
Derivative, Swap Type, Average Fixed Price | $ / bbl	47.98
Fair Value Asset	$ 0
Fair Value Liability	$ 1,563
Crude Oil | Fourth Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps/Put option 1
Notional Volume, per day | bbl	8,455
Derivative, Swap Type, Average Fixed Price | $ / bbl	47.98
Fair Value Asset	$ 0
Fair Value Liability	$ 1,251
Crude Oil | First Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	2,946
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.87
Fair Value Asset	$ 0
Fair Value Liability	$ 356
Crude Oil | Second Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	2,921
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.87
Fair Value Asset	$ 0
Fair Value Liability	$ 307
Crude Oil | Third Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	2,897
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.87
Fair Value Asset	$ 0
Fair Value Liability	$ 258
Crude Oil | Fourth Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	2,898
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.87
Fair Value Asset	$ 0
Fair Value Liability	$ 231

Impact of Derivative Activities

Impact of Derivative Activities on Condensed Consolidated Statements of Income (Detail) - USD ($) $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended	8 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 12, 2016	Sep. 30, 2017	Sep. 12, 2016	Sep. 30, 2017
Successor [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives	$ (4,369)		$ (12,275)		$ 15,802
Predecessor [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives		$ 8,934		$ (8,333)

Fair Value of Derivative Instru

Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative assets, current	$ 6,140	$ 0
Derivative Asset, Noncurrent	2,520	0
Derivative assets	8,660	0
Commodity derivative liabilities – current	13,634	12,932
Derivative Liability, Noncurrent	4,923	14,437
Derivative Liability	18,557	27,369
Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative Liability	8,700
Commodity contracts | Derivative assets/liabilities - current
Derivatives, Fair Value [Line Items]
Derivative assets, current	6,140	0
Commodity derivative liabilities – current	13,634	12,932
Commodity contracts | Noncurrent Derivative Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Noncurrent	2,520	0
Derivative Liability, Noncurrent	$ 4,923	$ 14,437

Summary of Property and Equipme

Summary of Property and Equipment (Detail) $ in Thousands	9 Months Ended
	Sep. 30, 2017USD ($)$ / bbl	Dec. 31, 2016USD ($)	Sep. 30, 2016$ / bbl	Sep. 12, 2016$ / bbl
Property, Plant and Equipment [Abstract]
Proved Oil and Gas Property, Full Cost Method	$ 369,384	$ 251,083
Unproved Oil and Gas Property, Full Cost Method	147,594	4,719
Oil and Gas Property, Full Cost Method, Gross	516,978	255,802
Other property and equipment	12,484	3,575
Total properties and equipment	529,462	259,377
Accumulated depreciation, depletion and amortization	(43,402)	(11,904)
Property and equipment, net (successful efforts method)	486,060	247,473
Unproved Oil and Gas Property excluded	147,600	$ 4,700
Undeveloped Leasehold Costs Transferred	1,900
Capitalized Costs, Proved Properties	1,600
Interest Costs Capitalized	$ 100
Successor [Member]
Property, Plant and Equipment [Line Items]
Amortization Expense Per Physical Unit of Production | $ / bbl	11.93		11.09
Predecessor [Member]
Property, Plant and Equipment [Line Items]
Amortization Expense Per Physical Unit of Production | $ / bbl				10.04

Summary of Long-Term Debt (Deta

Summary of Long-Term Debt (Detail) - USD ($)		Sep. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 200,000,000
Revolving credit facility	[1]	57,000,000	$ 25,000,000
Second Lien Facility		200,000,000	0
Unamortized Loan Commitment and Origination Fees and Unamortized Discounts or Premiums		11,945,000	0
Debt Instrument, Unamortized Discount		(4,000,000)	0
Unamortized Debt Issuance Expense		(7,945,000)	0
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net		245,055,000	25,000,000
Long-term Debt		257,000,000	$ 25,000,000
Revolving Credit Facility
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 237,500,000
[1]	2 Issuance costs of the Credit Facility, which represent costs attributable to the access to credit over it’s contractual term, have been presented as a component of Other assets (see Note 11) and are being amortized over the term of the Credit Facility using the straight-line method.

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail) - USD ($)		9 Months Ended
		Sep. 30, 2017	Dec. 31, 2016
Debt Disclosure [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 200,000,000
Debt Issuance Costs, Line of Credit Arrangements, Gross		1,700,000
Write off of Deferred Debt Issuance Cost		800,000
Long-term Line of Credit	[1]	$ 57,000,000	$ 25,000,000
Debt Instrument, Discounted Percentage		98.00%
Interest Coverage Ratio, Maximum		3
Current Ratio		1
Second Lien Facility		$ 200,000,000	0
Proceeds from Debt, Net of Issuance Costs		188,100,000
Debt Instrument, Unamortized Discount		4,000,000	0
Unamortized Debt Issuance Expense		$ 7,945,000	0
Year 2 [Member]
Debt Disclosure [Line Items]
Prepayment Premium		102.00%
Prepayment Premium, Change in Control		102.00%
Year 3 [Member]
Debt Disclosure [Line Items]
Prepayment Premium		101.00%
Prepayment Premium, Change in Control		101.00%
Revolving Credit Facility
Debt Disclosure [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 237,500,000
Interest Rate at Period End		4.4163%
Revolving Credit Facility | Future Period [Member]
Debt Disclosure [Line Items]
Debt To E B I T D Ratio Maximum		4
Revolving Credit Facility | Future Period Two [Member]
Debt Disclosure [Line Items]
Debt To E B I T D Ratio Maximum		3.75
Revolving Credit Facility | Future Period Three [Member]
Debt Disclosure [Line Items]
Debt To E B I T D Ratio Maximum		3.50
Letter of Credit
Debt Disclosure [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.50%
Line of Credit [Member]
Debt Disclosure [Line Items]
Letters of Credit Outstanding, Amount		$ 800,000	$ 800,000
Line of Credit [Member] | Letter of Credit
Debt Disclosure [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 5,000,000
Second Lien Facility [Member]
Debt Disclosure [Line Items]
Interest rate option one, applicable margin rate over Adjusted LIBOR		7.00%
Interest rate option two, applicable margin rate		6.00%
Second Lien Facility, Initial Interest Rate		8.34%
Second Lien Facility, Effective Interest Rate		9.86%
Minimum [Member] | Revolving Credit Facility
Debt Disclosure [Line Items]
Interest rate option one, applicable margin rate over Adjusted LIBOR		2.00%
Interest rate option two, applicable margin rate		3.00%
Maximum [Member] | Revolving Credit Facility
Debt Disclosure [Line Items]
Interest rate option one, applicable margin rate over Adjusted LIBOR		3.00%
Interest rate option two, applicable margin rate		4.00%
Interest Payable One [Member] | Revolving Credit Facility
Debt Disclosure [Line Items]
Debt Instrument, Interest Payable Period		1 month
Interest Payable Two [Member] | Revolving Credit Facility
Debt Disclosure [Line Items]
Debt Instrument, Interest Payable Period		3 months
Interest Payable Three [Member] | Revolving Credit Facility
Debt Disclosure [Line Items]
Debt Instrument, Interest Payable Period		6 months
[1]	2 Issuance costs of the Credit Facility, which represent costs attributable to the access to credit over it’s contractual term, have been presented as a component of Other assets (see Note 11) and are being amortized over the term of the Credit Facility using the straight-line method.

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Blended tax rate (as a percent)	35.52%
Federal statutory income tax rate (as a percent)	35.00%
Income taxes refund received (less than)		$ 0.1

Exit Activities (Detail)

Exit Activities (Detail) $ in Thousands	1 Months Ended	8 Months Ended	9 Months Ended		12 Months Ended
	Sep. 30, 2016USD ($)	Sep. 12, 2016USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Dec. 31, 2016
Predecessor [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Number of Positions Eliminated					53
Severance and Termination Benefits			$ 1,900	$ 2,000
Liabilities Subject to Compromise, Early Contract Termination Fees	$ 1,300			1,300
Payments for Restructuring				1,100
Restructuring Reserve, Accretion of Obligation		$ 317		$ 300
Successor [Member]
Restructuring Cost and Reserve [Line Items]
Severance and Termination Adjustment			100
Restructuring Reserve, Accretion of Obligation	$ 0		$ 0

Components of Selected Balance

Components of Selected Balance Sheet Accounts (Detail) - USD ($) $ in Thousands	Sep. 30, 2017		Dec. 31, 2016
Other current assets:
Tubular inventory and well materials	$ 2,297		$ 2,125
Prepaid expenses	818		903
Other Assets, Current	3,115		3,028
Other assets:
Deferred issuance costs of the Revolver	3,130		2,785
Earnest Money Deposits	3,205	[1]	0
Other	2,488		2,544
Other assets	8,823		5,329
Accounts payable and accrued liabilities:
Trade accounts payable	7,275		9,825
Drilling costs	10,620		2,479
Royalties and revenue – related	30,184		26,116
Compensation – related	3,135		2,557
Interest	107		55
Reserve for bankruptcy claims	3,922		3,922
Other	6,993		4,743
Accounts payable and accrued liabilities	62,236		49,697
Other liabilities:
Asset retirement obligations	3,041		2,459
Defined benefit pension obligations	946		1,025
Postretirement health care benefit obligations	544		488
Other	100		100
Other liabilities	$ 4,631		$ 4,072
[1]	1 Represents amount remaining in the escrow deposit for the Acquisition (see Note 3).

Assets and Liabilities Measured

Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Assets:
Derivative Asset, Current	$ 6,140	$ 0
Derivative Asset, Noncurrent	2,520	0
Liabilities:
Commodity derivative liabilities – current	13,634	12,932
Derivative Liability, Noncurrent	4,923	14,437
Fair Value, Measurements, Recurring | Commodity contracts
Assets:
Derivative Asset, Current	6,140
Derivative Asset, Noncurrent	2,520
Liabilities:
Commodity derivative liabilities – current	13,634	12,932
Derivative Liability, Noncurrent	4,923	14,437
Fair Value, Measurements, Recurring | Commodity contracts | Level 1
Assets:
Derivative Asset, Current	0
Derivative Asset, Noncurrent	0
Liabilities:
Commodity derivative liabilities – current	0	0
Derivative Liability, Noncurrent	0	0
Fair Value, Measurements, Recurring | Commodity contracts | Level 2
Assets:
Derivative Asset, Current	6,140
Derivative Asset, Noncurrent	2,520
Liabilities:
Commodity derivative liabilities – current	13,634	12,932
Derivative Liability, Noncurrent	4,923	14,437
Fair Value, Measurements, Recurring | Commodity contracts | Level 3
Assets:
Derivative Asset, Current	0
Derivative Asset, Noncurrent	0
Liabilities:
Commodity derivative liabilities – current	0	0
Derivative Liability, Noncurrent	$ 0	$ 0

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)bbl
Commitments and Contingencies Disclosure [Line Items]
Long-term Purchase Commitment, Minimum Volume Required | bbl	8,000
Marketing Agreement	10
Asset Retirement Obligation	$ 3
Legal Reserve
Commitments and Contingencies Disclosure [Line Items]
Reserve established for contingency matters	0.1
Crude Oil Gathering And Transportation Services
Commitments and Contingencies Disclosure [Line Items]
Contractual obligation, balance of 2017	2.5
Contractual Obligation, Due in 2018	10.4
Contractual Obligation, Due in 2019	11.7
Contractual Obligation, Due 2020 through 2025	13
Contractual Obligation, Due 2026	7.4
Contractual Obligation, Due 2027 through 2030	3.8
Contractual Obligation, Due 2031	2.2
Contract Drilling [Member]
Commitments and Contingencies Disclosure [Line Items]
Contractual Obligation	$ 6.9

Shareholders' Equity Rollforwar

Shareholders' Equity Rollforward (Details) - USD ($) $ in Thousands		9 Months Ended
		Sep. 30, 2017
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance		$ 185,548
Net income (loss)		43,463
All Other Changes		2,751
As of ending balance		231,762
Share-based compensation		2,700
Proceeds Attributable to Rights Offering		100
Common stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance		150
As of ending balance		150
Paid-in capital
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance		190,621
All Other Changes	[1]	2,751
As of ending balance		193,372
Retained earnings (accumulated deficit)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance		(5,296)
Net income (loss)		43,463
As of ending balance		38,167
Accumulated other comprehensive income
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance		73
As of ending balance		$ 73
Time Vested Restricted Stock Units [Domain]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares, Issued		12,252
[1]	Includes equity-classified share-based compensation of $2.7 million and $0.1 million from the receipt in May 2017 of proceeds attributable to the rights offering in 2016 that had been held in escrow, net of costs to register our common stock

Summary of Share-Based Compensa

Summary of Share-Based Compensation Expense (Detail) $ / shares in Units, $ in Thousands	1 Months Ended		2 Months Ended		3 Months Ended	8 Months Ended	9 Months Ended
	Jan. 31, 2017trancheshares	Sep. 30, 2016USD ($)	Sep. 12, 2016USD ($)		Sep. 30, 2017USD ($)shares	Sep. 12, 2016USD ($)	Sep. 30, 2017USD ($)$ / sharesshares
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based compensation (equity-classified)							$ (2,700)
Time Vested Restricted Stock Units [Domain]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | shares					298,454		298,454
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares							$ 48.70
Share-based Compensation Arrangements By Share-based Payment Award, Award Amortization Period							5 years
Performance Restricted Stock Units [Domain]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | shares	98,526
Share-based Compensation Arrangements By Share-based Payment Award, Award Amortization Period	5 years
Share-based Compensation Arrangements By Share-based Payment Award, Performance Period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate, Minimum							1.44%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate, Maximum							1.51%
Performance Restricted Stock Units [Domain] | Minimum [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award							0.5963
Share-based Compensation Arrangements By Share-based Payment Award, Number Of Award Tranches | tranche	2
Share-based Compensation Arrangement by Share-based Payment Award, Shares, Expected to Vest, Percentage	0.00%
Performance Restricted Stock Units [Domain] | Maximum [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award							0.6218
Share-based Compensation Arrangements By Share-based Payment Award, Number Of Award Tranches | tranche	3
Share-based Compensation Arrangement by Share-based Payment Award, Shares, Expected to Vest, Percentage	200.00%
Performance Restricted Stock Units [Domain] | Year 1 [Domain] | Minimum [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares							$ 47.70
Performance Restricted Stock Units [Domain] | Share-based Compensation Award, Tranche Two [Member] | Maximum [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares							$ 65.28
Time Vested Restricted Stock Units - Employees [Domain] [Domain]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | shares					190,891		190,891
Employees and Directors [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | shares					749,600		749,600
Predecessor [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Other Stock Based Compensation Expense			$ 147	[1]		$ 1,511
Share-based compensation (equity-classified)						(1,511)
Allocated Share-based Compensation Expense			147			1,492
Defined Contribution Plan, Cost						400
Predecessor [Member] | Other Pension, Postretirement and Supplemental Plans [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)						100
Predecessor [Member] | Liability-classified awards
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based compensation (equity-classified)			$ 0			$ 19
Successor [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Other Stock Based Compensation Expense		$ 0			$ 1,013		$ 2,707
Share-based compensation (equity-classified)		0					(2,707)
Allocated Share-based Compensation Expense		0			1,013		2,707
Defined Contribution Plan, Cost		100					300
Successor [Member] | Other Pension, Postretirement and Supplemental Plans [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)		100					100
Successor [Member] | Liability-classified awards
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based compensation (equity-classified)		$ 0			$ 0		$ 0
[1]	1 Amounts for the period from July 1, 2016 through September 12, 2016 periods have been recasted (see Note 2).

Interest Expense Components of

Interest Expense Components of Interest Expense (Details) - USD ($) $ in Thousands	1 Months Ended	2 Months Ended		3 Months Ended		6 Months Ended		8 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 12, 2016		Sep. 30, 2017		Jun. 30, 2017	Jun. 30, 2016	Sep. 12, 2016		Sep. 30, 2017
Components of Interest Expense [Line Items]
Write off of Deferred Debt Issuance Cost										$ 800
Successor [Member]
Components of Interest Expense [Line Items]
Interest Expense, Borrowings	$ 180			$ 879	[1]					1,784	[2]
Amortization of Debt Issuance Costs	38			374						1,362
Interest Paid, Capitalized	0			(51)						(132)
Interest Expense	$ 218			1,202						$ 3,014
Write off of Deferred Debt Issuance Cost				$ 200		$ 800
Predecessor [Member]
Components of Interest Expense [Line Items]
Interest Expense, Borrowings		$ 1,363	[3]					$ 36,013	[4]
Amortization of Debt Issuance Costs		0						22,188
Interest Paid, Capitalized		0						(183)
Interest Expense		1,363						58,018
Contractual Interest Expense on Prepetition Liabilities Not Recognized in Statement of Operations		19,300						66,100
Debtor Reorganization Items, Write-off of Debt Issuance Costs and Debt Discounts							$ 20,500
Senior Notes Due 2019 [Domain] | Predecessor [Member]
Components of Interest Expense [Line Items]
Contractual Interest Expense on Prepetition Liabilities Not Recognized in Statement of Operations		4,400						46,300
Senior Notes Due 2020 [Domain] | Predecessor [Member]
Components of Interest Expense [Line Items]
Contractual Interest Expense on Prepetition Liabilities Not Recognized in Statement of Operations		$ 13,400						$ 15,300
[1]	2 The three months ended September 30, 2017 includes a $0.2 million write-off attributable to a change in the composition of financial institutions comprising the Credit Facility’s bank group in connection with the Third Amendment (see Note 8).
[2]	2 The nine months ended September 30, 2017 includes a total of $0.8 million of write-offs attributable to changes in the composition of financial institutions comprising the Credit Facility’s bank group in connection with amendments to the Credit Facility (see Note 8). The period from January 1, 2016 through September 12, 2016 includes $20.5 million related to the accelerated write-off of unamortized debt issuance costs associated with the RBL and Senior Notes.
[3]	1 Absent the bankruptcy proceedings and the corresponding suspension of the accrual of interest on unsecured debt, we would have recorded total contractual interest expense of $19.3 million for the period from July 1, 2016 through September 12, 2016, including $4.4 million and $13.4 million attributable to the 7.25% Senior Notes due 2019 (“2019 Senior Notes”) and the 8.5% Senior Notes due 2020 (“2020 Senior Notes”).
[4]	1 Absent the bankruptcy proceedings and the corresponding suspension of the accrual of interest on unsecured debt, we would have recorded total contractual interest expense of $66.1 million for the period from January 1, 2016 through September 12, 2016, including $15.3 million and $46.3 million attributable to the 2019 Senior Notes and the 2020 Senior Notes, respectively.

Components of Calculation of Ba

Components of Calculation of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended		8 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 12, 2016	Sep. 30, 2017		Sep. 12, 2016		Sep. 30, 2017
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income (loss)							$ 43,463
Successor [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount			55,000
Net income (loss)	$ (3,441)		$ (5,947)				43,463
Net loss attributable to common shareholders, Diluted	$ (3,441)		$ (5,947)				$ 43,463
Weighted-average shares – basic	14,992,000		14,994,000				14,993,000
Effect of dilutive securities	0		0	[1]			69,000	[2]
Weighted-average shares – diluted	14,992,000		14,994,000				15,062,000
Preferred Stock Dividends and Other Adjustments	$ 0		$ 0				$ 0
Net Income (Loss) Available to Common Stockholders, Basic	$ (3,441)		$ (5,947)				$ 43,463
Predecessor [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income (loss)		$ 1,155,341			$ 1,054,602
Net loss attributable to common shareholders, Diluted		$ 1,155,341			$ 1,048,630
Weighted-average shares – basic		89,292,000			88,013,000
Effect of dilutive securities		22,166,000			36,074,000
Weighted-average shares – diluted		111,458,000			124,087,000
Preferred Stock Dividends and Other Adjustments		$ 0			$ (5,972)	[3]
Net Income (Loss) Available to Common Stockholders, Basic		$ 1,155,341			$ 1,048,630
Predecessor [Member] | Series A Preferred Stock
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Perpetual Preferred Stock, dividend rate (as a percent)					6.00%
Predecessor [Member] | Series B Preferred Stock
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Perpetual Preferred Stock, dividend rate (as a percent)					6.00%
[1]	The number of dilutive securities for the three months ended September 30, 2017, which is attributable to RSUs and PRSUs, was determined under the “treasury stock” method. For the three months ended September 30, 2017, approximately 0.1 million of potentially dilutive securities attributable to RSUs had the effect of being anti-dilutive and were excluded from the calculation of diluted loss per common share.
[2]	2 The number of dilutive securities for the three and nine months ended September 30, 2017, which is attributable to RSUs and PRSUs, was determined under the “treasury stock” method.
[3]	1 Dividends attributable to our Series A 6% Convertible Perpetual Preferred Stock and Series B 6% Convertible Perpetual Preferred Stock (together, the “Series A and B Preferred Stock”) were excluded from the computation of diluted loss per share for the period from January 1, 2016 through September 12, 2016, as their assumed conversion would have been anti-dilutive.