Ranger Oil (ROCC) 10-Q 8 Aug 18 2018 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Aug. 03, 2018
Document Documentand Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q2
Trading Symbol	PVAC
Entity Registrant Name	PENN VIRGINIA CORP
Entity Central Index Key	77,159
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		15,058,480

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenues
Gain on sales of assets, net	$ 4	$ (134)	$ 79	$ (69)
Total revenues	111,580	36,282	188,791	71,268
Operating expenses
Lease operating	8,730	5,370	16,026	10,286
Production and ad valorem taxes	5,795	2,119	9,887	4,098
General and administrative	5,322	3,702	11,793	7,809
Depreciation, depletion and amortization	31,273	11,076	53,354	20,886
Total operating expenses	55,694	24,822	98,993	48,185
Operating income (loss)	55,886	11,460	89,798	23,083
Other income (expense)
Interest expense	(6,150)	(1,274)	(10,751)	(1,812)
Derivatives	(52,241)	11,061	(71,036)	28,077
Other, net	(16)	82	(74)	62
Income (loss) before income taxes	(2,521)	21,329	7,937	49,410
Income tax benefit (expense)	0	0	(163)	0
Net income (loss)	(2,521)	21,329	7,774	49,410
Net income (loss) attributable to common shareholders	$ (2,521)	$ 21,329	$ 7,774	$ 49,410
Net income (loss) per share:
Basic (in dollars per share)	$ (0.17)	$ 1.42	$ 0.52	$ 3.30
Diluted (in dollars per share)	$ (0.17)	$ 1.42	$ 0.51	$ 3.27
Weighted average shares outstanding – basic (in shares)	15,058	14,992	15,050	14,992
Weighted average shares outstanding – diluted (in shares)	15,058	15,050	15,171	15,097
Oil and Gas, Exploration and Production [Member]
Revenue from External Customer [Line Items]
Crude oil	$ 101,716	$ 32,351	$ 172,974	$ 62,424
Revenues
Revenue from Contract with Customer, Including Assessed Tax	101,716	32,351	172,974	62,424
Oil and Condensate [Member]
Revenue from External Customer [Line Items]
Crude oil	5,533	2,043	8,479	4,345
Revenues
Revenue from Contract with Customer, Including Assessed Tax	5,533	2,043	8,479	4,345
Natural Gas, Production [Member]
Revenue from External Customer [Line Items]
Crude oil	3,912	1,880	6,702	4,223
Revenues
Revenue from Contract with Customer, Including Assessed Tax	3,912	1,880	6,702	4,223
Product and Service, Other [Member]
Revenue from External Customer [Line Items]
Crude oil	415	142	557	345
Revenues
Revenue from Contract with Customer, Including Assessed Tax	415	142	557	345
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Operating expenses
Cost of Goods and Services Sold	$ 4,574	$ 2,555	$ 7,933	$ 5,106

CONDENSED CONSOLIDATED STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (2,521)	$ 21,329	$ 7,774	$ 49,410
Other comprehensive loss:
Change in pension and postretirement obligations, net of tax of $0 and $0 in 2016	0	0	0	0
Total Other Comprehensive Income (Loss), Net of Tax	0	0	0	0
Comprehensive income (loss)	$ (2,521)	$ 21,329	$ 7,774	$ 49,410

CONDENSED CONSOLIDATED STATEME4

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Statement of Comprehensive Income [Abstract]
Change in pension and postretirement obligations, net of tax	$ 0	$ 0	$ 0	$ 0

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 11,521	$ 11,017
Accounts receivable, net of allowance for doubtful accounts	71,572	69,821
Derivative assets	33	0
Other current assets	5,194	6,250
Total current assets	88,320	87,088
Property and equipment, net (full cost method)	791,624	529,059
Derivative assets	54	0
Deferred Tax Assets, Net	4,780	4,943
Other assets	2,956	8,507
Total assets	887,734	629,597
Current liabilities
Accounts payable and accrued liabilities	127,982	96,181
Derivative liabilities	63,257	27,777
Total current liabilities	191,239	123,958
Other liabilities	5,493	4,833
Derivative liabilities	29,566	13,900
Long-term debt, net	432,824	265,267
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; 15,058,480 and 15,018,870 shares issued as of June 30, 2018 and December 31, 2017, respectively	151	150
Paid-in capital	195,980	194,123
Retained earnings	32,481	27,366
Accumulated other comprehensive income	0	0
Total shareholders’ equity	228,612	221,639
Total liabilities and shareholders’ equity	$ 887,734	$ 629,597

CONDENSED CONSOLIDATED BALANCE6

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Jun. 30, 2018	Dec. 31, 2017
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	15,058,480	15,018,870
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	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Cash flows from operating activities
Net income (loss)	$ 7,774	$ 49,410
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	53,354	20,886
Derivative contracts:
Net (gains) losses	71,036	(28,077)
Cash settlements, net	(19,977)	(2,458)
Deferred income tax expense	163	0
(Gain) loss on sales of assets, net	(79)	69
Non-cash interest expense	1,644	988
Share-based compensation (equity-classified)	2,451	1,694
Other, net	26	38
Changes in operating assets and liabilities, net	4,026	(6,533)
Net cash provided by operating activities	120,418	36,017
Cash flows from investing activities
Acquisitions, net	(86,835)	0
Capital expenditures	(201,350)	(43,583)
Proceeds from sales of assets, net	2,525	0
Net cash used in investing activities	(285,660)	(43,583)
Cash flows from financing activities
Proceeds from credit facility borrowings	166,500	14,000
Repayment of credit facility borrowings	0	(2,000)
Debt issuance costs paid	(754)	(1,090)
Proceeds received from rights offering, net	0	55
Other, net	0	(55)
Net cash provided by financing activities	165,746	10,910
Net increase in cash and cash equivalents	504	3,344
Cash and cash equivalents – beginning of period	11,017	6,761
Cash and cash equivalents – end of period	11,521	10,105
Cash paid for:
Interest, net of amounts capitalized	8,953	795
Reorganization items, net	442	901
Non-cash investing and financing activities:
Changes in accounts receivable related to acquisitions	(26,631)	0
Changes in other assets related to acquisitions	(2,469)	0
Changes in accrued liabilities related to acquisitions	(15,099)	0
Changes in accrued liabilities related to capital expenditures	12,231	2,322
Changes in other liabilities for asset retirement obligations related to acquisitions	$ 382	$ 0

Nature of Operations

Nature of Operations	6 Months Ended
	Jun. 30, 2018
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 Gonzales, Lavaca and DeWitt Counties in South Texas.

Basis of Presentation

Basis of Presentation	6 Months Ended
	Jun. 30, 2018
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, 2017 . Operating results for the six months ended June 30, 2018 , are not necessarily indicative of the results that may be expected for the year ending December 31, 2018 . Reclassifications We have reclassified certain amounts included within “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet as of December 31, 2017, as disclosed in Note 11, in order to conform to the current period presentation. Adoption of Recently Issued Accounting Pronouncements Effective January 1, 2018, we adopted and began applying the relevant guidance provided in Accounting Standards Update (“ASU”) 2017–07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017–07”). ASU 2017–07 requires employers to disaggregate the service cost component from the other components of net periodic 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 periodic 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 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 there are interest and other costs associated with the legacy obligations. As required, ASU 2017–07 has been applied retrospectively to periods prior to 2018. Accordingly, the entirety of the expense associated with these plans, which was less than $ 0.1 million , has been included as a component of the “Other income (expense)” caption in our Condensed Consolidated Statement of Operations for each of the three and six months ended June 30, 2017 . Prior to 2018, all costs associated with these plans were included in the “General and administrative” (“G&A”) expenses caption. Effective January 1, 2018, we adopted and began applying the relevant guidance provided in ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”) and related amendments to GAAP which, together with ASU 2014–09, represent Accounting Standards Codification (“ASC”) Topic 606, Revenues from Contracts with Customers (“ASC Topic 606”). We adopted ASC Topic 606 using the cumulative effect transition method (see Note 5 for the impact and disclosures associated with the adoption of ASC Topic 606. Recently Issued Accounting Pronouncements Pending Adoption In June 2016, the Financial Accounting Standards Board (“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. Together with recent related amendments to GAAP, ASU 2016–02 represents ASC Topic 842, Leases (“ASC Topic 842”) which supersedes all current GAAP with respect to leases. 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. ASC Topic 842 also will require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ASC Topic 842 is January 1, 2019, with early adoption permitted. ASC Topic 842 will be applicable to our existing leases for office facilities and certain office equipment, vehicles and certain field equipment, land easements and similar arrangements for rights-of-way, and potentially to certain drilling rig and completion contracts with terms in excess of 12 months, to the extent we may have such contracts in the future. In addition, we believe that our crude oil and natural gas gathering commitment arrangements, as described in Note 13, include provisions that could be construed as leases. Our crude oil and natural gas gathering arrangements are fairly complex and include, among other provisions, multiple elements and term lengths, certain volumetric-based minimums and varying degrees of optionality available to both us and the service providers. Furthermore, these arrangements have certain material payment terms that are variable in nature which, depending upon the outcome of our analysis and resulting conclusions, could have a significant impact on the amounts recognized as right of use assets and corresponding lease liabilities. We anticipate that the adoption of ASC Topic 842 may significantly increase our total assets and liabilities. Accordingly, we are continuing to evaluate the effect that ASC Topic 842 will have on our Consolidated Financial Statements and related disclosures. We plan to adopt ASC Topic 842 on the effective date in 2019 using the optional transition method and will recognize a cumulative-effect adjustment to the opening balance of retained earnings. We are also continuing to monitor developments regarding ASC Topic 842 that are unique to our industry. Going Concern Presumption Our unaudited Condensed Consolidated Financial Statements 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, with the exception of the divestiture of our Mid-Continent oil and gas properties as described in Note 3, no subsequent events have occurred that would require recognition in our Condensed Consolidated Financial Statements or disclosure in the Notes thereto.

Acquisitions and Divestitures

Acquisitions and Divestitures	6 Months Ended
	Jun. 30, 2018
Acquisitions [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures Acquisitions Hunt Acquisition In December 2017, we entered into a purchase and sale agreement with Hunt Oil Company (“Hunt”) to acquire certain oil and gas assets in the Eagle Ford Shale, primarily in Gonzales County, Texas for $ 86.0 million in cash, subject to adjustments (the “Hunt Acquisition”). The Hunt Acquisition had an effective date of October 1, 2017, and closed on March 1, 2018, at which time we paid cash consideration of $ 84.4 million . In connection with the Hunt Acquisition, we also acquired working interests in certain wells that we previously drilled as operator in which Hunt had rights to participate prior to the transaction closing. Accumulated costs, net of suspended revenues for these wells was $ 13.8 million , which we have reflected as a component of the total net assets acquired. We funded the Hunt Acquisition with borrowings under our credit agreement (the “Credit Facility”). The Hunt Acquisition expanded our net leasehold position by approximately 9,700 net acres, substantially all of which is held by production, in the northwestern portion of our Eagle Ford acreage. The final settlement of the Hunt Acquisition occurred in July 2018, at which time an additional $ 0.2 million of acquisition costs was allocated from certain working capital components and Hunt transferred $ 1.4 million to us primarily for suspended revenues attributable to the acquired properties. We incurred a total of $ 0.5 million of transaction costs for legal, due diligence and other professional fees associated with the Hunt Acquisition, including $ 0.1 million in 2017 and $ 0.4 million in the first quarter of 2018. These costs have been recognized as a component of our G&A expenses. We accounted for the Hunt Acquisition by applying the acquisition method of accounting as of March 1, 2018. The following table represents the final fair values assigned to the net assets acquired and the total acquisition cost incurred, including consideration transferred to Hunt: Assets Oil and gas properties - proved $ 82,443 Oil and gas properties - unproved 16,339 Liabilities Asset retirement obligations 356 Net assets acquired $ 98,426 Cash consideration paid to Hunt $ 84,403 Application of working capital adjustments 245 Accumulated costs, net of suspended revenues, for wells in which Hunt had rights to participate 13,778 Total acquisition costs incurred $ 98,426 Devon Acquisition In July 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 million in cash (the “Devon Acquisition”). Upon execution of the Purchase Agreement, we deposited $10.3 million as earnest money into an escrow account (the “Escrow Account”). The Devon Acquisition had an effective date of March 1, 2017, and closed on September 29, 2017, at which time we paid cash consideration of $189.9 million and $7.1 million was released from the Escrow Account to Devon. In November 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. As of December 31, 2017, $3.2 million remained in the Escrow Account, which was included as a component of noncurrent “Other assets” on our Condensed Consolidated Balance Sheet. The final settlements of the Devon Acquisition together with the tag-along rights acquisition, occurred in February 2018, at which time $ 2.5 million in cash was transferred from the Escrow Account to Devon, and the remaining $ 0.7 million was distributed to us. In addition, Devon transferred $ 0.4 million to us for suspended revenues attributable to the acquired properties. The Devon Acquisition was financed with the net proceeds received from borrowings under the $200 million Second Lien Credit Agreement dated as of September 29, 2017 (the “Second Lien Facility”) (see Note 8 for terms of the Second Lien Facility) and incremental borrowings under the Credit Facility. We incurred a total of $1.0 million of transaction costs in 2017 associated with the Devon Acquisition, including advisory, legal, due diligence and other professional fees. These costs have been recognized as a component of our G&A expenses. We accounted for the Devon Acquisition by applying the acquisition method of accounting as of September 29, 2017. The following table represents the final fair values assigned to the net assets acquired and the total consideration transferred: Assets Oil and gas properties - proved $ 42,866 Oil and gas properties - unproved 146,686 Other property and equipment 8,642 Liabilities Revenue suspense 355 Asset retirement obligations 494 Net assets acquired $ 197,345 Cash consideration paid to Devon and tag-along parties, net $ 190,277 Amount transferred to Devon from the Escrow Account 9,519 Application of working capital adjustments, net (2,451 ) Total consideration transferred $ 197,345 Valuation of Acquisitions The fair values of the oil and gas properties acquired in the Hunt and Devon Acquisitions 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, (v) the timing of our development plans and (vi) 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. Impact of Acquisitions on Actual and Pro Forma Results of Operations The results of operations attributable to the Hunt Acquisition and Devon Acquisition have been included in our Consolidated Financial Statements for the periods after March 1, 2018 and after September 29, 2017, respectively. The Hunt Acquisition provided revenues and estimated earnings (including revenues less operating expenses and excluding allocations of interest expense and income taxes) of approximately $ 0.4 million and $ 0.2 million , respectively, for the period from March 1, 2018 through March 31, 2018. As the properties and working interests acquired in connection with the Hunt and Devon Acquisitions are included within our existing Eagle Ford acreage, it is not practical or meaningful to disclose revenues and earnings unique to those assets for periods beyond those during which they were acquired, as they were fully integrated into our regional operations soon after their acquisition. The following table presents unaudited summary pro forma financial information for the three and six months ended June 30, 2018 and 2017, assuming the Hunt and Devon Acquisitions 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 Hunt and Devon Acquisitions and the entry into the Second Lien Facility had occurred as of this date, or the results of operations for any future periods. Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Total revenues $ 111,580 $ 51,978 $ 194,036 $ 99,699 Net income (loss) $ (2,521 ) $ 22,651 $ 10,868 $ 50,839 Net income (loss) per share - basic $ (0.17 ) $ 1.51 $ 0.72 $ 3.39 Net income (loss) per share - diluted $ (0.17 ) $ 1.51 $ 0.72 $ 3.37 Divestiture s Mid-Continent Divestiture In June 2018, we entered into a purchase and sale agreement with a third party to sell all of our remaining Mid-Continent oil and gas properties, located primarily in Oklahoma in the Granite Wash, for $ 6.0 million in cash, subject to customary adjustments. Upon the signing of the purchase and sale agreement, the buyer paid us a deposit in the amount of $ 0.7 million . The deposit has been reflected as a component of “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet. The sale has an effective date of March 1, 2018 and closed on July 31, 2018, at which time we received proceeds of $ 5.5 million . The sale proceeds and de-recognition of certain assets and liabilities will be recorded as a reduction of our net oil and gas properties. A final settlement is scheduled to occur in the fourth quarter of 2018. The properties have asset retirement obligations (“AROs”) of $ 0.3 million . We also had a net working capital deficit attributable to the oil and gas properties of $ 1.1 million as of June 30, 2018. The net pre-tax operating income attributable to the Mid-Continent assets was $ 0.6 million and $ 0.3 million for the three months ended June 30, 2018 and 2017, and $ 1.4 million and $ 0.6 million for the six months ended June 30, 2018 and 2017, respectively. Sales of Undeveloped Acreage, Rights and Other Assets In February 2018, we sold our undeveloped acreage holdings in the Tuscaloosa Marine Shale in Louisiana that were scheduled to expire in 2019. In March 2018, we sold certain undeveloped deep leasehold rights in Oklahoma, and in May 2018, we sold certain pipeline assets in our former Marcellus Shale operating region. We received a combined total of $ 1.7 million for these leasehold and other assets which were applied as a reduction of our net oil and gas properties.

Bankruptcy Proceedings and Emer

Bankruptcy Proceedings and Emergence Bankruptcy Proceedings and Emergence	6 Months Ended
	Jun. 30, 2018
Reorganizations [Abstract]
Bankruptcy Proceedings and Emergence	Bankruptcy Proceedings and Emergence On May 12, 2016, 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 Bankruptcy Court confirmed our Second Amended Joint Chapter 11 Plan of Reorganization of Penn Virginia Corporation and its Debtor Affiliates, and we subsequently emerged from bankruptcy on September 12, 2016 (the “Emergence Date”). Effective January 17, 2018, the Bankruptcy Court closed the eight cases attributable to our subsidiaries, leaving the aforementioned lead case open pending the entry of a final decree or order by the Bankruptcy Court. 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 August 3, 2018, certain claims were still in the process of resolution. While most of these matters are unsecured claims for which shares of our common stock have been allocated, certain of these matters must be settled with cash payments. As of June 30, 2018 , 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 Revenue

Accounts Receivable and Revenues from Contracts with Customers	6 Months Ended
	Jun. 30, 2018
Receivables [Abstract]
Accounts Receivable and Revenues from Contracts with Customers	Accounts Receivable and Revenues from Contracts with Customers Accounts Receivable and Major Customers The following table summarizes our accounts receivable by type as of the dates presented: June 30, December 31, 2018 2017 Customers $ 55,736 $ 39,106 Joint interest partners 17,834 32,493 Other 364 584 73,934 72,183 Less: Allowance for doubtful accounts (2,362 ) (2,362 ) $ 71,572 $ 69,821 For the six months ended June 30, 2018 , three customers accounted for $157.8 million , or approximately 84% , of our consolidated product revenues. The revenues generated from these customers during the six months ended June 30, 2018 , were $81.0 million , $41.0 million and $35.8 million , or 43% , 22% and 19% of the consolidated total, respectively. As of June 30, 2018 and December 31, 2017 , $41.9 million and $32.1 million , or approximately 75% and 82% , 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. For the six months ended June 30, 2017 , one customer accounted for $64.6 million , or approximately 91% , of our consolidated product revenues. Revenue from Contracts with Customers Adoption of ASC Topic 606 Effective January 1, 2018, we adopted ASC Topic 606 and have applied the guidance therein to our contacts with customers for the sale of commodity products (crude oil, NGLs and natural gas) as well as marketing services that we provide to our joint venture partners and other third parties. ASC Topic 606 provides for a five-step revenue recognition process model to determine the transfer of goods or services to consumers in an amount that reflects the consideration to which we expect to be entitled in exchange for such goods and services. Upon the adoption of ASC Topic 606, we: (i) changed the presentation of our NGL product revenues from a gross basis to a net basis and changed the classification of certain natural gas processing costs associated with NGLs from a component of “Gathering, processing and transportation” (“GPT”) expense to a reduction of NGL product revenues as described in further detail below, (ii) wrote off $ 2.7 million of accounts receivable arising from natural gas imbalances accounted for under the entitlements method as a direct reduction to our beginning balance of retained earnings as of January 1, 2018, and (iii) adopted the sales method with respect to production imbalance transactions beginning after December 31, 2017. The following table illustrates the impact of the adoption of ASC Topic 606 on our Condensed Consolidated Statement of Operations for the three and six months ended June 30, 2018 : Three Months Ended June 30, 2018 As Determined As Reported Under Increase Under Prior GAAP ASC Topic 606 (Decrease) Revenues Crude oil $ 101,716 $ 101,716 $ — Natural gas liquids $ 6,103 $ 5,533 $ (570 ) Natural gas $ 3,912 $ 3,912 $ — Marketing services (included in Other revenues, net) $ 153 $ 153 $ — Operating expenses Gathering, processing and transportation $ 5,144 $ 4,574 $ (570 ) Net loss $ (2,521 ) $ (2,521 ) $ — Six Months Ended June 30, 2018 As Determined As Reported Under Increase Under Prior GAAP ASC Topic 606 (Decrease) Revenues Crude oil $ 172,974 $ 172,974 $ — Natural gas liquids $ 9,495 $ 8,479 $ (1,016 ) Natural gas $ 6,702 $ 6,702 $ — Marketing services (included in Other revenues, net) $ 245 $ 245 $ — Operating expenses Gathering, processing and transportation $ 8,949 $ 7,933 $ (1,016 ) Net income $ 7,774 $ 7,774 $ — Accounting Policies for Revenue Recognition and Associated Costs Crude oil . We sell our crude oil production to our customers at either the wellhead or a contractually agreed-upon delivery point, including certain regional central delivery point terminals or pipeline inter-connections. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality, location differentials and, if applicable, deductions for intermediate transportation. Costs incurred by us for gathering and transporting the products to an agreed-upon delivery point are recognized as a component of GPT expense. NGLs . We have natural gas processing contracts in place with certain midstream processing vendors. We deliver “wet” natural gas to our midstream processing vendors at the inlet of their processing facilities through gathering lines, certain of which we own and others which are owned by gathering service providers. Subsequent to processing, NGLs are delivered or otherwise transported to a third-party customer. Depending upon the nature of the contractual arrangements with the midstream processing vendors, particularly those attributable to the marketing of the NGL products, we recognize revenue for NGL products on either a gross or net basis. For those contracts where we have determined that we are the principal, and the ultimate third party is our customer, we recognize revenue on a gross basis, with associated processing costs presented as GPT expenses. For those contracts where we have determined that we are the agent and the midstream processing vendor is our customer, we recognize NGL product revenues based on a net basis with processing costs presented as a reduction of revenue. Based on an analysis of all of our existing natural gas processing contracts, we have determined that, as of January 1, 2018, and through June 30, 2018 , we are the agent and our midstream processing vendors are our customers with respect to all of our NGL product sales. Natural gas . Subsequent to the aforementioned processing of “wet” natural gas and the separation of NGL products, the “dry” or residue gas is delivered to us at the tailgate of the midstream processing vendors’ facilities and we market the product to our customers, most of whom are interstate pipelines. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality and location differentials, as applicable. Costs incurred by us for gathering and transportation from the wellhead through the processing facilities are recognized as a component of GPT expenses. Marketing services . We provide marketing services to certain of our joint venture partners and other third parties with respect to oil and gas production for which we are the operator. Pricing for such services represents a negotiated fixed rate fee based on the sales price of the underlying oil and gas products. Production attributable to joint venture partners from wells that we operate that are not subject to marketing agreements are delivered in kind. Marketing revenue is recognized simultaneously with the sale of our commodity production to our customers. Direct costs associated with our marketing efforts are included in G&A expenses. Transaction Prices, Contract Balances and Performance Obligations Substantially all of our commodity product sales are short-term in nature with contract terms of one year or less. Accordingly, we have applied the practical expedient included in ASC Topic 606, which provides for an exemption from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Under our commodity product sales contracts, we bill our customers and recognize revenue when our performance obligations have been satisfied as described above. At that time, we have determined that payment is unconditional. Accordingly, our commodity sales contracts do not create contract assets or liabilities as those terms are defined in ASC Topic 606. We record revenue in the month that our oil and gas production is delivered to our customers. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production, particularly from properties that are operated by our joint venture partners. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized.

Derivative Instruments

Derivative Instruments	6 Months Ended
	Jun. 30, 2018
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 to be acceptable credit risks, to hedge against the variability in cash flows associated with anticipated sales of our future production. 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”) 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 are currently unhedged with respect to NGL and natural gas production. The following table sets forth our commodity derivative positions, presented on a net basis by period of maturity, as of June 30, 2018 : Average Weighted Volume Per Average Fair Value Instrument Day Price Asset Liability Crude Oil: (barrels) ($/barrel) Third quarter 2018 Swaps-WTI 10,455 $ 57.05 $ — $ 14,270 Third quarter 2018 Swaps-LLS 6,000 $ 65.27 — 5,605 Fourth quarter 2018 Swaps-WTI 10,455 $ 57.05 — 11,332 Fourth quarter 2018 Swaps-LLS 6,000 $ 65.27 — 4,418 First quarter 2019 Swaps-WTI 6,446 $ 54.46 — 6,999 First quarter 2019 Swaps-LLS 5,000 $ 59.17 — 5,310 Second quarter 2019 Swaps-WTI 6,421 $ 54.48 — 6,115 Second quarter 2019 Swaps-LLS 5,000 $ 59.17 — 4,568 Third quarter 2019 Swaps-WTI 6,397 $ 54.50 — 5,337 Third quarter 2019 Swaps-LLS 5,000 $ 59.17 — 3,876 Fourth quarter 2019 Swaps-WTI 6,398 $ 54.50 — 4,635 Fourth quarter 2019 Swaps-LLS 5,000 $ 59.17 — 3,221 First quarter 2020 Swaps-WTI 6,000 $ 54.09 — 3,846 Second quarter 2020 Swaps-WTI 6,000 $ 54.09 — 3,302 Third quarter 2020 Swaps-WTI 6,000 $ 54.09 — 2,844 Fourth quarter 2020 Swaps-WTI 6,000 $ 54.09 — 2,451 Settlements to be paid in subsequent period 4,607 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: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Derivative gains (losses) $ (52,241 ) $ 11,061 $ (71,036 ) $ 28,077 The effects of derivative gains and (losses) and cash settlements are reported as adjustments to reconcile net income 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: June 30, 2018 December 31, 2017 Derivative Derivative Derivative Derivative Type Balance Sheet Location Assets Liabilities Assets Liabilities Commodity contracts Derivative assets/liabilities – current $ 33 $ 63,257 $ — $ 27,777 Commodity contracts Derivative assets/liabilities – noncurrent 54 29,566 — 13,900 $ 87 $ 92,823 $ — $ 41,677 As of June 30, 2018 , we reported net commodity derivative liabilities of $92.7 million . The contracts associated with this position are with eight 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	6 Months Ended
	Jun. 30, 2018
Property, Plant and Equipment [Abstract]
Property and Equipment	Property and Equipment The following table summarizes our property and equipment as of the dates presented: June 30, December 31, 2018 2017 Oil and gas properties: Proved $ 756,863 $ 460,029 Unproved 134,943 117,634 Total oil and gas properties 891,806 577,663 Other property and equipment 16,105 12,712 Total properties and equipment 907,911 590,375 Accumulated depreciation, depletion and amortization (116,287 ) (61,316 ) $ 791,624 $ 529,059 Unproved property costs of $ 134.9 million and $ 117.6 million have been excluded from amortization as of June 30, 2018 and December 31, 2017 , respectively. We transferred $ 5.6 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 six months ended June 30, 2018 . We capitalized internal costs of $ 1.6 million and $1.1 million and interest of $ 4.7 million and less than $0.1 million during the six months ended June 30, 2018 and 2017 , respectively, 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 $15.36 and $11.74 for the six months ended June 30, 2018 and 2017 , respectively.

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt The following table summarizes our debt obligations as of the dates presented: June 30, 2018 December 31, 2017 Principal Unamortized Discount and Deferred Issuance Costs 1, 2 Principal Unamortized Discount and Deferred Issuance Costs 1, 2 Credit facility $ 243,500 $ 77,000 Second lien term loan 200,000 $ 10,676 200,000 $ 11,733 Totals 443,500 $ 10,676 277,000 $ 11,733 Less: Unamortized discount (3,506 ) (3,839 ) Less: Unamortized deferred issuance costs (7,170 ) (7,894 ) Long-term debt, net $ 432,824 $ 265,267 _______________________ 1 Issuance costs of the Credit Facility, which represent costs attributable to the access to credit over its 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. 2 Discount and issuance costs of the Second Lien Facility are being amortized over the term of the underlying loan using the effective-interest method Credit Facility On the Emergence Date, we entered into the Credit Facility. The Credit Facility provides for a $340.0 million revolving commitment and borrowing base and a $5 million sublimit for the issuance of letters of credit. In March 2018, the borrowing base under the Credit Facility was redetermined from $237.5 million to $340.0 million pursuant to the Master Assignment, Agreement and Amendment No. 4 to the Credit Facility (the “Fourth Amendment”). In the six months ended June 30, 2018 , we paid and capitalized issue costs of $ 0.7 million in connection with the Fourth Amendment. 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 redetermined generally 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 April 2018 redetermination was accelerated to March in connection with the Hunt Acquisition. The Credit Facility is available to us 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 June 30, 2018 and December 31, 2017 . 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 June 30, 2018 , the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 5.58% . 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. There are no significant restrictions on our ability 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 of 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 June 30, 2018 , and through the date upon which the Condensed Consolidated Financial Statements were issued, 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 $187.8 million from the Second Lien Facility net of an original issue discount (“OID”) of $4.0 million and issue costs of $8.2 million . The proceeds from the Second Lien Facility were used to fund the Devon 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% . As of June 30, 2018 , the actual interest rate of outstanding borrowings under the Second Lien Facility was 9.10% . 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 9.89% . 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 Guarantor Subsidiaries. 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 June 30, 2018 , and through the date upon which the Consolidated Financial Statements were issued, we were in compliance with all of the covenants under the Second Lien Facility.

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes On December 22, 2017, the U.S. Congress enacted comprehensive tax legislation as part of the budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act (the “TCJA”). The TCJA makes broad and complex changes to the U.S. tax code, including but not limited to, (i) reducing the U.S. federal corporate income tax rate from 35 % to 21 %; (ii) allowing the immediate deduction of certain new investments in lieu of depreciation expense over time; (iii) creating a new limitation on deductible interest expense; (iv) changing rules related to use and limitations of net operating loss (“NOL”) carryforwards created in tax years beginning after December 31, 2017, and (v) repeal of the corporate alternative minimum tax (“AMT”). In connection with our initial analysis of the impact of the TCJA, our Condensed Consolidated Balance Sheet as of December 31, 2017 included a deferred tax asset of $ 4.9 million attributable to our AMT credit carryforwards that were previously fully reserved, but became realizable in connection with the AMT provisions of the TCJA. We continue to analyze the impacts of the TCJA on the Company and refine our estimates during 2018. We recognized a federal and state income tax expense for the six months ended June 30, 2018 at the blended rate of 21.6% ; however, the federal and state tax expense was offset by an adjustment to the valuation allowance against our net deferred tax assets along with an adjustment of $ 0.2 million to the deferred tax asset related to sequestration of a portion of the aforementioned AMT credit carryforward resulting in an effective tax rate of 2.1% . The effect of the adjustment was to reduce our deferred tax asset to $ 4.8 million as of June 30, 2018. We recognized a federal income tax benefit for the six months ended June 30, 2017 at the blended rate of 35.2% 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 had no liability for unrecognized tax benefits as of June 30, 2018 . There were no interest and penalty charges recognized during the periods ended June 30, 2018 and 2017 . Tax years from 2013 forward remain open for examination by the Internal Revenue Service and various state jurisdictions.

Executive Retirement

Executive Retirement	6 Months Ended
	Jun. 30, 2018
Restructuring and Related Activities [Abstract]
Executive Retirement	Executive Retirement Effective February 28, 2018, Mr. Harry Quarls retired from his position as a director and Executive Chairman of the Company. In connection with his retirement, we entered into a separation and consulting agreement (“Separation Agreement”) whereby Mr. Quarls will provide transition and support services to us through December 31, 2018. We paid Mr. Quarls $ 0.3 million for such services and a mutually agreed-upon amount for any services in excess of a minimum level established in the Separation Agreement. The Separation Agreement included a general release of claims and provided for the accelerated vesting of certain share-based compensation awards for which we recognized expense of $ 0.6 million during the six months ended June 30, 2018 (see Note 15). The costs associated with the Separation Agreement, including the share-based compensation charges, are included as a component of G&A expenses in our Condensed Consolidated Statements of Operation.

Additional Balance Sheet Detail

Additional Balance Sheet Detail	6 Months Ended
	Jun. 30, 2018
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: June 30, December 31, 2018 2017 Other current assets: Tubular inventory and well materials $ 3,817 $ 5,146 Prepaid expenses 1,377 1,104 $ 5,194 $ 6,250 Other assets: Deferred issuance costs of the Credit Facility $ 2,923 $ 2,857 Deposit in escrow 1 — 3,210 Other 33 2,440 $ 2,956 $ 8,507 Accounts payable and accrued liabilities: Trade accounts payable $ 34,582 $ 22,579 Drilling costs 34,620 22,389 Royalties and revenue – related 43,862 39,287 Production, ad valorem and other taxes 2 3,827 1,275 Compensation – related 2,802 2,975 Interest 377 223 Reserve for bankruptcy claims 3,940 3,933 Deposit received for divestiture of Mid-Continent properties 3 700 — Other 2 3,272 3,520 $ 127,982 $ 96,181 Other liabilities: Asset retirement obligations $ 3,987 $ 3,286 Defined benefit pension obligations 897 971 Postretirement health care benefit obligations 509 476 Other 100 100 $ 5,493 $ 4,833 _______________________ 1 Represents the amount remaining in the Escrow Account for the Devon Acquisition, which was utilized to fund the remaining liabilities due to Devon for the final settlement in March 2018 (see Note 3). 2 The amount for December 31, 2017 was reclassified from Accounts payable and accrued expenses - Other. 3 Represents the deposit paid to us related to the Mid-Continent divestiture (see Note 3).

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements We apply the authoritative accounting provisions included in GAAP 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 June 30, 2018 , 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: June 30, 2018 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Assets: Commodity derivative assets – current $ 33 $ — $ 33 $ — Commodity derivative assets – noncurrent $ 54 $ — $ 54 $ — Liabilities: Commodity derivative liabilities – current $ (63,257 ) $ — $ (63,257 ) $ — Commodity derivative liabilities – noncurrent $ (29,566 ) $ — $ (29,566 ) $ — December 31, 2017 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Liabilities: Commodity derivative liabilities – current $ (27,777 ) $ — $ (27,777 ) $ — Commodity derivative liabilities – noncurrent $ (13,900 ) $ — $ (13,900 ) $ — 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 six months ended June 30, 2018 and 2017 . 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 and LLS crude oil 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 Hunt and Devon Acquisitions, 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.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Gathering and Intermediate Transportation Commitments We have long-term agreements with Republic Midstream, LLC (“Republic Midstream”) and Republic Midstream Marketing, LLC (“Republic Marketing” and, together with Republic Midstream, collectively, “Republic”) to provide 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 (gross) to Republic, or to 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 gathering and transportation agreement are as follows: $ 5.3 million for the remainder of 2018, $ 11.7 million for 2019, $ 13.0 million per year for 2020 through 2025, $ 7.4 million for 2026, $ 3.8 million per year for 2027 through 2030 and $ 2.2 million for 2031. Drilling, Completion and Other Commitments We have contractual commitments for three drilling rigs as of June 30, 2018 with terms expiring in August 2018, September 2018 and November 2018, respectively. We also have one-year purchase commitments for the utilization of certain frac services and the purchase of certain materials for completion operations. Both the frac services and materials commitments were effective January 1, 2018. We have approximately $ 22.6 million of combined obligations associated with these commitments. In May 2018, we committed to a five-year lease for new corporate office facilities that will begin in August 2018. The minimum lease commitments are as follows: less than $0.1 million for 2018, $0.4 million for 2019, $0.6 million for 2020, $0.6 million for 2021, $0.6 million for 2022 and $0.6 million for 2023. 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 June 30, 2018 , we continue to maintain a $0.1 million reserve for a litigation matter. As of June 30, 2018 , we also had AROs of approximately $4.0 million attributable to the plugging of abandoned wells.

Shareholders' Equity

Shareholders' Equity	6 Months Ended
	Jun. 30, 2018
Equity [Abstract]
Shareholders' Equity	Shareholders’ Equity The following tables summarize the components of our shareholders ’ equity and the changes therein as of and for the six months ended June 30, 2018 : December 31, All Other June 30, 2017 Net Income Changes 1 2018 Common stock $ 150 $ — $ 1 $ 151 Paid-in capital 194,123 — 1,857 195,980 Retained earnings 27,366 7,774 (2,659 ) 32,481 Accumulated other comprehensive income — — — — $ 221,639 $ 7,774 $ (801 ) $ 228,612 _______________________ 1 Includes equity-classified share-based compensation of $2.5 million during the six months ended June 30, 2018 . During the six months ended June 30, 2018 , 38,115 and 1,495 shares of common stock were issued in connection with the vesting of certain time-vested restricted stock units (“RSUs”) and performance restricted stock units (“PRSUs”), net of shares withheld for income taxes, respectively. This also includes a write-off of $ 2.7 million for certain accounts receivable attributable to natural gas imbalances accounted for under the entitlements method prior to January 1, 2018, in connection with the adoption of ASC Topic 606 (see Note 5).

Share-Based Compensation and Ot

Share-Based Compensation and Other Benefit Plans	6 Months Ended
	Jun. 30, 2018
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 G&A expenses in our Condensed Consolidated Statements of Operations. We reserved 749,600 shares of common stock for issuance under the Penn Virginia Corporation Management Incentive Plan for future share-based compensation awards. A total of 322,437 RSUs and 98,526 PRSUs have been granted as of June 30, 2018 . We recognized $0.9 million and $0.8 million and $2.5 million and $1.7 million of expense attributable to the RSUs and PRSUs for the three and six months ended June 30, 2018 and 2017 , respectively. Approximately $ 0.6 million of the expense for the 2018 six-month period was attributable to the accelerated vesting of certain awards of our former Executive Chairman. In the six months ended June 30, 2018 and 2017 , we granted 17,456 and 148,837 RSUs to certain employees with an average grant-date fair value of $ 43.43 and $51.50 per RSU, respectively. The RSUs are being charged to expense on a straight-line basis over a range of four to five years. In the six months ended June 30, 2018 , 38,115 shares vested, net of shares withheld for income taxes. In the six months ended June 30, 2017 , we granted 62,675 PRSUs to members of our management. No PRSUs were granted during the six months ended June 30, 2018 . In the six months ended June 30, 2018 , 1,495 shares vested, net of shares withheld for income taxes. Previously-issued 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 $0.2 million and $0.3 million of expense attributable to the 401(k) Plan for the three and six months ended June 30, 2018 , respectively, and $0.1 million and $0.2 million for the three and six months ended June 30, 2017 , respectively. The charges for the 401(k) Plan are recorded as a component of G&A expenses. 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 each of the three and six months ended June 30, 2018 and 2017 . The charges for these plans are recorded as a component of “Other income (expense)” in our Condensed Consolidated Statements of Operation.

Interest Expense

Interest Expense	6 Months Ended
	Jun. 30, 2018
Banking and Thrift [Abstract]
Interest Expense	Interest Expense The following table summarizes the components of interest expense for the periods presented: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Interest on borrowings and related fees $ 7,730 $ 515 $ 13,778 $ 905 Accretion of original issue discount 1 168 — 333 — Amortization of debt issuance costs 680 800 1,311 988 Capitalized interest (2,428 ) (41 ) (4,671 ) (81 ) $ 6,150 $ 1,274 $ 10,751 $ 1,812 ___________________ 1 Attributable to the Second Lien Facility (see Note 8).

Earnings per Share

Earnings per Share	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Earnings per Share	Earnings per Share The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings per share for the periods presented: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Net income (loss) - basic and diluted $ (2,521 ) $ 21,329 $ 7,774 $ 49,410 Weighted-average shares – basic 15,058 14,992 15,050 14,992 Effect of dilutive securities 1 — 58 121 105 Weighted-average shares – diluted 15,058 15,050 15,171 15,097 _______________________ 1 For the three months ended June 30, 2018, approximately 0.1 million potentially dilutive securities, represented by RSUs and PRSUs, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per share.

Basis of Presentation (Policies

Basis of Presentation (Policies)	6 Months Ended
	Jun. 30, 2018
Schedule of Policies [Line Items]
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, 2017 . Operating results for the six months ended June 30, 2018 , are not necessarily indicative of the results that may be expected for the year ending December 31, 2018 . Reclassifications We have reclassified certain amounts included within “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet as of December 31, 2017, as disclosed in Note 11, in order to conform to the current period presentation. Adoption of Recently Issued Accounting Pronouncements Effective January 1, 2018, we adopted and began applying the relevant guidance provided in Accounting Standards Update (“ASU”) 2017–07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017–07”). ASU 2017–07 requires employers to disaggregate the service cost component from the other components of net periodic 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 periodic 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 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 there are interest and other costs associated with the legacy obligations. As required, ASU 2017–07 has been applied retrospectively to periods prior to 2018. Accordingly, the entirety of the expense associated with these plans, which was less than $ 0.1 million , has been included as a component of the “Other income (expense)” caption in our Condensed Consolidated Statement of Operations for each of the three and six months ended June 30, 2017 . Prior to 2018, all costs associated with these plans were included in the “General and administrative” (“G&A”) expenses caption. Effective January 1, 2018, we adopted and began applying the relevant guidance provided in ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”) and related amendments to GAAP which, together with ASU 2014–09, represent Accounting Standards Codification (“ASC”) Topic 606, Revenues from Contracts with Customers (“ASC Topic 606”). We adopted ASC Topic 606 using the cumulative effect transition method (see Note 5 for the impact and disclosures associated with the adoption of ASC Topic 606. Recently Issued Accounting Pronouncements Pending Adoption In June 2016, the Financial Accounting Standards Board (“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. Together with recent related amendments to GAAP, ASU 2016–02 represents ASC Topic 842, Leases (“ASC Topic 842”) which supersedes all current GAAP with respect to leases. 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. ASC Topic 842 also will require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ASC Topic 842 is January 1, 2019, with early adoption permitted. ASC Topic 842 will be applicable to our existing leases for office facilities and certain office equipment, vehicles and certain field equipment, land easements and similar arrangements for rights-of-way, and potentially to certain drilling rig and completion contracts with terms in excess of 12 months, to the extent we may have such contracts in the future. In addition, we believe that our crude oil and natural gas gathering commitment arrangements, as described in Note 13, include provisions that could be construed as leases. Our crude oil and natural gas gathering arrangements are fairly complex and include, among other provisions, multiple elements and term lengths, certain volumetric-based minimums and varying degrees of optionality available to both us and the service providers. Furthermore, these arrangements have certain material payment terms that are variable in nature which, depending upon the outcome of our analysis and resulting conclusions, could have a significant impact on the amounts recognized as right of use assets and corresponding lease liabilities. We anticipate that the adoption of ASC Topic 842 may significantly increase our total assets and liabilities. Accordingly, we are continuing to evaluate the effect that ASC Topic 842 will have on our Consolidated Financial Statements and related disclosures. We plan to adopt ASC Topic 842 on the effective date in 2019 using the optional transition method and will recognize a cumulative-effect adjustment to the opening balance of retained earnings. We are also continuing to monitor developments regarding ASC Topic 842 that are unique to our industry. Going Concern Presumption Our unaudited Condensed Consolidated Financial Statements 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, with the exception of the divestiture of our Mid-Continent oil and gas properties as described in Note 3, no subsequent events have occurred that would require recognition in our Condensed Consolidated Financial Statements or disclosure in the Notes thereto.
New Accounting Pronouncements	Adoption of Recently Issued Accounting Pronouncements Effective January 1, 2018, we adopted and began applying the relevant guidance provided in Accounting Standards Update (“ASU”) 2017–07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017–07”). ASU 2017–07 requires employers to disaggregate the service cost component from the other components of net periodic 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 periodic 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 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 there are interest and other costs associated with the legacy obligations. As required, ASU 2017–07 has been applied retrospectively to periods prior to 2018. Accordingly, the entirety of the expense associated with these plans, which was less than $ 0.1 million , has been included as a component of the “Other income (expense)” caption in our Condensed Consolidated Statement of Operations for each of the three and six months ended June 30, 2017 . Prior to 2018, all costs associated with these plans were included in the “General and administrative” (“G&A”) expenses caption. Effective January 1, 2018, we adopted and began applying the relevant guidance provided in ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”) and related amendments to GAAP which, together with ASU 2014–09, represent Accounting Standards Codification (“ASC”) Topic 606, Revenues from Contracts with Customers (“ASC Topic 606”). We adopted ASC Topic 606 using the cumulative effect transition method (see Note 5 for the impact and disclosures associated with the adoption of ASC Topic 606. Recently Issued Accounting Pronouncements Pending Adoption In June 2016, the Financial Accounting Standards Board (“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. Together with recent related amendments to GAAP, ASU 2016–02 represents ASC Topic 842, Leases (“ASC Topic 842”) which supersedes all current GAAP with respect to leases. 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. ASC Topic 842 also will require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ASC Topic 842 is January 1, 2019, with early adoption permitted. ASC Topic 842 will be applicable to our existing leases for office facilities and certain office equipment, vehicles and certain field equipment, land easements and similar arrangements for rights-of-way, and potentially to certain drilling rig and completion contracts with terms in excess of 12 months, to the extent we may have such contracts in the future. In addition, we believe that our crude oil and natural gas gathering commitment arrangements, as described in Note 13, include provisions that could be construed as leases. Our crude oil and natural gas gathering arrangements are fairly complex and include, among other provisions, multiple elements and term lengths, certain volumetric-based minimums and varying degrees of optionality available to both us and the service providers. Furthermore, these arrangements have certain material payment terms that are variable in nature which, depending upon the outcome of our analysis and resulting conclusions, could have a significant impact on the amounts recognized as right of use assets and corresponding lease liabilities. We anticipate that the adoption of ASC Topic 842 may significantly increase our total assets and liabilities. Accordingly, we are continuing to evaluate the effect that ASC Topic 842 will have on our Consolidated Financial Statements and related disclosures. We plan to adopt ASC Topic 842 on the effective date in 2019 using the optional transition method and will recognize a cumulative-effect adjustment to the opening balance of retained earnings. We are also continuing to monitor developments regarding ASC Topic 842 that are unique to our industry.
Revenue from Contract with Customer	Revenue from Contracts with Customers Adoption of ASC Topic 606 Effective January 1, 2018, we adopted ASC Topic 606 and have applied the guidance therein to our contacts with customers for the sale of commodity products (crude oil, NGLs and natural gas) as well as marketing services that we provide to our joint venture partners and other third parties. ASC Topic 606 provides for a five-step revenue recognition process model to determine the transfer of goods or services to consumers in an amount that reflects the consideration to which we expect to be entitled in exchange for such goods and services. Upon the adoption of ASC Topic 606, we: (i) changed the presentation of our NGL product revenues from a gross basis to a net basis and changed the classification of certain natural gas processing costs associated with NGLs from a component of “Gathering, processing and transportation” (“GPT”) expense to a reduction of NGL product revenues as described in further detail below, (ii) wrote off $ 2.7 million of accounts receivable arising from natural gas imbalances accounted for under the entitlements method as a direct reduction to our beginning balance of retained earnings as of January 1, 2018, and (iii) adopted the sales method with respect to production imbalance transactions beginning after December 31, 2017. The following table illustrates the impact of the adoption of ASC Topic 606 on our Condensed Consolidated Statement of Operations for the three and six months ended June 30, 2018 : Three Months Ended June 30, 2018 As Determined As Reported Under Increase Under Prior GAAP ASC Topic 606 (Decrease) Revenues Crude oil $ 101,716 $ 101,716 $ — Natural gas liquids $ 6,103 $ 5,533 $ (570 ) Natural gas $ 3,912 $ 3,912 $ — Marketing services (included in Other revenues, net) $ 153 $ 153 $ — Operating expenses Gathering, processing and transportation $ 5,144 $ 4,574 $ (570 ) Net loss $ (2,521 ) $ (2,521 ) $ — Six Months Ended June 30, 2018 As Determined As Reported Under Increase Under Prior GAAP ASC Topic 606 (Decrease) Revenues Crude oil $ 172,974 $ 172,974 $ — Natural gas liquids $ 9,495 $ 8,479 $ (1,016 ) Natural gas $ 6,702 $ 6,702 $ — Marketing services (included in Other revenues, net) $ 245 $ 245 $ — Operating expenses Gathering, processing and transportation $ 8,949 $ 7,933 $ (1,016 ) Net income $ 7,774 $ 7,774 $ — Accounting Policies for Revenue Recognition and Associated Costs Crude oil . We sell our crude oil production to our customers at either the wellhead or a contractually agreed-upon delivery point, including certain regional central delivery point terminals or pipeline inter-connections. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality, location differentials and, if applicable, deductions for intermediate transportation. Costs incurred by us for gathering and transporting the products to an agreed-upon delivery point are recognized as a component of GPT expense. NGLs . We have natural gas processing contracts in place with certain midstream processing vendors. We deliver “wet” natural gas to our midstream processing vendors at the inlet of their processing facilities through gathering lines, certain of which we own and others which are owned by gathering service providers. Subsequent to processing, NGLs are delivered or otherwise transported to a third-party customer. Depending upon the nature of the contractual arrangements with the midstream processing vendors, particularly those attributable to the marketing of the NGL products, we recognize revenue for NGL products on either a gross or net basis. For those contracts where we have determined that we are the principal, and the ultimate third party is our customer, we recognize revenue on a gross basis, with associated processing costs presented as GPT expenses. For those contracts where we have determined that we are the agent and the midstream processing vendor is our customer, we recognize NGL product revenues based on a net basis with processing costs presented as a reduction of revenue. Based on an analysis of all of our existing natural gas processing contracts, we have determined that, as of January 1, 2018, and through June 30, 2018 , we are the agent and our midstream processing vendors are our customers with respect to all of our NGL product sales. Natural gas . Subsequent to the aforementioned processing of “wet” natural gas and the separation of NGL products, the “dry” or residue gas is delivered to us at the tailgate of the midstream processing vendors’ facilities and we market the product to our customers, most of whom are interstate pipelines. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality and location differentials, as applicable. Costs incurred by us for gathering and transportation from the wellhead through the processing facilities are recognized as a component of GPT expenses. Marketing services . We provide marketing services to certain of our joint venture partners and other third parties with respect to oil and gas production for which we are the operator. Pricing for such services represents a negotiated fixed rate fee based on the sales price of the underlying oil and gas products. Production attributable to joint venture partners from wells that we operate that are not subject to marketing agreements are delivered in kind. Marketing revenue is recognized simultaneously with the sale of our commodity production to our customers. Direct costs associated with our marketing efforts are included in G&A expenses. Transaction Prices, Contract Balances and Performance Obligations Substantially all of our commodity product sales are short-term in nature with contract terms of one year or less. Accordingly, we have applied the practical expedient included in ASC Topic 606, which provides for an exemption from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Under our commodity product sales contracts, we bill our customers and recognize revenue when our performance obligations have been satisfied as described above. At that time, we have determined that payment is unconditional. Accordingly, our commodity sales contracts do not create contract assets or liabilities as those terms are defined in ASC Topic 606. We record revenue in the month that our oil and gas production is delivered to our customers. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production, particularly from properties that are operated by our joint venture partners. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized.
Fair Value Measurements	We apply the authoritative accounting provisions included in GAAP 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 June 30, 2018 , the carrying values of all of these financial instruments approximated fair value.
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 and LLS crude oil 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 Hunt and Devon Acquisitions, 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.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	6 Months Ended
	Jun. 30, 2018
Acquisitions [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	We accounted for the Hunt Acquisition by applying the acquisition method of accounting as of March 1, 2018. The following table represents the final fair values assigned to the net assets acquired and the total acquisition cost incurred, including consideration transferred to Hunt: Assets Oil and gas properties - proved $ 82,443 Oil and gas properties - unproved 16,339 Liabilities Asset retirement obligations 356 Net assets acquired $ 98,426 Cash consideration paid to Hunt $ 84,403 Application of working capital adjustments 245 Accumulated costs, net of suspended revenues, for wells in which Hunt had rights to participate 13,778 Total acquisition costs incurred $ 98,426 We accounted for the Devon Acquisition by applying the acquisition method of accounting as of September 29, 2017. The following table represents the final fair values assigned to the net assets acquired and the total consideration transferred: Assets Oil and gas properties - proved $ 42,866 Oil and gas properties - unproved 146,686 Other property and equipment 8,642 Liabilities Revenue suspense 355 Asset retirement obligations 494 Net assets acquired $ 197,345 Cash consideration paid to Devon and tag-along parties, net $ 190,277 Amount transferred to Devon from the Escrow Account 9,519 Application of working capital adjustments, net (2,451 ) Total consideration transferred $ 197,345
Business Acquisition, Pro Forma Information	The pro forma financial information does not purport to represent what our actual results of operations would have been if the Hunt and Devon Acquisitions and the entry into the Second Lien Facility had occurred as of this date, or the results of operations for any future periods. Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Total revenues $ 111,580 $ 51,978 $ 194,036 $ 99,699 Net income (loss) $ (2,521 ) $ 22,651 $ 10,868 $ 50,839 Net income (loss) per share - basic $ (0.17 ) $ 1.51 $ 0.72 $ 3.39 Net income (loss) per share - diluted $ (0.17 ) $ 1.51 $ 0.72 $ 3.37

Accounts Receivable and Reven27

Accounts Receivable and Revenues from Contracts with Customers (Tables)	6 Months Ended
	Jun. 30, 2018
Receivables [Abstract]
Summary of Accounts Receivable	The following table summarizes our accounts receivable by type as of the dates presented: June 30, December 31, 2018 2017 Customers $ 55,736 $ 39,106 Joint interest partners 17,834 32,493 Other 364 584 73,934 72,183 Less: Allowance for doubtful accounts (2,362 ) (2,362 ) $ 71,572 $ 69,821
Revenue from External Customers by Products and Services	The following table illustrates the impact of the adoption of ASC Topic 606 on our Condensed Consolidated Statement of Operations for the three and six months ended June 30, 2018 : Three Months Ended June 30, 2018 As Determined As Reported Under Increase Under Prior GAAP ASC Topic 606 (Decrease) Revenues Crude oil $ 101,716 $ 101,716 $ — Natural gas liquids $ 6,103 $ 5,533 $ (570 ) Natural gas $ 3,912 $ 3,912 $ — Marketing services (included in Other revenues, net) $ 153 $ 153 $ — Operating expenses Gathering, processing and transportation $ 5,144 $ 4,574 $ (570 ) Net loss $ (2,521 ) $ (2,521 ) $ — Six Months Ended June 30, 2018 As Determined As Reported Under Increase Under Prior GAAP ASC Topic 606 (Decrease) Revenues Crude oil $ 172,974 $ 172,974 $ — Natural gas liquids $ 9,495 $ 8,479 $ (1,016 ) Natural gas $ 6,702 $ 6,702 $ — Marketing services (included in Other revenues, net) $ 245 $ 245 $ — Operating expenses Gathering, processing and transportation $ 8,949 $ 7,933 $ (1,016 ) Net income $ 7,774 $ 7,774 $ —

Derivative Instruments (Tables)

Derivative Instruments (Tables)	6 Months Ended
	Jun. 30, 2018
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 June 30, 2018 : Average Weighted Volume Per Average Fair Value Instrument Day Price Asset Liability Crude Oil: (barrels) ($/barrel) Third quarter 2018 Swaps-WTI 10,455 $ 57.05 $ — $ 14,270 Third quarter 2018 Swaps-LLS 6,000 $ 65.27 — 5,605 Fourth quarter 2018 Swaps-WTI 10,455 $ 57.05 — 11,332 Fourth quarter 2018 Swaps-LLS 6,000 $ 65.27 — 4,418 First quarter 2019 Swaps-WTI 6,446 $ 54.46 — 6,999 First quarter 2019 Swaps-LLS 5,000 $ 59.17 — 5,310 Second quarter 2019 Swaps-WTI 6,421 $ 54.48 — 6,115 Second quarter 2019 Swaps-LLS 5,000 $ 59.17 — 4,568 Third quarter 2019 Swaps-WTI 6,397 $ 54.50 — 5,337 Third quarter 2019 Swaps-LLS 5,000 $ 59.17 — 3,876 Fourth quarter 2019 Swaps-WTI 6,398 $ 54.50 — 4,635 Fourth quarter 2019 Swaps-LLS 5,000 $ 59.17 — 3,221 First quarter 2020 Swaps-WTI 6,000 $ 54.09 — 3,846 Second quarter 2020 Swaps-WTI 6,000 $ 54.09 — 3,302 Third quarter 2020 Swaps-WTI 6,000 $ 54.09 — 2,844 Fourth quarter 2020 Swaps-WTI 6,000 $ 54.09 — 2,451 Settlements to be paid in subsequent period 4,607
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: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Derivative gains (losses) $ (52,241 ) $ 11,061 $ (71,036 ) $ 28,077
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: June 30, 2018 December 31, 2017 Derivative Derivative Derivative Derivative Type Balance Sheet Location Assets Liabilities Assets Liabilities Commodity contracts Derivative assets/liabilities – current $ 33 $ 63,257 $ — $ 27,777 Commodity contracts Derivative assets/liabilities – noncurrent 54 29,566 — 13,900 $ 87 $ 92,823 $ — $ 41,677

Property and Equipment (Tables)

Property and Equipment (Tables)	6 Months Ended
	Jun. 30, 2018
Property, Plant and Equipment [Abstract]
Summary of Property and Equipment	The following table summarizes our property and equipment as of the dates presented: June 30, December 31, 2018 2017 Oil and gas properties: Proved $ 756,863 $ 460,029 Unproved 134,943 117,634 Total oil and gas properties 891,806 577,663 Other property and equipment 16,105 12,712 Total properties and equipment 907,911 590,375 Accumulated depreciation, depletion and amortization (116,287 ) (61,316 ) $ 791,624 $ 529,059

Long-Term Debt Long-Term Debt (

Long-Term Debt Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	The following table summarizes our debt obligations as of the dates presented: June 30, 2018 December 31, 2017 Principal Unamortized Discount and Deferred Issuance Costs 1, 2 Principal Unamortized Discount and Deferred Issuance Costs 1, 2 Credit facility $ 243,500 $ 77,000 Second lien term loan 200,000 $ 10,676 200,000 $ 11,733 Totals 443,500 $ 10,676 277,000 $ 11,733 Less: Unamortized discount (3,506 ) (3,839 ) Less: Unamortized deferred issuance costs (7,170 ) (7,894 ) Long-term debt, net $ 432,824 $ 265,267 _______________________ 1 Issuance costs of the Credit Facility, which represent costs attributable to the access to credit over its 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. 2 Discount and issuance costs of the Second Lien Facility are being amortized over the term of the underlying loan using the effective-interest method

Additional Balance Sheet Deta31

Additional Balance Sheet Detail (Tables)	6 Months Ended
	Jun. 30, 2018
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: June 30, December 31, 2018 2017 Other current assets: Tubular inventory and well materials $ 3,817 $ 5,146 Prepaid expenses 1,377 1,104 $ 5,194 $ 6,250 Other assets: Deferred issuance costs of the Credit Facility $ 2,923 $ 2,857 Deposit in escrow 1 — 3,210 Other 33 2,440 $ 2,956 $ 8,507 Accounts payable and accrued liabilities: Trade accounts payable $ 34,582 $ 22,579 Drilling costs 34,620 22,389 Royalties and revenue – related 43,862 39,287 Production, ad valorem and other taxes 2 3,827 1,275 Compensation – related 2,802 2,975 Interest 377 223 Reserve for bankruptcy claims 3,940 3,933 Deposit received for divestiture of Mid-Continent properties 3 700 — Other 2 3,272 3,520 $ 127,982 $ 96,181 Other liabilities: Asset retirement obligations $ 3,987 $ 3,286 Defined benefit pension obligations 897 971 Postretirement health care benefit obligations 509 476 Other 100 100 $ 5,493 $ 4,833 _______________________ 1 Represents the amount remaining in the Escrow Account for the Devon Acquisition, which was utilized to fund the remaining liabilities due to Devon for the final settlement in March 2018 (see Note 3). 2 The amount for December 31, 2017 was reclassified from Accounts payable and accrued expenses - Other. 3 Represents the deposit paid to us related to the Mid-Continent divestiture (see Note 3).

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2018
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: June 30, 2018 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Assets: Commodity derivative assets – current $ 33 $ — $ 33 $ — Commodity derivative assets – noncurrent $ 54 $ — $ 54 $ — Liabilities: Commodity derivative liabilities – current $ (63,257 ) $ — $ (63,257 ) $ — Commodity derivative liabilities – noncurrent $ (29,566 ) $ — $ (29,566 ) $ — December 31, 2017 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Liabilities: Commodity derivative liabilities – current $ (27,777 ) $ — $ (27,777 ) $ — Commodity derivative liabilities – noncurrent $ (13,900 ) $ — $ (13,900 ) $ —

Shareholders' Equity (Tables)

Shareholders' Equity (Tables)	6 Months Ended
	Jun. 30, 2018
Equity [Abstract]
Schedule of Stockholders Equity	The following tables summarize the components of our shareholders ’ equity and the changes therein as of and for the six months ended June 30, 2018 : December 31, All Other June 30, 2017 Net Income Changes 1 2018 Common stock $ 150 $ — $ 1 $ 151 Paid-in capital 194,123 — 1,857 195,980 Retained earnings 27,366 7,774 (2,659 ) 32,481 Accumulated other comprehensive income — — — — $ 221,639 $ 7,774 $ (801 ) $ 228,612 _______________________ 1 Includes equity-classified share-based compensation of $2.5 million during the six months ended June 30, 2018 . During the six months ended June 30, 2018 , 38,115 and 1,495 shares of common stock were issued in connection with the vesting of certain time-vested restricted stock units (“RSUs”) and performance restricted stock units (“PRSUs”), net of shares withheld for income taxes, respectively. This also includes a write-off of $ 2.7 million for certain accounts receivable attributable to natural gas imbalances accounted for under the entitlements method prior to January 1, 2018, in connection with the adoption of ASC Topic 606 (see Note 5).

Interest Expense (Tables)

Interest Expense (Tables)	6 Months Ended
	Jun. 30, 2018
Banking and Thrift [Abstract]
Interest Expense Net Disclosure	The following table summarizes the components of interest expense for the periods presented: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Interest on borrowings and related fees $ 7,730 $ 515 $ 13,778 $ 905 Accretion of original issue discount 1 168 — 333 — Amortization of debt issuance costs 680 800 1,311 988 Capitalized interest (2,428 ) (41 ) (4,671 ) (81 ) $ 6,150 $ 1,274 $ 10,751 $ 1,812 ___________________ 1 Attributable to the Second Lien Facility (see Note 8).

Earnings per Share (Tables)

Earnings per Share (Tables)	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Components of Calculation of Basic and Diluted Earnings Per Share	The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings per share for the periods presented: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Net income (loss) - basic and diluted $ (2,521 ) $ 21,329 $ 7,774 $ 49,410 Weighted-average shares – basic 15,058 14,992 15,050 14,992 Effect of dilutive securities 1 — 58 121 105 Weighted-average shares – diluted 15,058 15,050 15,171 15,097 _______________________ 1 For the three months ended June 30, 2018, approximately 0.1 million potentially dilutive securities, represented by RSUs and PRSUs, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per share.

Basis of Presentation (Details)

Basis of Presentation (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Other Pension, Postretirement and Supplemental Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	$ 0.1	$ 0.1	$ 0.1	$ 0.1

Acquisitions and Divestitures37

Acquisitions and Divestitures (Details)		Jul. 31, 2018USD ($)	Mar. 01, 2018USD ($)	Jul. 31, 2018USD ($)	Mar. 31, 2018USD ($)	Jun. 30, 2018USD ($)a$ / shares	Jun. 30, 2017USD ($)$ / shares	Jun. 30, 2018USD ($)a$ / shares	Jun. 30, 2017USD ($)$ / shares	Dec. 31, 2017USD ($)	Feb. 28, 2018USD ($)	Nov. 01, 2017USD ($)	Sep. 29, 2017USD ($)a
Business Acquisition [Line Items]
Cash Received for Suspended Revenues Attributable to Acquired Properties			$ 355,000
Business Acquisition, Transaction Costs						$ 500,000		$ 500,000
Capitalized Costs, Proved Properties						1,600,000	$ 1,100,000	1,600,000	$ 1,100,000
Asset Retirement Obligation						4,000,000		4,000,000
Share-based compensation (equity-classified)						900,000	800,000	2,451,000	1,694,000
Proceeds from sales of assets, net								1,700,000
Guarantee Deposit	[1]					700,000		700,000		$ 0
Earnest Money Deposits	[2]					0		0		3,210,000
Business Acquisition, Pro Forma Revenue						111,580,000	51,978,000	194,036,000	99,699,000
Property, Plant and Equipment, Gross						907,911,000		907,911,000		590,375,000
Amount Transferred from Escrow Account											$ 2,500,000
Escrow Distributed											$ 700,000
Amount Transferred from Escrow Account													$ 7,100,000
Business Acquisition, Pro Forma Income (Loss) from Continuing Operations, Net of Tax						$ (2,521,000)	$ 22,651,000	$ 10,868,000	$ 50,839,000
Business Acquisition, Pro Forma Earnings Per Share, Basic | $ / shares						$ (0.17)	$ 1.51	$ 0.72	$ 3.39
Business Acquisition, Pro Forma Earnings Per Share, Diluted | $ / shares						$ (0.17)	$ 1.51	$ 0.72	$ 3.37
Second Lien Facility						$ 200,000,000		$ 200,000,000		200,000,000			200,000,000
Hunt Acquisition [Member]
Business Acquisition [Line Items]
Other Payments to Acquire Businesses								$ 86,000,000
Cash Paid on Date of Acquisition			84,403,000
Accumulated Costs, net of suspended revenues, for wells in which Hunt elected not to participate			13,778,000
Acreage, Net | a						9,700		9,700
Working Capital Adjustments, Net						$ (245,000)		$ (245,000)
Business Acquisition, Transaction Costs			98,426,000		$ 400,000					100,000
Capitalized Costs, Proved Properties			82,443,000
Capitalized Costs, Unproved Properties			16,339,000
Asset Retirement Obligation			356,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net			98,426,000
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual					400,000
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual					$ 200,000
Devon Acquisition [Member]
Business Acquisition [Line Items]
Other Payments to Acquire Businesses										205,000,000
Cash Paid on Date of Acquisition			190,277,000										$ 189,900,000
Acreage, Net | a													19,600
Working Capital Adjustments, Net			(2,451,000)
Cash Received for Suspended Revenues Attributable to Acquired Properties								400,000
Business Acquisition, Transaction Costs													$ 1,000,000
Capitalized Costs, Proved Properties			42,866,000
Capitalized Costs, Unproved Properties			146,686,000
Asset Retirement Obligation			494,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net			197,345,000
Escrow Deposit													$ 10,300,000
Earnest Money Deposits										$ 3,200,000
Additional working interests												$ 700,000
Property, Plant and Equipment, Gross			8,642,000
Amount Transferred from Escrow Account			9,519,000
Preliminary Purchase Price			197,345,000
Mid-Continent Divestiture [Member]
Business Acquisition [Line Items]
Working Capital Adjustments, Net			$ 1,100,000
Asset Retirement Obligation						300,000		300,000
Proceeds from sales of assets, net								6,000,000
Guarantee Deposit						700,000		700,000
Pre-Tax Operating Income Attributable to Assets Sold						$ (600,000)	$ (300,000)	$ (1,400,000)	$ (600,000)
Subsequent Event [Member] | Hunt Acquisition [Member]
Business Acquisition [Line Items]
Working Capital Adjustments, Net		$ (200,000)		$ (200,000)
Cash Received for Suspended Revenues Attributable to Acquired Properties				$ 1,400,000
Subsequent Event [Member] | Mid-Continent Divestiture [Member]
Business Acquisition [Line Items]
Proceeds from sales of assets, net		$ 5,500,000
[1]	Represents the deposit paid to us related to the Mid-Continent divestiture (see Note 3).
[2]	Represents the amount remaining in the Escrow Account for the Devon Acquisition, which was utilized to fund the remaining liabilities due to Devon for the final settlement in March 2018 (see Note 3).

Bankruptcy Proceedings and Em38

Bankruptcy Proceedings and Emergence (Details) $ in Thousands	May 12, 2016subsidiary	Jun. 30, 2018USD ($)	Dec. 31, 2017USD ($)
Reorganizations [Abstract]
Number of Subsidiaries Filing Chapter 11 Bankruptcy | subsidiary	8
Bankruptcy Claims, amount reserved for outstanding claims | $		$ 3,940	$ 3,933

Accounts Receivable and Reven39

Accounts Receivable and Revenues from Contracts with Customers - Summary of Accounts Receivable (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Receivables [Abstract]
Customers	$ 55,736	$ 39,106
Joint interest partners	17,834	32,493
Other	364	584
Accounts Receivable, Gross, Current, Total	73,934	72,183
Less: Allowance for doubtful accounts	(2,362)	(2,362)
Accounts receivable, net of allowance for doubtful accounts	$ 71,572	$ 69,821

Accounts Receivable and Reven40

Accounts Receivable and Revenues from Contracts with Customers - Additional Information (Details) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2018USD ($)	Jun. 30, 2017USD ($)	Jun. 30, 2018USD ($)Customer	Jun. 30, 2017USD ($)Customer	Dec. 31, 2017USD ($)
Accounts, Notes, Loans and Financing Receivable [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic	$ (2,521)	$ 21,329	$ 7,774	$ 49,410
Document Period End Date			Jun. 30, 2018
Sales Revenue | Customer Concentration Risk [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Number of major customers | Customer			3	1
Revenues, major customers			$ 157,800	$ 64,600
Concentration risk, percentage			84.00%	91.00%
Sales Revenue | Customer Concentration Risk [Member] | Major Customer 1
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers			$ 81,000
Concentration risk, percentage			43.00%
Sales Revenue | Customer Concentration Risk [Member] | Major Customer 2
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers			$ 41,000
Concentration risk, percentage			22.00%
Sales Revenue | Customer Concentration Risk [Member] | Major Customer 3
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers			$ 35,800
Concentration risk, percentage			19.00%
Accounts Receivable | Credit Concentration Risk
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration risk, percentage			75.00%		82.00%
Accounts receivable, major customers	41,900		$ 41,900		$ 32,100
Oil and Gas, Exploration and Production [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	101,716	32,351	172,974	$ 62,424
Oil and Condensate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	5,533	2,043	8,479	4,345
Natural Gas, Production [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	3,912	1,880	6,702	4,223
Oil and Gas, Refining and Marketing [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	153		245
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Cost of Goods and Services Sold	4,574	$ 2,555	7,933	$ 5,106
Calculated under Revenue Guidance in Effect before Topic 606 [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic	(2,521)		7,774
Calculated under Revenue Guidance in Effect before Topic 606 [Member] | Oil and Gas, Exploration and Production [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	101,716		172,974
Calculated under Revenue Guidance in Effect before Topic 606 [Member] | Oil and Condensate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	6,103		9,495
Calculated under Revenue Guidance in Effect before Topic 606 [Member] | Natural Gas, Production [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	3,912		6,702
Calculated under Revenue Guidance in Effect before Topic 606 [Member] | Oil and Gas, Refining and Marketing [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	153		245
Calculated under Revenue Guidance in Effect before Topic 606 [Member] | Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Cost of Goods and Services Sold	5,144		8,949
Difference between Revenue Guidance in Effect before and after Topic 606 [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic, Increase (Decrease)	0		0
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Oil and Gas, Exploration and Production [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Including Assessed Tax, Increase (Decrease)	0		0
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Oil and Condensate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Including Assessed Tax, Increase (Decrease)	(570)		(1,016)
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Natural Gas, Production [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Including Assessed Tax, Increase (Decrease)	0		0
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Oil and Gas, Refining and Marketing [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Including Assessed Tax, Increase (Decrease)	0		0
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Cost of Goods and Services Sold, Increase (Decrease)	$ (570)		$ (1,016)

Accounts Receivable and Reven41

Accounts Receivable and Revenues from Contracts with Customers - Revenue from Contracts with Customers (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic	$ (2,521)	$ 21,329	$ 7,774	$ 49,410
Calculated under Revenue Guidance in Effect before Topic 606 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic	$ (2,521)		$ 7,774

Derivative Instruments - Additi

Derivative Instruments - Additional Information (Detail) $ in Thousands	6 Months Ended
	Jun. 30, 2018USD ($)Entity	Dec. 31, 2017USD ($)
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative assets	$ 92,823	$ 41,677
Commodity contracts
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative assets	$ 92,700
Number of derivative counterparties | Entity	8
Commodity contracts | Crude Oil
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Third-party quoted forward prices	West Texas Intermediate (“WTI”) crude oil

Commodity Derivative Positions

Commodity Derivative Positions (Detail) $ in Thousands	6 Months Ended
	Jun. 30, 2018USD ($)bbl$ / bbl
Settlement Agreement [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Fair Value Asset
Fair Value Liability	$ 4,607
Crude Oil | Third Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	10,455
Derivative, Swap Type, Average Fixed Price | $ / bbl	57.05
Fair Value Asset	$ 0
Fair Value Liability	$ 14,270
Crude Oil | Fourth Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	10,455
Derivative, Swap Type, Average Fixed Price | $ / bbl	57.05
Fair Value Asset	$ 0
Fair Value Liability	$ 11,332
Crude Oil | First Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	6,446
Derivative, Swap Type, Average Fixed Price | $ / bbl	54.46
Fair Value Asset	$ 0
Fair Value Liability	$ 6,999
Crude Oil | Second Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	6,421
Derivative, Swap Type, Average Fixed Price | $ / bbl	54.48
Fair Value Asset	$ 0
Fair Value Liability	$ 6,115
Crude Oil | Third Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	6,397
Derivative, Swap Type, Average Fixed Price | $ / bbl	54.50
Fair Value Asset	$ 0
Fair Value Liability	$ 5,337
Crude Oil | Fourth Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	6,398
Derivative, Swap Type, Average Fixed Price | $ / bbl	54.50
Fair Value Asset	$ 0
Fair Value Liability	$ 4,635
Crude Oil | First Quarter 2020 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	6,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	54.09
Fair Value Asset	$ 0
Fair Value Liability	$ 3,846
Crude Oil | Second Quarter 2020 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	6,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	54.09
Fair Value Asset	$ 0
Fair Value Liability	$ 3,302
Crude Oil | Third Quarter 2020 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	6,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	54.09
Fair Value Asset	$ 0
Fair Value Liability	$ 2,844
Crude Oil | Fourth Quarter 2020 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	6,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	54.09
Fair Value Asset	$ 0
Fair Value Liability	$ 2,451
Louisiana Light Sweet [Member] | Third Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps-LLS
Notional Volume, per day | bbl	6,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	65.27
Fair Value Asset	$ 0
Fair Value Liability	$ 5,605
Louisiana Light Sweet [Member] | Fourth Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps-LLS
Notional Volume, per day | bbl	6,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	65.27
Fair Value Asset	$ 0
Fair Value Liability	$ 4,418
Louisiana Light Sweet [Member] | First Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps-LLS
Notional Volume, per day | bbl	5,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	59.17
Fair Value Asset	$ 0
Fair Value Liability	$ 5,310
Louisiana Light Sweet [Member] | Second Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps-LLS
Notional Volume, per day | bbl	5,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	59.17
Fair Value Asset	$ 0
Fair Value Liability	$ 4,568
Louisiana Light Sweet [Member] | Third Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps-LLS
Notional Volume, per day | bbl	5,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	59.17
Fair Value Asset	$ 0
Fair Value Liability	$ 3,876
Louisiana Light Sweet [Member] | Fourth Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps-LLS
Notional Volume, per day | bbl	5,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	59.17
Fair Value Asset	$ 0
Fair Value Liability	$ 3,221

Impact of Derivative Activities

Impact of Derivative Activities on Condensed Consolidated Statements of Income (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives	$ (52,241)	$ 11,061	$ (71,036)	$ 28,077

Fair Value of Derivative Instru

Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Derivative Asset, Current	$ 33	$ 0
Derivative liabilities	63,257	27,777
Derivative Asset, Noncurrent	54	0
Derivative assets	87	0
Derivative Liability, Noncurrent	29,566	13,900
Derivative Liability	92,823	41,677
Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative Liability	92,700
Commodity contracts | Current Derivative Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Current	33	0
Derivative liabilities	63,257	27,777
Commodity contracts | Noncurrent Derivative Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Noncurrent	54	0
Derivative Liability, Noncurrent	$ 29,566	$ 13,900

Summary of Property and Equipme

Summary of Property and Equipment (Detail) $ in Thousands	6 Months Ended
	Jun. 30, 2018USD ($)$ / bbl	Jun. 30, 2017USD ($)$ / bbl	Dec. 31, 2017USD ($)
Property, Plant and Equipment [Abstract]
Proved Oil and Gas Property, Full Cost Method	$ 756,863		$ 460,029
Unproved Oil and Gas Property, Full Cost Method	134,943		117,634
Oil and Gas Property, Full Cost Method, Gross	891,806		577,663
Other property and equipment	16,105		12,712
Total properties and equipment	907,911		590,375
Accumulated depreciation, depletion and amortization	(116,287)		(61,316)
Property and equipment, net (successful efforts method)	791,624		529,059
Unproved Oil and Gas Property excluded	134,900		$ 117,600
Undeveloped Leasehold Costs Transferred	5,600
Capitalized Costs, Proved Properties	1,600	$ 1,100
Interest Costs Capitalized	$ 4,700	$ 100
Amortization Expense Per Physical Unit of Production | $ / bbl	15.36	11.74

Long-Term Debt - Summary of Lon

Long-Term Debt - Summary of Long-Term Debt (Details) - USD ($)		Jun. 30, 2018	Dec. 31, 2017	Sep. 29, 2017
Debt Instrument [Line Items]
Revolving credit facility		$ 243,500,000	$ 77,000,000
Second Lien Facility		200,000,000	200,000,000	$ 200,000,000
Unamortized Loan Commitment and Origination Fees and Unamortized Discounts or Premiums	[1],[2]	10,676,000	11,733,000
Debt Instrument, Unamortized Discount		(3,506,000)	(3,839,000)	(4,000,000)
Unamortized Debt Issuance Expense		(7,170,000)	(7,894,000)	$ (8,200,000)
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net		432,824,000	265,267,000
Long-term Debt		$ 443,500,000	$ 277,000,000
[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 its 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 ($)	6 Months Ended	9 Months Ended
	Jun. 30, 2018	Sep. 30, 2017	Dec. 31, 2017	Sep. 29, 2017
Debt Disclosure [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 237,500,000
Debt Issuance Costs, Line of Credit Arrangements, Gross	$ 700,000
Interest Coverage Ratio, Maximum	3
Current Ratio	1
Second Lien Facility	$ 200,000,000		$ 200,000,000	$ 200,000,000
Proceeds from Debt, Net of Issuance Costs		$ 187,800,000
Debt Instrument, Unamortized Discount	3,506,000		3,839,000	4,000,000
Unamortized Debt Issuance Expense	$ 7,170,000		7,894,000	$ 8,200,000
Debt Instrument, Discounted Percentage	98.00%
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	$ 340,000,000
Interest Rate at Period End	5.58%
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	9.10%	8.34%
Second Lien Facility, Effective Interest Rate	9.89%
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

Income Taxes (Details)

Income Taxes (Details) - USD ($)	6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Federal statutory income tax rate (as a percent)	2100.00%	35.20%	3500.00%
Deferred Tax Assets, Net	$ 4,780,000		$ 4,943,000
Blended tax rate (as a percent)	21.60%
Income Tax Expense (Benefit), Continuing Operations, Adjustment of Deferred Tax (Asset) Liability	$ 200,000
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Percent	2.10%
Unrecognized Tax Benefits	$ 0
Income Tax Examination, Penalties and Interest Expense	$ 0	$ 0

Executive Retirement (Detail)

Executive Retirement (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2018USD ($)
Restructuring and Related Activities [Abstract]
Separation Agreement, Consulting Fees	$ 0.3
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost	$ 0.6

Components of Selected Balance

Components of Selected Balance Sheet Accounts (Detail) - USD ($) $ in Thousands		Jun. 30, 2018	Dec. 31, 2017
Other current assets:
Tubular inventory and well materials		$ 3,817	$ 5,146
Prepaid expenses		1,377	1,104
Other Assets, Current		5,194	6,250
Other assets:
Deferred issuance costs of the Revolver		2,923	2,857
Earnest Money Deposits	[1]	0	3,210
Other		33	2,440
Other assets		2,956	8,507
Accounts payable and accrued liabilities:
Trade accounts payable		34,582	22,579
Drilling costs		34,620	22,389
Royalties and revenue – related		43,862	39,287
Production, ad valorem and other taxes	[2]	3,827	1,275
Compensation – related		2,802	2,975
Interest		377	223
Reserve for bankruptcy claims		3,940	3,933
Guarantee Deposit	[3]	700	0
Other	[2]	3,272	3,520
Accounts payable and accrued liabilities		127,982	96,181
Other liabilities:
Asset retirement obligations		3,987	3,286
Defined benefit pension obligations		897	971
Postretirement health care benefit obligations		509	476
Other		100	100
Other liabilities		$ 5,493	$ 4,833
[1]	Represents the amount remaining in the Escrow Account for the Devon Acquisition, which was utilized to fund the remaining liabilities due to Devon for the final settlement in March 2018 (see Note 3).
[2]	The amount for December 31, 2017 was reclassified from Accounts payable and accrued expenses - Other.
[3]	Represents the deposit paid to us related to the Mid-Continent divestiture (see Note 3).

Assets and Liabilities Measured

Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Assets:
Derivative Asset, Current	$ 33	$ 0
Derivative Asset, Noncurrent	54	0
Liabilities:
Commodity derivative liabilities – current	63,257	27,777
Derivative Liability, Noncurrent	29,566	13,900
Fair Value, Measurements, Recurring | Commodity contracts
Assets:
Derivative Asset, Current	33
Derivative Asset, Noncurrent	54
Liabilities:
Commodity derivative liabilities – current	63,257	27,777
Derivative Liability, Noncurrent	29,566	13,900
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	33
Derivative Asset, Noncurrent	54
Liabilities:
Commodity derivative liabilities – current	63,257	27,777
Derivative Liability, Noncurrent	29,566	13,900
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	6 Months Ended
	Jun. 30, 2018USD ($)bbl
Commitments and Contingencies Disclosure [Line Items]
Long-term Purchase Commitment, Minimum Volume Required | bbl	8,000
Marketing Agreement	10 years
Asset Retirement Obligation	$ 4
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, Due in 2018	5.3
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	22.6
2018 [Domain]
Commitments and Contingencies Disclosure [Line Items]
Operating Leases, Rent Expense, Net	0.1
2019 [Domain]
Commitments and Contingencies Disclosure [Line Items]
Operating Leases, Rent Expense, Net	0.4
2020 [Domain]
Commitments and Contingencies Disclosure [Line Items]
Operating Leases, Rent Expense, Net	0.6
2021 [Domain]
Commitments and Contingencies Disclosure [Line Items]
Operating Leases, Rent Expense, Net	0.6
2022 [Domain]
Commitments and Contingencies Disclosure [Line Items]
Operating Leases, Rent Expense, Net	0.6
2023 [Domain]
Commitments and Contingencies Disclosure [Line Items]
Operating Leases, Rent Expense, Net	$ 0.6

Shareholders' Equity Rollforwar

Shareholders' Equity Rollforward (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance				$ 221,639
Net income (loss)		$ (2,521)	$ 21,329	7,774	$ 49,410
All Other Changes	[1]			(801)
As of ending balance		228,612		228,612
Share-based compensation		900	$ 800	2,451	$ 1,694
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification				2,700
Common stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance				150
All Other Changes	[1]			1
As of ending balance		151		151
Paid-in capital
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance				194,123
All Other Changes	[1]			1,857
As of ending balance		195,980		195,980
Retained earnings
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance				27,366
Net income (loss)				7,774
All Other Changes	[1]			(2,659)
As of ending balance		32,481		32,481
Accumulated other comprehensive income
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance				0
As of ending balance		$ 0		$ 0
Time Vested Restricted Stock Units [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares, Issued		38,115		38,115
Performance Restricted Stock Units [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares, Issued		1,495		1,495
[1]	Includes equity-classified share-based compensation of $2.5 million during the six months ended June 30, 2018. During the six months ended June 30, 2018, 38,115 and 1,495 shares of common stock were issued in connection with the vesting of certain time-vested restricted stock units (“RSUs”) and performance restricted stock units (“PRSUs”), net of shares withheld for income taxes, respectively. This also includes a write-off of $2.7 million for certain accounts receivable attributable to natural gas imbalances accounted for under the entitlements method prior to January 1, 2018, in connection with the adoption of ASC Topic 606 (see Note 5).

Share-Based Compensation and 55

Share-Based Compensation and Other Benefit Plans - Summary of Share-Based Compensation Expense (Details) $ / shares in Units, $ in Thousands	1 Months Ended	3 Months Ended		6 Months Ended
	Jan. 31, 2017tranche	Jun. 30, 2018USD ($)shares	Jun. 30, 2017USD ($)shares	Jun. 30, 2018USD ($)$ / sharesshares	Jun. 30, 2017USD ($)$ / sharesshares
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based compensation (equity-classified) | $		$ 900	$ 800	$ 2,451	$ 1,694
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost | $				600
Defined Contribution Plan, Cost | $		200	100	300	200
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	$ 100	$ 100
Time Vested Restricted Stock Units [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		322,437		322,437
Shares, Issued		38,115		38,115
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares				$ 43.43	$ 51.50
Time Vested Restricted Stock Units [Member] | Minimum [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangements By Share-based Payment Award, Award Amortization Period				4 years
Time Vested Restricted Stock Units [Member] | Maximum [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangements By Share-based Payment Award, Award Amortization Period				5 years
Performance restricted-Employees [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			98,526		98,526
Performance Restricted Stock Units [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		0	62,675	0	62,675
Shares, Issued		1,495		1,495
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 [Member] | 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 [Member] | 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 [Member] | Year 1 [Member] | 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 [Member] | Year 2 [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 [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		17,456	148,837	17,456	148,837
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		749,600		749,600

Interest Expense Components of

Interest Expense Components of Interest Expense (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Banking and Thrift [Abstract]
Interest Expense, Borrowings		$ 7,730	$ 515	$ 13,778	$ 905
Amortization of Debt Discount (Premium)	[1]	168	0	333	0
Amortization of Debt Issuance Costs		680	800	1,311	988
Interest Paid, Capitalized, Investing Activities		(2,428)	(41)	(4,671)	(81)
Interest Expense		$ 6,150	$ 1,274	$ 10,751	$ 1,812
[1]	Attributable to the Second Lien Facility (see Note 8).

Components of Calculation of Ba

Components of Calculation of Basic and Diluted Earnings Per Share (Details) - USD ($) shares in Thousands, $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income (loss)		$ (2,521)	$ 21,329	$ 7,774	$ 49,410
Weighted-average shares – basic		15,058	14,992	15,050	14,992
Effect of dilutive securities	[1]	0	58	121	105
Weighted-average shares – diluted		15,058	15,050	15,171	15,097
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		100
[1]	For the three months ended June 30, 2018, approximately 0.1 million potentially dilutive securities, represented by RSUs and PRSUs, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per share.