Ranger Oil (ROCC) 10-Q 9 May 18 2018 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2018	May 04, 2018
Document Documentand Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1
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
	Mar. 31, 2018	Mar. 31, 2017
Revenues
Crude oil	$ 71,258	$ 30,073
Natural gas liquids	2,946	2,302
Natural gas	2,790	2,343
Gain on sales of assets, net	75	65
Other, net	142	203
Total revenues	77,211	34,986
Operating expenses
Lease operating	7,296	4,916
Gathering, processing and transportation	3,359	2,551
Production and ad valorem taxes	4,092	1,979
General and administrative	6,471	4,107
Depreciation, depletion and amortization	22,081	9,810
Total operating expenses	43,299	23,363
Operating income (loss)	33,912	11,623
Other income (expense)
Interest expense	(4,601)	(538)
Derivatives	(18,795)	17,016
Other, net	(58)	(20)
Income (loss) before income taxes	10,458	28,081
Income tax benefit (expense)	(163)	0
Net income (loss)	10,295	28,081
Net income (loss) attributable to common shareholders	$ 10,295	$ 28,081
Net income (loss) per share:
Basic (in dollars per share)	$ 0.68	$ 1.87
Diluted (in dollars per share)	$ 0.68	$ 1.86
Weighted average shares outstanding – basic (in shares)	15,042	14,992
Weighted average shares outstanding – diluted (in shares)	15,081	15,126

CONDENSED CONSOLIDATED STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 10,295	$ 28,081
Other comprehensive loss:
Change in pension and postretirement obligations, net of tax of $0 and $0 in 2016	0	0
Total Other Comprehensive Income (Loss), Net of Tax	0	0
Comprehensive income (loss)	$ 10,295	$ 28,081

CONDENSED CONSOLIDATED STATEME4

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Statement of Comprehensive Income [Abstract]
Change in pension and postretirement obligations, net of tax	$ 0	$ 0

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 7,319	$ 11,017
Accounts receivable, net of allowance for doubtful accounts	55,957	69,821
Other current assets	6,756	6,250
Total current assets	70,032	87,088
Property and equipment, net (full cost method)	691,283	529,059
Derivative assets	32	0
Deferred Tax Assets, Net, Noncurrent	4,780	4,943
Other assets	3,273	8,507
Total assets	769,400	629,597
Current liabilities
Accounts payable and accrued liabilities	97,134	96,181
Derivative liabilities	36,820	27,777
Total current liabilities	133,954	123,958
Other liabilities	5,308	4,833
Derivative liabilities	16,108	13,900
Long-term debt, net	383,766	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; 15,058,210 and 15,018,870 shares issued as of March 31, 2018 and December 31, 2017, respectively	151	150
Paid-in capital	195,111	194,123
Retained earnings	35,002	27,366
Accumulated other comprehensive income	0	0
Total shareholders’ equity	230,264	221,639
Total liabilities and shareholders’ equity	$ 769,400	$ 629,597

CONDENSED CONSOLIDATED BALANCE6

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Mar. 31, 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	15,058,210	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	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Cash flows from operating activities
Net income (loss)	$ 10,295	$ 28,081
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	22,081	9,810
Derivative contracts:
Net (gains) losses	18,795	(17,016)
Cash settlements, net	(7,576)	(1,992)
Deferred Income Tax Expense (Benefit)	163	0
Gain on sales of assets, net	(75)	(65)
Non-cash interest expense	796	188
Share-based compensation (equity-classified)	1,576	846
Other, net	13	18
Changes in operating assets and liabilities, net	(7,386)	(10,728)
Net cash provided by operating activities	38,682	9,142
Cash flows from investing activities
Acquisitions, net	(83,338)	0
Capital expenditures	(77,839)	(17,741)
Proceeds from sales of assets, net	1,551	0
Net cash used in investing activities	(159,626)	(17,741)
Cash flows from financing activities
Proceeds from credit facility borrowings	118,000	7,000
Repayment of credit facility borrowings	0	(2,000)
Debt issuance costs paid	(754)	0
Proceeds from (Payments for) Other Financing Activities	0	(30)
Net cash provided by financing activities	117,246	4,970
Cash paid for:
Interest, net of amounts capitalized	3,662	348
Reorganization items, net	161	634
Non-cash investing and financing activities:
Changes in accrued liabilities related to capital expenditures	9,616	2,262
Increase (Decrease) in Accounts Receivable, Acquisitions	(26,627)	0
Increase (Decrease) in Other Assets, Acquisitions	(2,469)	0
Increase (Decrease) in Accrued Liabilities, Acquisitions	(15,320)	0
Net decrease in cash and cash equivalents	(3,698)	(3,629)
Cash and cash equivalents – beginning of period	11,017	6,761
Cash and cash equivalents – end of period	$ 7,319	$ 3,132

Nature of Operations

Nature of Operations	3 Months Ended
	Mar. 31, 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 South Texas. Our operations are substantially concentrated with over 90 percent of our production and revenues and all of our capital expenditures attributable to this region. We also have less significant operations in Oklahoma, primarily consisting of non-operated properties in the Granite Wash.

Basis of Presentation

Basis of Presentation	3 Months Ended
	Mar. 31, 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 three months ended March 31, 2018 , are not necessarily indicative of the results that may be expected for the year ending December 31, 2018 . 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 benefit cost. The service cost component of net periodic benefit cost shall be reported in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period, except for amounts capitalized. All other components of net benefit cost shall be presented outside of a subtotal for income from operations. The line item used to present the components other than the service cost shall be disclosed if the other components are not presented in a separate line item or items. ASU 2017–07 is applicable to our legacy retiree benefit plans which cover a limited population of former employees. There is no service cost associated with these plans as they are not applicable to current employees, but rather interest and other costs associated with the legacy obligations. 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 Consolidated Statement of Operations for the three months ended March 31, 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 with related amendments to GAAP which, together with ASU 2014–09, represent Accounting Standards Codification 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 ASCO Topic 606. Recently Issued Accounting Pronouncements Pending Adoption In June 2016, the FASB issued ASU 2016–13, Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”), which changes the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities, among others. ASU 2016–13 is required to be adopted using the modified retrospective method by January 1, 2020, with early adoption permitted for fiscal periods beginning after December 15, 2018. In contrast to current guidance, which considers current information and events and utilizes a probable threshold, (an “incurred loss” model), ASU 2016–13 mandates an “expected loss” model. The expected loss model: (i) estimates the risk of loss even when risk is remote, (ii) estimates losses over the contractual life, (iii) considers past events, current conditions and reasonable supported forecasts and (iv) has no recognition threshold. ASU 2016–13 will have applicability to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners which have a higher credit risk than those associated with our traditional customer receivables. At this time, we do not anticipate that the adoption of ASU 2016–13 will have a significant impact on our Consolidated Financial Statements and related disclosures; however, we are continuing to evaluate the requirements and the period for which we will adopt the standard as well as monitoring developments regarding ASU 2016–13 that are unique to our industry. In February 2016, the FASB issued ASU 2016–02, Leases (“ASU 2016–02”), which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases with terms of more than twelve months. Consistent with current GAAP, the recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease. ASU 2016–02 also will require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ASU 2016–02 is January 1, 2019, with early adoption permitted. We believe that ASU 2016–02 will likely be applicable to our oil and natural gas gathering commitment arrangements as described in Note 13, our existing leases for office facilities and certain office equipment, land easements and similar arrangements for rights-of-way and potentially to certain drilling rig and completion contracts with terms in excess of twelve months to the extent we may have such contracts in the future. Our oil and natural gas gathering arrangements are fairly complex and involve multiple elements that could be construed as leases. Accordingly, we are continuing to evaluate the effect that ASU 2016–02 will have on our Consolidated Financial Statements and related disclosures as well as the period for which we will adopt the standard, however, at this time, we believe that we will likely adopt ASU 2016–02 on the effective date in 2019. We are also continuing to monitor developments regarding ASU 2016–02 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 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 (Notes)	3 Months Ended
	Mar. 31, 2018
Acquisitions [Abstract]
Acquisitions And Dispositions Disclosure [Text Block]	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 and Lavaca Counties, Texas for $ 86.0 million in cash, subject to adjustments (the “Hunt Acquisition”). The Hunt Acquisition has 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 expands our core 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. As a result of the Hunt Acquisition we are the operator of substantially all of our Eagle Ford acreage. 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 preliminary 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 $ 82,198 Oil and gas properties - unproved 16,339 Liabilities Asset retirement obligations (“AROs”) 356 Net assets acquired $ 98,181 Cash consideration paid to Hunt $ 84,403 Accumulated costs, net of suspended revenues, for wells in which Hunt had rights to participate 13,778 Total acquisition costs incurred $ 98,181 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 has 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 $ 0.3 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. The Devon Properties include increases in working interests of many properties for which we are the operator as well as other properties that are contiguous to our existing asset base in South Texas. 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 months ended March, 31, 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 March 31, 2018 2017 Total revenues $ 82,456 $ 47,721 Net income $ 13,390 $ 28,189 Net income (loss) per share - basic $ 0.89 $ 1.88 Net income (loss) per share - diluted $ 0.89 $ 1.86 Divestiture s In February 2018, we sold our undeveloped acreage holdings in the Tuscaloosa Marine Shale in Louisiana that were scheduled to expire in 2019 and in March 2018 we sold certain undeveloped deep leasehold rights in Oklahoma. We received a combined total of $ 1.6 million for these leasehold assets which were applied as a reduction of our net oil and gas properties.

Bankruptcy Proceeding Bankruptc

Bankruptcy Proceeding Bankruptcy Proceedings	3 Months Ended
	Mar. 31, 2018
Reorganizations [Abstract]
Reorganization under Chapter 11 of US Bankruptcy Code Disclosure [Text Block]	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 (the “Plan”), 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 May 4, 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 March 31, 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 Major C

Accounts Receivable and Major Customers	3 Months Ended
	Mar. 31, 2018
Receivables [Abstract]
Accounts Receivable and Major 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: March 31, December 31, 2018 2017 Customers $ 43,764 $ 39,106 Joint interest partners 13,808 32,493 Other 747 584 58,319 72,183 Less: Allowance for doubtful accounts (2,362 ) (2,362 ) $ 55,957 $ 69,821 For the three months ended March 31, 2018 , three customers accounted for $70.6 million , or approximately 91% , of our consolidated product revenues. The revenues generated from these customers during the three months ended March 31, 2018 were $31.0 million , $26.4 million and $13.2 million , or 40% , 34% and 17% of the consolidated total, respectively. As of March 31, 2018 and December 31, 2017 , $38.8 million and $32.1 million , or approximately 89% 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 three months ended March 31, 2017 , one customer accounted for $31.2 million , or approximately 90% , 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 the adoption of ASC Topic 606 on our Condensed Consolidated Statement of Operations for the three months ended March 31, 2018: As Determined As Reported Under Increase Under Prior GAAP ASC Topic 606 (Decrease) Revenues Crude oil $ 71,258 $ 71,258 $ — Natural gas liquids $ 3,392 $ 2,946 $ (446 ) Natural gas $ 2,790 $ 2,790 $ — Marketing services (included in Other, net revenues) $ 92 $ 92 $ — Operating expenses Gathering, processing and transportation $ 3,805 $ 3,359 $ (446 ) Net income $ 10,295 $ 10,295 $ — 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 in our two primary operating regions. 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 March 31, 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	3 Months Ended
	Mar. 31, 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 are 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 March 31, 2018 : Average Weighted Volume Per Average Fair Value Instrument Day Price Asset Liability Crude Oil: (barrels) ($/barrel) Second quarter 2018 Swaps-WTI 6,484 $ 51.09 $ — $ 7,888 Second quarter 2018 Swaps-LLS 2,500 $ 55.18 — 2,735 Third quarter 2018 Swaps-WTI 6,455 $ 51.10 — 6,998 Third quarter 2018 Swaps-LLS 2,500 $ 55.18 — 2,404 Fourth quarter 2018 Swaps-WTI 6,455 $ 51.10 — 5,960 Fourth quarter 2018 Swaps-LLS 2,500 $ 55.18 — 2,003 First quarter 2019 Swaps-WTI 4,946 $ 52.03 — 3,372 First quarter 2019 Swaps-LLS 2,500 $ 51.30 — 2,422 Second quarter 2019 Swaps-WTI 4,921 $ 52.04 — 2,861 Second quarter 2019 Swaps-LLS 2,500 $ 51.30 — 2,144 Third quarter 2019 Swaps-WTI 4,897 $ 52.05 — 2,404 Third quarter 2019 Swaps-LLS 2,500 $ 51.30 — 1,897 Fourth quarter 2019 Swaps-WTI 4,898 $ 52.05 — 2,011 Fourth quarter 2019 Swaps-LLS 2,500 $ 51.30 — 1,660 First quarter 2020 Swaps-WTI 4,000 $ 52.67 — 1,123 Second quarter 2020 Swaps-WTI 4,000 $ 52.67 — 866 Third quarter 2020 Swaps-WTI 4,000 $ 52.67 — 650 Fourth quarter 2020 Swaps-WTI 4,000 $ 52.67 — 461 Settlements to be paid in subsequent period 3,037 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 March 31, 2018 2017 Derivative gains (losses) $ (18,795 ) $ 17,016 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: March 31, 2018 December 31, 2017 Derivative Derivative Derivative Derivative Type Balance Sheet Location Assets Liabilities Assets Liabilities Commodity contracts Derivative assets/liabilities – current $ — $ 36,820 $ — $ 27,777 Commodity contracts Derivative assets/liabilities – noncurrent 32 16,108 — 13,900 $ 32 $ 52,928 $ — $ 41,677 As of March 31, 2018 , we reported total commodity derivative liabilities of $52.9 million . The contracts associated with this position are with five 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	3 Months Ended
	Mar. 31, 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: March 31, December 31, 2018 2017 Oil and gas properties: Proved $ 624,747 $ 460,029 Unproved 137,722 117,634 Total oil and gas properties 762,469 577,663 Other property and equipment 13,702 12,712 Total properties and equipment 776,171 590,375 Accumulated depreciation, depletion and amortization (84,888 ) (61,316 ) $ 691,283 $ 529,059 Unproved property costs of $ 137.7 million and $ 117.6 million have been excluded from amortization as of March 31, 2018 and December 31, 2017 , respectively. We transferred less than $ 0.1 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 three months ended March 31, 2018 . We capitalized internal costs of $ 0.7 million and $0.6 million and interest of $ 2.2 million and less than $0.1 million during the three months ended March 31, 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 $15.20 and $11.47 for the three months ended March 31, 2018 and 2017 , respectively.

Long-Term Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt The following table summarizes our debt obligations as of the dates presented: March 31, 2018 December 31, 2017 Principal Unamortized Discount and Deferred Issuance Costs 1 Principal Unamortized Discount and Deferred Issuance Costs 1 Credit facility 2 $ 195,000 $ 77,000 Second lien term loans 200,000 $ 11,234 200,000 $ 11,733 Totals 395,000 $ 11,234 277,000 $ 11,733 Less: Unamortized discount (3,674 ) (3,839 ) Less: Unamortized deferred issuance costs (7,560 ) (7,894 ) Long-term debt, net $ 383,766 $ 265,267 _______________________ 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. 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 three months ended March 31, 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 generally redetermined semi-annually in April and October of each year. Additionally, the Credit Facility lenders may, at their discretion, initiate a redetermination at any time during the six-month period between scheduled redeterminations. The 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 March 31, 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 March 31, 2018 , the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 5.34% . 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 March 31, 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 March 31, 2018 , the actual interest rate of outstanding borrowings under the Second Lien Facility was 8.88% . 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 subsidiary guarantors. The Second Lien Facility has no financial covenants, but contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, merger, consolidation or sale of assets and transactions with affiliates and other customary covenants. As illustrated in the table above, the OID and issue costs of the Second Lien Facility are presented as reductions to the outstanding term loans. These costs are subject to amortization using the interest method over the five-year term of the Second Lien Facility. As of March 31, 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	3 Months Ended
	Mar. 31, 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) the requirement to pay a one-time transition tax on all undistributed earnings of foreign subsidiaries; (ii) reducing the U.S. federal corporate income tax rate from 35 % to 21 %; (iii) generally eliminating U.S. federal income taxes on dividends from foreign subsidiaries; (iv) allowing the immediate deduction of certain new investments in lieu of depreciation expense over time; (v) creating a new limitation on deductible interest expense; (vi) changing rules related to use and limitations of net operating loss (“NOL”) carryforwards created in tax years beginning after December 31, 2017 and (vii) 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 three months ended March 31, 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 1.6% . The effect of the adjustment was to reduce our deferred tax asset to $ 4.8 million as of March 31, 2018. We recognized a federal income tax benefit for the three months ended March 31, 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 March 31, 2018. There were no interest and penalty charges recognized during the periods ended March 31, 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	3 Months Ended
	Mar. 31, 2018
Restructuring and Related Activities [Abstract]
Exit Activities	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 three months ended March 31, 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	3 Months Ended
	Mar. 31, 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: March 31, December 31, 2018 2017 Other current assets: Tubular inventory and well materials $ 5,391 $ 5,146 Prepaid expenses 1,365 1,104 $ 6,756 $ 6,250 Other assets: Deferred issuance costs of the Credit Facility $ 3,268 $ 2,857 Deposit in escrow 1 — 3,210 Other 5 2,440 $ 3,273 $ 8,507 Accounts payable and accrued liabilities: Trade accounts payable $ 17,223 $ 22,579 Drilling costs 32,005 22,389 Royalties and revenue – related 34,995 39,287 Compensation – related 1,791 2,975 Interest 366 223 Reserve for bankruptcy claims 3,933 3,933 Other 6,821 4,795 $ 97,134 $ 96,181 Other liabilities: Asset retirement obligations $ 3,777 $ 3,286 Defined benefit pension obligations 940 971 Postretirement health care benefit obligations 491 476 Other 100 100 $ 5,308 $ 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).

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements We apply the authoritative accounting provisions for measuring the fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date. Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and our Credit Facility and Second Lien Facility borrowings. As of March 31, 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: March 31, 2018 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Assets: Commodity derivative assets – noncurrent $ 32 $ — $ 32 $ — Liabilities: Commodity derivative liabilities – current $ (36,820 ) $ — $ (36,820 ) $ — Commodity derivative liabilities – noncurrent (16,108 ) — (16,108 ) — 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 three months ended March 31, 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	3 Months Ended
	Mar. 31, 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: $ 7.9 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 and Completion Commitments We have contractual commitments for three drilling rigs as of March 31, 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 proppant materials. Both the frac services and materials commitments were effective January 1, 2018. We have approximately $ 37.0 million of combined obligations associated with these commitments. Legal and Regulatory We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, results of operations or cash flows. As of March 31, 2018 , we continue to maintain a $0.1 million reserve for a litigation matter. As of March 31, 2018 , we also had AROs of approximately $3.8 million attributable to the plugging of abandoned wells.

Shareholders' Equity

Shareholders' Equity	3 Months Ended
	Mar. 31, 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 three months ended March 31, 2018 : December 31, All Other March 31, 2017 Net Income Changes 1 2018 Common stock $ 150 $ — $ 1 $ 151 Paid-in capital 194,123 — 988 195,111 Retained earnings 27,366 10,295 (2,659 ) 35,002 Accumulated other comprehensive income — — — — $ 221,639 $ 10,295 $ (1,670 ) $ 230,264 _______________________ 1 Includes equity-classified share-based compensation of $ 1.6 million during the three months ended March 31, 2018 . During the three months ended March 31, 2018 , 37,845 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. 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 accordance with the adoption of ASC Topic 606 (see Note 5).

Share-Based Compensation and Ot

Share-Based Compensation and Other Benefit Plans	3 Months Ended
	Mar. 31, 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 310,700 RSUs and 98,526 PRSUs have been granted as of March 31, 2018 . We recognized $1.6 million and $0.8 million of expense attributable to the RSUs and PRSUs for the three months ended March 31, 2018 and 2017 , respectively. Approximately $ 0.6 million of the expense for the 2018 period was attributable to the accelerated vesting of certain awards of our former Executive Chairman. In the three months ended March 31, 2018 and 2017 , we granted 5,719 and 146,834 RSUs to certain employees with an average grant-date fair value of $ 36.52 and $51.71 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 three months ended March 31, 2018 , 37,845 shares vested, net of shares withheld for income taxes. In the three months ended March 31, 2017 , we granted 62,675 PRSUs to members of our management. No PRSUs were granted during the three months ended March 31, 2018 . In the three months ended March 31, 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 $0.1 million of expense attributable to the 401(k) Plan for each of the three months ended March 31, 2018 and 2017 . 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 months ended March 31, 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	3 Months Ended
	Mar. 31, 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 March 31, 2018 2017 Interest on borrowings and related fees $ 6,048 $ 390 Accretion of original issue discount 1 165 — Amortization of debt issuance costs 631 188 Capitalized interest (2,243 ) (40 ) $ 4,601 $ 538 ___________________ 1 Includes accretion of original issue discount attributable to the Second Lien Facility (see Note 8).

Earnings (Loss) per Share

Earnings (Loss) per Share	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
Earnings (Loss) 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 March 31, 2018 2017 Net income - basic and diluted $ 10,295 $ 28,081 Weighted-average shares – basic 15,042 14,992 Effect of dilutive securities 1 39 134 Weighted-average shares – diluted 15,081 15,126 _______________________ 1 The number of dilutive securities for the three months ended March 31, 2018 and 2017 , which is attributable to RSUs and PRSUs, was determined under the “treasury stock” method.

Basis of Presentation (Policies

Basis of Presentation (Policies)	3 Months Ended
	Mar. 31, 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 three months ended March 31, 2018 , are not necessarily indicative of the results that may be expected for the year ending December 31, 2018 . 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 benefit cost. The service cost component of net periodic benefit cost shall be reported in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period, except for amounts capitalized. All other components of net benefit cost shall be presented outside of a subtotal for income from operations. The line item used to present the components other than the service cost shall be disclosed if the other components are not presented in a separate line item or items. ASU 2017–07 is applicable to our legacy retiree benefit plans which cover a limited population of former employees. There is no service cost associated with these plans as they are not applicable to current employees, but rather interest and other costs associated with the legacy obligations. 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 Consolidated Statement of Operations for the three months ended March 31, 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 with related amendments to GAAP which, together with ASU 2014–09, represent Accounting Standards Codification 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 ASCO Topic 606. Recently Issued Accounting Pronouncements Pending Adoption In June 2016, the FASB issued ASU 2016–13, Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”), which changes the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities, among others. ASU 2016–13 is required to be adopted using the modified retrospective method by January 1, 2020, with early adoption permitted for fiscal periods beginning after December 15, 2018. In contrast to current guidance, which considers current information and events and utilizes a probable threshold, (an “incurred loss” model), ASU 2016–13 mandates an “expected loss” model. The expected loss model: (i) estimates the risk of loss even when risk is remote, (ii) estimates losses over the contractual life, (iii) considers past events, current conditions and reasonable supported forecasts and (iv) has no recognition threshold. ASU 2016–13 will have applicability to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners which have a higher credit risk than those associated with our traditional customer receivables. At this time, we do not anticipate that the adoption of ASU 2016–13 will have a significant impact on our Consolidated Financial Statements and related disclosures; however, we are continuing to evaluate the requirements and the period for which we will adopt the standard as well as monitoring developments regarding ASU 2016–13 that are unique to our industry. In February 2016, the FASB issued ASU 2016–02, Leases (“ASU 2016–02”), which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases with terms of more than twelve months. Consistent with current GAAP, the recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease. ASU 2016–02 also will require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ASU 2016–02 is January 1, 2019, with early adoption permitted. We believe that ASU 2016–02 will likely be applicable to our oil and natural gas gathering commitment arrangements as described in Note 13, our existing leases for office facilities and certain office equipment, land easements and similar arrangements for rights-of-way and potentially to certain drilling rig and completion contracts with terms in excess of twelve months to the extent we may have such contracts in the future. Our oil and natural gas gathering arrangements are fairly complex and involve multiple elements that could be construed as leases. Accordingly, we are continuing to evaluate the effect that ASU 2016–02 will have on our Consolidated Financial Statements and related disclosures as well as the period for which we will adopt the standard, however, at this time, we believe that we will likely adopt ASU 2016–02 on the effective date in 2019. We are also continuing to monitor developments regarding ASU 2016–02 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 no subsequent events have occurred that would require recognition in our Condensed Consolidated Financial Statements or disclosure in the Notes thereto.
Fair Value Measurements	We apply the authoritative accounting provisions for measuring the fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date. Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and our Credit Facility and Second Lien Facility borrowings. As of March 31, 2018 , the carrying values of all of these financial instruments approximated fair value.
New Accounting Pronouncements, Policy [Policy Text Block]	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 benefit cost. The service cost component of net periodic benefit cost shall be reported in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period, except for amounts capitalized. All other components of net benefit cost shall be presented outside of a subtotal for income from operations. The line item used to present the components other than the service cost shall be disclosed if the other components are not presented in a separate line item or items. ASU 2017–07 is applicable to our legacy retiree benefit plans which cover a limited population of former employees. There is no service cost associated with these plans as they are not applicable to current employees, but rather interest and other costs associated with the legacy obligations. 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 Consolidated Statement of Operations for the three months ended March 31, 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 with related amendments to GAAP which, together with ASU 2014–09, represent Accounting Standards Codification 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 ASCO Topic 606. Recently Issued Accounting Pronouncements Pending Adoption In June 2016, the FASB issued ASU 2016–13, Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”), which changes the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities, among others. ASU 2016–13 is required to be adopted using the modified retrospective method by January 1, 2020, with early adoption permitted for fiscal periods beginning after December 15, 2018. In contrast to current guidance, which considers current information and events and utilizes a probable threshold, (an “incurred loss” model), ASU 2016–13 mandates an “expected loss” model. The expected loss model: (i) estimates the risk of loss even when risk is remote, (ii) estimates losses over the contractual life, (iii) considers past events, current conditions and reasonable supported forecasts and (iv) has no recognition threshold. ASU 2016–13 will have applicability to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners which have a higher credit risk than those associated with our traditional customer receivables. At this time, we do not anticipate that the adoption of ASU 2016–13 will have a significant impact on our Consolidated Financial Statements and related disclosures; however, we are continuing to evaluate the requirements and the period for which we will adopt the standard as well as monitoring developments regarding ASU 2016–13 that are unique to our industry. In February 2016, the FASB issued ASU 2016–02, Leases (“ASU 2016–02”), which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases with terms of more than twelve months. Consistent with current GAAP, the recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease. ASU 2016–02 also will require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ASU 2016–02 is January 1, 2019, with early adoption permitted. We believe that ASU 2016–02 will likely be applicable to our oil and natural gas gathering commitment arrangements as described in Note 13, our existing leases for office facilities and certain office equipment, land easements and similar arrangements for rights-of-way and potentially to certain drilling rig and completion contracts with terms in excess of twelve months to the extent we may have such contracts in the future. Our oil and natural gas gathering arrangements are fairly complex and involve multiple elements that could be construed as leases. Accordingly, we are continuing to evaluate the effect that ASU 2016–02 will have on our Consolidated Financial Statements and related disclosures as well as the period for which we will adopt the standard, however, at this time, we believe that we will likely adopt ASU 2016–02 on the effective date in 2019. We are also continuing to monitor developments regarding ASU 2016–02 that are unique to our industry.
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.

New Accounting Pronouncement (P

New Accounting Pronouncement (Policies)	3 Months Ended
	Mar. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer [Text Block]	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 the adoption of ASC Topic 606 on our Condensed Consolidated Statement of Operations for the three months ended March 31, 2018: As Determined As Reported Under Increase Under Prior GAAP ASC Topic 606 (Decrease) Revenues Crude oil $ 71,258 $ 71,258 $ — Natural gas liquids $ 3,392 $ 2,946 $ (446 ) Natural gas $ 2,790 $ 2,790 $ — Marketing services (included in Other, net revenues) $ 92 $ 92 $ — Operating expenses Gathering, processing and transportation $ 3,805 $ 3,359 $ (446 ) Net income $ 10,295 $ 10,295 $ — 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 in our two primary operating regions. 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 March 31, 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. The following table illustrates the impact of the the adoption of ASC Topic 606 on our Condensed Consolidated Statement of Operations for the three months ended March 31, 2018: As Determined As Reported Under Increase Under Prior GAAP ASC Topic 606 (Decrease) Revenues Crude oil $ 71,258 $ 71,258 $ — Natural gas liquids $ 3,392 $ 2,946 $ (446 ) Natural gas $ 2,790 $ 2,790 $ — Marketing services (included in Other, net revenues) $ 92 $ 92 $ — Operating expenses Gathering, processing and transportation $ 3,805 $ 3,359 $ (446 ) Net income $ 10,295 $ 10,295 $ —

Acquisitions and Divestitures27

Acquisitions and Divestitures (Tables)	3 Months Ended
	Mar. 31, 2018
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	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 We accounted for the Hunt Acquisition by applying the acquisition method of accounting as of March 1, 2018. The following table represents the preliminary 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 $ 82,198 Oil and gas properties - unproved 16,339 Liabilities Asset retirement obligations (“AROs”) 356 Net assets acquired $ 98,181 Cash consideration paid to Hunt $ 84,403 Accumulated costs, net of suspended revenues, for wells in which Hunt had rights to participate 13,778 Total acquisition costs incurred $ 98,181
Business Acquisition, Pro Forma Information [Table Text Block]	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 March 31, 2018 2017 Total revenues $ 82,456 $ 47,721 Net income $ 13,390 $ 28,189 Net income (loss) per share - basic $ 0.89 $ 1.88 Net income (loss) per share - diluted $ 0.89 $ 1.86

Accounts Receivable and Major28

Accounts Receivable and Major Customers (Tables)	3 Months Ended
	Mar. 31, 2018
Receivables [Abstract]
Revenue from Contract with Customer [Text Block]	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 the adoption of ASC Topic 606 on our Condensed Consolidated Statement of Operations for the three months ended March 31, 2018: As Determined As Reported Under Increase Under Prior GAAP ASC Topic 606 (Decrease) Revenues Crude oil $ 71,258 $ 71,258 $ — Natural gas liquids $ 3,392 $ 2,946 $ (446 ) Natural gas $ 2,790 $ 2,790 $ — Marketing services (included in Other, net revenues) $ 92 $ 92 $ — Operating expenses Gathering, processing and transportation $ 3,805 $ 3,359 $ (446 ) Net income $ 10,295 $ 10,295 $ — 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 in our two primary operating regions. 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 March 31, 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. The following table illustrates the impact of the the adoption of ASC Topic 606 on our Condensed Consolidated Statement of Operations for the three months ended March 31, 2018: As Determined As Reported Under Increase Under Prior GAAP ASC Topic 606 (Decrease) Revenues Crude oil $ 71,258 $ 71,258 $ — Natural gas liquids $ 3,392 $ 2,946 $ (446 ) Natural gas $ 2,790 $ 2,790 $ — Marketing services (included in Other, net revenues) $ 92 $ 92 $ — Operating expenses Gathering, processing and transportation $ 3,805 $ 3,359 $ (446 ) Net income $ 10,295 $ 10,295 $ —
Summary of Accounts Receivable	The following table summarizes our accounts receivable by type as of the dates presented: March 31, December 31, 2018 2017 Customers $ 43,764 $ 39,106 Joint interest partners 13,808 32,493 Other 747 584 58,319 72,183 Less: Allowance for doubtful accounts (2,362 ) (2,362 ) $ 55,957 $ 69,821

Derivative Instruments (Tables)

Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2018 : Average Weighted Volume Per Average Fair Value Instrument Day Price Asset Liability Crude Oil: (barrels) ($/barrel) Second quarter 2018 Swaps-WTI 6,484 $ 51.09 $ — $ 7,888 Second quarter 2018 Swaps-LLS 2,500 $ 55.18 — 2,735 Third quarter 2018 Swaps-WTI 6,455 $ 51.10 — 6,998 Third quarter 2018 Swaps-LLS 2,500 $ 55.18 — 2,404 Fourth quarter 2018 Swaps-WTI 6,455 $ 51.10 — 5,960 Fourth quarter 2018 Swaps-LLS 2,500 $ 55.18 — 2,003 First quarter 2019 Swaps-WTI 4,946 $ 52.03 — 3,372 First quarter 2019 Swaps-LLS 2,500 $ 51.30 — 2,422 Second quarter 2019 Swaps-WTI 4,921 $ 52.04 — 2,861 Second quarter 2019 Swaps-LLS 2,500 $ 51.30 — 2,144 Third quarter 2019 Swaps-WTI 4,897 $ 52.05 — 2,404 Third quarter 2019 Swaps-LLS 2,500 $ 51.30 — 1,897 Fourth quarter 2019 Swaps-WTI 4,898 $ 52.05 — 2,011 Fourth quarter 2019 Swaps-LLS 2,500 $ 51.30 — 1,660 First quarter 2020 Swaps-WTI 4,000 $ 52.67 — 1,123 Second quarter 2020 Swaps-WTI 4,000 $ 52.67 — 866 Third quarter 2020 Swaps-WTI 4,000 $ 52.67 — 650 Fourth quarter 2020 Swaps-WTI 4,000 $ 52.67 — 461 Settlements to be paid in subsequent period 3,037
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 March 31, 2018 2017 Derivative gains (losses) $ (18,795 ) $ 17,016
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: March 31, 2018 December 31, 2017 Derivative Derivative Derivative Derivative Type Balance Sheet Location Assets Liabilities Assets Liabilities Commodity contracts Derivative assets/liabilities – current $ — $ 36,820 $ — $ 27,777 Commodity contracts Derivative assets/liabilities – noncurrent 32 16,108 — 13,900 $ 32 $ 52,928 $ — $ 41,677

Property and Equipment (Tables)

Property and Equipment (Tables)	3 Months Ended
	Mar. 31, 2018
Property, Plant and Equipment [Abstract]
Summary of Property and Equipment	The following table summarizes our property and equipment as of the dates presented: March 31, December 31, 2018 2017 Oil and gas properties: Proved $ 624,747 $ 460,029 Unproved 137,722 117,634 Total oil and gas properties 762,469 577,663 Other property and equipment 13,702 12,712 Total properties and equipment 776,171 590,375 Accumulated depreciation, depletion and amortization (84,888 ) (61,316 ) $ 691,283 $ 529,059

Long-Term Debt Long-Term Debt (

Long-Term Debt Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2018
Debt Instrument [Line Items]
Schedule of Long-term Debt Instruments [Table Text Block]	The following table summarizes our debt obligations as of the dates presented: March 31, 2018 December 31, 2017 Principal Unamortized Discount and Deferred Issuance Costs 1 Principal Unamortized Discount and Deferred Issuance Costs 1 Credit facility 2 $ 195,000 $ 77,000 Second lien term loans 200,000 $ 11,234 200,000 $ 11,733 Totals 395,000 $ 11,234 277,000 $ 11,733 Less: Unamortized discount (3,674 ) (3,839 ) Less: Unamortized deferred issuance costs (7,560 ) (7,894 ) Long-term debt, net $ 383,766 $ 265,267

Additional Balance Sheet Deta32

Additional Balance Sheet Detail (Tables)	3 Months Ended
	Mar. 31, 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: March 31, December 31, 2018 2017 Other current assets: Tubular inventory and well materials $ 5,391 $ 5,146 Prepaid expenses 1,365 1,104 $ 6,756 $ 6,250 Other assets: Deferred issuance costs of the Credit Facility $ 3,268 $ 2,857 Deposit in escrow 1 — 3,210 Other 5 2,440 $ 3,273 $ 8,507 Accounts payable and accrued liabilities: Trade accounts payable $ 17,223 $ 22,579 Drilling costs 32,005 22,389 Royalties and revenue – related 34,995 39,287 Compensation – related 1,791 2,975 Interest 366 223 Reserve for bankruptcy claims 3,933 3,933 Other 6,821 4,795 $ 97,134 $ 96,181 Other liabilities: Asset retirement obligations $ 3,777 $ 3,286 Defined benefit pension obligations 940 971 Postretirement health care benefit obligations 491 476 Other 100 100 $ 5,308 $ 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).

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 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: March 31, 2018 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Assets: Commodity derivative assets – noncurrent $ 32 $ — $ 32 $ — Liabilities: Commodity derivative liabilities – current $ (36,820 ) $ — $ (36,820 ) $ — Commodity derivative liabilities – noncurrent (16,108 ) — (16,108 ) — 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)	3 Months Ended
	Mar. 31, 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 three months ended March 31, 2018 : December 31, All Other March 31, 2017 Net Income Changes 1 2018 Common stock $ 150 $ — $ 1 $ 151 Paid-in capital 194,123 — 988 195,111 Retained earnings 27,366 10,295 (2,659 ) 35,002 Accumulated other comprehensive income — — — — $ 221,639 $ 10,295 $ (1,670 ) $ 230,264 _______________________ 1 Includes equity-classified share-based compensation of $ 1.6 million during the three months ended March 31, 2018 . During the three months ended March 31, 2018 , 37,845 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. 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 accordance with the adoption of ASC Topic 606 (see Note 5).

Interest Expense (Tables)

Interest Expense (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2018 2017 Interest on borrowings and related fees $ 6,048 $ 390 Accretion of original issue discount 1 165 — Amortization of debt issuance costs 631 188 Capitalized interest (2,243 ) (40 ) $ 4,601 $ 538 ___________________ 1 Includes accretion of original issue discount attributable to the Second Lien Facility (see Note 8).
Debt Instrument [Line Items]
Interest Expense	Interest Expense The following table summarizes the components of interest expense for the periods presented: Three Months Ended March 31, 2018 2017 Interest on borrowings and related fees $ 6,048 $ 390 Accretion of original issue discount 1 165 — Amortization of debt issuance costs 631 188 Capitalized interest (2,243 ) (40 ) $ 4,601 $ 538 ___________________ 1 Includes accretion of original issue discount attributable to the Second Lien Facility (see Note 8).

Earnings per Share (Tables)

Earnings per Share (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2018 2017 Net income - basic and diluted $ 10,295 $ 28,081 Weighted-average shares – basic 15,042 14,992 Effect of dilutive securities 1 39 134 Weighted-average shares – diluted 15,081 15,126 _______________________ 1 The number of dilutive securities for the three months ended March 31, 2018 and 2017 , which is attributable to RSUs and PRSUs, was determined under the “treasury stock” method.

Revenue with Customers (Tables)

Revenue with Customers (Tables)	3 Months Ended
	Mar. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer [Text Block]	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 the adoption of ASC Topic 606 on our Condensed Consolidated Statement of Operations for the three months ended March 31, 2018: As Determined As Reported Under Increase Under Prior GAAP ASC Topic 606 (Decrease) Revenues Crude oil $ 71,258 $ 71,258 $ — Natural gas liquids $ 3,392 $ 2,946 $ (446 ) Natural gas $ 2,790 $ 2,790 $ — Marketing services (included in Other, net revenues) $ 92 $ 92 $ — Operating expenses Gathering, processing and transportation $ 3,805 $ 3,359 $ (446 ) Net income $ 10,295 $ 10,295 $ — 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 in our two primary operating regions. 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 March 31, 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. The following table illustrates the impact of the the adoption of ASC Topic 606 on our Condensed Consolidated Statement of Operations for the three months ended March 31, 2018: As Determined As Reported Under Increase Under Prior GAAP ASC Topic 606 (Decrease) Revenues Crude oil $ 71,258 $ 71,258 $ — Natural gas liquids $ 3,392 $ 2,946 $ (446 ) Natural gas $ 2,790 $ 2,790 $ — Marketing services (included in Other, net revenues) $ 92 $ 92 $ — Operating expenses Gathering, processing and transportation $ 3,805 $ 3,359 $ (446 ) Net income $ 10,295 $ 10,295 $ —

Nature of Operations Nature of

Nature of Operations Nature of Operations (Details)	3 Months Ended
	Mar. 31, 2018
TEXAS | Eagle Ford Shale
Concentration Risk [Line Items]
Concentration risk, percentage (more than)	90.00%

Basis of Presentation (Details)

Basis of Presentation (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Oil and Condensate Revenue	$ 2,946	$ 2,302
Basic (in dollars per share)	$ 0.68	$ 1.87
Diluted (in dollars per share)	$ 0.68	$ 1.86
Gas Gathering, Transportation, Marketing and Processing Costs	$ 3,359	$ 2,551
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)	$ 100	$ 100

Acquisitions and Divestitures40

Acquisitions and Divestitures (Details) $ / shares in Units, $ in Thousands	1 Months Ended		3 Months Ended			12 Months Ended
	Mar. 31, 2018USD ($)a		Mar. 31, 2018USD ($)a$ / shares		Mar. 31, 2017USD ($)$ / shares	Dec. 31, 2017USD ($)	Mar. 01, 2018USD ($)	Feb. 28, 2018USD ($)	Nov. 01, 2017USD ($)	Sep. 29, 2017USD ($)a
Business Acquisition [Line Items]
Proceeds from sales of assets, net			$ 1,551		$ 0
Earnest Money Deposits	$ 0	[1]	0	[1]		$ 3,210
Business Acquisition, Pro Forma Revenue			82,456		47,721
Capitalized Costs, Proved Properties	700		700		600
Property, Plant and Equipment, Gross	776,171		776,171			590,375
Asset Retirement Obligation	3,800		3,800
Amount Transferred from Escrow Account								$ 2,500
Escrow Distributed								$ 700
Cash Received for Suspended Revenues Attributable to Acquired Properties			355
Amount Transferred from Escrow Account										$ 7,100
Business Acquisition, Pro Forma Income (Loss) from Continuing Operations, Net of Tax			$ 13,390		$ 28,189
Business Acquisition, Pro Forma Earnings Per Share, Basic | $ / shares			$ 890		$ 1,880
Business Acquisition, Pro Forma Earnings Per Share, Diluted | $ / shares			$ 890		$ 1,860
Second Lien Facility	200,000		$ 200,000			200,000				$ 200,000
Business Acquisition, Transaction Costs	500		$ 500
Hunt Acquisition [Domain]
Business Acquisition [Line Items]
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual	$ 0
Acreage, Net | a	9,700		9,700
Other Payments to Acquire Businesses			$ 86,000
Capitalized Costs, Proved Properties							$ 82,198
Capitalized Costs, Unproved Properties							16,339
Asset Retirement Obligation							356
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net							98,181
Cash Paid on Date of Acquisition							84,403
Accumulated Costs, net of suspended revenues, for wells in which Hunt elected not to participate							13,778
Business Acquisition, Transaction Costs	$ 400		400			100	98,181
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual	$ 0
Devon Acquisition [Member]
Business Acquisition [Line Items]
Acreage, Net | a										19,600
Other Payments to Acquire Businesses						205,000
Escrow Deposit										$ 10,300
Earnest Money Deposits						$ 3,200
Additional working interests									$ 700
Capitalized Costs, Proved Properties							42,866
Capitalized Costs, Unproved Properties							146,686
Property, Plant and Equipment, Gross							8,642
Asset Retirement Obligation							494
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net							197,345
Cash Paid on Date of Acquisition							190,277			189,900
Amount Transferred from Escrow Account							9,519
Cash Received for Suspended Revenues Attributable to Acquired Properties			$ 300
Working Capital Adjustments, Net							(2,451)
Preliminary Purchase Price							$ 197,345
Business Acquisition, Transaction Costs										$ 1,000
[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).

Bankruptcy Proceeding Bankrup41

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

Summary of Accounts Receivable

Summary of Accounts Receivable (Detail) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Receivables [Abstract]
Customers	$ 43,764	$ 39,106
Joint interest partners	13,808	32,493
Other	747	584
Accounts Receivable, Gross, Current, Total	58,319	72,183
Less: Allowance for doubtful accounts	(2,362)	(2,362)
Accounts receivable, net of allowance for doubtful accounts	$ 55,957	$ 69,821

Accounts Receivable and Major43

Accounts Receivable and Major Customers - Additional Information (Detail) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2018USD ($)Customer	Mar. 31, 2017USD ($)Customer	Dec. 31, 2017USD ($)
Accounts, Notes, Loans and Financing Receivable [Line Items]
Document Period End Date	Mar. 31, 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	$ 70.6	$ 31.2
Concentration risk, percentage	91.00%	90.00%
Sales Revenue | Customer Concentration Risk [Member] | Major Customer 1
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers	$ 31
Concentration risk, percentage	40.00%
Sales Revenue | Customer Concentration Risk [Member] | Major Customer 2
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers	$ 26.4
Concentration risk, percentage	34.00%
Sales Revenue | Customer Concentration Risk [Member] | Major Customer Three [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers	$ 13.2
Concentration risk, percentage	17.00%
Accounts Receivable | Credit Concentration Risk
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration risk, percentage	89.00%		82.00%
Accounts receivable, major customers	$ 38.8		$ 32.1

Accounts Receivable and Major44

Accounts Receivable and Major Customers Revenue from Contracts with Customers (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Exploration and Production Revenue	$ 71,258	$ 30,073
Oil and Condensate Revenue	2,946	2,302
Natural Gas Production Revenue	2,790	2,343
Refining and Marketing Revenue	92
Gas Gathering, Transportation, Marketing and Processing Costs	3,359	2,551
Net Income (Loss) Available to Common Stockholders, Basic	10,295	$ 28,081
Calculated under Revenue Guidance in Effect before Topic 606 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Exploration and Production Revenue	71,258
Oil and Condensate Revenue	3,392
Natural Gas Production Revenue	2,790
Refining and Marketing Revenue	92
Gas Gathering, Transportation, Marketing and Processing Costs	3,805
Net Income (Loss) Available to Common Stockholders, Basic	10,295
Difference between Revenue Guidance in Effect before and after Topic 606 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Exploration and Production Revenue	0
Oil and Condensate Revenue	446
Natural Gas Production Revenue	0
Refining and Marketing Revenue	0
Gas Gathering, Transportation, Marketing and Processing Costs	446
Net Income (Loss) Available to Common Stockholders, Basic	$ 0

Derivative Instruments - Additi

Derivative Instruments - Additional Information (Detail) $ in Thousands	3 Months Ended
	Mar. 31, 2018USD ($)Entity	Dec. 31, 2017USD ($)
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative assets	$ 52,928	$ 41,677
Commodity contracts
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative assets	$ 52,900
Number of derivative counterparties | Entity	5
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	3 Months Ended
	Mar. 31, 2018USD ($)bbl$ / bbl	Dec. 31, 2017USD ($)
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative Liability	$ 52,928	$ 41,677
Settlement Agreement [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Fair Value Asset
Fair Value Liability	$ 3,037
Crude Oil | Second Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	6,484
Derivative, Swap Type, Average Fixed Price | $ / bbl	51.09
Fair Value Asset	$ 0
Fair Value Liability	$ 7,888
Crude Oil | Third Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	6,455
Derivative, Swap Type, Average Fixed Price | $ / bbl	51.10
Fair Value Asset	$ 0
Fair Value Liability	$ 6,998
Crude Oil | Fourth Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	6,455
Derivative, Swap Type, Average Fixed Price | $ / bbl	51.10
Fair Value Asset	$ 0
Fair Value Liability	$ 5,960
Crude Oil | First Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	4,946
Derivative, Swap Type, Average Fixed Price | $ / bbl	52.03
Fair Value Asset	$ 0
Fair Value Liability	$ 3,372
Crude Oil | Second Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	4,921
Derivative, Swap Type, Average Fixed Price | $ / bbl	52.04
Fair Value Asset	$ 0
Fair Value Liability	$ 2,861
Crude Oil | Third Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	4,897
Derivative, Swap Type, Average Fixed Price | $ / bbl	52.05
Fair Value Asset	$ 0
Fair Value Liability	$ 2,404
Crude Oil | Fourth Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	4,898
Derivative, Swap Type, Average Fixed Price | $ / bbl	52.05
Fair Value Asset	$ 0
Fair Value Liability	$ 2,011
Crude Oil | First Quarter 2020 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	4,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	52.67
Fair Value Asset	$ 0
Fair Value Liability	$ 1,123
Crude Oil | Second Quarter 2020 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	4,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	52.67
Fair Value Asset	$ 0
Fair Value Liability	$ 866
Crude Oil | Third Quarter 2020 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	4,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	52.67
Fair Value Asset	$ 0
Fair Value Liability	$ 650
Crude Oil | Fourth Quarter 2020 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Notional Volume, per day | bbl	4,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	52.67
Fair Value Asset	$ 0
Fair Value Liability	$ 461
Louisiana Light Sweet [Member] | Second Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps-LLS
Notional Volume, per day | bbl	2,500
Derivative, Swap Type, Average Fixed Price | $ / bbl	55.18
Fair Value Asset	$ 0
Fair Value Liability	$ 2,735
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	2,500
Derivative, Swap Type, Average Fixed Price | $ / bbl	55.18
Fair Value Asset	$ 0
Fair Value Liability	$ 2,404
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	2,500
Derivative, Swap Type, Average Fixed Price | $ / bbl	55.18
Fair Value Asset	$ 0
Fair Value Liability	$ 2,003
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	2,500
Derivative, Swap Type, Average Fixed Price | $ / bbl	51.30
Fair Value Asset	$ 0
Fair Value Liability	$ 2,422
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	2,500
Derivative, Swap Type, Average Fixed Price | $ / bbl	51.30
Fair Value Asset	$ 0
Fair Value Liability	$ 2,144
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	2,500
Derivative, Swap Type, Average Fixed Price | $ / bbl	51.30
Fair Value Asset	$ 0
Fair Value Liability	$ 1,897
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	2,500
Derivative, Swap Type, Average Fixed Price | $ / bbl	51.30
Fair Value Asset	$ 0
Fair Value Liability	$ 1,660

Impact of Derivative Activities

Impact of Derivative Activities on Condensed Consolidated Statements of Income (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives	$ (18,795)	$ 17,016

Fair Value of Derivative Instru

Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ 36,820	$ 27,777
Derivative Asset, Noncurrent	32	0
Derivative assets	32	0
Derivative Liability, Noncurrent	16,108	13,900
Derivative Liability	52,928	41,677
Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative Liability	52,900
Commodity contracts | Current Derivative Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Current	0	0
Derivative liabilities	36,820	27,777
Commodity contracts | Noncurrent Derivative Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Noncurrent	32	0
Derivative Liability, Noncurrent	$ 16,108	$ 13,900

Summary of Property and Equipme

Summary of Property and Equipment (Detail) $ in Thousands	3 Months Ended
	Mar. 31, 2018USD ($)$ / bbl	Mar. 31, 2017USD ($)$ / bbl	Dec. 31, 2017USD ($)
Property, Plant and Equipment [Abstract]
Proved Oil and Gas Property, Full Cost Method	$ 624,747		$ 460,029
Unproved Oil and Gas Property, Full Cost Method	137,722		117,634
Oil and Gas Property, Full Cost Method, Gross	762,469		577,663
Other property and equipment	13,702		12,712
Total properties and equipment	776,171		590,375
Accumulated depreciation, depletion and amortization	(84,888)		(61,316)
Property and equipment, net (successful efforts method)	691,283		529,059
Unproved Oil and Gas Property excluded	137,700		$ 117,600
Undeveloped Leasehold Costs Transferred	100
Capitalized Costs, Proved Properties	700	$ 600
Interest Costs Capitalized	$ 2,200	$ 100
Amortization Expense Per Physical Unit of Production | $ / bbl	15.2	11.47

Summary of Long-Term Debt (Deta

Summary of Long-Term Debt (Detail) - USD ($)		Mar. 31, 2018	Dec. 31, 2017	Sep. 29, 2017
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 237,500,000
Revolving credit facility	[1]	195,000,000	$ 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		11,234,000	11,733,000
Debt Instrument, Unamortized Discount		(3,674,000)	(3,839,000)	(4,000,000)
Unamortized Debt Issuance Expense		(7,560,000)	(7,894,000)	$ (8,200,000)
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net		383,766,000	265,267,000
Long-term Debt		395,000,000	$ 277,000,000
Revolving Credit Facility
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 340,000,000
[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.

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail) - USD ($)		3 Months Ended	9 Months Ended
		Mar. 31, 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
Long-term Line of Credit	[1]	$ 195,000,000		$ 77,000,000
Debt Instrument, Discounted Percentage		98.00%
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		3,674,000		3,839,000	4,000,000
Unamortized Debt Issuance Expense		$ 7,560,000		7,894,000	$ 8,200,000
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		5.3407%
Revolving Credit Facility | Future Period Three [Member]
Debt Disclosure [Line Items]
Debt To E B I T D Ratio Maximum		3.50
Letter of Credit
Debt Disclosure [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.50%
Line of Credit [Member]
Debt Disclosure [Line Items]
Letters of Credit Outstanding, Amount		$ 800,000		$ 800,000
Line of Credit [Member] | Letter of Credit
Debt Disclosure [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 5,000,000
Second Lien Facility [Member]
Debt Disclosure [Line Items]
Interest rate option one, applicable margin rate over Adjusted LIBOR		7.00%
Interest rate option two, applicable margin rate		6.00%
Second Lien Facility, Initial Interest Rate		8.88%	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
[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.

Income Taxes (Details)

Income Taxes (Details) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Separation Agreement, Consulting Fees	$ 300,000
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	1.60%
Federal statutory income tax rate (as a percent)	2100.00%	35.20%	3500.00%
Deferred Tax Assets, Net, Noncurrent	$ 4,780,000		$ 4,943,000
Income Tax Examination, Penalties and Interest Expense	0	$ 0
Unrecognized Tax Benefits	$ 0

Executive Retirement (Detail)

Executive Retirement (Detail) $ in Millions	3 Months Ended
	Mar. 31, 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	Mar. 31, 2018		Dec. 31, 2017
Other current assets:
Tubular inventory and well materials	$ 5,391		$ 5,146
Prepaid expenses	1,365		1,104
Other Assets, Current	6,756		6,250
Other assets:
Deferred issuance costs of the Revolver	3,268		2,857
Earnest Money Deposits	0	[1]	3,210
Other	5		2,440
Other assets	3,273		8,507
Accounts payable and accrued liabilities:
Trade accounts payable	17,223		22,579
Drilling costs	32,005		22,389
Royalties and revenue – related	34,995		39,287
Compensation – related	1,791		2,975
Interest	366		223
Reserve for bankruptcy claims	3,933		3,933
Other	6,821		4,795
Accounts payable and accrued liabilities	97,134		96,181
Other liabilities:
Asset retirement obligations	3,777		3,286
Defined benefit pension obligations	940		971
Postretirement health care benefit obligations	491		476
Other	100		100
Other liabilities	$ 5,308		$ 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).

Assets and Liabilities Measured

Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Assets:
Derivative Asset, Noncurrent	$ 32	$ 0
Liabilities:
Commodity derivative liabilities – current	36,820	27,777
Derivative Liability, Noncurrent	16,108	13,900
Fair Value, Measurements, Recurring | Commodity contracts
Assets:
Derivative Asset, Noncurrent	32
Liabilities:
Commodity derivative liabilities – current	36,820	27,777
Derivative Liability, Noncurrent	16,108	13,900
Fair Value, Measurements, Recurring | Commodity contracts | Level 1
Assets:
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, Noncurrent	32
Liabilities:
Commodity derivative liabilities – current	36,820	27,777
Derivative Liability, Noncurrent	16,108	13,900
Fair Value, Measurements, Recurring | Commodity contracts | Level 3
Assets:
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	3 Months Ended
	Mar. 31, 2018USD ($)bbl
Commitments and Contingencies Disclosure [Line Items]
Long-term Purchase Commitment, Minimum Volume Required | bbl	8,000
Marketing Agreement	10
Asset Retirement Obligation	$ 3.8
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	7.9
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	$ 37

Shareholders' Equity Rollforwar

Shareholders' Equity Rollforward (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance		$ 221,639
Net income (loss)		10,295	$ 28,081
All Other Changes		(1,670)
As of ending balance		230,264
Share-based compensation		1,576	$ 846
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
Paid-in capital
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance		194,123
All Other Changes	[1]	988
As of ending balance		195,111
Retained earnings
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance		27,366
Net income (loss)		10,295
All Other Changes	[1]	(2,659)
As of ending balance		35,002
Accumulated other comprehensive income
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance		0
As of ending balance		$ 0
Time Vested Restricted Stock Units [Domain]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares, Issued		37,845
Performance Restricted Stock Units [Domain]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares, Issued		1,495
[1]	Includes equity-classified share-based compensation of $1.6 million during the three months ended March 31, 2018. During the three months ended March 31, 2018, 37,845 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. 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 accordance with the adoption of ASC Topic 606 (see Note 5).

Summary of Share-Based Compensa

Summary of Share-Based Compensation Expense (Detail) $ / shares in Units, $ in Thousands	1 Months Ended	3 Months Ended
	Jan. 31, 2017tranche	Mar. 31, 2018USD ($)$ / sharesshares	Mar. 31, 2017USD ($)$ / sharesshares
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based compensation (equity-classified) | $		$ 1,576	$ 846
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost | $		600
Defined Contribution Plan, Cost | $		100	100
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
Time Vested Restricted Stock Units [Domain]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant		310,700
Shares, Issued		37,845
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares		$ 36.52	$ 51.71
Time Vested Restricted Stock Units [Domain] | 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 [Domain] | 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 [Domain]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant			98,526
Performance Restricted Stock Units [Domain]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant		0	62,675
Shares, Issued		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 [Domain] | Minimum [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award		0.5963
Share-based Compensation Arrangements By Share-based Payment Award, Number Of Award Tranches | tranche	2
Share-based Compensation Arrangement by Share-based Payment Award, Shares, Expected to Vest, Percentage		0.00%
Performance Restricted Stock Units [Domain] | Maximum [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award		0.6218
Share-based Compensation Arrangements By Share-based Payment Award, Number Of Award Tranches | tranche	3
Share-based Compensation Arrangement by Share-based Payment Award, Shares, Expected to Vest, Percentage		200.00%
Performance Restricted Stock Units [Domain] | Year 1 [Domain] | Minimum [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares		$ 47.70
Performance Restricted Stock Units [Domain] | Share-based Compensation Award, Tranche Two [Member] | Maximum [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares		$ 65.28
Time Vested Restricted Stock Units - Employees [Domain] [Domain]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant		5,719	146,834
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

Interest Expense Components of

Interest Expense Components of Interest Expense (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018		Mar. 31, 2017
Banking and Thrift [Abstract]
Interest Expense, Borrowings	$ 6,048		$ 390
Amortization of Debt Discount (Premium)	165	[1]	0
Amortization of Debt Issuance Costs	631		188
Interest Paid, Capitalized	(2,243)		(40)
Interest Expense	$ 4,601		$ 538
[1]	Includes accretion of original issue discount attributable to the Second Lien Facility (see Note 8).

Components of Calculation of Ba

Components of Calculation of Basic and Diluted Earnings Per Share (Detail) - USD ($) shares in Thousands, $ in Thousands		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income (loss)		$ 10,295	$ 28,081
Weighted-average shares – basic		15,042	14,992
Effect of dilutive securities	[1]	39	134
Weighted-average shares – diluted		15,081	15,126
Net Income (Loss) Available to Common Stockholders, Basic		$ 10,295	$ 28,081
[1]	The number of dilutive securities for the three months ended March 31, 2018 and 2017, which is attributable to RSUs and PRSUs, was determined under the “treasury stock” method.