Ranger Oil (ROCC) 10-Q 10 May 17 2017 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	May 05, 2017
Document Documentand Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2,017
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 Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		14,992,018

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income tax benefit (expense)	$ 0
Net income (loss)	28,407
Weighted average shares outstanding – basic		85,941
Successor [Member]
Operating income (loss)	11,929
Reorganization items, net	28,407
Net income (loss)	28,407
Preferred stock dividends	0
Net income (loss) attributable to common shareholders	$ 28,407
Weighted average shares outstanding – basic	14,992
Weighted average shares outstanding – diluted	15,126
Revenues
Crude oil	$ 30,073
Natural gas liquids	2,302
Natural gas	2,343
Gain (loss) on sales of property and equipment, net	65
Other, net	602
Total revenues	35,385
Operating expenses
Lease operating	4,989
Gathering, processing and transportation	2,551
Production and ad valorem taxes	1,979
General and administrative	4,127
Exploration	0
Depreciation, depletion and amortization	9,810
Total operating expenses	23,456
Other income (expense)
Interest expense	(538)
Derivatives	17,016
Other, net	$ 0
Net income (loss) per share:
Basic (in dollars per share)	$ 1.89
Diluted (in dollars per share)	$ 1.88
Predecessor [Member]
Operating income (loss)		$ (12,507)
Reorganization items, net		(33,473)
Income tax benefit (expense)		0
Net income (loss)		(33,473)
Preferred stock dividends		(3,152)
Net income (loss) attributable to common shareholders		$ (36,625)
Weighted average shares outstanding – basic		85,941
Weighted average shares outstanding – diluted		85,941
Revenues
Crude oil		$ 25,966
Natural gas liquids		1,953
Natural gas		2,402
Gain (loss) on sales of property and equipment, net		(153)
Other, net		329
Total revenues		30,497
Operating expenses
Lease operating		6,192
Gathering, processing and transportation		3,818
Production and ad valorem taxes		753
General and administrative		17,102
Exploration		1,327
Depreciation, depletion and amortization		13,812
Total operating expenses		43,004
Other income (expense)
Interest expense		(24,434)
Derivatives		4,492
Other, net		$ (1,024)
Net income (loss) per share:
Basic (in dollars per share)		$ (0.43)
Diluted (in dollars per share)		$ (0.43)

CONDENSED CONSOLIDATED STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Net income (loss)	$ 28,407
Successor [Member]
Net income (loss)	28,407
Comprehensive income (loss)	28,407
Other comprehensive loss:
Change in pension and postretirement obligations, net of tax $0 in 2016	0
Total Other Comprehensive Income (Loss), Net of Tax	$ 0
Predecessor [Member]
Net income (loss)		$ (33,473)
Comprehensive income (loss)		(33,500)
Other comprehensive loss:
Change in pension and postretirement obligations, net of tax $0 in 2016		(27)
Total Other Comprehensive Income (Loss), Net of Tax		$ (27)

CONDENSED CONSOLIDATED STATEME4

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Successor [Member]
Change in pension and postretirement obligations, net of tax	$ 0
Predecessor [Member]
Change in pension and postretirement obligations, net of tax		$ (27)

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	$ 3,132	$ 6,761
Accounts receivable, net of allowance for doubtful accounts	38,667	29,095
Other current assets	3,110	3,028
Total current assets	44,909	38,884
Property and equipment, net (full cost method)	258,326	247,473
Other assets	5,176	5,329
Total assets	308,411	291,686
Current liabilities
Accounts payable and accrued liabilities	51,124	49,697
Commodity derivative liabilities – current	4,667	12,932
Total current liabilities	55,791	62,629
Derivative Liability, Noncurrent	3,694	14,437
Long-term Debt, Excluding Current Maturities	30,000	25,000
Other liabilities	4,136	4,072
Commitments and contingencies (Note 12)
Preferred Stock, Value, Issued	0
Shareholders’ equity:
Common stock of $0.01 par value – 45,000,000 shares authorized; 14,992,018 shares issued as of March 31, 2017 and December 31, 2016	150	150
Paid-in capital	191,456	190,621
Retained earnings (accumulated deficit)	23,111	(5,296)
Accumulated other comprehensive income	73	73
Total shareholders’ equity	214,790	185,548
Total liabilities and shareholders’ equity	$ 308,411	$ 291,686

CONDENSED CONSOLIDATED BALANCE6

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

CONDENSED CONSOLIDATED STATEME7

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash and cash equivalents – beginning of period	$ 6,761
Cash and cash equivalents – end of period	3,132
Cash flows from operating activities
Net income (loss)	28,407
Derivative contracts:
Share-based compensation (equity-classified)	846
Successor [Member]
Cash and cash equivalents – beginning of period	6,761
Net (decrease) increase in cash and cash equivalents	(3,629)
Cash and cash equivalents – end of period	3,132
Cash paid for:
Interest, net of amounts capitalized	348
Income taxes paid , net of (refunds)	0
Reorganization items, net	634
Non-cash investing and financing activities:
Capital Expenditures, Period Increase (Decrease)	2,262
Derivatives settled to reduce outstanding debt	0
Cash flows from operating activities
Net income (loss)	28,407
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	9,810
Accretion of firm transportation obligation	0
Derivative contracts:
Net gains	(17,016)
Cash settlements, net	(1,992)
(Gain) loss on sales of assets, net	(65)
Non-cash exploration expense	0
Non-cash interest expense	188
Share-based compensation (equity-classified)	846
Other, net	18
Changes in operating assets and liabilities, net	(10,728)
Net cash provided by operating activities	9,468
Cash flows from investing activities
Capital expenditures	(18,067)
Proceeds from sales of assets, net	0
Net cash used in investing activities	(18,067)
Cash flows from financing activities
Proceeds from credit facility borrowings	7,000
Repayment of credit facility borrowings	(2,000)
Other, net	(30)
Net cash provided by (used in) financing activities	$ 4,970
Predecessor [Member]
Cash and cash equivalents – beginning of period		$ 11,955
Net (decrease) increase in cash and cash equivalents		14,577
Cash and cash equivalents – end of period		26,532
Cash paid for:
Interest, net of amounts capitalized		594
Income taxes paid , net of (refunds)		(35)
Reorganization items, net		0
Non-cash investing and financing activities:
Capital Expenditures, Period Increase (Decrease)		(9,697)
Derivatives settled to reduce outstanding debt		22,860
Cash flows from operating activities
Net income (loss)		(33,473)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		13,812
Accretion of firm transportation obligation		175
Derivative contracts:
Net gains		(4,492)
Cash settlements, net		30,559
(Gain) loss on sales of assets, net		153
Non-cash exploration expense		856
Non-cash interest expense		1,269
Share-based compensation (equity-classified)		(602)
Other, net		(4)
Changes in operating assets and liabilities, net		20,278
Net cash provided by operating activities		28,531
Cash flows from investing activities
Capital expenditures		(14,005)
Proceeds from sales of assets, net		126
Net cash used in investing activities		(13,879)
Cash flows from financing activities
Proceeds from credit facility borrowings		0
Repayment of credit facility borrowings		(75)
Other, net		0
Net cash provided by (used in) financing activities		$ (75)

Nature of Operations

Nature of Operations	3 Months Ended
	Mar. 31, 2017
Accounting Policies [Abstract]
Nature of Operations	Nature of Operations Penn Virginia Corporation (together with its consolidated subsidiaries, unless the context otherwise requires, “Penn Virginia,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company engaged in the onshore exploration, development and production of oil, natural gas liquids (“NGLs”) and natural gas. Our current operations consist primarily of drilling unconventional horizontal development wells and operating our producing wells in the Eagle Ford Shale (the “Eagle Ford”) in South Texas. Our operations are substantially concentrated with over 90 percent of our production, revenues and capital expenditures attributable to this region. We also have less significant operations in Oklahoma, primarily consisting of non-operated properties in the Granite Wash. In August 2016, we terminated our remaining operations in the Marcellus Shale in Pennsylvania and are currently in the process of remediating the sites of our former wells in that region.

Basis of Presentation

Basis of Presentation	3 Months Ended
	Mar. 31, 2017
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Our unaudited Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of our subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our Condensed Consolidated Financial Statements have been included. Our Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Annual Report on Form 10-K for the year ended December 31, 2016 . Operating results for the three months ended March 31, 2017 , are not necessarily indicative of the results that may be expected for the year ending December 31, 2017 . Comparability of Financial Statements to Prior Periods We adopted and began applying the relevant guidance provided in GAAP with respect to the accounting and financial statement disclosures for entities that have emerged from bankruptcy proceedings (“Fresh Start Accounting”) on September 12, 2016. Accordingly, our Condensed Consolidated Financial Statements and Notes after September 12, 2016, are not comparable to the Condensed Consolidated Financial Statements and Notes through that date. To facilitate our financial statement presentations, we refer to the reorganized company in these Condensed Consolidated Financial Statements and Notes as the “Successor,” which is effectively a new reporting entity for financial reporting purposes, for periods subsequent to September 12, 2016, and the “Predecessor” for periods prior to September 13, 2016. In connection with our reorganization, we experienced a change in control as the outstanding common and preferred shares of the Predecessor were canceled and substantially all of the Successor’s new common stock was issued to the Predecessor’s creditors. Furthermore, our Condensed Consolidated Financial Statements and Notes have been presented with a “black line” division to delineate, where applicable, the lack of comparability between the Predecessor and Successor. In addition, we adopted the full cost method of accounting for our oil and gas properties effective with our adoption of Fresh Start Accounting. Accordingly, our results of operations, financial position and cash flows for the Successor periods will be substantially different from our historic trends. Going Concern Presumption Our unaudited Condensed Consolidated Financial Statements for the Successor periods have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. Subsequent Events Management has evaluated all of our activities through the issuance date of our Condensed Consolidated Financial Statements and has concluded that no subsequent events have occurred that would require recognition in our Condensed Consolidated Financial Statements or disclosure in the Notes thereto. Recently Issued Accounting Pronouncements In March 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017–07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017–07”) which provides guidance to improve the reporting of net benefit cost in financial statements. The guidance requires employers to disaggregate the service cost component from the other components of net benefit cost. The service cost component of net periodic benefit cost shall be reported in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period, except for amounts capitalized. All other components of net benefit cost shall be presented outside of a subtotal for income from operations. The line item used to present the components other than the service cost shall be disclosed if the other components are not presented in a separate line item or items. ASU 2017–07 is effective January 1, 2018 and is required to be applied retrospectively. ASU 2017–07 will be applicable to our legacy retiree benefit plans which cover a limited population of former employees. There is no service cost associated with these plans as they are not applicable to current employees, but rather “interest and other costs” associated with the legacy obligations. Upon the adoption of ASU 2017–07, the entirety of the expense associated with these plans will be presented as a component of the Other income (expense) caption in our Condensed Consolidated Statement of Operations. These costs are currently recognized as a component of ‘General and administrative’ expenses. The total cost associated with these plans is generally less than $0.1 million on an annual basis and is therefore not material. 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. 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 currently in the early stages of evaluating the requirements and the period for which we will adopt the standard. 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 12, our existing leases for office facilities and certain office equipment and potentially to certain drilling rig and completion contracts with terms in excess of twelve months to the extent we may have such contracts in the future. Our oil and natural gas gathering arrangements are fairly complex and involve multiple elements that could be construed as leases. Accordingly, we are continuing to evaluate the effect that ASU 2016–02 will have on our Consolidated Financial Statements and related disclosures as well as the period for which we will adopt the standard, however, at this time, we believe that we will likely adopt ASU 2016–02 in 2019. In May 2014, the FASB issued ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014–09 will replace most existing revenue recognition guidance in GAAP when it becomes effective on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. While traditional commodity sales transactions, property conveyances and joint interest arrangements in the oil and gas industry are not expected to be significantly impacted by ASU 2014–09, natural gas imbalances and other non-product revenues, including our ancillary marketing, gathering and transportation and water service revenues could be affected. Accordingly, we are continuing to evaluate the effect that ASU 2014–09 will have on our Consolidated Financial Statements and related disclosures, with a more focused analysis on these other revenue sources, which we do not believe are significant. We are also continuing to monitor developments regarding ASU 2014–09 that are unique to our industry. We will adopt ASU 2014–09 in 2018.

Bankruptcy Proceeding Bankruptc

Bankruptcy Proceeding Bankruptcy Proceedings	3 Months Ended
	Mar. 31, 2017
Reorganizations [Abstract]
Reorganization under Chapter 11 of US Bankruptcy Code Disclosure [Text Block]	Proceedings and Emergence On May 12, 2016 (the “Petition Date”), we and eight of our subsidiaries filed voluntary petitions ( In re Penn Virginia Corporation, et al, Case No. 16-32395 ) seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Virginia (the “Bankruptcy Court”). On August 11, 2016 (the “Confirmation Date”), the Bankruptcy Court confirmed our Second Amended Joint Chapter 11 Plan of Reorganization of Penn Virginia Corporation and its Debtor Affiliates (the “Plan”), and we subsequently emerged from bankruptcy on September 12, 2016 (the “Effective Date”). While our emergence from bankruptcy is effectively complete, certain administrative and claims resolution activities will continue under the authority of the Bankruptcy Court until complete. As of May 5, 2017, certain claims were still in the process of resolution. While most of these matters are unsecured claims for which shares of Successor common stock have been allocated, certain of these matters must be settled with cash payments. As of March 31, 2017, we had $ 3.9 million reserved for outstanding claims to be potentially settled in cash. This reserve is included as a component of “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet.

Accounts Receivable and Major C

Accounts Receivable and Major Customers	3 Months Ended
	Mar. 31, 2017
Receivables [Abstract]
Accounts Receivable and Major Customers	Accounts Receivable and Major Customers The following table summarizes our accounts receivable by type as of the dates presented: March 31, December 31, 2017 2016 Customers $ 23,331 $ 20,489 Joint interest partners 16,024 7,238 Other 1 1,693 3,789 41,048 31,516 Less: Allowance for doubtful accounts (2,381 ) (2,421 ) $ 38,667 $ 29,095 _______________________ 1 Includes amounts owed to us from joint venture partners for acquisitions in prior periods, severance tax refunds approved by state taxing authorities to be returned to us and other miscellaneous non-operating items. For the three months ended March 31, 2017 , one customer accounted for $31.2 million , or approximately 90% , of our consolidated product revenues. As of March 31, 2017 , $20.2 million , or approximately 86% , of our consolidated accounts receivable from customers was related to this customer. For the three months ended March 31, 2016 , two customers accounted for $26.5 million , or approximately 88% , of our consolidated product revenues. The revenues generated from these customers during the three months ended March 31, 2016 were $13.9 million and $12.6 million , or approximately 46% , and 42% of the consolidated total, respectively. As of December 31, 2016 , $16.7 million , or approximately 81% , of our consolidated accounts receivable from customers was related to these customers. No significant uncertainties exist related to the collectability of amounts owed to us by any of these customers.

Derivative Instruments

Derivative Instruments	3 Months Ended
	Mar. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments We utilize derivative instruments to mitigate our financial exposure to crude oil and natural gas 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 oil and gas 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 NYMEX Henry Hub gas and West Texas Intermediate crude oil 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. In March 2016, we terminated two of our pre-petition derivative contracts for $22.9 million and the proceeds were used to reduce our amount outstanding under our pre-petition credit agreement (the “RBL”). In connection with these transactions, the counterparties to the derivative contracts, which were also affiliates of lenders under the RBL, transferred the cash proceeds that were used for RBL repayments directly to the administrative agent under the RBL. Accordingly, all of these RBL repayments have been presented as non-cash financing activities on our Condensed Consolidated Statement of Cash Flows for the three months ended March 31, 2016. On May 13, 2016, we entered into new commodity derivative contracts, pursuant to which we hedged a substantial portion of our future crude oil production through the end of 2019 at a weighted-average price of approximately $49.12 per barrel. We are currently unhedged with respect to NGL and natural gas production. The following table sets forth our commodity derivative positions as of March 31, 2017 : Average Volume Per Weighted Average Price Fair Value Instrument Day Floor/Swap Ceiling Asset Liability Crude Oil: (barrels) ($/barrel) Second quarter 2017 Swaps 4,408 $ 48.62 $ — $ 1,003 Third quarter 2017 Swaps 4,408 $ 48.62 — 1,286 Fourth quarter 2017 Swaps 4,408 $ 48.62 — 1,355 First quarter 2018 Swaps 3,476 $ 49.12 — 881 Second quarter 2018 Swaps 3,476 $ 49.12 — 838 Third quarter 2018 Swaps 3,476 $ 49.12 — 780 Fourth quarter 2018 Swaps 3,476 $ 49.12 — 718 First quarter 2019 Swaps 2,916 $ 49.90 — 359 Second quarter 2019 Swaps 2,916 $ 49.90 — 338 Third quarter 2019 Swaps 2,916 $ 49.90 — 329 Fourth quarter 2019 Swaps 2,916 $ 49.90 — 332 Settlements to be paid in subsequent period — 142 Financial Statement Impact of Derivatives The impact of our derivative activities on income is included in “Derivatives” in our Condensed Consolidated Statements of Operations. The following table summarizes the effects of our derivative activities for the periods presented: Successor Predecessor Three Months Three Months Ended Ended March 31, 2017 March 31, 2016 Derivative gains $ 17,016 $ 4,492 The effects of derivative gains and (losses) and cash settlements (except for those cash settlements attributable to the aforementioned termination transactions) are reported as adjustments to reconcile net income (loss) to net cash provided by operating activities. These items are recorded in the “Derivative contracts” section of our Condensed Consolidated Statements of Cash Flows under “Net losses (gains)” and “Cash settlements, net.” The following table summarizes the fair values of our derivative instruments, as well as the locations of these instruments on our Condensed Consolidated Balance Sheets as of the dates presented: Fair Values as of March 31, 2017 December 31, 2016 Derivative Derivative Derivative Derivative Type Balance Sheet Location Assets Liabilities Assets Liabilities Commodity contracts Derivative assets/liabilities – current $ — $ 4,667 $ — $ 12,932 Commodity contracts Derivative assets/liabilities - noncurrent — 3,694 — 14,437 $ — $ 8,361 $ — $ 27,369 As of March 31, 2017 , we reported a net commodity derivative liability of $8.4 million . The contracts associated with this position are with three counterparties, all of which are investment grade financial institutions. This concentration may impact our overall credit risk, either positively or negatively, 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, 2017
Property, Plant and Equipment [Abstract]
Property and Equipment	Property and Equipment The following table summarizes our property and equipment as of the dates presented: March 31, December 31, 2017 2016 Oil and gas properties: Proved $ 272,947 $ 251,083 Unproved 3,468 4,719 Total oil and gas properties 276,415 255,802 Other property and equipment 3,575 3,575 Total properties and equipment 279,990 259,377 Accumulated depreciation, depletion and amortization (21,664 ) (11,904 ) $ 258,326 $ 247,473 Unproved property costs of $ 3.5 million and $ 4.7 million have been excluded from amortization as of March 31, 2017 and December 31, 2016, respectively. We transferred $ 1.9 million of undeveloped leasehold costs associated with acreage unlikely to be drilled or associated with proved undeveloped reserves, including capitalized interest, from unproved properties to the full cost pool during the three months ended March 31, 2017 . We capitalized internal costs of $ 0.6 million and interest of less than $ 0.1 million during the three months ended March 31, 2017 in accordance with our accounting policies. Average DD&A per BOE of proved oil and gas properties was $11.47 and $9.91 for the three months ended March 31, 2017 and 2016, respectively.

Long-Term Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt	Debt Credit Facility On the Effective Date upon our emergence from bankruptcy, we entered into our credit agreement (the “Credit Facility”). The Credit Facility provides for a $200 million revolving commitment and an initial borrowing base of $128 million . The Credit Facility also includes a $5 million sublimit for the issuance of letters of credit. 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. As of December 31, 2016, the borrowing base was $ 128 million . In March 2017, we and the lenders under the Credit Facility began the process for the April 2017 redetermination but we have not yet finalized the borrowing base increase as of the date of this quarterly report. Additionally, the Credit Facility lenders may, at their discretion, initiate a redetermination at any time during the six-month period between scheduled redeterminations. The Credit Facility is available to us to pay expenses associated with our bankruptcy proceedings and for general corporate purposes including working capital. The Credit Facility matures in September 2020. We had outstanding borrowings of $30 million and $25 million under the Credit Facility as of March 31, 2017 and December 31, 2016, respectively. We also had $0.8 million in letters of credit outstanding as of March 31, 2017 and December 31, 2016. The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 2.00% to 3.00% , determined based on the average availability under the Credit Facility or (b) a customary London interbank offered rate (“LIBOR”) plus an applicable margin ranging from 3.00% to 4.00% , determined based on the average availability under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on LIBOR borrowings is payable every one , three or six months, at our election, and is computed on the basis of a year of 360 days. As of March 31, 2017 , the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 3.915% . Unused commitment fees are charged at a rate of 0.50% . The Credit Facility is guaranteed by us and all of our subsidiaries (the “Guarantor Subsidiaries”). The guarantees under the Credit Facility are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. The parent company has no material independent assets or operations. There are no significant restrictions on the ability of the parent company or any of the Guarantor Subsidiaries to obtain funds through dividends, advances or loans. The obligations under the Credit Facility are secured by a first priority lien on substantially all of our assets. The Credit Facility requires us to maintain (1) a minimum interest coverage ratio (adjusted earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses as defined in the Credit Facility (“EBITDAX”) to adjusted interest expense), measured as of the last day of each fiscal quarter, of 3.00 to 1.00, (2) a minimum current ratio (as defined in the Credit Facility, which considers the unused portion of the total commitment as a current asset), measured as of the last day of each fiscal quarter of 1.00 to 1.00, and (3) a maximum leverage ratio (consolidated indebtedness to EBITDAX), measured as of the last day of each fiscal quarter, initially of 4.00 to 1.00, decreasing on December 31, 2017 to 3.75 to 1.00 and on March 31, 2018 and thereafter to 3.50 to 1.00. The Credit Facility also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, merger, consolidation or sale of assets, payment of dividends, and transactions with affiliates and other customary covenants. The Credit Facility contains customary events of default and remedies for credit facilities of this nature. If we do not comply with the financial and other covenants in the Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Credit Facility. As of March 31, 2017, we were in compliance with all of these covenants.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes We recognized a federal and state income tax expense for the three months ended March 31, 2017 at the blended rate of 35.52% ; however, the federal and state tax expense was fully offset by an adjustment to the valuation allowance against our net deferred tax assets. We recognized a federal income tax benefit for the three months ended March 31, 2016 at the statutory rate of 35% which was fully offset by a valuation allowance against our net deferred tax assets. We considered both the positive and negative evidence in determining that it was more likely than not that some portion or all of our deferred tax assets will not be realized, primarily as a result of cumulative losses. We received a state income tax refund of less than $0.1 million during the three month period ended March 31, 2016. We have evaluated the impact of the reorganization, including the change in control, resulting from our emergence from bankruptcy. From an income tax perspective, the most significant impact is attributable to our carryover tax attributes associated with our net operating losses (“NOLs”). We believe that the Successor will be able to fully absorb the cancellation of debt income realized by the Predecessor in connection with the reorganization with its adjusted NOL carryovers. The amount of the remaining NOL carryovers and the tax basis of our properties will be limited under Section 382 of the Internal Revenue Code due to the change in control that occurred upon our emergence from bankruptcy on the Effective Date. As the tax basis of our assets, primarily our oil and gas properties, is in excess of the carrying value, as adjusted in the Fresh Start Accounting process, the Successor is in a net deferred tax asset position. We have determined that it is more likely than not that we will not realize future income tax benefits from the additional tax basis and our remaining NOL carryovers. Accordingly, we have provided for a full valuation allowance of the underlying deferred tax assets.

Exit Activities

Exit Activities	3 Months Ended
	Mar. 31, 2017
Restructuring and Related Activities [Abstract]
Exit Activities	Exit Activities Prior to the Effective Date, the Predecessor committed to a number of actions, or exit activities, the most significant of which are described below. Reductions in Force In connection with efforts to reduce our administrative costs, we took certain actions to reduce our total employee headcount. In 2016, we reduced our total employee headcount by 53 employees including 10 of whom were terminated in the the three months ended March 31, 2016. We incurred charges of $ 0.7 million in connection with this action and paid a total of $ 0.4 million in severance and termination benefits during the three months ended March 31, 2016. We recognized an immaterial credit adjustment to the remaining obligation of less than $ 0.1 million during the three months ended March 31, 2017. There were no payments under these obligations during the three months ended March 31, 2017. The costs associated with these reduction-in-force actions are included as a component of our “General and administrative” expenses in our Condensed Consolidated Statements of Operations. The related obligation is included in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet. Drilling Rig Termination In connection with the suspension of our 2016 drilling program in the Eagle Ford, we terminated a drilling rig contract and incurred $ 0.4 million in early termination charges during the three months ended March 31, 2016. As this obligation represented a pre-petition liability of the Predecessor, it was discharged in connection with our emergence from bankruptcy. The vendor recovered a portion of the amount in the form of Successor common stock. Firm Transportation Obligation We had a contractual obligation for certain firm transportation capacity in the Appalachian region that was scheduled to expire in 2022 and, as a result of the sale of our natural gas assets in this region in 2012, we no longer had production available to satisfy this commitment. We originally recognized a liability in 2012 representing this obligation for the estimated discounted future net cash outflows over the remaining term of the contract. The accretion of the obligation through the Petition Date, net of any recoveries from periodic sales of our contractual capacity, was charged as an offset to Other revenue. During the three months ended March 31, 2016, we paid a total of $ 0.5 million and recognized accretion expense of $ 0.2 million attributable to the underlying obligation. In connection with our emergence from bankruptcy, we rejected the underlying contract.

Additional Balance Sheet Detail

Additional Balance Sheet Detail	3 Months Ended
	Mar. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Additional Balance Sheet Detail	Additional Balance Sheet Detail The following table summarizes components of selected balance sheet accounts as of the dates presented: March 31, December 31, 2017 2016 Other current assets: Tubular inventory and well materials $ 1,931 $ 2,125 Prepaid expenses 1,179 903 $ 3,110 $ 3,028 Other assets: Deferred issuance costs of the Credit Facility $ 2,597 $ 2,785 Other 2,579 2,544 $ 5,176 $ 5,329 Accounts payable and accrued liabilities: Trade accounts payable $ 6,617 $ 9,825 Drilling costs 4,741 2,479 Royalties and revenue – related 29,839 26,116 Compensation – related 1,345 2,557 Interest 57 55 Reserve for bankruptcy claims 3,922 3,922 Other 4,603 4,743 $ 51,124 $ 49,697 Other liabilities: Asset retirement obligations $ 2,532 $ 2,459 Defined benefit pension obligations 998 1,025 Postretirement health care benefit obligations 506 488 Other 100 100 $ 4,136 $ 4,072

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements We apply the authoritative accounting provisions for measuring 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 borrowings. As of March 31, 2017 , the carrying values of all of these financial instruments approximated fair value. Recurring Fair Value Measurements Certain financial assets and liabilities are measured at fair value on a recurring basis on our Condensed Consolidated Balance Sheets. The following tables summarize the valuation of those assets and liabilities as of the dates presented: March 31, 2017 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Liabilities: Commodity derivative liabilities – current $ (4,667 ) $ — $ (4,667 ) $ — Commodity derivative liabilities – noncurrent (3,694 ) — (3,694 ) — December 31, 2016 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Liabilities: Commodity derivative liabilities – current $ (12,932 ) $ — $ (12,932 ) $ — Commodity derivative liabilities – noncurrent (14,437 ) — (14,437 ) — Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one level of the fair value hierarchy to another level. In such instances, the transfer is deemed to have occurred at the beginning of the quarterly period in which the event or change in circumstances that caused the transfer occurred. There were no transfers during the three months ended March 31, 2017 and 2016 . We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below: • Commodity derivatives : We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for West Texas Intermediate crude oil and NYMEX Henry Hub gas closing prices as of the end of the reporting periods. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. Each of these is a level 2 input. Non-Recurring Fair Value Measurements The most significant non-recurring fair value measurements utilized in the preparation of our Condensed Consolidated Financial Statements are those attributable to the initial determination of AROs associated with the ongoing development of new oil and gas properties. The determination of the fair value of AROs is based upon regional market and facility specific information. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these significant fair value inputs are typically not observable, we have categorized the initial estimates as level 3 inputs. In addition, we utilize non-recurring fair value measurements with respect to the recognition and measurement of asset impairments, particularly during our Predecessor periods during which time we applied the successful efforts method to our oil and gas properties. The factors used to determine fair value for purposes of recognizing and measuring asset impairments while we applied the successful efforts method to our oil and gas properties during our Predecessor periods included, but were not limited to, estimates of proved and risk-adjusted probable reserves, future commodity prices, indicative sales prices for properties, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Because these significant fair value inputs were typically not observable, we have categorized the amounts as level 3 inputs. Under the full cost method, which we have applied since the Effective Date, we apply a ceiling test determination utilizing prescribed procedures. The full cost method is substantially different from the successful efforts method which relies upon fair value measurements.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2017
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 for gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production in the South Texas region as well as volume capacity support for certain downstream interstate pipeline transportation. Republic is obligated to gather and transport our crude oil and condensate from within a dedicated area in the Eagle Ford via a gathering system and intermediate takeaway pipeline connecting to a downstream interstate pipeline operated by a third party through 2041. We have a minimum volume commitment of 8,000 gross barrels of oil per day to Republic through 2031 under the gathering agreement. Under the marketing agreement, we have a 10 -year commitment to sell 8,000 barrels per day of crude oil to Republic, or any third party, utilizing Republic Marketing’s capacity on a certain downstream interstate pipeline. Excluding the potential impact of the effects of price escalation from commodity price changes, the minimum fee requirements under the Amended Agreements are as follows: $ 7.3 million for the remainder of 2017, $ 10.4 million for 2018, $ 11.7 million for 2019, $ 13.0 million for 2020 through 2025, $ 7.4 million for 2026, $ 3.8 million for 2027 through 2030 and $ 2.2 million for 2031. Drilling Commitments As of March 31, 2017, we had contractual commitments for two drilling rigs. The first rig is committed for the drilling of seven wells in the Eagle Ford based on a fixed daily rate. The second rig is subject to a six-month commitment which began in mid-March 2017. We have an approximate $ 2.7 million remaining obligation associated with this commitment. 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, 2017 , we continue to maintain a $0.1 million reserve for a litigation matter. As of March 31, 2017 , we also had AROs of approximately $2.7 million attributable to the plugging of abandoned wells.

Shareholders' Equity

Shareholders' Equity	3 Months Ended
	Mar. 31, 2017
Equity [Abstract]
Shareholders' Equity	Shareholders’ Equity The following tables summarize the components of our shareholders ’ equity (deficit) and the changes therein as of and for three months ended March 31, 2017 : As of As of December 31, All Other March 31, 2016 Net Income Changes 1 2017 Common stock 150 — — 150 Paid-in capital 190,621 — 835 191,456 Retained earnings (accumulated deficit) (5,296 ) 28,407 — 23,111 Accumulated other comprehensive income 73 — — 73 $ 185,548 $ 28,407 $ 835 $ 214,790 _______________________ 1 Includes equity-classified share-based compensation of $ 846 .

Share-Based Compensation and Ot

Share-Based Compensation and Other Benefit Plans	3 Months Ended
	Mar. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-Based Compensation and Other Benefit Plans	Share-Based Compensation and Other Benefit Plans Share-Based Compensation We recognize share-based compensation expense related to our share-based compensation plans as a component of “General and administrative” expense in our Condensed Consolidated Statements of Operations. In the Predecessor periods in 2016 we had outstanding equity-classified awards in the form of stock options, restricted stock units and deferred stock units. All outstanding equity-classified share-based compensation awards were canceled in connection with our emergence from bankruptcy. We reserved 749,600 shares of Successor common Stock for issuance under the Penn Virginia Corporation Management Incentive Plan for future share-based compensation awards. A total of 254,397 shares of time-vested restricted stock units (“RSUs”) and 62,675 performance restricted stock units (“PRSUs”) had been granted as of March 31, 2017 . The following table summarizes our share-based compensation expense (benefit) recognized for the periods presented: Successor Predecessor Three Months Three Months Ended Ended March 31, 2017 March 31, 2016 Equity-classified awards $ 846 $ (602 ) Liability-classified awards — (7 ) $ 846 $ (609 ) In January 2017, we granted 146,834 RSUs to certain employees with a grant-date fair value of $ 51.71 per RSU. The RSUs are being charged to expense on a straight-line basis over five years. In January 2017, we also granted 62,675 PRSUs to members of our senior management. The PRSUs were issued collectively in 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. The grant date fair values of the individual tranches were $ 65.28 for the first performance period tranche and $61.74 for each of the second and third performance period tranches. Due to their market condition, the PRSUs are being charged to expense using graded vesting over five years. The fair value of each PRSU award was estimated on the January 26, 2017 date of grant using a Monte Carlo simulation. Expected volatilities were based on historical volatilities. A risk-free rate of interest of 1.49% 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 and $0.2 million of expense attributable to the 401(k) Plan for the three months ended March 31, 2017 and 2016 , respectively. 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, 2017 and 2016 .

Interest Expense

Interest Expense	3 Months Ended
	Mar. 31, 2017
Banking and Thrift [Abstract]
Interest Expense	Interest Expense The following table summarizes the components of interest expense for the periods presented: Successor Predecessor Three Months Three Months Ended Ended March 31, 2017 March 31, 2016 Interest on borrowings and related fees $ 390 $ 23,305 Amortization of debt issuance costs 188 1,269 Capitalized interest (40 ) (140 ) $ 538 $ 24,434

Earnings (Loss) per Share

Earnings (Loss) per Share	3 Months Ended
	Mar. 31, 2017
Earnings Per Share [Abstract]
Earnings (Loss) per Share	Earnings (Loss) per Share The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings (loss) per share for the periods presented: Successor Predecessor Three Months Three Months Ended Ended March 31, 2017 March 31, 2016 Net income (loss) $ 28,407 $ (33,473 ) Less: Preferred stock dividends 1 — $ (3,152 ) Net income (loss) attributable to common shareholders – basic and diluted $ 28,407 $ (36,625 ) Weighted-average shares – basic 14,992 85,941 Effect of dilutive securities 2 134 — Weighted-average shares – diluted 15,126 85,941 _______________________ 1 Dividends attributable to our Series A 6% Convertible Perpetual Preferred Stock and Series B 6% Convertible Perpetual Preferred Stock (the “Series A and B Preferred Stock”) were excluded from the computation of diluted loss per share for the three months ended March 31, 2016 , as their assumed conversion would have been anti-dilutive. 2 The number of dilutive securities for the three months ended March 31, 2017, which is attributable to RSUs, was determined under the “treasury stock” method. The effect of PRSUs was anti-dilutive for the 2017 period. For the three months ended March 31, 2016 , approximately 27.6 million of potentially dilutive securities, including the Series A and Series B Preferred Stock, stock options and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted loss per common share.

Basis of Presentation (Policies

Basis of Presentation (Policies)	3 Months Ended
	Mar. 31, 2017
Schedule of Policies [Line Items]
New Accounting Pronouncements	Recently Issued Accounting Pronouncements In March 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017–07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017–07”) which provides guidance to improve the reporting of net benefit cost in financial statements. The guidance requires employers to disaggregate the service cost component from the other components of net benefit cost. The service cost component of net periodic benefit cost shall be reported in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period, except for amounts capitalized. All other components of net benefit cost shall be presented outside of a subtotal for income from operations. The line item used to present the components other than the service cost shall be disclosed if the other components are not presented in a separate line item or items. ASU 2017–07 is effective January 1, 2018 and is required to be applied retrospectively. ASU 2017–07 will be applicable to our legacy retiree benefit plans which cover a limited population of former employees. There is no service cost associated with these plans as they are not applicable to current employees, but rather “interest and other costs” associated with the legacy obligations. Upon the adoption of ASU 2017–07, the entirety of the expense associated with these plans will be presented as a component of the Other income (expense) caption in our Condensed Consolidated Statement of Operations. These costs are currently recognized as a component of ‘General and administrative’ expenses. The total cost associated with these plans is generally less than $0.1 million on an annual basis and is therefore not material. 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. 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 currently in the early stages of evaluating the requirements and the period for which we will adopt the standard. 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 12, our existing leases for office facilities and certain office equipment and potentially to certain drilling rig and completion contracts with terms in excess of twelve months to the extent we may have such contracts in the future. Our oil and natural gas gathering arrangements are fairly complex and involve multiple elements that could be construed as leases. Accordingly, we are continuing to evaluate the effect that ASU 2016–02 will have on our Consolidated Financial Statements and related disclosures as well as the period for which we will adopt the standard, however, at this time, we believe that we will likely adopt ASU 2016–02 in 2019. In May 2014, the FASB issued ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014–09 will replace most existing revenue recognition guidance in GAAP when it becomes effective on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. While traditional commodity sales transactions, property conveyances and joint interest arrangements in the oil and gas industry are not expected to be significantly impacted by ASU 2014–09, natural gas imbalances and other non-product revenues, including our ancillary marketing, gathering and transportation and water service revenues could be affected. Accordingly, we are continuing to evaluate the effect that ASU 2014–09 will have on our Consolidated Financial Statements and related disclosures, with a more focused analysis on these other revenue sources, which we do not believe are significant. We are also continuing to monitor developments regarding ASU 2014–09 that are unique to our industry. We will adopt ASU 2014–09 in 2018.
Basis of Presentation	Basis of Presentation Our unaudited Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of our subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our Condensed Consolidated Financial Statements have been included. Our Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Annual Report on Form 10-K for the year ended December 31, 2016 . Operating results for the three months ended March 31, 2017 , are not necessarily indicative of the results that may be expected for the year ending December 31, 2017 . Comparability of Financial Statements to Prior Periods We adopted and began applying the relevant guidance provided in GAAP with respect to the accounting and financial statement disclosures for entities that have emerged from bankruptcy proceedings (“Fresh Start Accounting”) on September 12, 2016. Accordingly, our Condensed Consolidated Financial Statements and Notes after September 12, 2016, are not comparable to the Condensed Consolidated Financial Statements and Notes through that date. To facilitate our financial statement presentations, we refer to the reorganized company in these Condensed Consolidated Financial Statements and Notes as the “Successor,” which is effectively a new reporting entity for financial reporting purposes, for periods subsequent to September 12, 2016, and the “Predecessor” for periods prior to September 13, 2016. In connection with our reorganization, we experienced a change in control as the outstanding common and preferred shares of the Predecessor were canceled and substantially all of the Successor’s new common stock was issued to the Predecessor’s creditors. Furthermore, our Condensed Consolidated Financial Statements and Notes have been presented with a “black line” division to delineate, where applicable, the lack of comparability between the Predecessor and Successor. In addition, we adopted the full cost method of accounting for our oil and gas properties effective with our adoption of Fresh Start Accounting. Accordingly, our results of operations, financial position and cash flows for the Successor periods will be substantially different from our historic trends. Going Concern Presumption Our unaudited Condensed Consolidated Financial Statements for the Successor periods have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. Subsequent Events Management has evaluated all of our activities through the issuance date of our Condensed Consolidated Financial Statements and has concluded that no subsequent events have occurred that would require recognition in our Condensed Consolidated Financial Statements or disclosure in the Notes thereto. Recently Issued Accounting Pronouncements In March 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017–07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017–07”) which provides guidance to improve the reporting of net benefit cost in financial statements. The guidance requires employers to disaggregate the service cost component from the other components of net benefit cost. The service cost component of net periodic benefit cost shall be reported in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period, except for amounts capitalized. All other components of net benefit cost shall be presented outside of a subtotal for income from operations. The line item used to present the components other than the service cost shall be disclosed if the other components are not presented in a separate line item or items. ASU 2017–07 is effective January 1, 2018 and is required to be applied retrospectively. ASU 2017–07 will be applicable to our legacy retiree benefit plans which cover a limited population of former employees. There is no service cost associated with these plans as they are not applicable to current employees, but rather “interest and other costs” associated with the legacy obligations. Upon the adoption of ASU 2017–07, the entirety of the expense associated with these plans will be presented as a component of the Other income (expense) caption in our Condensed Consolidated Statement of Operations. These costs are currently recognized as a component of ‘General and administrative’ expenses. The total cost associated with these plans is generally less than $0.1 million on an annual basis and is therefore not material. 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. 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 currently in the early stages of evaluating the requirements and the period for which we will adopt the standard. 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 12, our existing leases for office facilities and certain office equipment and potentially to certain drilling rig and completion contracts with terms in excess of twelve months to the extent we may have such contracts in the future. Our oil and natural gas gathering arrangements are fairly complex and involve multiple elements that could be construed as leases. Accordingly, we are continuing to evaluate the effect that ASU 2016–02 will have on our Consolidated Financial Statements and related disclosures as well as the period for which we will adopt the standard, however, at this time, we believe that we will likely adopt ASU 2016–02 in 2019. In May 2014, the FASB issued ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014–09 will replace most existing revenue recognition guidance in GAAP when it becomes effective on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. While traditional commodity sales transactions, property conveyances and joint interest arrangements in the oil and gas industry are not expected to be significantly impacted by ASU 2014–09, natural gas imbalances and other non-product revenues, including our ancillary marketing, gathering and transportation and water service revenues could be affected. Accordingly, we are continuing to evaluate the effect that ASU 2014–09 will have on our Consolidated Financial Statements and related disclosures, with a more focused analysis on these other revenue sources, which we do not believe are significant. We are also continuing to monitor developments regarding ASU 2014–09 that are unique to our industry. We will adopt ASU 2014–09 in 2018.
Fair Value Measurements	We apply the authoritative accounting provisions for measuring fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date.
Fair Value, Measurements, Recurring
Schedule of Policies [Line Items]
Fair Value Measurements	We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below: • Commodity derivatives : We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for West Texas Intermediate crude oil and NYMEX Henry Hub gas closing prices as of the end of the reporting periods. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. Each of these is a level 2 input.
Fair Value, Measurements, Nonrecurring
Schedule of Policies [Line Items]
Fair Value Measurements	Non-Recurring Fair Value Measurements The most significant non-recurring fair value measurements utilized in the preparation of our Condensed Consolidated Financial Statements are those attributable to the initial determination of AROs associated with the ongoing development of new oil and gas properties. The determination of the fair value of AROs is based upon regional market and facility specific information. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these significant fair value inputs are typically not observable, we have categorized the initial estimates as level 3 inputs. In addition, we utilize non-recurring fair value measurements with respect to the recognition and measurement of asset impairments, particularly during our Predecessor periods during which time we applied the successful efforts method to our oil and gas properties. The factors used to determine fair value for purposes of recognizing and measuring asset impairments while we applied the successful efforts method to our oil and gas properties during our Predecessor periods included, but were not limited to, estimates of proved and risk-adjusted probable reserves, future commodity prices, indicative sales prices for properties, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Because these significant fair value inputs were typically not observable, we have categorized the amounts as level 3 inputs. Under the full cost method, which we have applied since the Effective Date, we apply a ceiling test determination utilizing prescribed procedures. The full cost method is substantially different from the successful efforts method which relies upon fair value measurements.

Accounts Receivable and Major25

Accounts Receivable and Major Customers (Tables)	3 Months Ended
	Mar. 31, 2017
Receivables [Abstract]
Summary of Accounts Receivable	The following table summarizes our accounts receivable by type as of the dates presented: March 31, December 31, 2017 2016 Customers $ 23,331 $ 20,489 Joint interest partners 16,024 7,238 Other 1 1,693 3,789 41,048 31,516 Less: Allowance for doubtful accounts (2,381 ) (2,421 ) $ 38,667 $ 29,095 _______________________ 1 Includes amounts owed to us from joint venture partners for acquisitions in prior periods, severance tax refunds approved by state taxing authorities to be returned to us and other miscellaneous non-operating items.

Derivative Instruments (Tables)

Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivative Positions	The following table sets forth our commodity derivative positions as of March 31, 2017 : Average Volume Per Weighted Average Price Fair Value Instrument Day Floor/Swap Ceiling Asset Liability Crude Oil: (barrels) ($/barrel) Second quarter 2017 Swaps 4,408 $ 48.62 $ — $ 1,003 Third quarter 2017 Swaps 4,408 $ 48.62 — 1,286 Fourth quarter 2017 Swaps 4,408 $ 48.62 — 1,355 First quarter 2018 Swaps 3,476 $ 49.12 — 881 Second quarter 2018 Swaps 3,476 $ 49.12 — 838 Third quarter 2018 Swaps 3,476 $ 49.12 — 780 Fourth quarter 2018 Swaps 3,476 $ 49.12 — 718 First quarter 2019 Swaps 2,916 $ 49.90 — 359 Second quarter 2019 Swaps 2,916 $ 49.90 — 338 Third quarter 2019 Swaps 2,916 $ 49.90 — 329 Fourth quarter 2019 Swaps 2,916 $ 49.90 — 332 Settlements to be paid in subsequent period — 142
Impact of Derivative Activities on Condensed Consolidated Statements of Income	The impact of our derivative activities on income is included in “Derivatives” in our Condensed Consolidated Statements of Operations. The following table summarizes the effects of our derivative activities for the periods presented: Successor Predecessor Three Months Three Months Ended Ended March 31, 2017 March 31, 2016 Derivative gains $ 17,016 $ 4,492
Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets	The following table summarizes the fair values of our derivative instruments, as well as the locations of these instruments on our Condensed Consolidated Balance Sheets as of the dates presented: Fair Values as of March 31, 2017 December 31, 2016 Derivative Derivative Derivative Derivative Type Balance Sheet Location Assets Liabilities Assets Liabilities Commodity contracts Derivative assets/liabilities – current $ — $ 4,667 $ — $ 12,932 Commodity contracts Derivative assets/liabilities - noncurrent — 3,694 — 14,437 $ — $ 8,361 $ — $ 27,369

Property and Equipment (Tables)

Property and Equipment (Tables)	3 Months Ended
	Mar. 31, 2017
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, 2017 2016 Oil and gas properties: Proved $ 272,947 $ 251,083 Unproved 3,468 4,719 Total oil and gas properties 276,415 255,802 Other property and equipment 3,575 3,575 Total properties and equipment 279,990 259,377 Accumulated depreciation, depletion and amortization (21,664 ) (11,904 ) $ 258,326 $ 247,473

Additional Balance Sheet Deta28

Additional Balance Sheet Detail (Tables)	3 Months Ended
	Mar. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Components of Selected Balance Sheet Accounts	The following table summarizes components of selected balance sheet accounts as of the dates presented: March 31, December 31, 2017 2016 Other current assets: Tubular inventory and well materials $ 1,931 $ 2,125 Prepaid expenses 1,179 903 $ 3,110 $ 3,028 Other assets: Deferred issuance costs of the Credit Facility $ 2,597 $ 2,785 Other 2,579 2,544 $ 5,176 $ 5,329 Accounts payable and accrued liabilities: Trade accounts payable $ 6,617 $ 9,825 Drilling costs 4,741 2,479 Royalties and revenue – related 29,839 26,116 Compensation – related 1,345 2,557 Interest 57 55 Reserve for bankruptcy claims 3,922 3,922 Other 4,603 4,743 $ 51,124 $ 49,697 Other liabilities: Asset retirement obligations $ 2,532 $ 2,459 Defined benefit pension obligations 998 1,025 Postretirement health care benefit obligations 506 488 Other 100 100 $ 4,136 $ 4,072

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following tables summarize the valuation of those assets and liabilities as of the dates presented: March 31, 2017 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Liabilities: Commodity derivative liabilities – current $ (4,667 ) $ — $ (4,667 ) $ — Commodity derivative liabilities – noncurrent (3,694 ) — (3,694 ) — December 31, 2016 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Liabilities: Commodity derivative liabilities – current $ (12,932 ) $ — $ (12,932 ) $ — Commodity derivative liabilities – noncurrent (14,437 ) — (14,437 ) —

Shareholders' Equity (Tables)

Shareholders' Equity (Tables)	3 Months Ended
	Mar. 31, 2017
Equity [Abstract]
Schedule of Stockholders Equity	The following tables summarize the components of our shareholders ’ equity (deficit) and the changes therein as of and for three months ended March 31, 2017 : As of As of December 31, All Other March 31, 2016 Net Income Changes 1 2017 Common stock 150 — — 150 Paid-in capital 190,621 — 835 191,456 Retained earnings (accumulated deficit) (5,296 ) 28,407 — 23,111 Accumulated other comprehensive income 73 — — 73 $ 185,548 $ 28,407 $ 835 $ 214,790 _______________________ 1 Includes equity-classified share-based compensation of $ 846 .

Share-Based Compensation (Table

Share-Based Compensation (Tables)	3 Months Ended
	Mar. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of Share-Based Compensation Expense	The following table summarizes our share-based compensation expense (benefit) recognized for the periods presented: Successor Predecessor Three Months Three Months Ended Ended March 31, 2017 March 31, 2016 Equity-classified awards $ 846 $ (602 ) Liability-classified awards — (7 ) $ 846 $ (609 )

Interest Expense (Tables)

Interest Expense (Tables)	3 Months Ended
	Mar. 31, 2017
Banking and Thrift [Abstract]
Interest Expense Net Disclosure
Debt Instrument [Line Items]
Interest Expense	Interest Expense The following table summarizes the components of interest expense for the periods presented: Successor Predecessor Three Months Three Months Ended Ended March 31, 2017 March 31, 2016 Interest on borrowings and related fees $ 390 $ 23,305 Amortization of debt issuance costs 188 1,269 Capitalized interest (40 ) (140 ) $ 538 $ 24,434

Earnings per Share (Tables)

Earnings per Share (Tables)	3 Months Ended
	Mar. 31, 2017
Earnings Per Share [Abstract]
Components of Calculation of Basic and Diluted Earnings Per Share	_______________________ 1 Dividends attributable to our Series A 6% Convertible Perpetual Preferred Stock and Series B 6% Convertible Perpetual Preferred Stock (the “Series A and B Preferred Stock”) were excluded from the computation of diluted loss per share for the three months ended March 31, 2016 , as their assumed conversion would have been anti-dilutive. 2 The number of dilutive securities for the three months ended March 31, 2017, which is attributable to RSUs, was determined under the “treasury stock” method. The effect of PRSUs was anti-dilutive for the 2017 period. For the three months ended March 31, 2016 , approximately 27.6 million of potentially dilutive securities, including the Series A and Series B Preferred Stock, stock options and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted loss per common share. The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings (loss) per share for the periods presented: Successor Predecessor Three Months Three Months Ended Ended March 31, 2017 March 31, 2016 Net income (loss) $ 28,407 $ (33,473 ) Less: Preferred stock dividends 1 — $ (3,152 ) Net income (loss) attributable to common shareholders – basic and diluted $ 28,407 $ (36,625 ) Weighted-average shares – basic 14,992 85,941 Effect of dilutive securities 2 134 — Weighted-average shares – diluted 15,126 85,941

Nature of Operations Nature of

Nature of Operations Nature of Operations (Details)	3 Months Ended
	Mar. 31, 2017
TEXAS | Eagle Ford Shale
Concentration Risk [Line Items]
Concentration risk, percentage (more than)	90.00%

Bankruptcy Proceeding Bankrup35

Bankruptcy Proceeding Bankruptcy Proceeding (Details)	May 12, 2016subsidiary
Reorganizations [Abstract]
Number of Subsidiaries Filing Chapter 11 Bankruptcy	8

Summary of Accounts Receivable

Summary of Accounts Receivable (Detail) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Receivables [Abstract]
Customers	$ 23,331	$ 20,489
Joint interest partners	16,024	7,238
Other	1,693	3,789
Accounts Receivable, Gross, Current, Total	41,048	31,516
Less: Allowance for doubtful accounts	(2,381)	(2,421)
Accounts receivable, net of allowance for doubtful accounts	$ 38,667	$ 29,095

Accounts Receivable and Major37

Accounts Receivable and Major Customers - Additional Information (Detail) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2017USD ($)Customer	Mar. 31, 2016USD ($)Customer	Dec. 31, 2016USD ($)
Accounts Receivable | Credit Concentration Risk
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration risk, percentage			81.00%
Accounts receivable, major customers			$ 16.7
Successor [Member] | Sales Revenue | Customer Concentration Risk
Accounts, Notes, Loans and Financing Receivable [Line Items]
Number of major customers | Customer	1
Revenues, major customers	$ 31.2
Concentration risk, percentage	90.00%
Successor [Member] | Accounts Receivable | Credit Concentration Risk
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration risk, percentage	86.00%
Accounts receivable, major customers	$ 20.2
Predecessor [Member] | Sales Revenue | Customer Concentration Risk
Accounts, Notes, Loans and Financing Receivable [Line Items]
Number of major customers | Customer		2
Revenues, major customers		$ 26.5
Concentration risk, percentage		88.00%
Predecessor [Member] | Sales Revenue | Customer Concentration Risk | Major Customer 1
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers		$ 13.9
Concentration risk, percentage		46.00%
Predecessor [Member] | Sales Revenue | Customer Concentration Risk | Major Customer 2
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers		$ 12.6
Concentration risk, percentage		42.00%

Derivative Instruments - Additi

Derivative Instruments - Additional Information (Detail) $ in Thousands	3 Months Ended
	Mar. 31, 2017USD ($)Entity$ / bbl	Mar. 31, 2016USD ($)	Dec. 31, 2016USD ($)
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative assets	$ 8,361		$ 27,369
Commodity contracts
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative assets	$ 8,400
Number of derivative counterparties | Entity	3
Commodity contracts | Natural Gas
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Third-party quoted forward prices	NYMEX Henry Hub gas
Commodity contracts | Crude Oil
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Third-party quoted forward prices	West Texas Intermediate crude oil
Predecessor [Member]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivatives settled to reduce outstanding debt		$ 22,860
Predecessor [Member] | Crude Oil
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.12
Predecessor [Member] | March 2016 [Domain]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivatives Settled		$ 22,900

Commodity Derivative Positions

Commodity Derivative Positions (Detail) $ in Thousands	3 Months Ended
	Mar. 31, 2017USD ($)bbl$ / bbl	Dec. 31, 2016USD ($)
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative Liability	$ 8,361	$ 27,369
Settlement Agreement [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Fair Value Asset	0
Fair Value Liability	$ 142
Crude Oil | Second Quarter 2017 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	4,408
Derivative, Swap Type, Average Fixed Price | $ / bbl	48.62
Fair Value Asset	$ 0
Fair Value Liability	$ 1,003
Crude Oil | Third Quarter 2017 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	4,408
Derivative, Swap Type, Average Fixed Price | $ / bbl	48.62
Fair Value Asset	$ 0
Fair Value Liability	$ 1,286
Crude Oil | Fourth Quarter 2017 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	4,408
Derivative, Swap Type, Average Fixed Price | $ / bbl	48.62
Fair Value Asset	$ 0
Fair Value Liability	$ 1,355
Crude Oil | First Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	3,476
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.12
Fair Value Asset	$ 0
Fair Value Liability	$ 881
Crude Oil | Second Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	3,476
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.12
Fair Value Asset	$ 0
Fair Value Liability	$ 838
Crude Oil | Third Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	3,476
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.12
Fair Value Asset	$ 0
Fair Value Liability	$ 780
Crude Oil | Fourth Quarter 2018 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	3,476
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.12
Fair Value Asset	$ 0
Fair Value Liability	$ 718
Crude Oil | First Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	2,916
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.90
Fair Value Asset	$ 0
Fair Value Liability	$ 359
Crude Oil | Second Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	2,916
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.90
Fair Value Asset	$ 0
Fair Value Liability	$ 338
Crude Oil | Third Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	2,916
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.90
Fair Value Asset	$ 0
Fair Value Liability	$ 329
Crude Oil | Fourth Quarter 2019 [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	2,916
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.90
Fair Value Asset	$ 0
Fair Value Liability	$ 332

Impact of Derivative Activities

Impact of Derivative Activities on Condensed Consolidated Statements of Income (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Successor [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives	$ 17,016
Predecessor [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives		$ 4,492

Fair Value of Derivative Instru

Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative assets	$ 0	$ 0
Commodity derivative liabilities – current	4,667	12,932
Derivative Liability, Noncurrent	3,694	14,437
Derivative Liability	8,361	27,369
Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative Liability	8,400
Commodity contracts | Derivative assets/liabilities - current
Derivatives, Fair Value [Line Items]
Derivative assets, current	0	0
Commodity derivative liabilities – current	4,667	12,932
Commodity contracts | Noncurrent Derivative Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Noncurrent	0	0
Derivative Liability, Noncurrent	$ 3,694	$ 14,437

Summary of Property and Equipme

Summary of Property and Equipment (Detail) $ in Thousands	3 Months Ended
	Mar. 31, 2017USD ($)$ / bbl	Dec. 31, 2016USD ($)	Mar. 31, 2016$ / bbl
Property, Plant and Equipment [Line Items]
Unproved Oil and Gas Property excluded	$ 3,500	$ 4,700
Proved Oil and Gas Property, Full Cost Method	272,947	251,083
Unproved Oil and Gas Property, Full Cost Method	3,468	4,719
Oil and Gas Property, Full Cost Method, Gross	276,415	255,802
Other property and equipment	3,575	3,575
Total properties and equipment	279,990	259,377
Accumulated depreciation, depletion and amortization	(21,664)	(11,904)
Property and equipment, net (successful efforts method)	258,326	$ 247,473
Undeveloped Leasehold Costs Transferred	1,900
Capitalized Costs, Proved Properties	600
Interest Costs Capitalized	$ 100
Successor [Member]
Property, Plant and Equipment [Line Items]
Amortization Expense Per Physical Unit of Production | $ / bbl	11.47
Predecessor [Member]
Property, Plant and Equipment [Line Items]
Amortization Expense Per Physical Unit of Production | $ / bbl			9.905451656000

Summary of Long-Term Debt (Deta

Summary of Long-Term Debt (Detail) - USD ($)	Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 128,000,000	$ 128,000,000
Revolving credit facility	30,000,000	$ 25,000,000
Revolving Credit Facility
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 200,000,000

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail) - USD ($)	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Debt Disclosure [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 128,000,000	$ 128,000,000
Long-term Line of Credit	$ 30,000,000	25,000,000
Interest Coverage Ratio, Maximum	3
Current Ratio	1
Revolving Credit Facility
Debt Disclosure [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 200,000,000
Interest Rate at Period End	3.915%
Revolving Credit Facility | Future Period [Member]
Debt Disclosure [Line Items]
Debt To E B I T D Ratio Maximum	4
Revolving Credit Facility | Future Period Two [Member]
Debt Disclosure [Line Items]
Debt To E B I T D Ratio Maximum	3.75
Revolving Credit Facility | Future Period Three [Member]
Debt Disclosure [Line Items]
Debt To E B I T D Ratio Maximum	3.50
Letter of Credit
Debt Disclosure [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.50%
Line of Credit [Member]
Debt Disclosure [Line Items]
Letters of Credit Outstanding, Amount	$ 800,000	$ 800,000
Line of Credit [Member] | Letter of Credit
Debt Disclosure [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 5,000,000
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%
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%
Interest Payable One [Member] | Revolving Credit Facility
Debt Disclosure [Line Items]
Debt Instrument, Interest Payable Period	1 month
Interest Payable Two [Member] | Revolving Credit Facility
Debt Disclosure [Line Items]
Debt Instrument, Interest Payable Period	3 months
Interest Payable Three [Member] | Revolving Credit Facility
Debt Disclosure [Line Items]
Debt Instrument, Interest Payable Period	6 months

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income Tax Disclosure [Abstract]
Blended tax rate (as a percent)	35.52%
Federal statutory income tax rate (as a percent)	35.00%
Income taxes refund received (less than)		$ 0.1

Exit Activities (Detail)

Exit Activities (Detail) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2017USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2016
Predecessor [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Number of Positions Eliminated	10		53
Severance and Termination Benefits	$ 400	$ 700
Liabilities Subject to Compromise, Early Contract Termination Fees		400
Payments for Restructuring		500
Restructuring Reserve, Accretion of Obligation		$ 175
Successor [Member]
Restructuring Cost and Reserve [Line Items]
Severance and Termination Adjustment	100
Restructuring Reserve, Accretion of Obligation	$ 0

Components of Selected Balance

Components of Selected Balance Sheet Accounts (Detail) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Bankruptcy Claims, amount reserved for outstanding claims	$ 3,922	$ 3,922
Other current assets:
Tubular inventory and well materials	1,931	2,125
Prepaid expenses	1,179	903
Other Assets, Current	3,110	3,028
Other assets:
Deferred issuance costs of the Revolver	2,597	2,785
Other	2,579	2,544
Other assets	5,176	5,329
Accounts payable and accrued liabilities:
Trade accounts payable	6,617	9,825
Drilling costs	4,741	2,479
Royalties and revenue – related	29,839	26,116
Compensation – related	1,345	2,557
Interest	57	55
Other	4,603	4,743
Accounts payable and accrued liabilities	51,124	49,697
Other liabilities:
Asset retirement obligations	2,532	2,459
Defined benefit pension obligations	998	1,025
Postretirement health care benefit obligations	506	488
Other	100	100
Other liabilities	$ 4,136	$ 4,072

Assets and Liabilities Measured

Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative liabilities – current	$ 4,667	$ 12,932
Liabilities:
Derivative Liability, Noncurrent	3,694	14,437
Fair Value, Measurements, Recurring | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative liabilities – current	4,667	12,932
Liabilities:
Derivative Liability, Noncurrent	3,694	14,437
Fair Value, Measurements, Recurring | Commodity contracts | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative liabilities – current	0	0
Liabilities:
Derivative Liability, Noncurrent	0	0
Fair Value, Measurements, Recurring | Commodity contracts | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative liabilities – current	4,667	12,932
Liabilities:
Derivative Liability, Noncurrent	3,694	14,437
Fair Value, Measurements, Recurring | Commodity contracts | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative liabilities – current	0	0
Liabilities:
Derivative Liability, Noncurrent	$ 0	$ 0

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)bbl
Commitments and Contingencies Disclosure [Line Items]
Long-term Purchase Commitment, Minimum Volume Required | bbl	8,000
Marketing Agreement	10
Asset Retirement Obligation	$ 2.7
Legal Reserve
Commitments and Contingencies Disclosure [Line Items]
Reserve established for contingency matters	0.1
Crude Oil Gathering And Transportation Services
Commitments and Contingencies Disclosure [Line Items]
Contractual obligation, balance of 2015	7.3
Contractual Obligation, Due in Third Year	10.4
Contractual Obligation, Due in Fourth Year	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	$ 2.7

Shareholders' Equity Rollforwar

Shareholders' Equity Rollforward (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2017USD ($)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance	$ 185,548
Net income (loss)	28,407
All Other Changes	835
As of ending balance	214,790
Share-based compensation	846
Common stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance	150
As of ending balance	150
Paid-in capital
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance	190,621
All Other Changes	835	[1]
As of ending balance	191,456
Retained earnings (accumulated deficit)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance	(5,296)
Net income (loss)	28,407
As of ending balance	23,111
Accumulated other comprehensive income
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance	73
As of ending balance	$ 73
[1]	ncludes equity-classified share-based compensation of $846.

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$ / sharesshares	Mar. 31, 2017USD ($)shares	Mar. 31, 2016USD ($)
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based compensation (equity-classified)		$ 846
Time Vested Restricted Stock Units [Domain]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | shares	146,834	254,397
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares	$ 51.71
Share-based Compensation Arrangements By Share-based Payment Award, Award Amortization Period	5 years
Performance Restricted Stock Units [Domain]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | shares		62,675
Share-based Compensation Arrangements By Share-based Payment Award, Award Amortization Period	5 years
Share-based Compensation Arrangements By Share-based Payment Award, Number Of Award Tranches | tranche	3
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		1.49%
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, 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, Shares, Expected to Vest, Percentage	200.00%
Performance Restricted Stock Units [Domain] | Year 1 [Domain]
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
Performance Restricted Stock Units [Domain] | Year 2
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	61.74
Performance Restricted Stock Units [Domain] | Year 3
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	$ 61.74
Employees and Directors [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | shares		749,600
Predecessor [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Other Stock Based Compensation Expense			$ (602)
Share-based compensation (equity-classified)			(602)
Allocated Share-based Compensation Expense			(609)
Defined Contribution Plan, Cost Recognized			200
Predecessor [Member] | Other Pension Plan, Postretirement or Supplemental Plans [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Pension and Other Postretirement Benefit Expense			100
Predecessor [Member] | Liability-classified awards
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based compensation (equity-classified)			$ 7
Successor [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Other Stock Based Compensation Expense		$ 846
Share-based compensation (equity-classified)		846
Allocated Share-based Compensation Expense		846
Defined Contribution Plan, Cost Recognized		100
Successor [Member] | Other Pension Plan, Postretirement or Supplemental Plans [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Pension and Other Postretirement Benefit Expense		100
Successor [Member] | Liability-classified awards
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based compensation (equity-classified)		$ 0

Interest Expense Components of

Interest Expense Components of Interest Expense (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Components of Interest Expense [Line Items]
Interest Paid, Capitalized	$ 40
Successor [Member]
Components of Interest Expense [Line Items]
Interest Expense	538
Amortization of Debt Issuance Costs	188
Interest Expense, Borrowings	$ 390
Predecessor [Member]
Components of Interest Expense [Line Items]
Interest Expense		$ 24,434
Interest Paid, Capitalized		140
Amortization of Debt Issuance Costs		1,269
Interest Expense, Borrowings		$ 23,305

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, 2017	Mar. 31, 2016
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income (loss)	$ 28,407
Weighted-average shares – basic		85,941
Effect of dilutive securities		0
Successor [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income (loss)	28,407
Less: Preferred stock dividends	0
Net income (loss) attributable to common shareholders, Basic	28,407
Net loss attributable to common shareholders, Diluted	$ 28,407
Weighted-average shares – basic	14,992
Effect of dilutive securities	134
Weighted-average shares – diluted	15,126
Predecessor [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income (loss)		$ (33,473)
Less: Preferred stock dividends		(3,152)
Net income (loss) attributable to common shareholders, Basic		(36,625)
Net loss attributable to common shareholders, Diluted		$ (36,625)
Weighted-average shares – basic		85,941
Weighted-average shares – diluted		85,941
Potentially dilutive securities with the effect of being anti-dilutive excluded from the calculation of diluted earnings per common share		27,600
Predecessor [Member] | Series A Preferred Stock
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Perpetual Preferred Stock, dividend rate (as a percent)	6.00%
Predecessor [Member] | Series B Preferred Stock
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Perpetual Preferred Stock, dividend rate (as a percent)	6.00%