Rex Energy 10-Q 8 Aug 18 2018 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Aug. 06, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q2
Trading Symbol	REXX
Entity Registrant Name	REX ENERGY CORP
Entity Central Index Key	1,397,516
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		10,707,788

Consolidated Balance Sheets (Un

Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current Assets
Cash and Cash Equivalents	$ 28,780	$ 15,247
Restricted Cash	33,106
Accounts Receivable	28,588	25,974
Taxes Receivable	48	2,049
Short-Term Derivative Instruments	4,796	8,008
Inventory, Prepaid Expenses and Other	3,389	4,614
Total Current Assets	98,707	55,892
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties	1,062,986	1,086,625
Unevaluated Oil and Gas Properties	174,608	186,523
Other Property and Equipment	20,066	19,640
Wells and Facilities in Progress	2,552	38,660
Pipelines	16,528	16,803
Total Property and Equipment	1,276,740	1,348,251
Less: Accumulated Depreciation, Depletion and Amortization	(384,556)	(463,899)
Net Property and Equipment	892,184	884,352
Other Assets	35	44
Long-Term Derivative Instruments	1,463	1,719
Deferred Tax Assets - Long Term	130	130
Total Assets	992,519	942,137
Current Liabilities
Accounts Payable	82,679	62,354
Current Maturities of Long-Term Debt	261,315	834,325
Debtor-in Possession Term Loan Payable	35,000
Accrued Liabilities	30,936	45,218
Short-Term Derivative Instruments	19,095	14,892
Total Current Liabilities	429,025	956,789
Noncurrent Liabilities
Long-Term Derivative Instruments	12,075	14,249
Other Long-Term Debt		8,156
Other Deposits and Liabilities		7,153
Future Abandonment Cost	8,626	9,352
Liabilities Subject to Compromise	667,624
Total Liabilities	1,117,350	995,699
Commitments and Contingencies (See Note 13)
Stockholders’ Equity
Preferred Stock	1	1
Common Stock	11	10
Additional Paid-In Capital	654,721	652,917
Accumulated Deficit	(779,564)	(706,490)
Total Stockholders’ Equity	(124,831)	(53,562)
Total Liabilities and Stockholders’ Equity	$ 992,519	$ 942,137

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) (Unaudited) - $ / shares	Jun. 30, 2018	Dec. 31, 2017
Statement Of Financial Position [Abstract]
Preferred Stock, par value	$ 0.001	$ 0.001
Preferred Stock, shares authorized	100,000	100,000
Preferred Stock, shares issued	3,987	3,987
Preferred Stock, shares outstanding	3,987	3,987
Common Stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	100,000,000	100,000,000
Common Stock, shares issued	10,707,788	10,244,394
Common Stock, shares outstanding	10,707,788	10,244,394

Consolidated Statements of Oper

Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$ 75,155	$ 47,457	$ 140,180	$ 99,522
Other Operating Revenue	3	5	7	11
TOTAL OPERATING REVENUE	75,158	47,462	140,187	99,533
OPERATING EXPENSES
Production and Lease Operating Expense	36,756	29,374	70,602	58,308
General and Administrative Expense	4,422	4,294	10,946	8,828
(Gain) Loss on Disposal of Assets		(124)	647	(1,959)
Impairment Expense	4,334	3,032	12,503	4,577
Exploration Expense	122	99	350	319
Depreciation, Depletion, Amortization and Accretion	16,953	15,501	32,081	30,969
Other Operating (Income) Expense	1,492	(98)	1,695	(118)
TOTAL OPERATING EXPENSES	64,079	52,078	128,824	100,924
INCOME (LOSS) FROM OPERATIONS	11,079	(4,616)	11,363	(1,391)
OTHER INCOME (EXPENSE)
Interest Expense	(14,118)	(12,122)	(36,765)	(21,266)
(Loss) Gain on Derivatives, Net	(14,328)	10,386	(60,754)	18,766
Other (Expense) Income	(13,952)	20	(14,955)	(7)
Loss on Extinguishments of Debt		(3,271)		(3,022)
Reorganization Items, Net	28,635		28,635
TOTAL OTHER EXPENSE	(13,763)	(4,987)	(83,839)	(5,529)
LOSS BEFORE INCOME TAX	(2,684)	(9,603)	(72,476)	(6,920)
Income Tax Benefit			0	0
NET LOSS	(2,684)	(9,603)	(72,476)	(6,920)
Preferred Stock Dividends	(598)	(598)	(1,196)	(1,196)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (3,282)	$ (10,201)	$ (73,672)	$ (8,116)
Earnings per common share:
Basic - Net Loss Attributable to Rex Energy Common Shareholders	$ (0.31)	$ (1.03)	$ (6.96)	$ (0.83)
Basic - Weighted Average Shares of Common Stock Outstanding	10,708	9,881	10,587	9,825
Diluted - Net Loss Attributable to Rex Energy Common Shareholders	$ (0.31)	$ (1.03)	$ (6.96)	$ (0.83)
Diluted - Weighted Average Shares of Common Stock Outstanding	10,708	9,881	10,587	9,825

Consolidated Statement of Chang

Consolidated Statement of Changes in Stockholders' Equity (Deficit) (Unaudited) - 6 months ended Jun. 30, 2018 - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Preferred Stock	Additional Paid-in Capital	Accumulated Deficit
Balance at Dec. 31, 2017	$ (53,562)	$ 10	$ 1	$ 652,917	$ (706,490)
Balance (in shares) at Dec. 31, 2017		10,244	4
Equity Based Compensation	1,206			1,206
Issuance of Restricted Stock, Net of Forfeitures (in shares)		(27)
Preferred Dividends in Arrears Paid in Common Shares	1	$ 1		598	(598)
Preferred Dividends in Arrears Paid in Common Shares (in shares)		491
Net Loss	(72,476)				(72,476)
Balance at Jun. 30, 2018	$ (124,831)	$ 11	$ 1	$ 654,721	$ (779,564)
Balance (in shares) at Jun. 30, 2018		10,708	4

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$ (72,476)	$ (6,920)
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
Depreciation, Depletion, Amortization and Accretion	32,081	30,969
Loss (Gain) on Derivatives	60,754	(18,766)
Cash Settlement of Derivatives	(6,862)	(5,525)
Equity-based Compensation Expense	1,200	571
Non-cash Exploration Expenses		13
Impairment Expense	12,503	4,577
Non-cash Interest Expense	2,881	12,431
Loss on Extinguishments of Debt		3,022
Loss (Gain) on Sale of Assets	647	(1,959)
Non-cash Reorganization items, net	(43,509)
Other Non-cash Expenses	566	41
Changes in operating assets and liabilities
Accounts Receivable	(342)	7,229
Taxes Receivable	2,001	163
Inventory, Prepaid Expenses and Other Assets	336	52
Accounts Payable and Accrued Liabilities	41,478	(1,484)
Other Assets and Liabilities	(147)	(1,104)
NET CASH PROVIDED BY OPERATING ACTIVITIES	31,111	23,310
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	16,384	24,513
Acquisitions of Undeveloped Acreage	(871)	(1,783)
Capital Expenditures for Development of Oil & Gas Properties and Equipment	(100,136)	(54,004)
NET CASH USED IN INVESTING ACTIVITIES	(84,623)	(31,274)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Line of Credit, net of Discounts	69,846	171,000
Proceeds from Debtor-In-Possession Financing	35,000
Repayments of Long-Term Debt and Line of Credit		(145,170)
Repayments of Loans and Other Notes Payable	(945)	(319)
Reorganization Item - Debtor-In-Possession Financing Fee	(3,750)
Debt Issuance Costs		(7,791)
Payment of Preferred Dividends in Arrears		(598)
NET CASH PROVIDED BY FINANCING ACTIVITIES	100,151	17,122
Net Increase in Cash, Cash Equivalents and Restricted Cash	46,639	9,158
Beginning Cash, Cash Equivalents and Restricted Cash	15,247	3,697
Ending Cash, Cash Equivalents and Restricted Cash	61,886	12,855
SUPPLEMENTAL DISCLOSURES
Cash and Cash Equivalents	28,780	12,855
Restricted Cash	33,106
Ending Cash, Cash Equivalents and Restricted Cash	61,886	12,855
Interest Paid, net of capitalized interest	11,965	8,494
Cash Received for Income Taxes	(2,001)	(163)
NON-CASH ACTIVITIES
Proceeds held in Escrow - non-cash component of Gain on Sale of Assets	150	5,000
Increase (Decrease) in Accounts Payable and Accrued Liabilities for Capital Expenditures	(30,943)	1,652
Increase Long Term Debt - Equipment Financing	345	607
Decrease in Senior Notes carrying value net of Issuance Costs, Deferred Gain on Exchanges, and Net Discount due to Debt to Equity Conversions		(879)
Decrease in Bond Interest Payable due to Debt to Equity Conversions		(12)
Increase in Common Stock outstanding due to Debt to Equity Conversions		467
Illinois Basin Operations
NON-CASH ACTIVITIES
Change in fair value of contingent consideration receivable - sale of Illinois Basin	$ 729	$ (1,893)

Basis of Presentation and Princ

Basis of Presentation and Principles of Consolidation	6 Months Ended
	Jun. 30, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Basis of Presentation and Principles of Consolidation	1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION Rex Energy Corporation, together with our subsidiaries (the “Company”), is an independent natural gas, NGL and condensate company with operations currently focused in the Appalachian Basin. We are focused on Marcellus Shale, Utica Shale and Upper Devonian Shale drilling and exploration activities. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties. The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of all of our wholly owned subsidiaries. We report our interests in natural gas, NGL and condensate properties using the proportional consolidation method of accounting. All intercompany balances and transactions have been eliminated. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries together. In preparing the accompanying Consolidated Financial Statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. The interim Consolidated Financial Statements of the Company are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented. Actual results may differ from those estimates and results for interim periods are not necessarily indicative of results to be expected for a full year or for previously reported periods due in part, but not limited to, the volatility in prices for natural gas, NGLs and crude oil, future impact of financial derivative instruments, interest rates, estimates of reserves, drilling risks, geological risks, transportation restrictions, the timing of acquisitions, product demand, market consumption, interruption in production, our ability to obtain additional capital, and the success of natural gas, NGL and oil recovery techniques. Certain amounts and disclosures have been condensed or omitted from these Consolidated Financial Statements pursuant to the rules and regulations of the Securities and Exchange Commission. Therefore, these interim financial statements should be read in conjunction with the audited Consolidated Financial Statements and related notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2017. Consolidation of Guarantor Subsidiaries Subsequent to the sale of our Illinois Basin operations in 2016, our subsidiaries Rex Energy IV, LLC and Penntex Resources Illinois, Inc. were dormant entities with no assets or operations. Effective April 10, 2018, we consolidated Rex Energy IV, LLC and Penntex Resources Illinois, Inc. by way of a merger with and into Rex Energy I, LLC. Bankruptcy Accounting On May 18, 2018 (the “Petition Date”), the Company and certain of its direct subsidiaries (collectively with the Company, the “Rex Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Western District of Pennsylvania (“Bankruptcy Court”). During the pendency of the Chapter 11 proceedings, the Debtors will operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The consolidated financial statements have been prepared as if we are a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “Reorganization Items, Net” on our consolidated statements of operations. In addition, prepetition unsecured and under-secured obligations that may be impacted by the bankruptcy reorganization process have been classified as “Liabilities Subject to Compromise” on our consolidated balance sheet at June 30, 2018. These liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, although they may be settled for less. The accompanying consolidated financial statements do not purport to reflect or provide for the consequences of the Chapter 11 proceedings. In particular, the consolidated financial statements do not purport to show: (i) the realizable value of assets on a liquidation basis or their availability to satisfy liabilities; (ii) the amount of prepetition liabilities that may be allowed for claims or contingencies, or the status and priority thereof; (iii) the effect on shareholders’ deficit accounts of any changes that may be made to our capitalization; or (iv) the effect on operations of any changes that may be made to our business. While operating as debtors-in-possession under Chapter 11 of the Bankruptcy Code, we may sell or otherwise dispose of or liquidate assets or settle liabilities in amounts other than those reflected on our consolidated financial statements, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business. Further, a plan of reorganization (a “Plan”) could materially change the amounts and classifications on our historical consolidated financial statements. Use of Estimates The preparation of the accompanying condensed consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of natural gas, NGLs, and oil future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods. Reverse Stock Split On May 12, 2017, we effected a one-for-ten reverse stock split. As a result of the reverse stock split, each ten shares of our common stock automatically combined into and became one share of our common stock. Any fractional shares which would have otherwise been due as a result of the reverse split were rounded up to the nearest whole share. As a result of the reverse stock split, we reduced the issued number of common shares from 99.0 million to 9.9 million. The reverse stock split automatically and proportionately adjusted, based on the one-for-ten split ratio, all issued and outstanding shares of our common stock, as well as common stock underlying stock options, warrants and other derivative securities outstanding at the time of the effectiveness of the reverse stock split. The exercise price on outstanding equity based-grants proportionately increased, while the number of shares available under our equity-based plans also was proportionately reduced. Share and per share data for the periods presented reflect the effects of this reverse stock split. References to numbers of shares of common stock and per share data in the accompanying financial statements and notes thereto have been adjusted to reflect the reverse stock split on a retroactive basis.

Petition Relief Under Chapter 1

Petition Relief Under Chapter 11 and Going Concern Assessment	6 Months Ended
	Jun. 30, 2018
Reorganizations [Abstract]
Petition Relief Under Chapter 11 and Going Concern Assessment	2. PETITION RELIEF UNDER CHAPTER 11 AND GOING CONCERN ASSESSMENT Chapter 11 Proceedings On the Petition Date, the Rex Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Rex Debtors’ Chapter 11 cases are being administered jointly under the caption In re R.E. Gas Development, LLC, et al., Case No. 18-22032. The Rex Debtors are operating their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court has granted certain relief requested by the Rex Debtors, allowing us to use our cash to fund the Chapter 11 proceedings, pursuant to an agreement with the first lien lenders, and giving us the authority to, among other things, continue to pay employee wages and benefits without interruption, to utilize our current cash management system and to make royalty payments. During the pendency of the Chapter 11 proceedings, all transactions outside the ordinary course of our business require prior approval of the Bankruptcy Court. For goods and services provided following the Petition Date, we intend to pay vendors in full under normal terms. In order to exit Chapter 11 successfully, the Rex Debtors will need to obtain confirmation by the Bankruptcy Court of a Plan that satisfies the requirements of the Bankruptcy Code. On July 25, 2018, the Debtors filed with the Bankruptcy Court a proposed Plan (as may be amended, modified or supplemented from time to time, the “Proposed Plan”) for the resolution of the outstanding claims against and interests in the Debtors pursuant to the Bankruptcy Code. On July 25, 2018, the Debtors filed with the Bankruptcy Court a related proposed disclosure statement (as may be amended, modified or supplemented from time to time, the “Proposed Disclosure Statement”). In addition to being voted on by holders of impaired claims and equity interests, the Proposed Plan must satisfy certain requirements of the Bankruptcy Code and must be approved, or confirmed, by the Bankruptcy Court in order to become effective. If accepted by holders of impaired claims and equity interests, the Proposed Plan would, among other things, resolve the Debtors’ prepetition obligations, and set forth the revised capital structure of the newly reorganized entity, unless all or substantially all of the Debtors' assets are sold during the Chapter 11 proceedings. The Debtors will seek approval of the Proposed Disclosure Statement on August 23, 2018, and, if obtained, will solicit votes on the Proposed Plan. Under certain circumstances set forth in Section 1129(b) of the Bankruptcy Code, the Bankruptcy Court may confirm the Proposed Plan even if it has not been accepted by all impaired classes of claims and equity interests. The precise requirements and evidentiary showing for confirming a Plan notwithstanding its rejection by one or more impaired classes of claims or equity interests depends upon a number of factors, including the status and seniority of the claims or equity interests in the rejecting class (i.e., unsecured or secured claims, subordinated or senior claims). Generally, with respect to equity shares, a Plan may be “crammed down” even if the shareholders receive no recovery if the proponent of the Plan demonstrates that (1) no class junior to the equity shares are receiving or retaining property under the Plan and (2) no class of claims or interests senior to the equity shares are being paid more than in full. Sale Process On June 1, 2018, the Rex Debtors filed with the Bankruptcy Court a Motion For Orders Pursuant To Section 363 of the Bankruptcy Code: (I)(A) Approving Bidding Procedures For The Sale Of The Debtors’ Assets, (B) Scheduling An Auction And Approving The Form And Manner Of Notice Thereof, (C) Approving Assumption And Assignment Procedures and (D) Scheduling A Sale Hearing And Approving The Form And Manner Of Notice Thereof; (II)(A) Approving The Sale Of The Debtors’ Assets Free And Clear Of Liens, Claims, Interests And Encumbrances and (B) Approving The Assumption And Assignment Of Executory Contracts And Unexpired Leases; and (III) Granting Related Relief. On June 29, 2018, the Bankruptcy Court entered an order approving the bidding procedures and scheduling the auction. We have been in discussions with various third parties who may be interested in purchasing some or all of the assets of the Rex Debtors through the bankruptcy process, either through a sale pursuant to Section 363 of Chapter 11 of the Bankruptcy Code or in connection with the Proposed Plan. At this time, it is not possible to predict accurately the effect of the Chapter 11 reorganization process on our business, creditors or stockholders, when the Rex Debtors may emerge from Chapter 11 or what the disposition will be of any claims against the Rex Debtors. Our future results depend on the timely and successful confirmation and implementation of the Proposed Plan. Copies of all court filings made in our Chapter 11 cases are available from Prime Clerk, Claims and Noticing Agent for the bankruptcy proceedings, at https://cases.primeclerk.com/rexenergy/Home-Index. Magnitude of Potential Claims On July 2, 2018, the Rex Debtors filed with the Bankruptcy Court schedules and statements setting forth, among other things, the assets and liabilities of the Rex Debtors, subject to the assumptions filed in connection therewith. On August 1, 2018, the Debtors filed amended schedules and statements. The schedules and statements may be subject to further amendment or modification after filing. Holders of prepetition claims will be required to file proofs of claims by the applicable deadline for filing certain proofs of claims in the Rex Debtors’ Chapter 11 cases. The court has set August 6, 2018 as the bar date for filing of general claims, and November 14, 2018 as the bar date for filing of governmental claims. Differences between amounts scheduled by the Rex Debtors and claims by creditors will be investigated and resolved in connection with the claims resolution process. Liabilities Subject to Compromise Our consolidated balance sheet includes amounts classified as “Liabilities Subject to Compromise,” which represent prepetition liabilities that have been allowed, or that we anticipate will be allowed, as claims in our Chapter 11 cases. The amounts represent our current estimate of known or potential obligations to be resolved in connection with the Chapter 11 proceedings. The differences between the liabilities we have estimated and the claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. We will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary. Such adjustments may be material. The following table summarizes the components of liabilities subject to compromise included on the condensed consolidated balance sheet: June 30, 2018 (in thousands) Accounts Payable and Accrued Expenses $ 27,716 Accrued Interest Payable 30,043 Debt (See Note 8) 609,865 Liabilities Subject to Compromise $ 667,624 Reorganization Items, Net We have incurred and are expected to continue to incur significant costs associated with the reorganization. These costs, which are expensed as incurred, are expected to significantly affect our results of operations. Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments are determined. The following table summarizes the components of reorganization items included on the consolidated statements of operations: Three Ended June 30, 2018 (in thousands) Legal and Professional Fees $ (9,817 ) Unamortized Deferred Financing Balances (a) 43,509 Debtor-in Possession Financing Fees (3,750 ) Effect of Early Hedge Terminations (1,175 ) Other (132 ) Reorganization Items, net $ 28,635 (a) Effect of Filing on Creditors and Shareholders Subject to certain exceptions, under the Bankruptcy Code, the filing of Bankruptcy Petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Rex Debtors or their property to recover, collect or secure a claim arising prior to the Petition Date. Absent an order of the Bankruptcy Court, substantially all of the Rex Debtors’ prepetition liabilities are subject to settlement under the Bankruptcy Code. Creditors are stayed from taking any actions against the Rex Debtors as a result of defaults on the Rex Debtors’ debt obligations (which defaults were triggered prior to or by the filing of Bankruptcy Petitions), subject to certain limited exceptions permitted by the Bankruptcy Code. We did not record interest expense on our 1%/8% senior secured second lien notes (“Second Lien Notes”) or our unsecured 6.25% Senior Notes due 2022 and unsecured 8.875% Senior Notes due 2020 (the “Unsecured Notes”) for the period from May 18, 2018 (Petition Date), through June 30, 2018. For that period, contractual interest on the Second Lien Notes and the Unsecured Notes was approximately $5.7 million. Generally, under the Bankruptcy Code, prepetition liabilities and post-petition liabilities must be satisfied in full before the holders of our existing common and preferred shares are entitled to receive any settlement or retain any property under a Plan. The ultimate recovery to creditors and/or shareholders, if any, will not be determined until confirmation and implementation of one or more Plans. No assurance can be given as to what values, if any, will be ascribed in the Chapter 11 proceedings to each of these constituencies or what types or amounts of settlements, if any, they will receive. A Plan could result in holders of the Rex Debtors’ liabilities and/or equity shares receiving no settlement on account of their interests and cancellation of their holdings. Appointment of Creditors Committee On May 29, 2018, the Bankruptcy Court appointed the official committee for unsecured creditors (the “UCC”). The UCC and its legal representatives have a right to be heard on all matters that come before the Bankruptcy Court with respect to the Rex Debtors. Rejection of Executory Contracts Subject to certain exceptions, under the Bankruptcy Code, the Rex Debtors may assume, assign or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and satisfaction of certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a prepetition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Rex Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a prepetition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert unsecured claims in the Bankruptcy Court against the applicable Rex Debtor’s estate for damages. Generally, the assumption of an executory contract or unexpired lease requires the Rex Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with any of the Rex Debtors in this Quarterly Report on Form 10-Q, including where applicable a quantification of our obligations under any such executory contract or unexpired lease with the applicable Rex Debtor, is qualified by any overriding rejection rights we have under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Rex Debtors expressly preserve all of their rights with respect thereto. Covenant Violations Our filing of the Bankruptcy Petitions constituted an event of default under our Term Loan Credit Facility, and the indentures governing the Second Lien Notes and the Unsecured Notes, which resulted in automatic acceleration of our obligations under those instruments. However, our outstanding obligations under the Term Loan Credit Facility and the indentures governing the Unsecured Notes were accelerated prior to the Petition Date. In addition to the non-payment of second lien interest, we also encountered additional events of default related to certain non-financial covenants associated with our term loan agreement. These additional events of default are a result of our failure to timely deliver to the term loan lenders our unaudited quarterly financial statements for the quarter ended December 31, 2017 and our annual audited financial statements for the year ended December 31, 2017, as well as related inadvertent failures to provide accurate related written notices to the lenders, and written notices of the events of default in a subsequent draw request under the term loan agreement. Additionally, other events of default have occurred, including the receipt of a going concern explanatory paragraph from our independent registered public accounting firm on our consolidated financial statements for the year ended December 31, 2017. We received a notice of acceleration on April 27, 2018, from the lenders under our term loan agreement demanding immediate payment of all outstanding notes and loans, together with all accrued interest, fees, yield maintenance and call protection amounts. Under the Bankruptcy Code, the creditors under these debt agreements are stayed from taking any action against us as a result of an event of default. See Note 8 “Debt” Ability to Continue as a Going Concern The significant risks and uncertainties related to our covenant violations, liquidity and Chapter 11 proceedings described above raise substantial doubt about our ability to continue as a going concern. The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If we cannot continue as a going concern, adjustments to the carrying values and classification of our assets and liabilities and the reported amounts of income and expenses could be required and could be material.

Recently Issued Accounting Pron

Recently Issued Accounting Pronouncements	6 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
Recently Issued Accounting Pronouncements	3. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases • a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and • a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Public business entities are required to apply the amendment of this update for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. We are currently evaluating the potential impact of this standard on our results of operations and internal control environment. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments • debt prepayment or debt extinguishment costs; • settlement of zero-coupon debt instruments or other instruments with coupon rates that are insignificant in relation to the effective interest rate of borrowing; • contingent consideration payments made after a business combination; • proceeds from the settlement of insurance claims; • proceeds from the settlement of corporate-owned life insurance policies; • distributions received from equity method investees; • beneficial interest in securitization transactions; and • separately identifiable cash flows and application of the Predominance Principle. Public business entities are required to apply the amendments of this update for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. We adopted this standard effective January 1, 2018 on a retrospective basis. Adoption of the standard did not have an impact on the presentation of our consolidated statements of cash flows In May 2017, the FASB issued ASU 2017-09, Stock Compensation - Scope of Modification Accounting

Revenue Recognition

Revenue Recognition	6 Months Ended
	Jun. 30, 2018
Revenue From Contract With Customer [Abstract]
Revenue Recognition	4. REVENUE RECOGNITION Effective January 1, 2018, we adopted Accounting Standards Codification (“ASC”) 606, “Revenue from Contracts with Customers,” using the modified retrospective method applied to those contracts which were not completed as of January 1, 2018. Under the modified retrospective method, we recognized the cumulative effect of initially applying the new revenue standard as an adjustment to the opening balance of retained earnings; however, no material adjustment was required as a result of adopting ASC 606. Results for reporting periods beginning on January 1, 2018 are presented under the new revenue standard. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. We performed an analysis of the impact of adopting ASC 606 across all revenue streams and did not identify any changes to its revenue recognition policies that would result in a material impact to its consolidated financial statements. We also implemented processes and controls to ensure new contracts are reviewed for the appropriate accounting treatment and to generate the required disclosures under the standards. Revenues Sources and Sales Cycle Revenue from operations is derived from sales of natural gas, NGL and condensate products produced by our well properties for which we are the operator. A de minimis percentage of revenue is also earned from either working interests, royalty interests, or small override interests we hold in various non-operated well properties. Our sales revenue is generated from on-going daily or monthly sales of volumes of gas and oil commodities, the sales volumes determined by metering or other measurement methods at the delivery point when control of the commodities transfers to the customer. Revenue Recognition – Contracts with Customers We recognize sales of our natural gas, NGL and condensate products when control of the product is transferred to the customer at delivery points specified in each commodity purchase contract. Under our commodity sales contracts, the delivery of each unit of natural gas, NGLs or condensate represents a separate performance obligation, and revenue is recognized at the point in time when the performance obligations are fulfilled. There are no significant financing components associated with our revenues from sales to customers as payment terms are typically within 30 to 60 days of control transfer. Sales revenue recognized corresponds directly with the value to the customer of our performance completed to date. We record revenue from sales of our natural gas, NGL and condensate production in the amount equal to our net revenue interest in sales from the producing properties. Under ASC 606, we recognize revenues based on a determination of when control of its commodities is transferred and whether it is acting as a principal or agent in certain transactions. All facts and circumstances of an arrangement are considered and judgment is often required in making this determination. We consider risk of loss an important indicator of when control transfers, which is comprised of risks associated with loss of product during processing. We concluded that title, custody, and acceptance are not by themselves determinative indicators of control, as such factors may be present in the case of a sale or the performance of a service. As a result of this analysis, we concluded that the Company represents the principal and the ultimate third party is its customer, which implies that the Company maintains control of the product through the tailgate of gas processing plants in certain natural gas processing in accordance with the control model in ASC 606. As a result, there were no changes to our presentation of revenues and expenses for these agreements. Pricing of Commodity Sales Our natural gas production is primarily sold under contracts that are typically priced at a differential to published commodity index prices for the producing area due to the natural gas quality and the proximity to major consuming markets. NGL and condensate production is sold under contract pricing referenced to various liquids commodity index prices. All revenue from production is generated from our operations in the Appalachian Basin. Production Imbalances We use the sales method to account for natural gas production imbalances. If our sales volume for a well exceeds our proportionate share of production from the well, a liability is recognized to the extent that our share of estimate d remaining recoverable reserves from the well is insufficient to satisfy this imbalance. No receivables are recorded for those wells on which we have taken less than our proportionate share of production. Contract Balances Under our product sales contracts, our customers are invoiced once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to material contract assets or contract liabilities. Performance Obligations Our contracts with customers represent a series of performance obligations satisfied over time when a performance obligation is satisfied by the transfer of control over a product to the customer. The transfer of control is generally considered to occur when we have transferred custody, title, risk of loss and relinquished any repurchase rights or other similar rights. Our commodity sales contracts are established to facilitate on-going sales of our products with our customers over the term of the contract, with pricing and delivery terms identified in each contract. We do not have contracts with customers that describe the performance obligation in terms of a defined gross total delivery volume over time. We utilized the practical expedient in ASC 606-10-50-14(A) which states that disclosure of the portion of a transaction price allocated to remaining performance obligations is not required if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our sales contracts, each unit of product generally represents a separate performance obligation; therefore future sales volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. As of June 30, 2018 and December 31, 2017, we had trade receivable balances related to revenue from contracts with customers of approximately $25.9 million and $21.7 million, respectively. The following table summarizes our disaggregated revenues recognized from contracts with customers in our Consolidated Statements of Operations for the three and six month periods ended June 30, 2018 and 2017. Three Months Ended June 30, Six Months Ended June 30, ($ in Thousands) 2018 2017 2018 2017 Revenues from Contracts with Customers by Product Natural Gas $ 29,705 $ 29,097 $ 59,387 $ 60,442 NGLs 32,293 15,367 61,011 32,667 Condensate 13,157 2,993 19,782 6,413 Total $ 75,155 $ 47,457 $ 140,180 $ 99,522

Oil and Gas Properties - Joint

Oil and Gas Properties - Joint Ventures and Divestitures	6 Months Ended
	Jun. 30, 2018
Business Combinations [Abstract]
Oil and Gas Properties - Joint Ventures and Divestitures	5. OIL AND GAS PROPERTIES – JOINT VENTURES AND DIVESTITURES Benefit Street Partners, LLC On March 1, 2016, we entered into a joint exploration and development agreement with an affiliate of Benefit Street Partners, LLC (“BSP”) to jointly develop 58 specifically designated wells in our Moraine East and Warrior North operated areas. BSP agreed to participate in and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, all of which have already been drilled, completed, placed in sales and paid for by BSP. BSP also agreed to participate in and fund 65.0% of the estimated well costs for six designated wells in Warrior North, Ohio, all of which have been drilled, completed, placed in sales and paid for by BSP. BSP also has the option to participate in the development of 36 additional wells and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. To date, BSP has exercised its option to participate in 23 of these additional wells. Total consideration for this transaction could be up to $175.0 million with approximately $134.0 million committed as of June 30, 2018. BSP has paid for its interest in the elected wells as of December 31, 2017, and no additional elections have occurred during the quarter ended June 30, 2018. The remainder of the proceeds may be received if BSP makes additional elections as additional wells are drilled to total depth or placed in sales. BSP earns an assignment of 15%-20% working interest in acreage located within each of the units in which it participates. As of June 30, 2018, all 45 committed wells were in line and producing. The BSP transaction constitutes a pooling of assets in a joint undertaking to develop these specific properties for which there is substantial uncertainty about the ability to recover the costs applicable to our interest in the properties. Under the terms of the agreement, we hold a substantial obligation for future performance, which may not be proportionally reimbursed by BSP. Due to the uncertainty that exists on the recoverability of costs associated with our retained interest, proceeds received from BSP are considered a recovery of costs and no gain or loss is recognized. Sale of Warrior South Assets On January 11, 2017, we, together with MFC Drilling, Inc., and ABARTA Oil & Gas Co., Inc. sold substantially all of our jointly owned oil and gas interests in Noble, Guernsey, and Belmont Counties, Ohio, to Antero Resources Corporation. These interests comprised our Warrior South development area. The effective date for the transaction is October 1, 2016. The sales agreement includes representations, warranties, covenants and agreements as well as various provisions for purchase price and post-closing adjustments customary for transactions of this type. Total consideration for the transaction was approximately $50.0 million, with approximately $29.1 million net to us, subject to customary closing and post-closing adjustments. We received approximately $24.1 million of proceeds on January 11, 2017. Approximately $5.0 million of the total proceeds due to us was held in escrow and released to us in December 2017. The sale of assets resulted in a gain on disposal of assets of approximately $1.8 million in January 2017. This gain includes the additional proceeds held in escrow. The sale of assets included 14 gross wells with associated production of 15 Mmcfe/d, with 9 Mmcfe/d net to us, and approximately 6,200 gross acres, with 4,100 acres net to us. This acreage was considered non-core to us. We used the proceeds from the transaction to pay down amounts outstanding under our prior revolving line of credit and for general corporate purposes. Sale of Westmoreland Assets On March 13, 2018, we entered into a Purchase and Sale Agreement with XPR Resources, LLC (“XPR”), pursuant to which we agreed to sell to XPR certain of its non-operated oil and gas interests in 61 wells located in Westmoreland, Centre and Clearfield Counties, Pennsylvania, along with associated production and other ancillary assets. The acreage sold was considered non-core to us. In a related transaction, we entered into a Membership Interest Purchase Agreement on the same date with COG2, LLC (“COG2”), an affiliate of XPR, pursuant to which we agreed to sell to COG2 its 40% membership interest in RW Gathering, LLC. Closing occurred on March 21, 2018, with an effective date for the transactions of January 1, 2018. Total consideration for the transactions was approximately $17.2 million, subject to customary closing and post-closing adjustments. We received approximately $16.4 million of proceeds on March 23, 2018, prior to closing adjustments. Approximately $0.2 million of the total proceeds due to us is being held in escrow. The sale of assets resulted in a loss on the disposal of assets of approximately $0.6 million in the first quarter of 2018.

Future Abandonment Cost

Future Abandonment Cost	6 Months Ended
	Jun. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
Future Abandonment Cost	6. FUTURE ABANDONMENT COST Future abandonment costs are recognized as obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed. If the fair value of a recorded future abandonment cost changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Accretion expense totaled $0.2 million and $0.5 million for the three and six months ended June 30, 2018, respectively, and $0.5 million and $1.0 million for the three and six months ended June 30, 2017, respectively. These amounts are recorded as depreciation, depletion, amortization, and accretion expense on our Consolidated Statements of Operations. We account for future abandonment costs that relate to wells that are drilled jointly based on our working interest in those wells. ($ in Thousands) June 30, 2018 Beginning Balance at January 1, 2018 $ 9,939 Future Abandonment Obligation Incurred $ 137 Future Abandonment Obligation Settled $ (156 ) Future Abandonment Obligation Cancelled or Sold $ (877 ) Future Abandonment Obligation Revision of Estimated Obligation $ 99 Future Abandonment Obligation Accretion Expense $ 473 Total Future Abandonment Cost 1 $ 9,616 1

Concentrations of Credit Risk

Concentrations of Credit Risk	6 Months Ended
	Jun. 30, 2018
Risks And Uncertainties [Abstract]
Concentrations of Credit Risk	7. CONCENTRATIONS OF CREDIT RISK By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparties to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties. Our counterparties are investment grade financial institutions (see Note 8, Debt Derivative Instruments and Fair Value Measurements We depend on a relatively small number of purchasers for a substantial portion of our revenue. For the six months ended June 30, 2018, approximately 98.9% of our commodity sales came from five purchasers, with the largest single purchaser accounting for 62.1% of commodity sales. We believe the growth in our Appalachian estimated proved reserves, as well as the quantity of purchasers, will help us to minimize our future risks by diversifying our ratio of condensate and gas sales.

Debt

Debt	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Debt	8. DEBT Term Loan On April 28, 2017 (the “Effective Date”), we entered into a term loan agreement (“Term Loan”) with Angelo, Gordon Energy Servicer, LLC (“AGES”), as administrative agent, AGES, as collateral agent (in such capacity, the “Collateral Agent”), Macquarie Bank Limited, as issuing bank (in such capacity, the “Issuing Bank”), and the lenders from time to time party thereto. The Term Loan replaced our prior amended and restated senior secured revolving credit agreement with Royal Bank of Canada, as Administrative Agent, and the lenders from time to time party thereto (the “Prior Credit Agreement”). The Term Loan provides for a $143,500,000 secured term loan facility (the “Term Facility”) and a $156,500,000 secured delayed draw term loan facility (the “Delayed Draw Term Facility”), which includes a letter of credit sub-facility (the “Letter of Credit Sub-facility”). The proceeds of the initial loans under the Term Loan were used to refinance the loans then outstanding under the Prior Credit Agreement and payment of fees and expenses related thereto; the proceeds of future loans under the Delayed Draw Term Facility were used for cash collateralizing letters of credit under the Letter of Credit Sub-facility and general corporate purposes. We cash collateralized our outstanding letters of credit during the second quarter of 2018 in the amount of approximately $33.1 million. The maximum commitments of the lenders under the Term Loan were initially limited to $300,000,000. Subsequent to certain events of default under the Term Loan, we were limited to drawing approximately $261.3 million, inclusive of amounts drawn to cash collateralize the letters of credit. As of June 30, 2018, we had approximately $228.2 million in borrowings outstanding and approximately $33.1 million in outstanding cash collateralized letters of credit. Prepayments (including mandatory prepayments), terminations, refinancing, reductions and accelerations under the Term Loan were subject to a yield maintenance amount equal to the interest which would have accrued on such prepaid, terminated, refinanced, reduced or accelerated amount during the period beginning on the date of such prepayment, termination, refinancing, reduction or acceleration and ending on the date that is 30 months after the Effective Date and a call protection amount (a) during the period commencing on the Effective Date and ending on the date that is 30 months thereafter, in an amount equal to 3.0% of such prepaid, terminated, refinanced, reduced or accelerated amount and (b) during the period commencing on the date that is 30 months and one day after the Effective Date and ending on the date that is 36 months after the Effective Date, an amount equal to 1.0% of such prepaid, terminated, refinanced, reduced or accelerated amount (the “Make Whole Amount”). Some of the provisions are required to be bifurcated from the Term Loan and valued separately as derivatives. Due to the short-term nature of these amounts at June 30, 2018 they have been recorded at their fair value using Level 2 inputs. At March 31, 2018, we had recorded a fair value liability of approximately $53.0 million as Short-Term Derivative Instruments on our Consolidated Balance Sheet. During the second quarter of 2018, the Make Whole Amount became due and payable as a result of certain events of default and the subsequent acceleration of debt. As of June 30, 2018, the Make Whole Amount of $50 million, as referenced in the Restructuring Support Agreement, has been recorded in Accounts Payable on our Consolidated Balance Sheet. For the six months ended June 30, 2018, we have recorded a realized loss on derivatives of $50.0 million as Gain (Loss) on Derivatives, Net in the Consolidated Statement of Operations in connection with various events occurring during the first quarter, that led to the Chapter 11 Bankruptcy filing. Debtor-In-Possession Term Loan On May 23, 2018, we executed a senior-secured debtor-in-possession term loan agreement (“DIP Facility”) with AGES, as administrative agent, AGES, as collateral agent , Macquarie Bank Limited, as issuing bank and the lenders from time to time party thereto. The DIP Facility has a maturity date of November 18, 2018. In accordance with the final court order approving the DIP Facility dated July 11, 2018, the DIP Facility effectively consolidates our prior Term Loan balances of $261.3 million, the Make-Whole Amount of $50.0 million and additional borrowing capacity of $100.0 million (the “Additional Capacity”). As of June 30, 2018, we had $35.0 million in outstanding Additional Capacity borrowings under the DIP Facility which we incurred as interim financing approved by the Bankruptcy Court. Borrowings under the DIP Facility bear interest at a rate per annum equal to the “Adjusted LIBO Rate” (subject to a 1.00% floor) plus an 8.75% per annum margin. Upon the occurrence and continuance of an event of default under the DIP Facility, all outstanding loans bear interest at a rate equal to 4.00% per annum plus the then-effective rate of interest. Interest is payable in arrears on the last business day of each March, June, September and December. Interest on the Make-Whole Amount accrues from July 11, 2018 until the maturity date. Under the DIP Facility, we paid a $3.8 million up-front commitment fee which we expensed to Reorganization Items, net on our Statement of Operations. Additionally, we have agreed to pay an unused commitment fee of 3.25% on the average daily unused amount of the DIP Facility. The DIP Facility contains covenants that restrict our ability to, among other things, materially change the nature of our business, make dividend payments, enter into transactions with affiliates, create or acquire additional subsidiaries, incur indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens, and enter into agreements regarding swap and other derivative transactions. The DIP Facility also requires that we comply with the following financial covenants: (1) as of the last day of any fiscal quarter ending on or after June 30, 2018, the PDP Coverage Ratio (as defined in the DIP Facility) will not be less than 1.25 to 1.00; (2) our liquidity at all times must be greater than $10.0 million, and (3) each Friday we are required to submit budget variance reports showing that (i) aggregated receipts are not less than 85% of budgeted receipts, (ii) aggregated disbursements, other than capital expenditures, are not greater than 115% of budgeted disbursements and (iii) actual capital expenditures are not greater than 105% of budgeted capital expenditures. As of June 30, 2018, our PDP Coverage Ratio was 1.85 to 1.00 and our liquidity was approximately $88.8 million. To date we have complied with all budget variance testing covenants. Obligations under the DIP Facility are secured by a perfected first priority lien and a perfected junior lien on, and security interest in, all present and after-acquired property not subject to a valid, perfected and non-avoidable lien or security interest in existence on the Petition Date or to a valid lien in existence on the Petition Date that is perfected subsequent to the Petition Date as permitted by Bankruptcy Code Section 546(b). Obligations under the DIP Facility are also secured by a perfected first priority priming lien on, and security interest in, all prepetition collateral. Senior Notes On March 31, 2016, we completed an exchange offer and consent solicitation related to our 8.875% Senior Notes due 2020 (the “2020 Notes”) and 6.25% Senior Notes due 2022 (the “2022 Notes” and, together with the 2020 Notes, the “Existing Notes”; the Existing Notes, together with the Second Lien Notes are collectively referred to herein as the “Senior Notes”). We offered to exchange (the “Exchange”) any and all of the Existing Notes held by eligible holders for up to (i) $675.0 million aggregate principal amount of our new Second Lien Notes and (ii) 10.1 million shares of our common stock (the “Shares”). Subsequent to the Exchange, we had a total of $12.7 million of Existing Notes and $587.6 million of Second Lien Notes. We accounted for these transactions as troubled debt restructurings. As a result of the troubled debt exchanges, the future undiscounted cash flows of the Second Lien Notes are greater than the net carrying value of the Existing Notes. As such, no gain was recognized within our GAAP basis financial statements and a new effective interest rate was established. Following the completion of the Exchange, we entered into debt-for equity exchanges during the remainder of 2016, with certain holders of our Existing Notes, as well as holders of our Second Lien Notes, in which such Existing Notes and Second Lien Notes were exchanged for unrestricted shares of our common stock. These exchanges resulted in the retirement of $27.7 million in aggregate principal amount of our remaining Existing Notes and $45.7 million in aggregate principal amount of our outstanding Second Lien Notes, in exchange for the issuance of a total of approximately 2.4 million shares of unrestricted common stock during the year ended December 31, 2016. During the year ended December 31, 2017, we completed debt-for equity exchanges with certain holders of our Existing Notes. These exchanges resulted in the retirement of approximately $0.9 million in aggregate principal amount of our remaining Existing Notes, in exchange for approximately 0.1 million shares of unrestricted common stock. The exchanged notes were subsequently cancelled, resulting in a gain The Senior Notes are governed by indentures (the “Indentures”), which contain affirmative and negative covenants that are customary for instruments of this nature, including restrictions or limitations on our ability to incur additional debt, pay dividends, purchase or redeem stock or subordinated indebtedness, make investments, create liens, sell assets, merge with or into other companies or transfer substantially all of our assets, unless those actions satisfy the terms and conditions of the Indentures or are otherwise excepted or permitted. Interest is payable on our Second Lien Notes at a rate of 8.0% per annum on April 1 and October 1 of each year. We have not made the semi-annual interest payment to the holders of our Second Lien Notes that was due on April 2, 2018, and did not make the interest payment prior to the expiration of the 30 day grace period. On May 18, 2018, we ceased accruing interest on the Second Lien Notes in accordance with the provisions of ASC 852. Contractual interest that we have not accrued for the Second Lien Notes for the period of May 18, 2018 through June 30, 2018 is approximately $5.6 million. As of June 30, 2018, we had approximately $29.6 million of accrued interest related to the Second Lien Notes recorded in the Accrued Interest Payable component of our Liabilities Subject to Compromise balances on our Consolidated Balance Sheet. Interest is payable semi-annually on our Existing Notes. Interest on the 2020 Notes is payable at a rate of 8.875% per annum on June 1 and December 1 of each year, while interest on the 2022 Notes is payable at a rate of 6.25% per annum on February 1 and August 1 of each year. On May 18, 2018, we ceased accruing interest on the Existing Notes in accordance with the provisions of ASC 852. Contractual interest that we have not accrued for the Existing Notes for the period May 18, 2018 through June 30, 2018 is approximately $0.1 million. As of June 30, 2018, we had approximately $0.4 million of accrued interest related to the Existing NotesSecond Lien Notes recorded in the Accrued Interest Payable component of our Liabilities Subject to Compromise balances on our Consolidated Balance Sheet. As of June 30, 2018 Secured Debt Debt Balances included in Liabilities Subject to Compromise Term Loan - due April 2020 $ 261,315 $ — Debtor-In-Possession Term Loan - due November 2018 $ 35,000 $ — 8.875% Senior Notes due 2020 $ — $ 7,333 6.25% Senior Notes due 2022 — 5,363 1% / 8% Second Lien Senior Notes due 2020 — 587,606 Total Senior Notes $ — $ 600,302 Long-Term Capital Leases - Equipment Financing Due March, 2021 $ — $ 557 Due June, 2021 — 1,254 Due September, 2021 — 1,428 Due May, 2022 — 6,324 Total Capital Lease Obligations $ — $ 9,563 Debt Balances Subject to Compromise $ — $ 609,865 The weighted average interest rate on borrowed balances under the DIP Facility and the Term Loan for the three and six months ended June 30, 2018 December 31, 2017 Principal Unamortized net Premium / Discount Unamortized Debt Issuance Costs Deferred Gain on Debt Restructurings, Net Net Carrying Value Term Loans, Net Term Loan Draw - due April 2020 $ 189,500 $ (4,711 ) $ (2,761 ) $ — $ 182,028 Senior Notes, Net 8.875% Senior Notes due 2020 $ 7,333 $ — $ — $ (60 ) $ 7,273 6.25% Senior Notes due 2022 5,363 — — (67 ) 5,296 1% / 8% Second Lien Senior Notes due 2020 587,606 — — 50,196 637,802 $ 600,302 $ — $ — $ 50,069 $ 650,371 Other Long-Term Debt Long-Term Capital Leases and Other Notes Payable- Equipment Financing Due March, 2021 $ 632 Due June, 2021 1,418 Due September, 2021 1,578 Due May 2022 6,454 Total Capital Lease Obligations $ 10,082 Less: Current Portion of Capital Leases and Other Notes Payable (1,926 ) $ 8,156 As of December 31, 2017, the Deferred Gain on Debt Restructurings, Net includes Unamortized Premiums/Discounts of $14.0 million, Unamortized Debt Issuance Costs of $33.6 million and Unamortized Deferred Gain on Debt Restructurings of $30.4 million.

Derivative Instruments And Fair

Derivative Instruments And Fair Value Measurements	6 Months Ended
	Jun. 30, 2018
Fair Value Of Financial Instruments And Derivative Instruments [Abstract]
Derivative Instruments And Fair Value Measurements	9. DERIVATIVE INSTRUMENTS AND FAIR VALUE MEASUREMENTS Our results of operations and operating cash flows are impacted by changes in market prices for oil, natural gas and NGLs. To mitigate a portion of the exposure to adverse market changes, we enter into natural gas, NGL and oil commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels that are less than our average price floor, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling, we make payments to our counterparties. We do not enter into these arrangements for speculative trading purposes. As of June 30, 2018 and December 31, 2017, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, basis swaps and three-way collars. We did not designate these instruments as cash flow hedges for accounting purposes. Accordingly, associated unrealized gains and losses are recorded directly as Gain (Loss) on Derivatives, Net in the Consolidated Statement of Operations. We enter into the majority of our derivative arrangements with two counterparties and have a netting agreement in place with these counterparties. We do not obtain collateral to support the agreements, but we believe our credit risk is currently minimal on these transactions. For additional information on the credit risk regarding our counterparties, see Note 6, Concentrations of Credit Risk, None of our commodity derivatives are designated for hedge accounting but are, to a degree, an economic offset to our commodity price exposure. We utilize the mark-to-market accounting method to account for these contracts. We recognize all gains and losses related to these contracts in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Expense. We paid net cash settlements of $4.9 Embedded Derivatives – Yield Maintenance and Call Protection We entered into the Term Loan in April 2017, which included certain call protection and yield maintenance provisions that require accelerated payments upon certain events. Prepayments (including mandatory prepayments), terminations, certain events of default, refinancing, reductions and accelerations under the Term Loan are subject to a yield maintenance amount equal to the interest which would have accrued on such prepaid, terminated, refinanced, reduced or accelerated amount during the period beginning on the date of such prepayment, termination, refinancing, reduction or acceleration and ending on the date that is 30 months after the Effective Date and a call protection amount (a) during the period commencing on the Effective Date and ending on the date that is 30 months thereafter, in an amount equal to 3.0% of such prepaid, terminated, refinanced, reduced or accelerated amount and (b) during the period commencing on the date that is 30 months and one day after the Effective Date and ending on the date that is 36 months after the Effective Date, an amount equal to 1.0% of such prepaid, terminated, refinanced, reduced or accelerated amount. Some of the provisions are required to be bifurcated from the Term Loan and valued separately as derivatives. Due to the short-term nature of these amounts at March 31, 2018 they have been recorded at their fair value using Level 2 inputs. As of June 30, 2018, we have recorded a fair value liability of approximately $50.0 million as Current Liability on our Consolidated Balance Sheet. For the six months ended June 30, 2018, we recorded a loss of approximately $50.0 million as Gain (Loss) on Derivatives, Net in the Consolidated Statement of Operations in connection with various events occurring during the first quarter, which led to our decision to file the Bankruptcy Petitions. As of December 31, 2017, the fair value of these embedded derivatives was not material. Contingent Consideration – Sale of Illinois Basin Operations In conjunction with the sale of our Illinois Basin operations, we executed a contract with the buyer that would allow us to receive future cash payments from the buyer if index pricing targets as defined in the contract are achieved at specified future dates. We have evaluated the contract and concluded that it meets the definition and requirements for accounting treatment as a derivative instrument, as prescribed in ASC 815-10-15-83. We recorded the contract at its initial fair value of approximately $1.2 million as additional consideration in the calculation of the gain on the sale of the assets. Fair value was determined through application of mathematical models designed to provide fair value estimates utilizing probability measures and the market index measures underlying the contract. The fair value will be adjusted at each future reporting period for the duration of the contract, which concludes June 30, 2019. As of June 30, 2018 and December 31, 2017, the contingent consideration contract was valued at $2.5 million and $1.7 million, respectively. For the three month period ended June 30, 2018, the average index price for oil as specified in the contract was in excess of the required threshold price for the quarter, and we recognized income of approximately $0.8 million, representing the discounted fair value of the additional consideration earned during the quarter. The contract stipulates that the buyer will remit to us $0.9 million not later than July 15, 2019, for the consideration earned during the three months ended June 30, 2018. The discounted fair value of approximately $0.8 million is included in Accounts Receivable on our Consolidated Balance Sheets as of June 30, 2018. Derivative Instruments On May 18, 2018, the Bankruptcy Court approved a motion to continue our derivative programs in the normal course of business. In conjunction with the Bankruptcy Petitions, one of our derivative counterparties elected to terminate their outstanding contracts with us, resulting in a $2.0 million liability. Approximately $0.8 million was related to the fair value of the derivatives on the date of termination, which was recognized as (Loss) Gain on Derivatives, Net for the three and six months ended June 30, 2018. Approximately $1.2 million was related to costs associated with the early termination of the derivative positions and was recorded as Reorganization Items, Net for the three and six months ended June 30, 2018. The following table summarizes the location and amounts of gains and losses on our derivative instruments, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three and six months ended June 30, 2018 and 2017: For the Three Months Ended June 30, For the Six Months Ended June 30, ($ in Thousands) 2018 2017 2018 2017 Oil $ (3,817 ) $ 791 $ (5,553 ) $ 1,934 Natural Gas (213 ) 6,132 3,179 6,072 NGLs (14,383 ) 3,938 (10,714 ) 12,653 Contingent Consideration 1,120 (475 ) 2,334 (1,893 ) Embedded Derivatives 2,965 — (50,000 ) — (Loss) Gain on Derivatives, Net $ (14,328 ) $ 10,386 $ (60,754 ) $ 18,766 Our derivative instruments are recorded on the balance sheet as either an asset or a liability, in either case measured at fair value. The fair value associated with our derivative instruments was a net liability of approximately $24.9 million and approximately $19.4 million at June 30, 2018 and December 31, 2017, respectively. Our open asset/(liability) financial commodity derivative instrument positions at June 30, 2018 consisted of: Period Volume Put Option Floor Ceiling Swap Fair Market Value ($ in Thousands) Oil 2018 - Swaps 85,750 Bbls $ — $ — $ — $ 57.47 $ (817 ) 2018 - Three-Way Collars 42,000 Bbls 41.82 51.09 60.75 — (413 ) 2019 - Swaps 118,000 Bbls — — — 55.89 (1,231 ) 2019 - Collars 18,000 Bbls — 45.00 55.80 — (125 ) 2019 - Three-Way Collars 42,000 Bbls 38.57 48.57 58.86 — (375 ) 2020 - Swaps 24,000 Bbls — — — 51.00 (304 ) 2020 - Collars 22,500 Bbls 45.00 55.80 (167 ) 2020 - Three-Way Collars 21,500 Bbls 38.95 48.95 60.22 — (103 ) 2021 - Swaps 6,000 Bbls — — — 51.00 (76 ) 2021 - Collars 16,500 Bbls — 45.00 55.80 — (125 ) 2021 - Three-Way Collars 62,500 Bbls 37.44 47.04 57.98 — (240 ) 2022 - Three-Way Collars 23,000 Bbls 39.35 49.35 60.43 — (60 ) 481,750 Bbls $ (4,037 ) Natural Gas 2018 - Swaps 12,127,500 Mcf — — — 2.98 $ 394 2018 - Three-Way Collars 4,260,000 Mcf 2.31 2.88 3.55 — 310 2018 - Calls 2,920,000 Mcf — — 3.97 — (19 ) 2018 - Collars 2,222,500 Mcf — 2.60 3.04 — (134 ) 2018 - Basis Swaps - Dominion South 9,808,000 Mcf — — — (0.83 ) (1,858 ) 2018 - Basis Swaps - Texas Gas 7,360,000 Mcf — — — (0.13 ) 324 2019 - Swaps 7,500,000 Mcf — — — 2.91 129 2019 - Three-Way Collars 8,045,000 Mcf 2.35 2.81 3.43 — 313 2019 - Collars 4,471,750 Mcf — 2.62 3.03 — (227 ) 2019 - Basis Swaps - Dominion South 12,775,000 Mcf — — — (0.84 ) (3,725 ) 2020 - Swaps 4,642,500 Mcf — — — 2.90 242 2020 - Three-Way Collars 4,935,000 Mcf 2.33 2.77 3.31 — 350 2020 - Collars 2,645,000 Mcf — 2.65 3.03 — (34 ) 2020 - Basis Swaps - Dominion South 7,320,000 Mcf — — — (0.84 ) (2,068 ) 2021 - Swaps 900,000 Mcf — — — 2.90 59 2021 - Three-Way Collars 1,346,250 Mcf 2.32 2.74 3.20 — 97 2021 - Collars 792,500 Mcf — 2.65 3.05 — 43 2021 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (185 ) 2022 - Collars 147,500 Mcf — 2.65 3.05 — 11 2022 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (185 ) 2023 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (185 ) 2024 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (185 ) 108,818,500 Mcf $ (6,533 ) NGLs 2018 - C3+ NGL Swaps 640,036 Bbls — — — 33.06 $ (8,150 ) 2018 - Ethane Swaps 780,000 Bbls — — — 12.13 (450 ) 2019 - C3+ NGL Swaps 570,814 Bbls — — — 30.90 (4,524 ) 2019 - C5 Collars 113,040 Bbls — 45.00 54.83 — (964 ) 2019 - Ethane Swaps 1,264,750 Bbls — — — 12.60 322 2020 - C3+ NGL Swaps 191,112 Bbls — — — 32.22 (1,875 ) 2020 - C5 Collars 28,260 Bbls — 45.00 54.83 — (241 ) 2020 - Ethane Swaps 1,007,750 Bbls — — — 12.31 (73 ) 2021 - C3+ NGL Swap 88,404 Bbls — — — 41.70 (599 ) 2021 - Ethane Swaps 724,000 Bbls — — — 12.27 (98 ) 2022 - C3+ NGL Swap 9,420 Bbls — — — 50.50 (33 ) 2022 - Ethane Swaps 352,250 Bbls — — — 12.27 (107 ) 5,769,836 Bbls $ (16,791 ) The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017 is summarized below: June 30, December 31, ($ in Thousands) 2018 2017 Short-Term Derivative Assets: NGL—Swaps $ 365 $ 928 Natural Gas—Swaps 1,118 3,734 Natural Gas—Collars 22 183 Natural Gas—Basis Swaps 328 191 Natural Gas—Three-Way Collars 513 1,721 Contingent Consideration - Sale of Illinois Basin 2,450 1,251 Total Short-Term Derivative Assets $ 4,796 $ 8,008 Long-Term Derivative Assets: NGL—Swaps $ 308 $ 409 Natural Gas—Swaps 422 411 Natural Gas—Collars 119 — Natural Gas—Three-Way Collars 614 429 Contingent Consideration - Sale of Illinois Basin — 470 Total Long-Term Derivative Assets $ 1,463 $ 1,719 Total Derivative Assets $ 6,259 $ 9,727 Short-Term Derivative Liabilities: Crude Oil—Collars $ (42 ) $ (31 ) Crude Oil—Three-Way Collars (650 ) (92 ) Crude Oil—Swaps (1,442 ) (518 ) NGL—Swaps (11,700 ) (10,281 ) NGL—Collars (482 ) — Natural Gas—Three-Way Collars (56 ) (49 ) Natural Gas—Collars (268 ) (146 ) Natural Gas—Basis Swaps (3,725 ) (3,621 ) Natural Gas—Call (19 ) (154 ) Natural Gas—Swaps (711 ) — Total Short - Term Derivative Liabilities $ (19,095 ) $ (14,892 ) Long-Term Derivative Liabilities: Crude Oil—Three-Way Collars $ (541 ) $ (161 ) Crude Oil—Swaps (986 ) (202 ) Crude Oil—Collars (376 ) (425 ) NGL—Swaps (4,560 ) (4,482 ) NGL—Collars (723 ) (385 ) NGL—Three Way Collars — (66 ) Natural Gas—Swaps (5 ) (423 ) Natural Gas—Basis Swaps (4,671 ) (7,120 ) Natural Gas—Collars (213 ) (713 ) Natural Gas—Three-Way Collars — (272 ) Total Long-Term Derivative Liabilities $ (12,075 ) $ (14,249 ) Total Derivative Liabilities $ (31,170 ) $ (29,141 ) Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. We utilize a fair value hierarchy that gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows: Level 1—Observable inputs, such as quoted prices in active markets for identical assets or liabilities as of the reporting date. Level 2—Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars and other like derivative contracts, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Level 3—Unobservable inputs that are supported by little or no market activity. Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Our Level 2 fair value measurements are composed of our derivative contracts and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, probability factors, interest rates and discount rates, or can be confirmed from other active markets. The fair values recorded as of June 30, 2018 and December 31, 2017 were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party. We had no Level 3 commodity derivative contracts outstanding as of June 30, 2018 or December 31, 2017. The fair value of our derivative instruments may be different from the settlement value based on company-specific inputs, such as credit ratings, futures markets and forward curves, and readily available buyers and sellers for such assets and liabilities. During the three and six months ended June 30, 2018 and for the year ended December 31, 2017 there were no transfers into or out of Level 1 or Level 2 measurements. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value: Fair Value Measurements at June 30, 2018 ($ in Thousands) Total Carrying Value as of June 30, 2018 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ (24,911 ) $ — $ (24,911 ) $ — Fair Value Measurements at December 31, 2017 ($ in Thousands) Total Carrying Value as of December 31, 2017 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ (19,414 ) $ — $ (19,414 ) $ — Net derivative asset values are determined primarily by quoted futures and options prices and utilization of the counterparties’ credit default risk and net derivative liabilities are determined primarily by quoted futures and options prices and utilization of our credit default risk. The credit default risk of our counterparties and us are based on metrics such as interest coverage, operating cash flow and leverage ratios that calculate the likelihood that a firm will be unable to repay its lenders or fulfill payment obligations. The value of our oil derivatives are composed of three-way collar, call protected swap and deferred put spread contracts for notional barrels of oil at interval New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) oil prices. The fair values attributable to our oil derivatives as of June 30, 2018 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil and (iii) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our gas derivatives are composed of swap, collars, swaption, three way collar, basis swap, cap swap, call and put spread contracts for notional volumes of gas contracted at NYMEX Henry Hub (“HH”). The fair values attributable to our gas derivative contracts as of June 30, 2018 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our NGL derivatives are composed of swaps for notional volumes of NGLs contracted at NYMEX Mont Belvieu. The fair values attributable to our NGL derivative contracts as of June 30, 2018 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for Mont Belvieu, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. We classify our derivatives as Level 2 if the inputs used in the valuation models are directly observable for substantially the full term of the instrument; however, if the significant inputs were not observable for substantially the full term of the instrument, we would classify those derivatives as Level 3. We categorize our measurements as Level 2 because the valuation of our derivative instruments are based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instruments. Future Abandonment Cost We report the fair value of asset retirement obligations on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 2, Future Abandonment Costs, Financial Instruments Not Recorded at Fair Value The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements: June 30, 2018 December 31, 2017 ($ in Thousands) Carrying Amount Fair Value Carrying Amount Fair Value Senior Notes, Net of Issuance Costs $ 600,302 $ 6,730 $ 650,371 $ 264,438 Term Loan 261,315 252,966 182,028 182,028 Debtor In Possession Secured Term Loan 35,000 35,000 — — Capital Leases and Other Obligations 9,563 7,065 10,082 7,138 Total $ 906,180 $ 301,761 $ 842,481 $ 453,604 The fair value of the secured lines of credit approximates carrying value based on borrowing rates available to us for bank loans with similar terms and maturities and would be classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes uses pricing that is readily available in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 1 in the fair value hierarchy. The fair value of our capital leases and other obligations are determined using a discounted cash flow approach based on the interest rate and payment terms of the obligations and assumed discount rate. The fair values of the obligations could be significantly influenced by the discount rate assumptions, which is unobservable. Accordingly, the fair value of the capital leases and other obligations would be classified as Level 3 in the fair value hierarchy. The carrying values of all classes of cash and cash equivalents, accounts receivables and accounts payables are considered to be representative of their respective fair values due to the short term maturities of those instruments. Other Fair Value Measurements During the six months ended June 30, 2018 and 2017, we recorded other than temporary impairments of $12.5 million and $4.6 million, respectively, related to proven and unproved properties. We primarily use proved reserve reports in our determination of impairment of proved properties. These proved reserve reports are generated with inputs that are primarily established internally with the use of internally developed engineering estimates and methodologies. The inputs used in determining fair value as a part of the impairment expense calculation are considered to be Level 3 within the fair value hierarchy. Impairment considerations for unproved properties include future development plans for the leases, remaining months on the lease’s primary term, and market value for similar acreage in the area. For additional information on our impairment expense, see Note 15, Impairment Expense

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Income Taxes	10. INCOME TAXES We recognize deferred income taxes for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value. Income tax included in continuing operations was as follows: Three Months Ended June 30, Six Months Ended June 30, ($ in Thousands) 2018 2017 2018 2017 Income Tax Benefit (Expense) $ — $ — $ — $ — Effective Tax Rate 0.0 % 0.0 % 0.0 % 0.0 % Management estimates the annual effective income tax rate quarterly, based on current annual forecasted results. Items unrelated to current year ordinary income are recognized entirely in the period identified as a discrete item of tax. The quarterly income tax provision is composed of tax on ordinary income provided at the most recent estimated annual effective tax rate, adjusted for the tax effect of these discrete items. For the six months ended June 30, 2018, the estimated annual effective tax rate applied to ordinary losses from operations was 0.0%. The estimated annual effective tax rate differs from the U.S. statutory rate of 21.0% primarily due to the effect of maintaining a full valuation allowance against our deferred tax assets. Discrete period tax expense was not material and is also offset by a full valuation allowance resulting in zero tax expense for the period. For the six months ended June 30, 2017 the estimated annual effective tax rate applied to ordinary losses from operations was 0.0%. The estimated annual effective tax rate differs from the U.S. statutory rate of 35.0% primarily due to the effect of maintaining a full valuation allowances against our deferred tax assets. Discrete period tax expense was not material and is also offset by a full valuation allowance resulting in zero tax expense for the period. No income tax payments were made for the six months ended June 30, 2018. Income tax payments made during the six months ended June 30, 2017 were $2.0 million. Tax refunds received during the six months ended June 30, 2018 were approximately $2.0 million, and refunds received during the six months ended June 30, 2017 were approximately $0.2 million. On December 22, 2017, the Tax Cuts and Jobs Act (the “Tax Act”) was enacted. The Tax Act significantly changed the Internal Revenue Code, reducing the Federal statutory corporate income tax rate from 35% to 21%, allowing for bonus depreciation on certain qualified property, eliminating the alternative minimum tax for corporate taxpayers, adding new limitations on the deductibility of business interest expense deduction for net operating losses. The Tax Act also authorizes the Treasury Department to issue regulations with respect to the new provisions. We are still in the process of fully analyzing the Tax Cuts and Jobs Act and its effects on the Company. We cannot predict how the changes in the Tax Cuts and Jobs Act, regulations, or other guidance issued under it or conforming or non-conforming state tax rules might affect us or our business. In addition, there can be no assurance that U.S. tax laws, including the corporate income tax rate, will not undergo significant changes in the near future.

Stockholders_ Equity

Stockholders’ Equity	6 Months Ended
	Jun. 30, 2018
Equity [Abstract]
Stockholders’ Equity	11. STOCKHOLDERS’ EQUITY Nasdaq Delisting On April 3, 2018, we received a Staff Determination Letter from the Listing Qualifications Department (the “Staff”) of The Nasdaq Stock Market LLC (“Nasdaq”) indicating that, based on our continued non-compliance with Nasdaq Listing Rule 5550(b), our common stock would be suspended from trading on Nasdaq at the opening of business on April 12, 2018, and a Form 25-NSE would be filed with the Securities and Exchange Commission, which would remove our common stock from listing and registration on Nasdaq, in each case unless we request an appeal before the Nasdaq Hearings Panel (the “Panel”). We did not appeal this determination. Nasdaq filed a Form 25-NSE on April 19, 2018. Following the delisting of our common stock from Nasdaq, our common stock has been quoted on the OTC Markets Group’s Pink marketplace. Reverse Stock Split As discussed in Note 1, Basis of Presentation and Principles of Consolidation references to numbers of shares of common stock and per share data in the accompanying financial statements and notes thereto have been adjusted to reflect the reverse stock split on a retroactive basis. Common Stock On May 5, 2017, our common shareholders approved a decrease in the number of authorized shares from 200,000,000 to 100,000,000 common shares, contingent upon the effectiveness of a reverse stock split, which occurred on May 12, 2017. As of June 30, 2018, we have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of June 30, 2018 and December 31, 2017, shares of common stock issued and outstanding totaled 10,707,788 and 10,244,394, respectively. During the six months ended June 30, 2017, we issued approximately 0.1 million shares of our common stock in conjunction with debt for equity exchanges completed with certain holders of our Senior Notes. See Note 8, Debt Preferred Stock As of both June 30, 2018 and December 31, 2017, 3,987 shares of our 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (“Series A Preferred Stock”), were issued and outstanding. The annual dividend on each share of the Series A Preferred Stock is 6.0% per annum on the liquidation preference of $10,000 per share and is payable quarterly, in arrears, on February 15, May 15, August 15 and November 15 of each year. We pay cumulative dividends, when and if declared, in cash, stock or a combination thereof, on a quarterly basis at a rate of $600 per share, or 6.0%, per year. Dividends that are not declared and paid in accordance with the quarterly schedule will accumulate from the most recent date upon which dividends were paid but will not bear interest. In February 2016, we suspended our quarterly dividend payment. Dividends of $1.8 million were declared by our Board of Directors in 2017, bringing dividends in arrears current through August 15, 2016. Dividends declared and paid in 2017 were composed of cash dividends of $150.00 per share in the aggregate amount of $1.2 million, for the periods of November 15, 2016 to February 15, 2016 and February 15, 2016 to May 15, 2016 and we paid a dividend of $150.00 per share in the aggregate amount of $0.6 million for the period of May 15, 2016 to August 15, 2016, which was paid in shares of our common stock. On February 15, 2018 If dividends are in arrears and unpaid for six or more quarterly periods (whether or not consecutive), the holders of the shares of Series A Preferred Stock will have the right to elect two additional directors to serve on our board of directors. We did not make the dividend payment due on May 15, 2018, which resulted in a total of six quarterly dividend payments in arrears.

Employee Benefit and Equity Pla

Employee Benefit and Equity Plans	6 Months Ended
	Jun. 30, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Employee Benefit and Equity Plans	12. EMPLOYEE BENEFIT AND EQUITY PLANS Equity Plans We recognize all share-based payments to employees, including grants of employee stock options, in our Consolidated Statements of Operations based on their grant-date fair values, using prescribed option-pricing models where applicable. The fair value is expensed over the requisite service period of the individual grantees, which generally equals one vesting period. We report any benefits of income tax deductions in excess of recognized financial accounting compensation as cash flows from financing activities, rather than as cash flows from operating activities. Stock Options During the six months ended June 30, 2018 and 2017, no new options to purchase shares of our common stock were granted. Stock-based compensation expense from operations relating to stock options outstanding for the three and six months ended June 30, 2018 was negligible. Stock-based compensation expense from operations relating to stock options outstanding for the three and six months ended June 30, 2017 was $0.1 million and $0.2 million, respectively. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative Expense. There were no stock options exercised during the six months ended June 30, 2018. There was no tax benefit related to stock option exercises for each of the six-month periods ended June 30, 2018 and 2017. A summary of the status of our issued and outstanding stock options as of June 30, 2018 is as follows: Outstanding Exercisable Exercise Price Number Outstanding at June 30, 2018 Weighted-Average Exercise Price Number Exercisable at June 30, 2018 Weighted-Average Exercise Price 9.70 2,667 $ 9.70 1,835 $ 9.70 16.90 57,169 $ 16.90 38,118 $ 16.90 49.00 4,000 $ 49.00 4,000 $ 49.00 50.40 3,070 $ 50.40 3,070 $ 50.40 104.20 2,217 $ 104.20 2,217 $ 104.20 69,123 $ 22.77 49,240 $ 25.26 The weighted average remaining contractual term for options outstanding at June 30, 2018 was 4.4 years and there was no aggregate intrinsic value. The weighted average remaining contractual term for options exercisable at June 30, 2018 was 4.3 years and there was no aggregate intrinsic value. As of June 30, 2018, unrecognized compensation expense related to stock options was negligible. Restricted Stock Awards During the six-month period ended June 30, 2018, there were no issuances of restricted common stock to employees. During the six-month period ended June 30, 2017, the Compensation Committee approved the issuance of an aggregate of 101,237 shares of restricted stock to 28 employees. Certain of our outstanding restricted stock awards granted in 2015 are subject to market-based vesting through a calculation of total shareholder return (“TSR”) of our common stock relative to a pre-defined peer group over a three-year period. The weighted average fair value of the TSR awards granted as of December 31, 2015 was $2.56 per share. There have been no TSR awards granted subsequent to December 31, 2015. Average fair values were estimated on the date of each grant using a Monte Carlo Simulation model that estimates the most likely outcome based on the terms of the award and used the following assumptions: Six Months Ended June 30, 2018 Year Ended December 31, 2017 Expected Dividend Yield 0.0% 0% Risk-Free Interest Rate 1.0% 1.0% Expected Volatility – Rex Energy 58.6% 58.6% Expected Volatility – Peer Group 29.8%-85.0% 29.8%-85.0% Market Index 35.6% 35.6% Expected Life Three Years Three Years Compensation expense from restricted stock awards associated with our operations was $0.1 million and $1.2 million for the three and six months ended June 30, 2018, respectively and it was $0.4 million and $0.4 million for the three and six months ended June 30, 2017, respectively. During the three months ended March 31, 2018, the board of directors approved a waiver to certain performance factors for restricted stock awards that vested in March 2018. This waiver resulted in the vesting of approximately 29,411 restricted stock awards with associated expense of approximately $0.9 million. During the six months ended June 30, 2017, 179,519 performance stock awards were forfeited due to not meeting specified targets, which resulted in a net reversal of prior compensation expense of approximately $0.1 million. As of June 30, 2018, total unrecognized compensation cost related to restricted common stock grants was approximately $0.3 million, which will be recognized over a weighted average period of 1.2 years. A summary of the restricted stock activity for the six months ended June 30, 2018 is as follows: Number of Shares Weighted-Average Grant Date Fair Value Restricted stock awards, as of December 31, 2017 200,475 $ 13.62 Awards — — Forfeitures (27,817 ) 15.13 Vested (56,976 ) 24.72 Restricted stock awards, as of June 30, 2018 $ 115,682 $ 7.79 Retention and Incentive Plans for Key Employees and Executives Subsequent to the Petition Date, the Bankruptcy Court approved motions to implement a Key Employee Retention Plan (“KERP”) and a Key Executive Incentive Plan (“KEIP”). The KERP is designed as a retention tool for key employees that will pay a fixed amount of $132,500 per quarter, for a total of three quarters, beginning on or about June 30, 2018. Amounts related to the KERP are accounted for as Accrued Expenses on our Consolidated Balance Sheet and expensed as Reorganization Items, net on our Consolidated Statement of Operations. As of June 30, 2018, we had approximately $0.1 million accrued related to the KERP. The KEIP is designed to incentivize our key executives to maximize value for the benefit of all of our stakeholders through the measurement period of May 2018 through December 2018. A portion of the payout of the KEIP is dependent on the achievement of certain performance goals, including production, lease operating expenses, and safety goals. A separate portion of the payout of the KEIP is dependent on the achievement of certain milestones for the emergence from bankruptcy through a successful plan of reorganization or closing of a sale of substantially all of the assets within certain specified timeframes. The total amount of compensation available under the KEIP plan is dependent on the level of operating performance and successful emergence from bankruptcy and range from approximately $1.2 million up to a maximum of $3.5 million in total. Amounts under the KEIP are accounted for as Accrued Expenses on our Consolidated Balance Sheet and expensed as General and Administrative Expense on our Consolidated Statement of Operations. As of June 30, 2018, we had approximately $0.4 million accrued related to the KEIP. Additional information on the KEIP and the KERP is available from Prime Clerk, Claims and Noticing Agent for the bankruptcy proceedings, at https://cases.primeclerk.com/rexenergy/Home-Index.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2018
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	13. COMMITMENTS AND CONTINGENCIES Legal Reserves We are involved in various legal proceedings that arise in the ordinary course of our business. Although we cannot predict the outcome of these proceedings with certainty, we do not currently expect these matters to have a material adverse effect on our consolidated financial position or results of operations. The accrual of reserves for legal matters is included in Accrued Liabilities on our Consolidated Balance Sheets. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and the subjective judgment of management. While we believe that these reserves are adequate, there are uncertainties associated with legal proceedings and we can give no assurance that our estimate of any related liability will not increase or decrease in the future. The reserved and unreserved exposures for our legal proceedings could change based upon developments in those proceedings or changes in the facts and circumstances. It is possible that we could incur losses in excess of the amounts currently accrued. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed our current accruals by an amount that would have a material adverse effect on our consolidated financial position, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred. For the quarter ended June 30, 2018, there were no significant changes with respect to the legal matters disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017, as supplemented by our Periodic Report on Form 10-Q for the period ended June 30, 2018. Environmental Due to the nature of the oil and natural gas business, we are exposed to possible environmental risks. We have implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. We conduct periodic reviews of our policies and properties to identify changes in the environmental risk profile. In these reviews we evaluate whether there is a probable liability, its amount and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any remediation effort. We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. As of June 30, 2018, we know of no significant probable or possible environmental contingent liabilities. Letters of Credit As of June 30, 2018, we have posted $32.0 million in various letters of credit to secure our drilling and related operations. During the second quarter, our various letters of credit were cash collateralized and the cash is shown on our Consolidated Balance Sheet as Restricted Cash. Lease Commitments As of June 30, 2018, we have lease commitments for various real estate leases. Rent expense is recognized on a straight-line basis and has been recorded in General and Administrative expense on our Consolidated Statements of Operations. Rent expense for the three and six months ended June 30, 2018 was approximately $0.2 million and $0.5 million, respectively, and $0.2 million and $0.5 million for the three and six months ended June 30, 2017, respectively. Lease commitments by year for each of the next five years are presented in the table below: ($ in Thousands) 2018 $ 488 2019 903 2020 802 2021 484 2022 496 Thereafter — Total $ 3,173 Capacity Reservation We have a capacity reservation arrangement with a subsidiary of MarkWest Energy Partners, L.P. (“MarkWest”) to ensure sufficient capacity at the cryogenic gas processing plants owned by MarkWest in Butler County, Pennsylvania to process our produced natural gas. In the event that we do not utilize the plants to process quantities of gas sufficient to meet specified volume commitments, we may be obligated to pay approximately $8.8 million in 2018, $17.6 million in 2019, $17.6 million in 2020, $17.5 million in 2021, $17.6 million in 2022 and $68.8 million thereafter, assuming our average net revenue interest in the region of approximately 56%. Charges incurred for unutilized processing capacity with MarkWest during the three and six months ended June 30, 2018 were $0.6 million and $1.2 million, respectively and $1.7 million and $3.3 million during the three and six months ended June 30, 2017, respectively. Water Supply Commitments We have contracted with a water district in Ohio to supply bulk water in support of our Ohio drilling operations. The contract is effective from July 5, 2017 through July 4, 2022. Over the duration the contract, we are obligated to purchase 150 million gallons of water at a fixed price of $7.50 per 1,000 gallons. As of June 30, 2018, our future commitment for unpurchased volumes is approximately $0.6 million. Operational Commitments We have contracted drilling rig services for one rig to support our Appalachian Basin operations. During the second quarter of 2018, we terminated the contract for this rig earlier than its original term. To satisfy the early release, we incurred approximately $1.2 million in early termination fees, which were classified as Other Operating expense in our Consolidated Statement of Operations as of June 30, 2018. We also have contracted completion services in the Appalachian Basin. During the second quarter of 2018, we did not meet the contracted total stage commitment before the end of the contract. To satisfy the remaining commitment owed, we incurred approximately $0.1 million in termination fees, which were classified as Other Operating Expense in our Consolidated Statement of Operations as of June 30, 2018. Natural Gas Gathering, Processing and Sales Agreements During the normal course of business, we have entered into certain agreements to ensure the gathering, transportation, processing and sales of specified quantities of our natural gas, NGLs and condensate. In some instances, we are obligated to pay shortfall fees, whereby we would pay a fee for any difference between actual volumes provided as compared to volumes that have been committed. In other instances, we are obligated to pay a fee on all volumes that are subject to the related agreement. In connection with our entry into certain of these agreements, we concurrently entered into a guaranty whereby we have guaranteed the payment of obligations under the specified agreements up to a maximum of $363.1 million through 2029. For the three and six months ended June 30, 2018, we incurred expenses related to the transportation, processing and marketing of our natural gas, condensate and NGLs of approximately $34.1 million and $65.2 million, respectively and $26.4 million and $52.7 million for the three and six months ended June 30, 2017, respectively. Expense related to these agreements makes up a substantial portion of our Lease Operating Expense, which we expect to continue as existing agreements commence and new transportation, processing and marketing agreements are entered that will enable us to sell our product. During the three and six months ended June 30, 2018, we incurred fees related to unutilized capacity commitments of approximately $0.7 million and $1.4 million, respectively and $0.7 million and $1.4 million during the three and six months ended June 30, 2017, respectively. The unutilized commitment fees are related to undeveloped properties that we acquired during 2014. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows: ($ in Thousands) 2018 $ 25,597 2019 51,096 2020 49,724 2021 46,729 2022 46,260 Thereafter 390,656 Total $ 610,062 Illinois Basin Oil Contingency On June 14, 2016, we, through our wholly owned subsidiaries, Penntex Resources Illinois, LLC, Rex Energy I, LLC, Rex Energy IV, LLC, Rex Energy Marketing, LLC, R. E. Ventures Holdings, LLC, and Rex Energy Operating Corp. (collectively, “Rex”), entered into a Purchase and Sale Agreement (the “Agreement”) with Campbell Development Group, LLC (“Campbell”). An addendum executed in conjunction with the Agreement allows for Rex to receive from Campbell potential additional proceeds of up to $9.9 million, in installments of $0.9 million per quarter, over the period beginning with the quarter ending December 31, 2016, and ending with the quarter ending June 30, 2019. For the proceeds to become payable by Campbell in any of the eleven individual quarters, the average spot price of WTI as published by the New York Mercantile Exchange must be in excess of the amount shown in the table below for the applicable quarter. As of June 30, 2018, the first seven of the eleven quarterly measurement periods have expired with the calculated average spot price of WTI of five out of the seven below the threshold price stipulated in the agreement. Consequently, we did not receive any additional proceeds for the first five measurement periods. As of June 30, 2018 the calculated average spot price of WTI was above the threshold price in the agreement, we then have qualified to receive the additional proceeds for the current period. As of June 30, 2018, we have the potential to receive up to $3.6 million of additional proceeds if the WTI exceeds the price per Bbl as specified in the agreement. Proceeds earned for any quarter are payable to us within one year and fifteen days following the end of the quarter in which additional proceeds are earned. For additional information, see Note 9, Derivative Instruments and Fair Value Measurements Calendar Quarter Ending West Texas Intermediate ("WTI") Average Price per Bbl (a) 9/30/2018 $ 62.25 12/31/2018 $ 62.75 3/31/2019 $ 63.25 6/30/2019 $ 63.75 Pennsylvania Impact Fee In 2012, Pennsylvania instituted a natural gas impact fee on producers of unconventional natural gas. The fee is imposed on every producer of unconventional gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. All fees owed are due on April 1 of each year. For the three and six months ended June 30, 2018, we recorded expense of approximately $0.5 million and $1.1 million, respectively and $0.8 million and $1.6 million for the three and six months ended June 30, 2017, respectively.

Earnings Per Common Share

Earnings Per Common Share	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Earnings Per Common Share	14. EARNINGS PER COMMON SHARE Basic income (loss) per common share is calculated based on the weighted average number of common shares outstanding at the end of the period, excluding restricted stock with performance-based and market-based vesting criteria. Diluted income per common share includes the speculative exercise of stock options and performance-based restricted stock which contain conditions that are not earnings or market-based, given that the hypothetical effect is not anti-dilutive. For the three and six months ended June 30, 2018, we excluded stock options to purchase 69,123 shares of our common stock, due to the exercise price of all exercisable outstanding options exceeding the average market price of our common shares during the period. For the three and six months ended June 30, 2017, we excluded stock options to purchase 112,348 shares of our common stock, due to the exercise price of all exercisable outstanding options exceeding the average market price of our common shares during the period. For the three and six months ended June 30, 2018, there were no performance-based restricted shares excluded. For the three and six months ended June 30, 2017, we excluded performance-based restricted stock of 43,124 shares and 71,715 shares, respectively, due to performance metrics that have not yet been attained (for additional information on our non-cash compensation plans, see Note 11, Employee Benefit and Equity Plans (in thousands, except per share amounts) Three Months Ended June 30, Six Months Ended June 30, Numerator: 2018 2017 2018 2017 Net Loss $ (2,684 ) $ (9,603 ) $ (72,476 ) $ (6,920 ) Less: Preferred Stock Dividends (598 ) (598 ) (1,196 ) (1,196 ) Net Loss Attributable to Common Shareholders $ (3,282 ) $ (10,201 ) $ (73,672 ) $ (8,116 ) Denominator: Weighted Average Common Shares Outstanding - Basic 10,708 9,881 10,587 9,825 Effect of Dilutive Securities: Employee Stock Options — — — — Employee Performance-Based Restricted Stock Awards — — — — Effect of Assumed Conversions of Preferred Stock — — — — Weighted Average Common Shares Outstanding - Diluted 10,708 9,881 10,587 9,825 Earnings per Common Share Attributable to Rex Energy Common Shareholders: Basic — Net Loss Attributable to Common Shareholders $ (0.31 ) $ (1.03 ) $ (6.96 ) $ (0.83 ) Diluted — Net Loss Attributable to Common Shareholders $ (0.31 ) $ (1.03 ) $ (6.96 ) $ (0.83 )

Equity Method Investments

Equity Method Investments	6 Months Ended
	Jun. 30, 2018
Equity Method Investments And Joint Ventures [Abstract]
Equity Method Investments	15. EQUITY METHOD INVESTMENTS RW Gathering, LLC RW Gathering, LLC (“RW Gathering”) is a Delaware limited liability company that we jointly owned with WPX Energy Inc. (“WPX”) and Summit Discovery Resources II, LLC and Sumitomo Corporation (collectively, “Sumitomo”), with our ownership equaling 40%. RW Gathering owns gas-gathering and other midstream assets that service jointly owned properties in Westmoreland and Clearfield Counties, Pennsylvania. Effective as of January 1, 2018, we sold our 40% interest in RW Gathering to COG2, LLC in connection with the sale of our interest in 61 wells located in Westmoreland, Centre and Clearfield Counties, Pennsylvania (the “Westmoreland Sale”). Fo r additional information regarding the Westmoreland Sale, see Note 5, Oil and Gas Properties – Joint Ventures and Divestitures During the six months ended June 30, 2018, we incurred approximately $0.2 million in compression expenses that were charged to us from Williams Production Appalachia, LLC. These costs are in relation to compression costs incurred by RW Gathering and are recorded as Production and Lease Operating Expense on our Consolidated Statement of Operations. As of December 31, 2017, there were no receivables or payables due between RW Gathering and us.

Impairment Expense

Impairment Expense	6 Months Ended
	Jun. 30, 2018
Impairment Of Oil And Gas Properties [Abstract]
Impairment Expense	16. IMPAIRMENT EXPENSE For the three and six months ended June 30, 2018, impairment expenses incurred were approximately $4.3 million and $12.5 million, respectively, and impairment expenses incurred for the three and six months ended June 30, 2017, were approximately $3.0 million and $4.6 million, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment. The expense incurred during the first six months of 2018 included approximately $11.3 million of undeveloped leases that expired or are expected to expire without being developed, the majority of which are in Butler County, Pennsylvania, and Warrior North in Ohio. Impairments of proved properties in our Westmoreland County operations totaled approximately $1.2 million during the first six months of 2018. The impairments were identified through an analysis of market conditions and future development plans that were in existence as of each period end related to these properties, which indicated that the carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets and future development plans. Our estimates of future cash flows attributable to our oil and gas properties could decline if commodity prices decline, which may result in our incurrence of additional impairment expense. As of June 30, 2018, we continued to carry the costs of undeveloped properties of approximately $174.6 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale and for which we currently have development, trade or lease extension plans. The expense incurred during the first six months of 2017 included approximately $3.8 million of undeveloped leases that expired or are expected to expire without being developed, the majority of which were in Butler County, Pennsylvania and Warrior North in Ohio. Impairments of proved properties in our Butler County operations totaled approximately $0.8 million during the first six months of 2017

Exploration Expense

Exploration Expense	6 Months Ended
	Jun. 30, 2018
Extractive Industries [Abstract]
Exploration Expense	17. EXPLORATION EXPENSE For the three and six months ended June 30, 2018, exploration expenses incurred were approximately $0.1 million and $0.3 million, respectively and approximately $0.1 million and $0.3 million for the three and six months ended June 30, 2017, respectively. Approximately $0.2 million of the expense incurred in 2018 was due to geological and geophysical type expenditures and the remaining $0.1 million was due to delay rentals. Approximately $0.2 million of the expense incurred in 2017 was due to geological and geophysical type expenditures and the remaining $0.1 million was due to delay rentals.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	6 Months Ended
	Jun. 30, 2018
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Financial Information	18. CONDENSED CONSOLIDATING FINANCIAL INFORMATION As of June 30, 2018, we had $600.3 million aggregate principal amount of outstanding Senior Notes, as shown in Note 8, Debt • Rex Energy I, LLC; • Rex Energy Operating Corporation; • R.E. Gas Development, LLC. The non-guarantor subsidiaries include certain consolidated subsidiaries, including R.E. Disposal, LLC, Rex Energy Marketing, LLC and R.E. Ventures Holdings, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of June 30, 2018, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries. The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the notes, (ii) the combined Guarantors, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of June 30, 2018 and December 31, 2017, the condensed consolidating statements of operations for the three and six months ended June 30, 2018 and 2017, and the condensed consolidating statements of cash flows for the six months ended June 30, 2018 and 2017. REX ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING BALANCE SHEETS AS OF JUNE 30, 2018 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 28,777 $ — $ 3 $ — $ 28,780 Restricted Cash — — 33,106 — 33,106 Accounts Receivable 26,961 — 1,627 — 28,588 Taxes Receivable — — 48 — 48 Short-Term Derivative Instruments 2,346 — 2,450 — 4,796 Inventory, Prepaid Expenses and Other 3,389 — — — 3,389 Total Current Assets 61,473 — 37,234 — 98,707 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,062,986 — — — 1,062,986 Unevaluated Oil and Gas Properties 174,608 — — — 174,608 Other Property and Equipment 20,066 — — — 20,066 Wells and Facilities in Progress 2,552 — — — 2,552 Pipelines 16,528 — — — 16,528 Total Property and Equipment 1,276,740 — — — 1,276,740 Less: Accumulated Depreciation, Depletion and Amortization (384,556 ) — — — (384,556 ) Net Property and Equipment 892,184 — — — 892,184 Other Assets 35 — — — 35 Intercompany Receivables — — 1,118,701 (1,118,701 ) — Investment in Subsidiaries – Net (2,805 ) — (287,208 ) 290,013 — Long-Term Derivative Instruments 1,463 — — — 1,463 Deferred Tax Assets - Long Term — — 130 — 130 Total Assets $ 952,350 $ — $ 868,857 $ (828,688 ) $ 992,519 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 32,679 $ — $ 50,000 $ — $ 82,679 Current Maturities of Long-Term Debt — — $ 261,315 — 261,315 Debtor-in Possession Term Loan Payable — — 35,000 — 35,000 Accrued Liabilities 18,074 — 12,862 — 30,936 Short-Term Derivative Instruments 19,095 — — — 19,095 Total Current Liabilities 69,848 — 359,177 — 429,025 Long-Term Derivative Instruments 12,075 — — — 12,075 Future Abandonment Cost 8,626 — — — 8,626 Liabilities Subject to Compromise 37,230 — 630,394 — 667,624 Intercompany Payables 1,114,295 4,406 — (1,118,701 ) — Total Liabilities 1,242,074 4,406 989,571 (1,118,701 ) 1,117,350 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 11 — 11 Additional Paid-In Capital 177,143 — 654,721 (177,143 ) 654,721 Accumulated Deficit (466,867 ) (4,406 ) (775,447 ) 467,156 (779,564 ) Total Stockholders’ Equity (289,724 ) (4,406 ) (120,714 ) 290,013 (124,831 ) Total Liabilities and Stockholders’ Equity $ 952,350 $ — $ 868,857 $ (828,688 ) $ 992,519 REX ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2018 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 75,155 $ — $ — $ — $ 75,155 Other Operating Revenue 3 — — — 3 TOTAL OPERATING REVENUE 75,158 — — — 75,158 OPERATING EXPENSES Production and Lease Operating Expense 36,756 — — — 36,756 General and Administrative Expense 4,235 — 187 — 4,422 Impairment Expense 4,334 — — — 4,334 Exploration Expense 122 — — — 122 Depreciation, Depletion, Amortization and Accretion 16,953 — — — 16,953 Other Operating Expense 1,492 — — — 1,492 TOTAL OPERATING EXPENSES 63,892 — 187 — 64,079 INCOME (LOSS) FROM OPERATIONS 11,266 — (187 ) — 11,079 OTHER INCOME (EXPENSE) Interest Expense (662 ) — (13,456 ) — (14,118 ) (Loss) Gain on Derivatives, Net (18,413 ) — 4,085 — (14,328 ) Other (Expense) Income 53 — (14,005 ) — (13,952 ) Reorganization Items, Net (1,314 ) — 29,949 — 28,635 Loss from Equity in Consolidated Subsidiaries — — (9,070 ) 9,070 — TOTAL OTHER INCOME (EXPENSE) (20,336 ) — (2,497 ) 9,070 (13,763 ) LOSS BEFORE INCOME TAX (9,070 ) — (2,684 ) 9,070 (2,684 ) Income tax Benefit — — — — — NET LOSS $ (9,070 ) $ — $ (2,684 ) $ 9,070 $ (2,684 ) Preferred Stock Dividends — — (598 ) — (598 ) NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (9,070 ) $ — $ (3,282 ) $ 9,070 $ (3,282 ) REX ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2018 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 140,180 $ — $ — $ — $ 140,180 Other Operating Revenue 7 — — — 7 TOTAL OPERATING REVENUE 140,187 — — — 140,187 OPERATING EXPENSES Production and Lease Operating Expense 70,602 — — — 70,602 General and Administrative Expense 9,739 — 1,207 — 10,946 Loss on Disposal of Assets 647 — — — 647 Impairment Expense 12,503 — — — 12,503 Exploration Expense 350 — — — 350 Depreciation, Depletion, Amortization and Accretion 32,081 — — — 32,081 Other Operating Expense 1,695 — — — 1,695 TOTAL OPERATING EXPENSES 127,617 — 1,207 — 128,824 INCOME (LOSS) FROM OPERATIONS 12,570 — (1,207 ) — 11,363 OTHER INCOME (EXPENSE) Interest Expense (1,333 ) — (35,432 ) — (36,765 ) Loss on Derivatives, Net (13,088 ) — (47,666 ) — (60,754 ) Other Expense (951 ) — (14,004 ) — (14,955 ) Reorganization Items, Net (1,313 ) — 29,948 — 28,635 (Loss) Income From Equity in Consolidated Subsidiaries — — (4,115 ) 4,115 — TOTAL OTHER INCOME (EXPENSE) (16,685 ) — (71,269 ) 4,115 (83,839 ) LOSS BEFORE INCOME TAX (4,115 ) — (72,476 ) 4,115 (72,476 ) Income Tax Benefit — — — — — NET LOSS $ (4,115 ) $ — $ (72,476 ) $ 4,115 $ (72,476 ) Preferred Stock Dividends — — (1,196 ) — (1,196 ) NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (4,115 ) $ — $ (73,672 ) $ 4,115 $ (73,672 ) REX ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2018 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net (Loss) Income $ (4,115 ) $ — $ (72,476 ) $ 4,115 (72,476 ) Adjustments to Reconcile Net Loss to Net Cash Provided (Used) by Operating Activities Depreciation, Depletion, Amortization and Accretion 32,081 — — — 32,081 Loss on Derivatives, Net 13,088 — 47,666 — 60,754 Cash Settlements of Derivatives (6,862 ) — — — (6,862 ) Equity-based Compensation Expense (7 ) — 1,207 — 1,200 Impairment Expense 12,503 — — — 12,503 Non-cash Interest Expense — — 2,881 — 2,881 Loss on Disposal of Assets 647 — — — 647 Non-cash Reorganization Items, Net — — (43,509 ) — (43,509 ) Other Non-cash Expense (Income) 588 — (22 ) — 566 Changes in operating assets and liabilities Accounts Receivable (342 ) — — — (342 ) Taxes Receivable — — 2,001 — 2,001 Inventory, Prepaid Expenses and Other Assets (2,173 ) — 2,509 — 336 Accounts Payable and Accrued Liabilities 7,778 — 33,700 — 41,478 Other Assets and Liabilities (147 ) — — — (147 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 53,039 — (26,043 ) 4,115 31,111 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 46,062 — (41,947 ) (4,115 ) — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 16,384 — — — 16,384 Acquisitions of Undeveloped Acreage (871 ) — — — (871 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (100,136 ) — — — (100,136 ) NET CASH USED IN INVESTING ACTIVITIES (38,561 ) — (41,947 ) (4,115 ) (84,623 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Line of Credit, net of Discounts — — 69,846 — 69,846 Proceeds from Debtor-in Possession Financing — — 35,000 — 35,000 Repayments of Loans and Other Long-Term Debt (945 ) — — — (945 ) Reorganization Item - Debtor-In-Possession Financing Fee — — (3,750 ) — (3,750 ) NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES (945 ) — 101,096 — 100,151 Net Increase in Cash, Cash Equivalents and Restricted Cash 13,533 — 33,106 — 46,639 Beginning Cash, Cash Equivalents and Restricted Cash 15,244 — 3 — 15,247 Ending Cash, Cash Equivalents and Restricted Cash $ 28,777 $ — $ 33,109 $ — $ 61,886 REX ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING BALANCE SHEETS AS OF DECEMBER 31, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 15,244 $ — $ 3 $ — $ 15,247 Accounts Receivable 25,974 — — — 25,974 Taxes Receivable — — 2,049 — 2,049 Short-Term Derivative Instruments 8,008 — — — 8,008 Inventory, Prepaid Expenses and Other 2,106 — 2,508 — 4,614 Total Current Assets 51,332 — 4,560 — 55,892 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,086,625 — — — 1,086,625 Unevaluated Oil and Gas Properties 186,523 — — — 186,523 Other Property and Equipment 19,640 — — — 19,640 Wells and Facilities in Progress 38,660 — — — 38,660 Pipelines 16,803 — — — 16,803 Total Property and Equipment 1,348,251 — — — 1,348,251 Less: Accumulated Depreciation, Depletion and Amortization (463,899 ) — — — (463,899 ) Net Property and Equipment 884,352 — — — 884,352 Other Assets 44 — — — 44 Intercompany Receivables — — 1,072,637 (1,072,637 ) — Investment in Subsidiaries – Net (2,484 ) — (272,261 ) 274,745 — Long-Term Derivative Instruments (2 ) — 1,721 — 1,719 Deferred Tax Assets - Long Term — — 130 — 130 Total Assets $ 933,242 $ — $ 806,787 $ (797,892 ) $ 942,137 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 62,354 $ — $ — $ — $ 62,354 Current Maturities of Long-Term Debt 1,926 — 832,399 — 834,325 Accrued Liabilities 32,214 — 13,004 — 45,218 Short-Term Derivative Instruments 14,892 — — — 14,892 Total Current Liabilities 111,386 — 845,403 — 956,789 Long-Term Derivative Instruments 14,249 — — — 14,249 Long-Term Debt — — — — — Other Long-Term Debt 8,156 — — — 8,156 Other Deposits and Liabilities 7,153 — — — 7,153 Future Abandonment Cost 9,352 — — — 9,352 Intercompany Payables 1,068,231 4,406 — (1,072,637 ) — Total Liabilities 1,218,527 4,406 845,403 (1,072,637 ) 995,699 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 10 — 10 Additional Paid-In Capital 177,144 — 652,917 (177,144 ) 652,917 Accumulated Deficit (462,429 ) (4,406 ) (691,544 ) 451,889 (706,490 ) Total Stockholders’ Equity (285,285 ) (4,406 ) (38,616 ) 274,745 (53,562 ) Total Liabilities and Stockholders’ Equity $ 933,242 $ — $ 806,787 $ (797,892 ) $ 942,137 REX ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 47,457 $ — $ — $ — $ 47,457 Other Operating Expense 5 — — — 5 TOTAL OPERATING REVENUE 47,462 — — — 47,462 OPERATING EXPENSES Production and Lease Operating Expense 29,374 — — — 29,374 General and Administrative Expense 3,771 — 523 — 4,294 Gain on Disposal of Assets (124 ) — — — (124 ) Impairment Expense 3,032 — — — 3,032 Exploration Expense 99 — — — 99 Depreciation, Depletion, Amortization and Accretion 15,501 — — — 15,501 Other Operating (Income) Expense (99 ) 1 — — (98 ) TOTAL OPERATING EXPENSES 51,554 1 523 — 52,078 LOSS FROM OPERATIONS (4,092 ) (1 ) (523 ) — (4,616 ) OTHER INCOME (EXPENSE) — Interest Expense (442 ) — (11,680 ) — (12,122 ) (Loss) Gain on Derivatives, Net 10,861 — (475 ) — 10,386 Other Income 20 — — 20 Loss on Extinguishments of Debt — — (3,271 ) (3,271 ) Income (Loss) From Equity in Consolidated Subsidiaries (1 ) — 6,346 (6,345 ) — TOTAL OTHER INCOME (EXPENSE) 10,438 — (9,080 ) (6,345 ) (4,987 ) INCOME (LOSS) BEFORE INCOME TAX 6,346 (1 ) (9,603 ) (6,345 ) (9,603 ) Income Tax Benefit — — — — — NET INCOME (LOSS) 6,346 (1 ) (9,603 ) (6,345 ) (9,603 ) Preferred Stock Dividends — — (598 ) — (598 ) NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 6,346 $ (1 ) $ (10,201 ) $ (6,345 ) $ (10,201 ) REX ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, Condensate and NGL Sales $ 99,522 $ — $ — $ — $ 99,522 Other Revenue 11 — — — 11 TOTAL OPERATING REVENUE 99,533 — — — 99,533 OPERATING EXPENSES Production and Lease Operating Expense 58,308 — — — 58,308 General and Administrative Expense 8,232 — 596 — 8,828 Gain on Disposal of Assets (1,959 ) — — — (1,959 ) Impairment Expense 4,577 — — — 4,577 Exploration Expense 319 — — — 319 Depreciation, Depletion, Amortization and Accretion 30,969 — — — 30,969 Other Operating (Income) Expense (119 ) 1 — — (118 ) TOTAL OPERATING EXPENSES 100,327 1 596 — 100,924 LOSS FROM OPERATIONS (794 ) (1 ) (596 ) — (1,391 ) OTHER INCOME (EXPENSE) Interest Expense (809 ) — (20,457 ) — (21,266 ) (Loss) Gain on Derivatives, Net 20,659 — (1,893 ) — 18,766 Other Expense (7 ) — — — (7 ) Loss on Extinguishments of Debt — — (3,022 ) — (3,022 ) Income (Loss) From Equity in Consolidated Subsidiaries (1 ) — 19,048 (19,047 ) — TOTAL OTHER INCOME (EXPENSE) 19,842 — (6,324 ) (19,047 ) (5,529 ) INCOME (LOSS) BEFORE INCOME TAX 19,048 (1 ) (6,920 ) (19,047 ) (6,920 ) Income Tax Benefit — — — — — NET INCOME (LOSS) 19,048 (1 ) (6,920 ) (19,047 ) (6,920 ) Preferred Stock Dividends — — (1,196 ) — (1,196 ) NET (LOSS) INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 19,048 $ (1 ) $ (8,116 ) $ (19,047 ) $ (8,116 ) CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 19,048 $ (1 ) $ (6,920 ) $ (19,047 ) $ (6,920 ) Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities Depreciation, Depletion, Amortization and Accretion 30,969 — — — 30,969 (Gain) Loss on Derivatives, Net (20,659 ) — 1,893 — (18,766 ) Cash Settlements of Derivatives (5,525 ) — — — (5,525 ) Equity-based Compensation Expense — — 571 — 571 Non-cash Exploration Expense 13 — — — 13 Gain on Disposal of Assets (1,959 ) — — — (1,959 ) Loss on Extinguishments of Debt — — 3,022 — 3,022 Non-cash Interest Expense — — 12,431 — 12,431 Impairment Expense 4,577 — — — 4,577 Other Non-Cash Expense 41 — — — 41 Changes in operating assets and liabilities Accounts Receivable 7,232 — (3 ) — 7,229 Taxes Receivable — 163 Inventory, Prepaid Expenses and Other Assets 638 — (586 ) — 52 Accounts Payable and Accrued Liabilities (1,484 ) — — — (1,484 ) Other Assets and Liabilities (1,104 ) — — — (1,104 ) NET CASH PROVIDED BY OPERATING ACTIVITIES 31,787 (1 ) 10,571 (19,047 ) 23,310 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 4,063 1 (23,111 ) 19,047 — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 24,513 — — — 24,513 Acquisitions of Undeveloped Acreage (1,783 ) — — — (1,783 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (54,004 ) — — — (54,004 ) NET CASH USED IN INVESTING ACTIVITIES (27,211 ) 1 (23,111 ) 19,047 (31,274 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit, net of Discounts — — 171,000 — 171,000 Repayments of Long Term Debt and Lines of Credit — — (145,170 ) — (145,170 ) Repayments of Loans and Other Long-Term Debt (319 ) — — — (319 ) Debt Issuance Costs — (7,791 ) (7,791 ) Payment of Preferred Dividends in arrears — — (598 ) — (598 ) NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES (319 ) — 17,441 — 17,122 NET INCREASE IN CASH 4,257 — 4,901 — 9,158 CASH – BEGINNING 3,694 — 3 — 3,697 CASH - ENDING $ 7,951 $ — $ 4,904 $ — $ 12,855

Subsequent Events

Subsequent Events	6 Months Ended
	Jun. 30, 2018
Subsequent Events [Abstract]
Subsequent Events	19. SUBSEQUENT EVENTS Approval of Final DIP Facility and Roll-up of Prepetition Secured Claims On July 11, 2018, the Bankruptcy Court issued a Final Order approving the motion (i) Authorizing The Debtors To Obtain Senior Secured, Superpriority, Post-Petition Financing, (II) Authorizing Use of Cash Collateral, (III) Granting Priming Liens, Priority Liens and Super-Priority Claims and (IV) Granting Adequate Protection To Prepetition Secured Parties. The approved motion authorized the Rex Debtors to obtain from our pre-petition First Lien lenders a post-petition delayed draw term loan facility in the aggregate principal amount of up to $411,315,322, consisting of the prior Term Loan balance of $261,315,322, the Make Whole Amount of $50,000,000, and $100,000,000 of funding available to finance post-petition operations throughout the Chapter 11 process (the “Additional Borrowing Capacity”). As of June 30, 2018, we had drawn $35,000,000 of the Additional Borrowing Capacity. The approval of the roll-up of the First Lien prepetition term debt and credit agreement Make Whole Amount into the final approved DIP Facility secures all claims held by our First Lien lenders with first-position priority claims status.

Summary Of Significant Accounti

Summary Of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates The preparation of the accompanying condensed consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of natural gas, NGLs, and oil future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.
Recently Issued Accounting Pronouncements	In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases • a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and • a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Public business entities are required to apply the amendment of this update for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. We are currently evaluating the potential impact of this standard on our results of operations and internal control environment. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments • debt prepayment or debt extinguishment costs; • settlement of zero-coupon debt instruments or other instruments with coupon rates that are insignificant in relation to the effective interest rate of borrowing; • contingent consideration payments made after a business combination; • proceeds from the settlement of insurance claims; • proceeds from the settlement of corporate-owned life insurance policies; • distributions received from equity method investees; • beneficial interest in securitization transactions; and • separately identifiable cash flows and application of the Predominance Principle. Public business entities are required to apply the amendments of this update for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. We adopted this standard effective January 1, 2018 on a retrospective basis. Adoption of the standard did not have an impact on the presentation of our consolidated statements of cash flows In May 2017, the FASB issued ASU 2017-09, Stock Compensation - Scope of Modification Accounting

Petition Relief Under Chapter27

Petition Relief Under Chapter 11 and Going Concern Assessment (Tables)	6 Months Ended
	Jun. 30, 2018
Reorganizations [Abstract]
Schedule of Components of Liabilities Subject to Compromise	The following table summarizes the components of liabilities subject to compromise included on the condensed consolidated balance sheet: June 30, 2018 (in thousands) Accounts Payable and Accrued Expenses $ 27,716 Accrued Interest Payable 30,043 Debt (See Note 8) 609,865 Liabilities Subject to Compromise $ 667,624
Summary of Components of Reorganization Items	The following table summarizes the components of reorganization items included on the consolidated statements of operations: Three Ended June 30, 2018 (in thousands) Legal and Professional Fees $ (9,817 ) Unamortized Deferred Financing Balances (a) 43,509 Debtor-in Possession Financing Fees (3,750 ) Effect of Early Hedge Terminations (1,175 ) Other (132 ) Reorganization Items, net $ 28,635 (a)

Revenue Recognition (Tables)

Revenue Recognition (Tables)	6 Months Ended
	Jun. 30, 2018
Revenue From Contract With Customer [Abstract]
Summary of Disaggregated Revenues Recognized from Contracts with Customers in Consolidated Statements of Operations	The following table summarizes our disaggregated revenues recognized from contracts with customers in our Consolidated Statements of Operations for the three and six month periods ended June 30, 2018 and 2017. Three Months Ended June 30, Six Months Ended June 30, ($ in Thousands) 2018 2017 2018 2017 Revenues from Contracts with Customers by Product Natural Gas $ 29,705 $ 29,097 $ 59,387 $ 60,442 NGLs 32,293 15,367 61,011 32,667 Condensate 13,157 2,993 19,782 6,413 Total $ 75,155 $ 47,457 $ 140,180 $ 99,522

Future Abandonment Cost (Tables

Future Abandonment Cost (Tables)	6 Months Ended
	Jun. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
Future Abandonment Costs	. We account for future abandonment costs that relate to wells that are drilled jointly based on our working interest in those wells. ($ in Thousands) June 30, 2018 Beginning Balance at January 1, 2018 $ 9,939 Future Abandonment Obligation Incurred $ 137 Future Abandonment Obligation Settled $ (156 ) Future Abandonment Obligation Cancelled or Sold $ (877 ) Future Abandonment Obligation Revision of Estimated Obligation $ 99 Future Abandonment Obligation Accretion Expense $ 473 Total Future Abandonment Cost 1 $ 9,616 1

Debt (Tables)

Debt (Tables)	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Components of Secured Debt and Debt Balances Subject to Compromise	June 30, 2018 Secured Debt Debt Balances included in Liabilities Subject to Compromise Term Loan - due April 2020 $ 261,315 $ — Debtor-In-Possession Term Loan - due November 2018 $ 35,000 $ — 8.875% Senior Notes due 2020 $ — $ 7,333 6.25% Senior Notes due 2022 — 5,363 1% / 8% Second Lien Senior Notes due 2020 — 587,606 Total Senior Notes $ — $ 600,302 Long-Term Capital Leases - Equipment Financing Due March, 2021 $ — $ 557 Due June, 2021 — 1,254 Due September, 2021 — 1,428 Due May, 2022 — 6,324 Total Capital Lease Obligations $ — $ 9,563 Debt Balances Subject to Compromise $ — $ 609,865
Components of Long-Term Debt and Lines of Credit	December 31, 2017 Principal Unamortized net Premium / Discount Unamortized Debt Issuance Costs Deferred Gain on Debt Restructurings, Net Net Carrying Value Term Loans, Net Term Loan Draw - due April 2020 $ 189,500 $ (4,711 ) $ (2,761 ) $ — $ 182,028 Senior Notes, Net 8.875% Senior Notes due 2020 $ 7,333 $ — $ — $ (60 ) $ 7,273 6.25% Senior Notes due 2022 5,363 — — (67 ) 5,296 1% / 8% Second Lien Senior Notes due 2020 587,606 — — 50,196 637,802 $ 600,302 $ — $ — $ 50,069 $ 650,371 Other Long-Term Debt Long-Term Capital Leases and Other Notes Payable- Equipment Financing Due March, 2021 $ 632 Due June, 2021 1,418 Due September, 2021 1,578 Due May 2022 6,454 Total Capital Lease Obligations $ 10,082 Less: Current Portion of Capital Leases and Other Notes Payable (1,926 ) $ 8,156

Derivative Instruments And Fa31

Derivative Instruments And Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2018
Fair Value Of Financial Instruments And Derivative Instruments [Abstract]
Schedule of Location and Amounts of Gains and Losses on Derivative Instruments	Derivative Instruments On May 18, 2018, the Bankruptcy Court approved a motion to continue our derivative programs in the normal course of business. In conjunction with the Bankruptcy Petitions, one of our derivative counterparties elected to terminate their outstanding contracts with us, resulting in a $2.0 million liability. Approximately $0.8 million was related to the fair value of the derivatives on the date of termination, which was recognized as (Loss) Gain on Derivatives, Net for the three and six months ended June 30, 2018. Approximately $1.2 million was related to costs associated with the early termination of the derivative positions and was recorded as Reorganization Items, Net for the three and six months ended June 30, 2018. The following table summarizes the location and amounts of gains and losses on our derivative instruments, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three and six months ended June 30, 2018 and 2017: For the Three Months Ended June 30, For the Six Months Ended June 30, ($ in Thousands) 2018 2017 2018 2017 Oil $ (3,817 ) $ 791 $ (5,553 ) $ 1,934 Natural Gas (213 ) 6,132 3,179 6,072 NGLs (14,383 ) 3,938 (10,714 ) 12,653 Contingent Consideration 1,120 (475 ) 2,334 (1,893 ) Embedded Derivatives 2,965 — (50,000 ) — (Loss) Gain on Derivatives, Net $ (14,328 ) $ 10,386 $ (60,754 ) $ 18,766
Asset or Liability Financial Commodity Derivative Instrument Positions	Our open asset/(liability) financial commodity derivative instrument positions at June 30, 2018 consisted of: Period Volume Put Option Floor Ceiling Swap Fair Market Value ($ in Thousands) Oil 2018 - Swaps 85,750 Bbls $ — $ — $ — $ 57.47 $ (817 ) 2018 - Three-Way Collars 42,000 Bbls 41.82 51.09 60.75 — (413 ) 2019 - Swaps 118,000 Bbls — — — 55.89 (1,231 ) 2019 - Collars 18,000 Bbls — 45.00 55.80 — (125 ) 2019 - Three-Way Collars 42,000 Bbls 38.57 48.57 58.86 — (375 ) 2020 - Swaps 24,000 Bbls — — — 51.00 (304 ) 2020 - Collars 22,500 Bbls 45.00 55.80 (167 ) 2020 - Three-Way Collars 21,500 Bbls 38.95 48.95 60.22 — (103 ) 2021 - Swaps 6,000 Bbls — — — 51.00 (76 ) 2021 - Collars 16,500 Bbls — 45.00 55.80 — (125 ) 2021 - Three-Way Collars 62,500 Bbls 37.44 47.04 57.98 — (240 ) 2022 - Three-Way Collars 23,000 Bbls 39.35 49.35 60.43 — (60 ) 481,750 Bbls $ (4,037 ) Natural Gas 2018 - Swaps 12,127,500 Mcf — — — 2.98 $ 394 2018 - Three-Way Collars 4,260,000 Mcf 2.31 2.88 3.55 — 310 2018 - Calls 2,920,000 Mcf — — 3.97 — (19 ) 2018 - Collars 2,222,500 Mcf — 2.60 3.04 — (134 ) 2018 - Basis Swaps - Dominion South 9,808,000 Mcf — — — (0.83 ) (1,858 ) 2018 - Basis Swaps - Texas Gas 7,360,000 Mcf — — — (0.13 ) 324 2019 - Swaps 7,500,000 Mcf — — — 2.91 129 2019 - Three-Way Collars 8,045,000 Mcf 2.35 2.81 3.43 — 313 2019 - Collars 4,471,750 Mcf — 2.62 3.03 — (227 ) 2019 - Basis Swaps - Dominion South 12,775,000 Mcf — — — (0.84 ) (3,725 ) 2020 - Swaps 4,642,500 Mcf — — — 2.90 242 2020 - Three-Way Collars 4,935,000 Mcf 2.33 2.77 3.31 — 350 2020 - Collars 2,645,000 Mcf — 2.65 3.03 — (34 ) 2020 - Basis Swaps - Dominion South 7,320,000 Mcf — — — (0.84 ) (2,068 ) 2021 - Swaps 900,000 Mcf — — — 2.90 59 2021 - Three-Way Collars 1,346,250 Mcf 2.32 2.74 3.20 — 97 2021 - Collars 792,500 Mcf — 2.65 3.05 — 43 2021 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (185 ) 2022 - Collars 147,500 Mcf — 2.65 3.05 — 11 2022 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (185 ) 2023 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (185 ) 2024 - Basis Swaps - Dominion South 3,650,000 Mcf — — — (0.72 ) (185 ) 108,818,500 Mcf $ (6,533 ) NGLs 2018 - C3+ NGL Swaps 640,036 Bbls — — — 33.06 $ (8,150 ) 2018 - Ethane Swaps 780,000 Bbls — — — 12.13 (450 ) 2019 - C3+ NGL Swaps 570,814 Bbls — — — 30.90 (4,524 ) 2019 - C5 Collars 113,040 Bbls — 45.00 54.83 — (964 ) 2019 - Ethane Swaps 1,264,750 Bbls — — — 12.60 322 2020 - C3+ NGL Swaps 191,112 Bbls — — — 32.22 (1,875 ) 2020 - C5 Collars 28,260 Bbls — 45.00 54.83 — (241 ) 2020 - Ethane Swaps 1,007,750 Bbls — — — 12.31 (73 ) 2021 - C3+ NGL Swap 88,404 Bbls — — — 41.70 (599 ) 2021 - Ethane Swaps 724,000 Bbls — — — 12.27 (98 ) 2022 - C3+ NGL Swap 9,420 Bbls — — — 50.50 (33 ) 2022 - Ethane Swaps 352,250 Bbls — — — 12.27 (107 ) 5,769,836 Bbls $ (16,791 )
Combined Fair Value of Derivatives	The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017 is summarized below: June 30, December 31, ($ in Thousands) 2018 2017 Short-Term Derivative Assets: NGL—Swaps $ 365 $ 928 Natural Gas—Swaps 1,118 3,734 Natural Gas—Collars 22 183 Natural Gas—Basis Swaps 328 191 Natural Gas—Three-Way Collars 513 1,721 Contingent Consideration - Sale of Illinois Basin 2,450 1,251 Total Short-Term Derivative Assets $ 4,796 $ 8,008 Long-Term Derivative Assets: NGL—Swaps $ 308 $ 409 Natural Gas—Swaps 422 411 Natural Gas—Collars 119 — Natural Gas—Three-Way Collars 614 429 Contingent Consideration - Sale of Illinois Basin — 470 Total Long-Term Derivative Assets $ 1,463 $ 1,719 Total Derivative Assets $ 6,259 $ 9,727 Short-Term Derivative Liabilities: Crude Oil—Collars $ (42 ) $ (31 ) Crude Oil—Three-Way Collars (650 ) (92 ) Crude Oil—Swaps (1,442 ) (518 ) NGL—Swaps (11,700 ) (10,281 ) NGL—Collars (482 ) — Natural Gas—Three-Way Collars (56 ) (49 ) Natural Gas—Collars (268 ) (146 ) Natural Gas—Basis Swaps (3,725 ) (3,621 ) Natural Gas—Call (19 ) (154 ) Natural Gas—Swaps (711 ) — Total Short - Term Derivative Liabilities $ (19,095 ) $ (14,892 ) Long-Term Derivative Liabilities: Crude Oil—Three-Way Collars $ (541 ) $ (161 ) Crude Oil—Swaps (986 ) (202 ) Crude Oil—Collars (376 ) (425 ) NGL—Swaps (4,560 ) (4,482 ) NGL—Collars (723 ) (385 ) NGL—Three Way Collars — (66 ) Natural Gas—Swaps (5 ) (423 ) Natural Gas—Basis Swaps (4,671 ) (7,120 ) Natural Gas—Collars (213 ) (713 ) Natural Gas—Three-Way Collars — (272 ) Total Long-Term Derivative Liabilities $ (12,075 ) $ (14,249 ) Total Derivative Liabilities $ (31,170 ) $ (29,141 )
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value	The following table presents the fair value hierarchy table for assets and liabilities measured at fair value: Fair Value Measurements at June 30, 2018 ($ in Thousands) Total Carrying Value as of June 30, 2018 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ (24,911 ) $ — $ (24,911 ) $ — Fair Value Measurements at December 31, 2017 ($ in Thousands) Total Carrying Value as of December 31, 2017 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ (19,414 ) $ — $ (19,414 ) $ —
Financial Instruments Not Recorded at Fair Value	The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements: June 30, 2018 December 31, 2017 ($ in Thousands) Carrying Amount Fair Value Carrying Amount Fair Value Senior Notes, Net of Issuance Costs $ 600,302 $ 6,730 $ 650,371 $ 264,438 Term Loan 261,315 252,966 182,028 182,028 Debtor In Possession Secured Term Loan 35,000 35,000 — — Capital Leases and Other Obligations 9,563 7,065 10,082 7,138 Total $ 906,180 $ 301,761 $ 842,481 $ 453,604

Income Taxes (Tables)

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Schedule of Income Tax Included in Continuing Operations	Income tax included in continuing operations was as follows: Three Months Ended June 30, Six Months Ended June 30, ($ in Thousands) 2018 2017 2018 2017 Income Tax Benefit (Expense) $ — $ — $ — $ — Effective Tax Rate 0.0 % 0.0 % 0.0 % 0.0 %

Employee Benefit And Equity P33

Employee Benefit And Equity Plans (Tables)	6 Months Ended
	Jun. 30, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Issued and Outstanding Stock Options	A summary of the status of our issued and outstanding stock options as of June 30, 2018 is as follows: Outstanding Exercisable Exercise Price Number Outstanding at June 30, 2018 Weighted-Average Exercise Price Number Exercisable at June 30, 2018 Weighted-Average Exercise Price 9.70 2,667 $ 9.70 1,835 $ 9.70 16.90 57,169 $ 16.90 38,118 $ 16.90 49.00 4,000 $ 49.00 4,000 $ 49.00 50.40 3,070 $ 50.40 3,070 $ 50.40 104.20 2,217 $ 104.20 2,217 $ 104.20 69,123 $ 22.77 49,240 $ 25.26
Monte Carlo Simulation Model Assumptions Used to Estimate Fair Value of Restricted Stock	Average fair values were estimated on the date of each grant using a Monte Carlo Simulation model that estimates the most likely outcome based on the terms of the award and used the following assumptions: Six Months Ended June 30, 2018 Year Ended December 31, 2017 Expected Dividend Yield 0.0% 0% Risk-Free Interest Rate 1.0% 1.0% Expected Volatility – Rex Energy 58.6% 58.6% Expected Volatility – Peer Group 29.8%-85.0% 29.8%-85.0% Market Index 35.6% 35.6% Expected Life Three Years Three Years
Summary of Nonvested Restricted Stock Activity	A summary of the restricted stock activity for the six months ended June 30, 2018 is as follows: Number of Shares Weighted-Average Grant Date Fair Value Restricted stock awards, as of December 31, 2017 200,475 $ 13.62 Awards — — Forfeitures (27,817 ) 15.13 Vested (56,976 ) 24.72 Restricted stock awards, as of June 30, 2018 $ 115,682 $ 7.79

Commitments and Contingencies (

Commitments and Contingencies (Tables)	6 Months Ended
	Jun. 30, 2018
Commitments And Contingencies Disclosure [Abstract]
Lease Commitments for Each of Next Five Years	As of June 30, 2018, we have lease commitments for various real estate leases. Rent expense is recognized on a straight-line basis and has been recorded in General and Administrative expense on our Consolidated Statements of Operations. Rent expense for the three and six months ended June 30, 2018 was approximately $0.2 million and $0.5 million, respectively, and $0.2 million and $0.5 million for the three and six months ended June 30, 2017, respectively. Lease commitments by year for each of the next five years are presented in the table below: ($ in Thousands) 2018 $ 488 2019 903 2020 802 2021 484 2022 496 Thereafter — Total $ 3,173
Minimum Net Obligations under Sales, Gathering and Transportation Agreements	Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows: ($ in Thousands) 2018 $ 25,597 2019 51,096 2020 49,724 2021 46,729 2022 46,260 Thereafter 390,656 Total $ 610,062
Average Spot Price	For the proceeds to become payable by Campbell in any of the eleven individual quarters, the average spot price of WTI as published by the New York Mercantile Exchange must be in excess of the amount shown in the table below for the applicable quarter. As of June 30, 2018, the first seven of the eleven quarterly measurement periods have expired with the calculated average spot price of WTI of five out of the seven below the threshold price stipulated in the agreement. Consequently, we did not receive any additional proceeds for the first five measurement periods. As of June 30, 2018 the calculated average spot price of WTI was above the threshold price in the agreement, we then have qualified to receive the additional proceeds for the current period. As of June 30, 2018, we have the potential to receive up to $3.6 million of additional proceeds if the WTI exceeds the price per Bbl as specified in the agreement. Proceeds earned for any quarter are payable to us within one year and fifteen days following the end of the quarter in which additional proceeds are earned. For additional information, see Note 9, Derivative Instruments and Fair Value Measurements Calendar Quarter Ending West Texas Intermediate ("WTI") Average Price per Bbl (a) 9/30/2018 $ 62.25 12/31/2018 $ 62.75 3/31/2019 $ 63.25 6/30/2019 $ 63.75

Earnings Per Common Share (Tabl

Earnings Per Common Share (Tables)	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Computation of Basic and Diluted Earning Per Common Share	The following table sets forth the computation of basic and diluted earnings per common share: (in thousands, except per share amounts) Three Months Ended June 30, Six Months Ended June 30, Numerator: 2018 2017 2018 2017 Net Loss $ (2,684 ) $ (9,603 ) $ (72,476 ) $ (6,920 ) Less: Preferred Stock Dividends (598 ) (598 ) (1,196 ) (1,196 ) Net Loss Attributable to Common Shareholders $ (3,282 ) $ (10,201 ) $ (73,672 ) $ (8,116 ) Denominator: Weighted Average Common Shares Outstanding - Basic 10,708 9,881 10,587 9,825 Effect of Dilutive Securities: Employee Stock Options — — — — Employee Performance-Based Restricted Stock Awards — — — — Effect of Assumed Conversions of Preferred Stock — — — — Weighted Average Common Shares Outstanding - Diluted 10,708 9,881 10,587 9,825 Earnings per Common Share Attributable to Rex Energy Common Shareholders: Basic — Net Loss Attributable to Common Shareholders $ (0.31 ) $ (1.03 ) $ (6.96 ) $ (0.83 ) Diluted — Net Loss Attributable to Common Shareholders $ (0.31 ) $ (1.03 ) $ (6.96 ) $ (0.83 )

Condensed Consolidating Finan36

Condensed Consolidating Financial Information (Tables)	6 Months Ended
	Jun. 30, 2018
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Balance Sheets	REX ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING BALANCE SHEETS AS OF JUNE 30, 2018 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 28,777 $ — $ 3 $ — $ 28,780 Restricted Cash — — 33,106 — 33,106 Accounts Receivable 26,961 — 1,627 — 28,588 Taxes Receivable — — 48 — 48 Short-Term Derivative Instruments 2,346 — 2,450 — 4,796 Inventory, Prepaid Expenses and Other 3,389 — — — 3,389 Total Current Assets 61,473 — 37,234 — 98,707 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,062,986 — — — 1,062,986 Unevaluated Oil and Gas Properties 174,608 — — — 174,608 Other Property and Equipment 20,066 — — — 20,066 Wells and Facilities in Progress 2,552 — — — 2,552 Pipelines 16,528 — — — 16,528 Total Property and Equipment 1,276,740 — — — 1,276,740 Less: Accumulated Depreciation, Depletion and Amortization (384,556 ) — — — (384,556 ) Net Property and Equipment 892,184 — — — 892,184 Other Assets 35 — — — 35 Intercompany Receivables — — 1,118,701 (1,118,701 ) — Investment in Subsidiaries – Net (2,805 ) — (287,208 ) 290,013 — Long-Term Derivative Instruments 1,463 — — — 1,463 Deferred Tax Assets - Long Term — — 130 — 130 Total Assets $ 952,350 $ — $ 868,857 $ (828,688 ) $ 992,519 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 32,679 $ — $ 50,000 $ — $ 82,679 Current Maturities of Long-Term Debt — — $ 261,315 — 261,315 Debtor-in Possession Term Loan Payable — — 35,000 — 35,000 Accrued Liabilities 18,074 — 12,862 — 30,936 Short-Term Derivative Instruments 19,095 — — — 19,095 Total Current Liabilities 69,848 — 359,177 — 429,025 Long-Term Derivative Instruments 12,075 — — — 12,075 Future Abandonment Cost 8,626 — — — 8,626 Liabilities Subject to Compromise 37,230 — 630,394 — 667,624 Intercompany Payables 1,114,295 4,406 — (1,118,701 ) — Total Liabilities 1,242,074 4,406 989,571 (1,118,701 ) 1,117,350 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 11 — 11 Additional Paid-In Capital 177,143 — 654,721 (177,143 ) 654,721 Accumulated Deficit (466,867 ) (4,406 ) (775,447 ) 467,156 (779,564 ) Total Stockholders’ Equity (289,724 ) (4,406 ) (120,714 ) 290,013 (124,831 ) Total Liabilities and Stockholders’ Equity $ 952,350 $ — $ 868,857 $ (828,688 ) $ 992,519 REX ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING BALANCE SHEETS AS OF DECEMBER 31, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 15,244 $ — $ 3 $ — $ 15,247 Accounts Receivable 25,974 — — — 25,974 Taxes Receivable — — 2,049 — 2,049 Short-Term Derivative Instruments 8,008 — — — 8,008 Inventory, Prepaid Expenses and Other 2,106 — 2,508 — 4,614 Total Current Assets 51,332 — 4,560 — 55,892 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,086,625 — — — 1,086,625 Unevaluated Oil and Gas Properties 186,523 — — — 186,523 Other Property and Equipment 19,640 — — — 19,640 Wells and Facilities in Progress 38,660 — — — 38,660 Pipelines 16,803 — — — 16,803 Total Property and Equipment 1,348,251 — — — 1,348,251 Less: Accumulated Depreciation, Depletion and Amortization (463,899 ) — — — (463,899 ) Net Property and Equipment 884,352 — — — 884,352 Other Assets 44 — — — 44 Intercompany Receivables — — 1,072,637 (1,072,637 ) — Investment in Subsidiaries – Net (2,484 ) — (272,261 ) 274,745 — Long-Term Derivative Instruments (2 ) — 1,721 — 1,719 Deferred Tax Assets - Long Term — — 130 — 130 Total Assets $ 933,242 $ — $ 806,787 $ (797,892 ) $ 942,137 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 62,354 $ — $ — $ — $ 62,354 Current Maturities of Long-Term Debt 1,926 — 832,399 — 834,325 Accrued Liabilities 32,214 — 13,004 — 45,218 Short-Term Derivative Instruments 14,892 — — — 14,892 Total Current Liabilities 111,386 — 845,403 — 956,789 Long-Term Derivative Instruments 14,249 — — — 14,249 Long-Term Debt — — — — — Other Long-Term Debt 8,156 — — — 8,156 Other Deposits and Liabilities 7,153 — — — 7,153 Future Abandonment Cost 9,352 — — — 9,352 Intercompany Payables 1,068,231 4,406 — (1,072,637 ) — Total Liabilities 1,218,527 4,406 845,403 (1,072,637 ) 995,699 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 10 — 10 Additional Paid-In Capital 177,144 — 652,917 (177,144 ) 652,917 Accumulated Deficit (462,429 ) (4,406 ) (691,544 ) 451,889 (706,490 ) Total Stockholders’ Equity (285,285 ) (4,406 ) (38,616 ) 274,745 (53,562 ) Total Liabilities and Stockholders’ Equity $ 933,242 $ — $ 806,787 $ (797,892 ) $ 942,137
Condensed Consolidating Statements of Operations	REX ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2018 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 75,155 $ — $ — $ — $ 75,155 Other Operating Revenue 3 — — — 3 TOTAL OPERATING REVENUE 75,158 — — — 75,158 OPERATING EXPENSES Production and Lease Operating Expense 36,756 — — — 36,756 General and Administrative Expense 4,235 — 187 — 4,422 Impairment Expense 4,334 — — — 4,334 Exploration Expense 122 — — — 122 Depreciation, Depletion, Amortization and Accretion 16,953 — — — 16,953 Other Operating Expense 1,492 — — — 1,492 TOTAL OPERATING EXPENSES 63,892 — 187 — 64,079 INCOME (LOSS) FROM OPERATIONS 11,266 — (187 ) — 11,079 OTHER INCOME (EXPENSE) Interest Expense (662 ) — (13,456 ) — (14,118 ) (Loss) Gain on Derivatives, Net (18,413 ) — 4,085 — (14,328 ) Other (Expense) Income 53 — (14,005 ) — (13,952 ) Reorganization Items, Net (1,314 ) — 29,949 — 28,635 Loss from Equity in Consolidated Subsidiaries — — (9,070 ) 9,070 — TOTAL OTHER INCOME (EXPENSE) (20,336 ) — (2,497 ) 9,070 (13,763 ) LOSS BEFORE INCOME TAX (9,070 ) — (2,684 ) 9,070 (2,684 ) Income tax Benefit — — — — — NET LOSS $ (9,070 ) $ — $ (2,684 ) $ 9,070 $ (2,684 ) Preferred Stock Dividends — — (598 ) — (598 ) NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (9,070 ) $ — $ (3,282 ) $ 9,070 $ (3,282 ) REX ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2018 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 140,180 $ — $ — $ — $ 140,180 Other Operating Revenue 7 — — — 7 TOTAL OPERATING REVENUE 140,187 — — — 140,187 OPERATING EXPENSES Production and Lease Operating Expense 70,602 — — — 70,602 General and Administrative Expense 9,739 — 1,207 — 10,946 Loss on Disposal of Assets 647 — — — 647 Impairment Expense 12,503 — — — 12,503 Exploration Expense 350 — — — 350 Depreciation, Depletion, Amortization and Accretion 32,081 — — — 32,081 Other Operating Expense 1,695 — — — 1,695 TOTAL OPERATING EXPENSES 127,617 — 1,207 — 128,824 INCOME (LOSS) FROM OPERATIONS 12,570 — (1,207 ) — 11,363 OTHER INCOME (EXPENSE) Interest Expense (1,333 ) — (35,432 ) — (36,765 ) Loss on Derivatives, Net (13,088 ) — (47,666 ) — (60,754 ) Other Expense (951 ) — (14,004 ) — (14,955 ) Reorganization Items, Net (1,313 ) — 29,948 — 28,635 (Loss) Income From Equity in Consolidated Subsidiaries — — (4,115 ) 4,115 — TOTAL OTHER INCOME (EXPENSE) (16,685 ) — (71,269 ) 4,115 (83,839 ) LOSS BEFORE INCOME TAX (4,115 ) — (72,476 ) 4,115 (72,476 ) Income Tax Benefit — — — — — NET LOSS $ (4,115 ) $ — $ (72,476 ) $ 4,115 $ (72,476 ) Preferred Stock Dividends — — (1,196 ) — (1,196 ) NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (4,115 ) $ — $ (73,672 ) $ 4,115 $ (73,672 ) REX ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, NGL and Condensate Sales $ 47,457 $ — $ — $ — $ 47,457 Other Operating Expense 5 — — — 5 TOTAL OPERATING REVENUE 47,462 — — — 47,462 OPERATING EXPENSES Production and Lease Operating Expense 29,374 — — — 29,374 General and Administrative Expense 3,771 — 523 — 4,294 Gain on Disposal of Assets (124 ) — — — (124 ) Impairment Expense 3,032 — — — 3,032 Exploration Expense 99 — — — 99 Depreciation, Depletion, Amortization and Accretion 15,501 — — — 15,501 Other Operating (Income) Expense (99 ) 1 — — (98 ) TOTAL OPERATING EXPENSES 51,554 1 523 — 52,078 LOSS FROM OPERATIONS (4,092 ) (1 ) (523 ) — (4,616 ) OTHER INCOME (EXPENSE) — Interest Expense (442 ) — (11,680 ) — (12,122 ) (Loss) Gain on Derivatives, Net 10,861 — (475 ) — 10,386 Other Income 20 — — 20 Loss on Extinguishments of Debt — — (3,271 ) (3,271 ) Income (Loss) From Equity in Consolidated Subsidiaries (1 ) — 6,346 (6,345 ) — TOTAL OTHER INCOME (EXPENSE) 10,438 — (9,080 ) (6,345 ) (4,987 ) INCOME (LOSS) BEFORE INCOME TAX 6,346 (1 ) (9,603 ) (6,345 ) (9,603 ) Income Tax Benefit — — — — — NET INCOME (LOSS) 6,346 (1 ) (9,603 ) (6,345 ) (9,603 ) Preferred Stock Dividends — — (598 ) — (598 ) NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 6,346 $ (1 ) $ (10,201 ) $ (6,345 ) $ (10,201 ) REX ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, Condensate and NGL Sales $ 99,522 $ — $ — $ — $ 99,522 Other Revenue 11 — — — 11 TOTAL OPERATING REVENUE 99,533 — — — 99,533 OPERATING EXPENSES Production and Lease Operating Expense 58,308 — — — 58,308 General and Administrative Expense 8,232 — 596 — 8,828 Gain on Disposal of Assets (1,959 ) — — — (1,959 ) Impairment Expense 4,577 — — — 4,577 Exploration Expense 319 — — — 319 Depreciation, Depletion, Amortization and Accretion 30,969 — — — 30,969 Other Operating (Income) Expense (119 ) 1 — — (118 ) TOTAL OPERATING EXPENSES 100,327 1 596 — 100,924 LOSS FROM OPERATIONS (794 ) (1 ) (596 ) — (1,391 ) OTHER INCOME (EXPENSE) Interest Expense (809 ) — (20,457 ) — (21,266 ) (Loss) Gain on Derivatives, Net 20,659 — (1,893 ) — 18,766 Other Expense (7 ) — — — (7 ) Loss on Extinguishments of Debt — — (3,022 ) — (3,022 ) Income (Loss) From Equity in Consolidated Subsidiaries (1 ) — 19,048 (19,047 ) — TOTAL OTHER INCOME (EXPENSE) 19,842 — (6,324 ) (19,047 ) (5,529 ) INCOME (LOSS) BEFORE INCOME TAX 19,048 (1 ) (6,920 ) (19,047 ) (6,920 ) Income Tax Benefit — — — — — NET INCOME (LOSS) 19,048 (1 ) (6,920 ) (19,047 ) (6,920 ) Preferred Stock Dividends — — (1,196 ) — (1,196 ) NET (LOSS) INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 19,048 $ (1 ) $ (8,116 ) $ (19,047 ) $ (8,116 )
Condensed Consolidating Statements of Cash Flows	REX ENERGY CORPORATION AND SUBSIDIARIES (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2018 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net (Loss) Income $ (4,115 ) $ — $ (72,476 ) $ 4,115 (72,476 ) Adjustments to Reconcile Net Loss to Net Cash Provided (Used) by Operating Activities Depreciation, Depletion, Amortization and Accretion 32,081 — — — 32,081 Loss on Derivatives, Net 13,088 — 47,666 — 60,754 Cash Settlements of Derivatives (6,862 ) — — — (6,862 ) Equity-based Compensation Expense (7 ) — 1,207 — 1,200 Impairment Expense 12,503 — — — 12,503 Non-cash Interest Expense — — 2,881 — 2,881 Loss on Disposal of Assets 647 — — — 647 Non-cash Reorganization Items, Net — — (43,509 ) — (43,509 ) Other Non-cash Expense (Income) 588 — (22 ) — 566 Changes in operating assets and liabilities Accounts Receivable (342 ) — — — (342 ) Taxes Receivable — — 2,001 — 2,001 Inventory, Prepaid Expenses and Other Assets (2,173 ) — 2,509 — 336 Accounts Payable and Accrued Liabilities 7,778 — 33,700 — 41,478 Other Assets and Liabilities (147 ) — — — (147 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 53,039 — (26,043 ) 4,115 31,111 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 46,062 — (41,947 ) (4,115 ) — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 16,384 — — — 16,384 Acquisitions of Undeveloped Acreage (871 ) — — — (871 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (100,136 ) — — — (100,136 ) NET CASH USED IN INVESTING ACTIVITIES (38,561 ) — (41,947 ) (4,115 ) (84,623 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Line of Credit, net of Discounts — — 69,846 — 69,846 Proceeds from Debtor-in Possession Financing — — 35,000 — 35,000 Repayments of Loans and Other Long-Term Debt (945 ) — — — (945 ) Reorganization Item - Debtor-In-Possession Financing Fee — — (3,750 ) — (3,750 ) NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES (945 ) — 101,096 — 100,151 Net Increase in Cash, Cash Equivalents and Restricted Cash 13,533 — 33,106 — 46,639 Beginning Cash, Cash Equivalents and Restricted Cash 15,244 — 3 — 15,247 Ending Cash, Cash Equivalents and Restricted Cash $ 28,777 $ — $ 33,109 $ — $ 61,886 CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2017 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 19,048 $ (1 ) $ (6,920 ) $ (19,047 ) $ (6,920 ) Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities Depreciation, Depletion, Amortization and Accretion 30,969 — — — 30,969 (Gain) Loss on Derivatives, Net (20,659 ) — 1,893 — (18,766 ) Cash Settlements of Derivatives (5,525 ) — — — (5,525 ) Equity-based Compensation Expense — — 571 — 571 Non-cash Exploration Expense 13 — — — 13 Gain on Disposal of Assets (1,959 ) — — — (1,959 ) Loss on Extinguishments of Debt — — 3,022 — 3,022 Non-cash Interest Expense — — 12,431 — 12,431 Impairment Expense 4,577 — — — 4,577 Other Non-Cash Expense 41 — — — 41 Changes in operating assets and liabilities Accounts Receivable 7,232 — (3 ) — 7,229 Taxes Receivable — 163 Inventory, Prepaid Expenses and Other Assets 638 — (586 ) — 52 Accounts Payable and Accrued Liabilities (1,484 ) — — — (1,484 ) Other Assets and Liabilities (1,104 ) — — — (1,104 ) NET CASH PROVIDED BY OPERATING ACTIVITIES 31,787 (1 ) 10,571 (19,047 ) 23,310 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 4,063 1 (23,111 ) 19,047 — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 24,513 — — — 24,513 Acquisitions of Undeveloped Acreage (1,783 ) — — — (1,783 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (54,004 ) — — — (54,004 ) NET CASH USED IN INVESTING ACTIVITIES (27,211 ) 1 (23,111 ) 19,047 (31,274 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit, net of Discounts — — 171,000 — 171,000 Repayments of Long Term Debt and Lines of Credit — — (145,170 ) — (145,170 ) Repayments of Loans and Other Long-Term Debt (319 ) — — — (319 ) Debt Issuance Costs — (7,791 ) (7,791 ) Payment of Preferred Dividends in arrears — — (598 ) — (598 ) NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES (319 ) — 17,441 — 17,122 NET INCREASE IN CASH 4,257 — 4,901 — 9,158 CASH – BEGINNING 3,694 — 3 — 3,697 CASH - ENDING $ 7,951 $ — $ 4,904 $ — $ 12,855

Basis of Presentation and Pri37

Basis of Presentation and Principles of Consolidation - Additional Information (Details)	May 12, 2017shares	Jun. 30, 2018shares	Dec. 31, 2017shares	Mar. 31, 2017shares
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Petition Date		May 18, 2018
Bankruptcy proceedings, court where petition was filed		U.S. Bankruptcy Court for the Western District of Pennsylvania
Reverse stock split		On May 5, 2017, our common shareholders approved a decrease in the number of authorized shares from 200,000,000 to 100,000,000 common shares, contingent upon the effectiveness of a reverse stock split, which occurred on May 12, 2017.
Common Stock, shares issued	9,900,000	10,707,788	10,244,394	99,000,000
Common Stock
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Reverse stock split	one-for-ten
Stockholders' equity, reverse stock split ratio	0.1

Petition Relief under Chapter38

Petition Relief under Chapter 11 and Going Concern Assessment - Schedule of Components of Liabilities Subject to Compromise (Details) $ in Thousands	Jun. 30, 2018USD ($)
Reorganizations [Abstract]
Accounts Payable and Accrued Expenses	$ 27,716
Accrued Interest Payable	30,043
Debt (See Note 8)	609,865
Liabilities Subject to Compromise	$ 667,624

Petition Relief under Chapter39

Petition Relief under Chapter 11 and Going Concern Assessment - Summary of Components of Reorganization Items (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018		Jun. 30, 2018
Reorganizations [Abstract]
Legal and Professional Fees	$ (9,817)		$ (9,817)
Unamortized Deferred Financing Balances	43,509	[1]	43,509
Debtor-in Possession Financing Fees	(3,750)		(3,750)
Effect of Early Hedge Terminations	(1,175)		(1,175)
Other	(132)		(132)
Reorganization Items, net	$ 28,635		$ 28,635
[1]	Acceleration of deferred gains on debt restructurings, deferred financing costs and unamortized net discounts for debt instruments previously accounted for as troubled debt restructurings pursuant to ASC 470-60, Troubled Debt Restructurings by Debtors.

Petition Relief under Chapter40

Petition Relief under Chapter 11 and Going Concern Assessment - Additional Information (Details) - USD ($)	1 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018	Apr. 28, 2017
Reorganizations [Line Items]
Settlement under plan of reorganization	$ 0	$ 0
Creditors committee, date of appointment		May 29, 2018
Second Lien Notes
Reorganizations [Line Items]
Debt instrument, interest rate	8.00%	8.00%
Contractual interest	$ 5,600,000
Second Lien Notes | Unsecured Notes
Reorganizations [Line Items]
Interest expense	0
Contractual interest	$ 5,700,000
1.00% Senior Secured Second Lien Notes due 2020
Reorganizations [Line Items]
Debt instrument, interest rate			1.00%
8.00% Senior Secured Second Lien Notes due 2020
Reorganizations [Line Items]
Debt instrument, interest rate			8.00%
6.25% Senior Notes | Unsecured Notes
Reorganizations [Line Items]
Debt instrument, interest rate	6.25%	6.25%
8.875% Senior Notes | Unsecured Notes
Reorganizations [Line Items]
Debt instrument, interest rate	8.875%	8.875%

Revenue Recognition - Additiona

Revenue Recognition - Additional Information (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Revenue From Contract With Customer [Abstract]
Payment term	30 to 60 days of control transfer
Trade receivable related revenue from contract with customers	$ 25.9	$ 21.7

Revenue Recognition - Summary o

Revenue Recognition - Summary of Disaggregated Revenues Recognized from Contracts with Customers in Consolidated Statements of Operations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation Of Revenue [Line Items]
Total Revenue	$ 75,155	$ 47,457	$ 140,180	$ 99,522
Natural Gas
Disaggregation Of Revenue [Line Items]
Total Revenue	29,705	29,097	59,387	60,442
NGL
Disaggregation Of Revenue [Line Items]
Total Revenue	32,293	15,367	61,011	32,667
Condensate
Disaggregation Of Revenue [Line Items]
Total Revenue	$ 13,157	$ 2,993	$ 19,782	$ 6,413

Oil and Gas Properties - Join43

Oil and Gas Properties - Joint Ventures and Divestitures - Additional Information (Details)	Mar. 23, 2018USD ($)	Jan. 11, 2017USD ($)aMMcfeWell	Mar. 01, 2016Well	Jan. 31, 2017USD ($)	Jun. 30, 2018USD ($)Well	Mar. 31, 2018USD ($)	Jun. 30, 2018USD ($)Well	Jun. 30, 2017USD ($)	Mar. 21, 2018USD ($)	Mar. 13, 2018Well	Jan. 01, 2018
Business Acquisition And Dispositions [Line Items]
Proceeds held in Escrow - non-cash component of Gain on Sale of Assets							$ 150,000	$ 5,000,000
Westmoreland, Centre and Clearfield Counties, PA
Business Acquisition And Dispositions [Line Items]
Number of non-operated oil and gas wells sold | Well										61
R W Gathering
Business Acquisition And Dispositions [Line Items]
Membership interest sold											40.00%
Westmoreland Centre and Clearfield Counties, PA and RW Gathering
Business Acquisition And Dispositions [Line Items]
Total consideration for the transaction									$ 17,200,000
Gain on disposal of assets						$ (600,000)
Proceeds received from the transactions	$ 16,400,000
Proceeds held in Escrow - non-cash component of Gain on Sale of Assets	$ 200,000
Sale of Warrior South Assets
Business Acquisition And Dispositions [Line Items]
Total consideration for the transaction		$ 29,100,000
Net proceeds from sale of property		24,100,000
Amount held in escrow		$ 5,000,000
Gain on disposal of assets				$ 1,800,000
Number of gross wells | Well		14
Production unit of natural gas | MMcfe		9
Net acres sold | a		4,100
Sale of Warrior South Assets | Rex, MFC Drilling, Inc., and ABARTA Oil & Gas Co., Inc.
Business Acquisition And Dispositions [Line Items]
Total consideration for the transaction		$ 50,000,000
Production unit of natural gas | MMcfe		15
Net acres sold | a		6,200
Benefit Street Partners Limited Liability Corporation
Business Acquisition And Dispositions [Line Items]
Amount received for working interest in wells by partners							$ 134,000,000
Number of wells in which BSP Options to Participate in development | Well					36		36
Percentage of working interest			65.00%
Number of wells in which BSP Options exercised to Participate in development | Well							23
Number of wells committed for line and producing | Well					45		45
Payments for interest in wells that have been drilled or in process of being drilled					$ 0
Benefit Street Partners Limited Liability Corporation | Maximum
Business Acquisition And Dispositions [Line Items]
Total consideration for the transaction							$ 175,000,000
Percentage of working interest earned in acreage			20.00%
Benefit Street Partners Limited Liability Corporation | Minimum
Business Acquisition And Dispositions [Line Items]
Percentage of working interest earned in acreage			15.00%
Benefit Street Partners Limited Liability Corporation | Moraine East and Warrior North
Business Acquisition And Dispositions [Line Items]
Number of specifically designated wells for development | Well			58
Benefit Street Partners Limited Liability Corporation | Butler County, Pennsylvania
Business Acquisition And Dispositions [Line Items]
Number of specifically designated wells for development | Well			16
Percentage of estimated well costs			15.00%
Number of drilled and completed wells to be placed into service | Well					16		16
Benefit Street Partners Limited Liability Corporation | Warrior North Ohio
Business Acquisition And Dispositions [Line Items]
Number of specifically designated wells for development | Well			6
Percentage of estimated well costs			65.00%
Number of drilled and completed wells to be placed into service | Well					6		6

Future Abandonment Cost - Addit

Future Abandonment Cost - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Asset Retirement Obligation Disclosure [Abstract]
Accretion expense	$ 200	$ 500	$ 473	$ 1,000

Future Abandonment Cost (Detail

Future Abandonment Cost (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Asset Retirement Obligation Disclosure [Abstract]
Beginning Balance at January 1, 2018				$ 9,939
Future Abandonment Obligation Incurred				137
Future Abandonment Obligation Settled				(156)
Future Abandonment Obligation Cancelled or Sold				(877)
Future Abandonment Obligation Revision of Estimated Obligation				99
Future Abandonment Obligation Accretion Expense		$ 200	$ 500	473	$ 1,000
Total Future Abandonment Cost	[1]	$ 9,616		$ 9,616
[1]	Includes approximately $1.0 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

Future Abandonment Cost (Parent

Future Abandonment Cost (Parenthetical) (Details) $ in Millions	Jun. 30, 2018USD ($)
Accrued Liablities | Remediation Property for Sale, Abandonment or Disposal
Asset Retirement Obligations [Line Items]
Short-term future abandonment costs	$ 1

Concentrations of Credit Risk -

Concentrations of Credit Risk - Additional Information (Details) - Sales - Customer Concentration Risk	6 Months Ended
	Jun. 30, 2018Customer
Purchaser
Concentration Risk [Line Items]
Percentage of revenue from major customers	98.90%
Number of major customers	5
Largest single purchaser
Concentration Risk [Line Items]
Percentage of revenue from major customers	62.10%

Debt - Term Loan - Additional I

Debt - Term Loan - Additional Information (Details) - USD ($)	Apr. 28, 2017	Jun. 30, 2018	Mar. 31, 2018
Debt Instrument [Line Items]
Outstanding letters of credit		$ 32,000,000
Term loan yield maintenance ending period post effective date		30 months
Term loan yield maintenance effective date ending period		30 months
Term loan yield maintenance effective date after day one		30 months
Term loan yield maintenance ending period post effective date after day one		36 months
Make whole amount		$ 50,000,000
Realize loss on derivatives as gain (loss) on derivative, net		(50,000,000)
Level 2 Inputs
Debt Instrument [Line Items]
Short-term derivative instruments		50,000,000	$ 53,000,000
Term Loans, Net
Debt Instrument [Line Items]
Outstanding letters of credit		33,100
Line of credit facility, maximum borrowing capacity	$ 300,000,000
Term Loans, Net | 30 Months After Effective Date
Debt Instrument [Line Items]
Percentage of prepayments, terminations, refinancing, reductions and accretions	3.00%
Term Loans, Net | 36 Months After Effective Date
Debt Instrument [Line Items]
Percentage of prepayments, terminations, refinancing, reductions and accretions	1.00%
Term Facility
Debt Instrument [Line Items]
Line of credit facility, current borrowing capacity	$ 143,500,000
Line of credit facility, amount outstanding		228,200,000
Secured Delayed Draw Term Loan Facility
Debt Instrument [Line Items]
Line of credit facility, remaining borrowing capacity	156,500,000
Letter Of Credit
Debt Instrument [Line Items]
Line of credit facility, remaining borrowing capacity		$ 33,100,000
Line of credit facility, maximum borrowing capacity	$ 261,300,000

Debt - Debtor-In-Possession Ter

Debt - Debtor-In-Possession Term Loan - Additional Information (Details) - USD ($) $ in Thousands	May 23, 2018	Jun. 30, 2018
Debt Instrument [Line Items]
Debtor-in-possession, outstanding additional capacity borrowings		$ 35,000
The DIP Facility
Debt Instrument [Line Items]
Debtor-in-possession,maturity date	Nov. 18, 2018
In accordance with court order debtor-in-possession term loan agreement consolidates date	Jul. 11, 2018
Debtor-in-possession, term loan balance	$ 261,300
Debtor-in-possession, make whole amount	50,000
Debtor-in-possession additional borrowing capacity	100,000
Debtor-in-possession, outstanding additional capacity borrowings	$ 35,000
Debtor-in-possession, outstanding loans bearing interest rate	4.00%
Debtor-in-possession, upfront commitment fee	$ 3,800
Debtor-in-possession, unused commitment fee	3.25%
PDP coverage ratio		185.00%
Debtor-in-possession. liquidity		$ 88,800
Financial covenants	(1) as of the last day of any fiscal quarter ending on or after June 30, 2018, the PDP Coverage Ratio (as defined in the DIP Facility) will not be less than 1.25 to 1.00; (2) our liquidity at all times must be greater than $10.0 million, and (3) each Friday we are required to submit budget variance reports showing that (i) aggregated receipts are not less than 85% of budgeted receipts, (ii) aggregated disbursements, other than capital expenditures, are not greater than 115% of budgeted disbursements and (iii) actual capital expenditures are not greater than 105% of budgeted capital expenditures. As of June 30, 2018, our PDP Coverage Ratio was 1.85 to 1.00 and our liquidity was approximately $88.8 million. To date we have complied with all budget variance testing covenants.
The DIP Facility | Minimum
Debt Instrument [Line Items]
PDP coverage ratio	125.00%
Debtor-in-possession. liquidity	$ 10,000
Aggregated disbursement other than capital expenditure percentage	115.00%
The DIP Facility | Maximum
Debt Instrument [Line Items]
Aggregate percentage of budgets receipts	85.00%
Actual capital expenditure percentage	105.00%
The DIP Facility | Adjusted LIBO Rate
Debt Instrument [Line Items]
Debtor-in-possession, rate per annum equal to adjusted LIBO Rate	1.00%
Debtor in possession, percentage of margin per annum	8.75%

Debt - Senior Notes - Additiona

Debt - Senior Notes - Additional Information (Details) - USD ($) shares in Millions	1 Months Ended	3 Months Ended				6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2017	Mar. 31, 2017	Mar. 31, 2016	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Apr. 28, 2017
Debt Instrument [Line Items]
Share of common stock					10.1
Issuance of unrestricted common stock shares							0.1	0.1	2.4
Gain on Extinguishments of Debt			$ (3,271,000)				$ (3,022,000)
Maximum
Debt Instrument [Line Items]
Senior notes offered for exchange					$ 675,000,000
Senior Notes, Net
Debt Instrument [Line Items]
Notes outstanding								$ 600,302,000
Gain on Extinguishments of Debt				$ 400,000
Deferred gain on debt restructuring								50,100,000
Remaining unamortized portion of deferred gain on debt restructurings						$ 43,600,000
Capital Leases
Debt Instrument [Line Items]
Average interest rate		16.50%				16.80%
Debt Restructurings
Debt Instrument [Line Items]
Unamortized net Premium / Discount								14,000,000
Unamortized Debt Issuance Costs								33,600,000
Unamortized deferred gain on debt restructurings								30,400,000
8.00% Senior Secured Second Lien Notes due 2020
Debt Instrument [Line Items]
Interest rate										8.00%
8.00% Senior Secured Second Lien Notes due 2020 | Senior Notes, Net
Debt Instrument [Line Items]
Interest rate	8.875%	8.875%				8.875%
Second Lien Notes
Debt Instrument [Line Items]
Interest rate	8.00%	8.00%				8.00%
Gain recognized due to troubled debt exchanges					$ 0
Notes outstanding	$ 587,600,000	$ 587,600,000				$ 587,600,000
Debt amount for conversion									$ 45,700,000
Expiration grace period						30 days
Contractual interest	5,600,000
Accrued interest	$ 29,600,000	$ 29,600,000				$ 29,600,000
Second Lien Notes | Senior Notes, Net
Debt Instrument [Line Items]
Interest rate	6.25%	6.25%				6.25%
Existing Notes
Debt Instrument [Line Items]
Notes outstanding	$ 12,700,000	$ 12,700,000				$ 12,700,000
Contractual interest	100,000
Accrued interest	$ 400,000	$ 400,000				$ 400,000
2022 Senior Notes
Debt Instrument [Line Items]
Retirement of notes								$ 900,000	$ 27,700,000
8.875% Senior Notes | Senior Notes, Net
Debt Instrument [Line Items]
Interest rate	8.875%	8.875%				8.875%
6.25% Senior Notes | Senior Notes, Net
Debt Instrument [Line Items]
Interest rate	6.25%	6.25%				6.25%
The DIP Facility | Term Loans, Net
Debt Instrument [Line Items]
Average interest rate		12.00%				11.00%

Components of Secured Debt and

Components of Secured Debt and Debt Balances Subject to Compromise (Details) $ in Thousands	Jun. 30, 2018USD ($)
Debt Instrument [Line Items]
Debt Balances included in Liabilities Subject to Compromise	$ 609,865
Term Loan - due April 2020
Debt Instrument [Line Items]
Secured Debt	261,315
Debtor-In-Possession Term Loan - due November 2018
Debt Instrument [Line Items]
Secured Debt	35,000
8.875% Senior Notes due 2020
Debt Instrument [Line Items]
Debt Balances included in Liabilities Subject to Compromise	7,333
6.25% Senior Notes due 2022
Debt Instrument [Line Items]
Debt Balances included in Liabilities Subject to Compromise	5,363
1% / 8% Second Lien Senior Notes due 2020
Debt Instrument [Line Items]
Debt Balances included in Liabilities Subject to Compromise	587,606
Total Senior Notes
Debt Instrument [Line Items]
Debt Balances included in Liabilities Subject to Compromise	600,302
Long-Term Capital Leases - Equipment Financing
Debt Instrument [Line Items]
Debt Balances included in Liabilities Subject to Compromise	9,563
Long-Term Capital Leases - Equipment Financing | Due March, 2021
Debt Instrument [Line Items]
Debt Balances included in Liabilities Subject to Compromise	557
Long-Term Capital Leases - Equipment Financing | Due June, 2021
Debt Instrument [Line Items]
Debt Balances included in Liabilities Subject to Compromise	1,254
Long-Term Capital Leases - Equipment Financing | Due September, 2021
Debt Instrument [Line Items]
Debt Balances included in Liabilities Subject to Compromise	1,428
Long-Term Capital Leases - Equipment Financing | Due May, 2022
Debt Instrument [Line Items]
Debt Balances included in Liabilities Subject to Compromise	$ 6,324

Components of Secured Debt an52

Components of Secured Debt and Debt Balances Subject to Compromis (Parenthetical) (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Term Loan - due April 2020
Debt Instrument [Line Items]
Debt instrument, maturity date, month and year	2020-04	2020-04
8.875% Senior Notes due 2020
Debt Instrument [Line Items]
Debt instrument, interest rate	8.875%
Debt instrument, maturity year	2,020
6.25% Senior Notes due 2022
Debt Instrument [Line Items]
Debt instrument, interest rate	6.25%
Debt instrument, maturity year	2,022
1% / 8% Second Lien Senior Notes due 2020
Debt Instrument [Line Items]
Debt instrument, interest rate	0.125%
Debt instrument, maturity year	2,020
Due March, 2021 | Long-Term Capital Leases - Equipment Financing
Debt Instrument [Line Items]
Debt instrument, maturity date, month and year	2021-03
Due June, 2021 | Long-Term Capital Leases - Equipment Financing
Debt Instrument [Line Items]
Debt instrument, maturity date, month and year	2021-06
Due September, 2021 | Long-Term Capital Leases - Equipment Financing
Debt Instrument [Line Items]
Debt instrument, maturity date, month and year	2021-09
Due May, 2022 | Long-Term Capital Leases - Equipment Financing
Debt Instrument [Line Items]
Debt instrument, maturity date, month and year	2022-05

Components of Long-Term Debt an

Components of Long-Term Debt and Lines of Credit (Details) $ in Thousands	Dec. 31, 2017USD ($)
Term Loans, Net | Term Loan Draw - due April 2020
Debt Instrument [Line Items]
Principal	$ 189,500
Unamortized net Premium / Discount	(4,711)
Unamortized Debt Issuance Costs	(2,761)
Net Carrying Value	182,028
Senior Notes, Net
Debt Instrument [Line Items]
Principal	600,302
Deferred Gain on Debt Restructurings, Net	50,069
Net Carrying Value	650,371
Senior Notes, Net | 6.25% Senior Notes due 2022
Debt Instrument [Line Items]
Principal	5,363
Deferred Gain on Debt Restructurings, Net	(67)
Net Carrying Value	5,296
Senior Notes, Net | 8.875% Senior Notes due 2020
Debt Instrument [Line Items]
Principal	7,333
Deferred Gain on Debt Restructurings, Net	(60)
Net Carrying Value	7,273
Senior Notes, Net | 1% / 8% Second Lien Senior Notes due 2020
Debt Instrument [Line Items]
Principal	587,606
Deferred Gain on Debt Restructurings, Net	50,196
Net Carrying Value	637,802
Other Long-Term Debt
Debt Instrument [Line Items]
Total Capital Lease Obligations	10,082
Less: Current Portion of Capital Leases and Other Notes Payable	(1,926)
Non-Current Portion of Capital Leases and Other Notes Payable	8,156
Other Long-Term Debt | Due March, 2021
Debt Instrument [Line Items]
Total Capital Lease Obligations	632
Other Long-Term Debt | Due June, 2021
Debt Instrument [Line Items]
Total Capital Lease Obligations	1,418
Other Long-Term Debt | Due September, 2021
Debt Instrument [Line Items]
Total Capital Lease Obligations	1,578
Other Long-Term Debt | Due May, 2022
Debt Instrument [Line Items]
Total Capital Lease Obligations	$ 6,454

Components of Long-Term Debt 54

Components of Long-Term Debt and Lines of Credit (Parenthetical) (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Term Loan Draw - due April 2020
Debt Instrument [Line Items]
Debt instrument, maturity date, month and year	2020-04	2020-04
8.875% Senior Notes due 2020
Debt Instrument [Line Items]
Debt instrument, interest rate	8.875%
Debt instrument, maturity year	2,020
8.875% Senior Notes due 2020 | Senior Notes, Net
Debt Instrument [Line Items]
Debt instrument, interest rate		8.875%
Debt instrument, maturity year		2,020
6.25% Senior Notes due 2022
Debt Instrument [Line Items]
Debt instrument, interest rate	6.25%
Debt instrument, maturity year	2,022
6.25% Senior Notes due 2022 | Senior Notes, Net
Debt Instrument [Line Items]
Debt instrument, interest rate		6.25%
Debt instrument, maturity year		2,022
1% / 8% Second Lien Senior Notes due 2020
Debt Instrument [Line Items]
Debt instrument, interest rate	0.125%
Debt instrument, maturity year	2,020
1% / 8% Second Lien Senior Notes due 2020 | Senior Notes, Net
Debt Instrument [Line Items]
Debt instrument, interest rate		0.125%
Debt instrument, maturity year		2,020
Due March, 2021 | Other Long-Term Debt
Debt Instrument [Line Items]
Debt instrument, maturity date, month and year		2021-03
Due June, 2021 | Other Long-Term Debt
Debt Instrument [Line Items]
Debt instrument, maturity date, month and year		2021-06
Due September, 2021 | Other Long-Term Debt
Debt Instrument [Line Items]
Debt instrument, maturity date, month and year		2021-09
Due May, 2022 | Other Long-Term Debt
Debt Instrument [Line Items]
Debt instrument, maturity date, month and year		2022-05

Derivative Instruments and Fa55

Derivative Instruments and Fair Value Measurements - Additional Information (Details) $ in Thousands	Jul. 15, 2019USD ($)	Apr. 28, 2017	Jun. 30, 2018USD ($)	Jun. 30, 2017USD ($)	Jun. 30, 2018USD ($)Entity	Jun. 30, 2017USD ($)	Dec. 31, 2017USD ($)	May 18, 2018USD ($)	Mar. 31, 2018USD ($)
Derivatives Fair Value [Line Items]
Number of counterparties entered into an arrangements | Entity					2
Cash Settlements of Derivatives Paid					$ 6,862	$ 5,525
Term loan yield maintenance ending period post effective date					30 months
Term loan yield maintenance effective date ending period					30 months
Term loan yield maintenance effective date after day one					30 months
Term loan yield maintenance ending period post effective date after day one					36 months
Gain (loss) on derivative, net					$ (50,000)
Derivative liability			$ 31,170		31,170		$ 29,141
Derivatives asset (liability)			24,900		24,900		19,400
Impairment Expense			4,334	$ 3,032	12,503	4,577
Bankruptcy
Derivatives Fair Value [Line Items]
Derivative liability								$ 2,000
(Loss) gain on derivatives			800		800
Early termination of derivatives			1,200		1,200
Discontinued Operations Assets Held For Sale | Illinois Basin Operations
Derivatives Fair Value [Line Items]
Fair value of contingent consideration derivative asset					1,200
Fair value of contingent consideration					2,500		$ 1,700
Discounted fair value of additional consideration earned income			800
Discounted fair value of accounts receivable			800		800
Discontinued Operations Assets Held For Sale | Illinois Basin Operations | Scenario Forecast
Derivatives Fair Value [Line Items]
Remitted amount	$ 900
Level 2 Inputs
Derivatives Fair Value [Line Items]
Short-term derivative instruments			50,000		50,000				$ 53,000
Term Loans, Net | 30 Months After Effective Date
Derivatives Fair Value [Line Items]
Percentage of prepayments, terminations, refinancing, reductions and accretions		3.00%
Term Loans, Net | 36 Months After Effective Date
Derivatives Fair Value [Line Items]
Percentage of prepayments, terminations, refinancing, reductions and accretions		1.00%
Commodity derivatives
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives Paid			$ (4,900)	$ (2,100)	$ (6,900)	$ (5,500)

Schedule of Location and Amount

Schedule of Location and Amounts of Gains and Losses on Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Derivative Instruments Gain Loss [Line Items]
(Loss) Gain on Derivatives, Net	$ (14,328)	$ 10,386	$ (60,754)	$ 18,766
Crude Oil
Derivative Instruments Gain Loss [Line Items]
(Loss) Gain on Derivatives, Net	(3,817)	791	(5,553)	1,934
Natural Gas
Derivative Instruments Gain Loss [Line Items]
(Loss) Gain on Derivatives, Net	(213)	6,132	3,179	6,072
Natural Gas Liquids
Derivative Instruments Gain Loss [Line Items]
(Loss) Gain on Derivatives, Net	(14,383)	3,938	(10,714)	12,653
Contingent Consideration
Derivative Instruments Gain Loss [Line Items]
(Loss) Gain on Derivatives, Net	1,120	$ (475)	2,334	$ (1,893)
Embedded Derivatives
Derivative Instruments Gain Loss [Line Items]
(Loss) Gain on Derivatives, Net	$ 2,965		$ (50,000)

Asset or Liability Financial Co

Asset or Liability Financial Commodity Derivative Instrument Positions (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2018USD ($)$ / bbl$ / McfbblMcf
Crude Oil 2018 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	85,750
Swap | $ / bbl	57.47
Derivatives asset (liability)	$ (817)
Crude Oil 2018 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	42,000
Put Option | $ / bbl	41.82
Floor | $ / bbl	51.09
Ceiling | $ / bbl	60.75
Derivatives asset (liability)	$ (413)
Crude Oil 2019 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	118,000
Swap | $ / bbl	55.89
Derivatives asset (liability)	$ (1,231)
Crude Oil 2019 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	42,000
Put Option | $ / bbl	38.57
Floor | $ / bbl	48.57
Ceiling | $ / bbl	58.86
Derivatives asset (liability)	$ (375)
Crude Oil 2019 | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	18,000
Floor | $ / bbl	45
Ceiling | $ / bbl	55.80
Derivatives asset (liability)	$ (125)
Crude Oil 2020 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	24,000
Swap | $ / bbl	51
Derivatives asset (liability)	$ (304)
Crude Oil 2020 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	21,500
Put Option | $ / bbl	38.95
Floor | $ / bbl	48.95
Ceiling | $ / bbl	60.22
Derivatives asset (liability)	$ (103)
Crude Oil 2020 | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	22,500
Floor | $ / bbl	45
Ceiling | $ / bbl	55.80
Derivatives asset (liability)	$ (167)
Crude Oil 2021 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	6,000
Swap | $ / bbl	51
Derivatives asset (liability)	$ (76)
Crude Oil 2021 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	62,500
Put Option | $ / bbl	37.44
Floor | $ / bbl	47.04
Ceiling | $ / bbl	57.98
Derivatives asset (liability)	$ (240)
Crude Oil 2021 | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	16,500
Floor | $ / bbl	45
Ceiling | $ / bbl	55.80
Derivatives asset (liability)	$ (125)
Crude Oil
Derivatives Fair Value [Line Items]
Volume | bbl	481,750
Derivatives asset (liability)	$ (4,037)
Crude Oil 2022 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	23,000
Put Option | $ / bbl	39.35
Floor | $ / bbl	49.35
Ceiling | $ / bbl	60.43
Derivatives asset (liability)	$ (60)
Natural Gas 2018 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	12,127,500
Swap | $ / Mcf	2.98
Derivatives asset (liability)	$ 394
Natural Gas 2018 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	4,260,000
Put Option | $ / Mcf	2.31
Floor | $ / Mcf	2.88
Ceiling | $ / Mcf	3.55
Derivatives asset (liability)	$ 310
Natural Gas 2018 | Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	2,222,500
Floor | $ / Mcf	2.60
Ceiling | $ / Mcf	3.04
Derivatives asset (liability)	$ (134)
Natural Gas 2018 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	9,808,000
Swap | $ / Mcf	(0.83)
Derivatives asset (liability)	$ (1,858)
Natural Gas 2018 | Basis Swaps - Texas Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	7,360,000
Swap | $ / Mcf	(0.13)
Derivatives asset (liability)	$ 324
Natural Gas 2018 | Calls
Derivatives Fair Value [Line Items]
Volume | Mcf	2,920,000
Ceiling | $ / Mcf	3.97
Derivatives asset (liability)	$ (19)
Natural Gas 2019 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	7,500,000
Swap | $ / Mcf	2.91
Derivatives asset (liability)	$ 129
Natural Gas 2019 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	8,045,000
Put Option | $ / Mcf	2.35
Floor | $ / Mcf	2.81
Ceiling | $ / Mcf	3.43
Derivatives asset (liability)	$ 313
Natural Gas 2019 | Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	4,471,750
Floor | $ / Mcf	2.62
Ceiling | $ / Mcf	3.03
Derivatives asset (liability)	$ (227)
Natural Gas 2019 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	12,775,000
Swap | $ / Mcf	(0.84)
Derivatives asset (liability)	$ (3,725)
Natural Gas 2020 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	4,642,500
Swap | $ / Mcf	2.90
Derivatives asset (liability)	$ 242
Natural Gas 2020 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	4,935,000
Put Option | $ / Mcf	2.33
Floor | $ / Mcf	2.77
Ceiling | $ / Mcf	3.31
Derivatives asset (liability)	$ 350
Natural Gas 2020 | Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	2,645,000
Floor | $ / Mcf	2.65
Ceiling | $ / Mcf	3.03
Derivatives asset (liability)	$ (34)
Natural Gas 2020 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	7,320,000
Swap | $ / Mcf	(0.84)
Derivatives asset (liability)	$ (2,068)
Natural Gas 2021 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	900,000
Swap | $ / Mcf	2.90
Derivatives asset (liability)	$ 59
Natural Gas 2021 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	1,346,250
Put Option | $ / Mcf	2.32
Floor | $ / Mcf	2.74
Ceiling | $ / Mcf	3.20
Derivatives asset (liability)	$ 97
Natural Gas 2021 | Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	792,500
Floor | $ / Mcf	2.65
Ceiling | $ / Mcf	3.05
Derivatives asset (liability)	$ 43
Natural Gas 2021 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	3,650,000
Swap | $ / Mcf	(0.72)
Derivatives asset (liability)	$ (185)
Natural Gas 2022 | Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	147,500
Floor | $ / Mcf	2.65
Ceiling | $ / Mcf	3.05
Derivatives asset (liability)	$ 11
Natural Gas 2022 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	3,650,000
Swap | $ / Mcf	(0.72)
Derivatives asset (liability)	$ (185)
Natural Gas 2023 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	3,650,000
Swap | $ / Mcf	(0.72)
Derivatives asset (liability)	$ (185)
Natural Gas 2024 | Basis Swaps - Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	3,650,000
Swap | $ / Mcf	(0.72)
Derivatives asset (liability)	$ (185)
Natural Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	108,818,500
Derivatives asset (liability)	$ (6,533)
Natural Gas Liquids Reserves 2018 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	640,036
Swap | $ / bbl	33.06
Derivatives asset (liability)	$ (8,150)
Natural Gas Liquids Reserves 2018 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	780,000
Swap | $ / bbl	12.13
Derivatives asset (liability)	$ (450)
Natural Gas Liquids Reserves 2019 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	570,814
Swap | $ / bbl	30.90
Derivatives asset (liability)	$ (4,524)
Natural Gas Liquids Reserves 2019 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	1,264,750
Swap | $ / bbl	12.60
Derivatives asset (liability)	$ 322
Natural Gas Liquids Reserves 2019 | C5 Collars
Derivatives Fair Value [Line Items]
Volume | bbl	113,040
Floor | $ / bbl	45
Ceiling | $ / bbl	54.83
Derivatives asset (liability)	$ (964)
Natural Gas Liquids Reserves 2020 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	191,112
Swap | $ / bbl	32.22
Derivatives asset (liability)	$ (1,875)
Natural Gas Liquids Reserves 2020 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	1,007,750
Swap | $ / bbl	12.31
Derivatives asset (liability)	$ (73)
Natural Gas Liquids Reserves 2020 | C5 Collars
Derivatives Fair Value [Line Items]
Volume | bbl	28,260
Floor | $ / bbl	45
Ceiling | $ / bbl	54.83
Derivatives asset (liability)	$ (241)
Natural Gas Liquids Reserves 2021 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	88,404
Swap | $ / bbl	41.70
Derivatives asset (liability)	$ (599)
Natural Gas Liquids Reserves 2021 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	724,000
Swap | $ / bbl	12.27
Derivatives asset (liability)	$ (98)
Natural Gas Liquids
Derivatives Fair Value [Line Items]
Volume | bbl	5,769,836
Derivatives asset (liability)	$ (16,791)
Natural Gas Liquids Reserves 2022 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	9,420
Swap | $ / bbl	50.50
Derivatives asset (liability)	$ (33)
Natural Gas Liquids Reserves 2022 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	352,250
Swap | $ / bbl	12.27
Derivatives asset (liability)	$ (107)

Combined Fair Value of Derivati

Combined Fair Value of Derivatives (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	$ 4,796	$ 8,008
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	1,463	1,719
Total Derivative Assets	6,259	9,727
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(19,095)	(14,892)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(12,075)	(14,249)
Total Derivative Liabilities	(31,170)	(29,141)
Contingent Consideration | Sale of Illinois Basin
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	2,450	1,251
Contingent Consideration | Sale of Illinois Basin
Long-Term Derivative Assets:
Total Long-Term Derivative Assets		470
Natural Gas Liquids | Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	365	928
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	308	409
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(11,700)	(10,281)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(4,560)	(4,482)
Natural Gas Liquids | Collars
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(482)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(723)	(385)
Natural Gas Liquids | Three Way Collars
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities		(66)
Natural Gas | Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	1,118	3,734
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	422	411
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(711)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(5)	(423)
Natural Gas | Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	22	183
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	119
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(268)	(146)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(213)	(713)
Natural Gas | Basis Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	328	191
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(3,725)	(3,621)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(4,671)	(7,120)
Natural Gas | Three Way Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	513	1,721
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	614	429
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(56)	(49)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities		(272)
Natural Gas | Calls
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(19)	(154)
Crude Oil | Swaps
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(1,442)	(518)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(986)	(202)
Crude Oil | Collars
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(42)	(31)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(376)	(425)
Crude Oil | Three Way Collars
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(650)	(92)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	$ (541)	$ (161)

Fair Value Hierarchy Table for

Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value (Details) - Commodity derivatives - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	$ (24,911)	$ (19,414)
Significant Other Observable Inputs (Level 2)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	$ (24,911)	$ (19,414)

Financial Instruments Not Recor

Financial Instruments Not Recorded at Fair Value (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Carrying Amount
Derivatives Fair Value [Line Items]
Senior Notes, Net of Issuance Costs	$ 600,302	$ 650,371
Term Loan	261,315	182,028
Debtor In Possession Secured Term Loan	35,000
Capital Leases and Other Obligations	9,563	10,082
Total	906,180	842,481
Fair Value
Derivatives Fair Value [Line Items]
Senior Notes, Net of Issuance Costs	6,730	264,438
Term Loan	252,966	182,028
Debtor In Possession Secured Term Loan	35,000
Capital Leases and Other Obligations	7,065	7,138
Total	$ 301,761	$ 453,604

Schedule of Income Tax Included

Schedule of Income Tax Included in Continuing Operations (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Income Tax Disclosure [Abstract]
Income Tax Benefit (Expense)			$ 0	$ 0
Effective Tax Rate	(0.00%)	(0.00%)	(0.00%)	(0.00%)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Estimated annual effective tax rate from continue operations	0.00%	0.00%	0.00%	0.00%
Statutory rate			21.00%		35.00%
Income Tax Benefit (Expense)			$ 0	$ 0
Estimated annual effective tax rate from continuing operations				(0.00%)
Income tax payments			0	$ 2,000,000
Income tax refunds			$ 2,000,000	$ 200,000

Stockholders' Equity - Addition

Stockholders' Equity - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	Feb. 15, 2018	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	May 12, 2017	May 05, 2017	Mar. 31, 2017	May 27, 2016
Schedule Of Capitalization Equity [Line Items]
Common stock, shares authorized		100,000,000		100,000,000			100,000,000		200,000,000
Preferred Stock, shares authorized		100,000		100,000
Common Stock, shares issued		10,707,788		10,244,394		9,900,000		99,000,000
Common Stock, shares outstanding		10,707,788		10,244,394
Issuance of common stock			100,000	100,000	2,400,000
Reverse stock split		On May 5, 2017, our common shareholders approved a decrease in the number of authorized shares from 200,000,000 to 100,000,000 common shares, contingent upon the effectiveness of a reverse stock split, which occurred on May 12, 2017.
Preferred Stock, par value		$ 0.001		$ 0.001
Preferred Stock, shares issued		3,987		3,987
Preferred Stock, shares outstanding		3,987		3,987
Preferred dividend paid in stock		$ 1
6.0% convertible perpetual preferred stock, Series A
Schedule Of Capitalization Equity [Line Items]
Preferred Stock, par value		$ 0.001		$ 0.001
Preferred Stock, shares issued		3,987		3,987
Preferred Stock, shares outstanding		3,987		3,987
Dividend per share in amount		$ 600
Dividend per share percentage		6.00%
Dividends declared on Preferred Stock				$ 1,800
Cash dividend paid per share				$ 150
Aggregate amount of cash dividend paid				$ 1,200
Preferred dividend paid per share	$ 150			$ 150
Preferred dividend paid in stock	$ 600			$ 600
Accumulated dividends in arrears		$ 3,600
Depositary shares
Schedule Of Capitalization Equity [Line Items]
Liquidation preference per share		$ 10,000

Employee Benefit and Equity P64

Employee Benefit and Equity Plans - Additional Information (Details)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2018USD ($)shares	Jun. 30, 2017USD ($)	Jun. 30, 2018USD ($)$ / sharesshares	Jun. 30, 2017USD ($)Personshares	Dec. 31, 2015$ / shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of option issued to purchase common stock | shares			0	0
Stock-based compensation expense			$ 1,200,000	$ 571,000
Stock options exercised | shares			0
Tax benefit related to stock option exercises			$ 0	0
Outstanding weighted average remaining term (in years)			4 years 4 months 24 days
Weighted average remaining term of options exercisable (in years)			4 years 3 months 18 days
Aggregate intrinsic value of options outstanding	$ 0		$ 0
Aggregate intrinsic value of options exercisable	0		0
Restricted stock or unit expense	900,000			100,000
Key Employee Retention Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Employee retention fixed amount per quarter			$ 132,500
Employee retention period			9 months
Accrued expenses related to retention and incentive plans	100,000		$ 100,000
Key Executive Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Accrued expenses related to retention and incentive plans	400,000		400,000
Compensation available under level of operating performance			1,200,000
Key Executive Incentive Plan | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Compensation available under level of operating performance			3,500,000
Stock Options
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense		$ 100,000		200,000
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	100,000	$ 400,000	$ 1,200,000	$ 400,000
Common stock issued by compensation committee | shares			0	101,237
Number of employees subjected to issuance of common stock | Person				28
Unrecognized compensation expense weighted average period, in years			1 year 2 months 12 days
Unrecognized compensation expense	$ 300,000		$ 300,000
Vested stock | shares			56,976
Restricted Stock | TSR
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value of TSR awards of per share estimated on date of grant | $ / shares			$ 0		$ 2.56
Restricted Stock | Certain Performance Factors Waived
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vested stock | shares	29,411			179,519

Summary of Issued and Outstandi

Summary of Issued and Outstanding Stock Options (Details)	Jun. 30, 2018$ / sharesshares
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Number Outstanding | shares	69,123
Weighted-Average Exercise Price, Outstanding	$ 22.77
Number Exercisable | shares	49,240
Weighted-Average Exercise Price, Exercisable	$ 25.26
Exercise Price Range 9.70
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 9.70
Number Outstanding | shares	2,667
Weighted-Average Exercise Price, Outstanding	$ 9.70
Number Exercisable | shares	1,835
Weighted-Average Exercise Price, Exercisable	$ 9.70
Exercise Price Range 16.90
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 16.90
Number Outstanding | shares	57,169
Weighted-Average Exercise Price, Outstanding	$ 16.90
Number Exercisable | shares	38,118
Weighted-Average Exercise Price, Exercisable	$ 16.90
Exercise Price Range 49.00
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 49
Number Outstanding | shares	4,000
Weighted-Average Exercise Price, Outstanding	$ 49
Number Exercisable | shares	4,000
Weighted-Average Exercise Price, Exercisable	$ 49
Exercise Price Range 50.40
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 50.40
Number Outstanding | shares	3,070
Weighted-Average Exercise Price, Outstanding	$ 50.40
Number Exercisable | shares	3,070
Weighted-Average Exercise Price, Exercisable	$ 50.40
Exercise Price Range 104.20
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 104.20
Number Outstanding | shares	2,217
Weighted-Average Exercise Price, Outstanding	$ 104.20
Number Exercisable | shares	2,217
Weighted-Average Exercise Price, Exercisable	$ 104.20

Monte Carlo Simulation Model As

Monte Carlo Simulation Model Assumptions Used to Estimate Fair Value of Restricted Stock (Details) - Monte Carlo Simulation Model	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected Dividend Yield	0.00%	0.00%
Risk-Free Interest Rate	1.00%	1.00%
Expected Volatility	58.60%	58.60%
Market Index	35.60%	35.60%
Expected Life	3 years	3 years
Peer Group
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected Volatility Rate Minimum	29.80%	29.80%
Expected Volatility Rate Maximum	85.00%	85.00%

Summary of Nonvested Stock Acti

Summary of Nonvested Stock Activity (Details) - Restricted Stock - $ / shares	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock awards, beginning balance, Number of Shares	200,475
Awards, Number of Shares	0	101,237
Forfeitures, Number of Shares	(27,817)
Vested, Number of Shares	(56,976)
Stock awards, ending balance, Number of Shares	115,682
Stock awards, beginning balance, Weighted Average Grant Date Fair Value	$ 13.62
Forfeitures, Weighted Average Grant Date Fair Value	15.13
Vested, Weighted Average Grant Date Fair Value	24.72
Stock awards, ending balance, Weighted Average Grant Date Fair Value	$ 7.79

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details)	Jun. 14, 2016USD ($)	Jun. 30, 2018USD ($)RigsQuarterlyInstallment	Jun. 30, 2017USD ($)	Jun. 30, 2018USD ($)RigsQuarterlyInstallment$ / galgal	Jun. 30, 2017USD ($)
Loss Contingencies [Line Items]
Significant probable or possible environmental contingent liabilities		$ 0		$ 0
Letters of credit		32,000,000		32,000,000
Rent expense		200,000	$ 200,000	500,000	$ 500,000
Maximum guarantee of payment of obligations		363,100,000		$ 363,100,000
Guarantee obligations period				2,029
Fees related to unutilized capacity commitments		700,000	700,000	$ 1,400,000	1,400,000
Production and Lease Operating Expense		36,756,000	29,374,000	70,602,000	58,308,000
Transportation, Processing and Marketing of Nature Gas
Loss Contingencies [Line Items]
Transportation, processing and marketing expenses of natural gas, condensate and natural gas liquids		$ 34,100,000	26,400,000	$ 65,200,000	52,700,000
Capacity Reservation
Loss Contingencies [Line Items]
Estimated working interest		56.00%		56.00%
Charges incurred for unutilized processing capacity		$ 600,000	1,700,000	$ 1,200,000	3,300,000
Capacity Reservation | 2018
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed		8,800,000		8,800,000
Capacity Reservation | 2019
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed		17,600,000		17,600,000
Capacity Reservation | 2020
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed		17,600,000		17,600,000
Capacity Reservation | 2021
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed		17,500,000		17,500,000
Capacity Reservation | 2022
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed		17,600,000		17,600,000
Capacity Reservation | Thereafter
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed		68,800,000		$ 68,800,000
Ohio Drilling Operations | Water Supply Commitments
Loss Contingencies [Line Items]
Water supply contract, effective date				Jul. 5, 2017
Water supply contract, maturity date				Jul. 4, 2022
Water contract purchase obligation | gal				150,000,000
Water Fixed price per gallon | $ / gal				0.0075
Future commitment for unpurchased volumes of water, amount		$ 600,000		$ 600,000
Drilling Commitments
Loss Contingencies [Line Items]
Number of rigs to support Appalachian Basin operations | Rigs		1		1
Number of contracts terminated | Rigs		1
Termination fees incurred		$ 1,200,000
Termination fees incurred relating to remaining commitment owed		$ 100,000
Illinois Basin Oil Contingency | Illinois Basin Operations | Discontinued Operations Assets Held For Sale
Loss Contingencies [Line Items]
Proceeds receivable quarterly installments.	$ 900,000
Proceeds receivable quarterly installments beginning period.	Dec. 31, 2016
Proceeds receivable quarterly installments ending period.	Jun. 30, 2019
Expiration of quarterly measurement period number | QuarterlyInstallment		7		7
Expiration of quarterly measurement period number with average spot price | QuarterlyInstallment		11		11
Additional proceeds receivable for first five quarterly installments				$ 0
Illinois Basin Oil Contingency | Illinois Basin Operations | Discontinued Operations Assets Held For Sale | Average Spot Price of West Texas Intermediate
Loss Contingencies [Line Items]
Expiration of quarterly measurement period number | QuarterlyInstallment		5		5
Illinois Basin Oil Contingency | Illinois Basin Operations | Discontinued Operations Assets Held For Sale | Maximum
Loss Contingencies [Line Items]
Additional proceeds from sale of oil and gas property and equipment	$ 9,900,000
Additional proceeds receivable for remaining six quarterly installments				$ 3,600,000
Proceeds Receivable Period for Quarterly Installments				1 year 15 days
Pennsylvania Impact Fee
Loss Contingencies [Line Items]
Production and Lease Operating Expense		$ 500,000	$ 800,000	$ 1,100,000	$ 1,600,000
Accrued impact fees		$ 1,100,000		$ 1,100,000

Lease Commitments for Each of N

Lease Commitments for Each of Next Five Years (Details) $ in Thousands	Jun. 30, 2018USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,018	$ 488
2,019	903
2,020	802
2,021	484
2,022	496
Total	$ 3,173

Minimum Net Obligations under S

Minimum Net Obligations under Sales, Gathering and Transportation Agreements (Details) $ in Thousands	Jun. 30, 2018USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,018	$ 25,597
2,019	51,096
2,020	49,724
2,021	46,729
2,022	46,260
Thereafter	390,656
Total	$ 610,062

Average Spot Price (Details)

Average Spot Price (Details) - Illinois Basin Operations - Discontinued Operations Assets Held For Sale - Illinois Basin Oil Contingency	6 Months Ended
	Jun. 30, 2018$ / bbl
9/30/2018
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
West Texas Intermediate ("WTI") Average Price per Bbl	62.25
12/31/2018
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
West Texas Intermediate ("WTI") Average Price per Bbl	62.75
3/31/2019
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
West Texas Intermediate ("WTI") Average Price per Bbl	63.25
6/30/2019
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
West Texas Intermediate ("WTI") Average Price per Bbl	63.75

Earnings Per Common Share - Add

Earnings Per Common Share - Additional Information (Details) - shares	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
6.0% convertible perpetual preferred stock, Series A
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Dividend per share percentage			6.00%
Conversion of Preferred Stock
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share	221,502	221,502	221,502	221,502
Stock Options
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share	69,123	112,348	69,123	112,348
Performance Based Restricted Stock Awards
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share	0	43,124	0	71,715

Earnings Per Share - Computatio

Earnings Per Share - Computation of Basic and Diluted Earning Per Common Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Numerator:
Net Loss	$ (2,684)	$ (9,603)	$ (72,476)	$ (6,920)
Less: Preferred Stock Dividends	(598)	(598)	(1,196)	(1,196)
Net Loss Attributable to Common Shareholders	$ (3,282)	$ (10,201)	$ (73,672)	$ (8,116)
Denominator:
Weighted Average Common Shares Outstanding - Basic	10,708	9,881	10,587	9,825
Effect of Dilutive Securities:
Weighted Average Common Shares Outstanding - Diluted	10,708	9,881	10,587	9,825
Earnings per Common Share Attributable to Rex Energy Common Shareholders:
Basic — Net Loss Attributable to Common Shareholders	$ (0.31)	$ (1.03)	$ (6.96)	$ (0.83)
Diluted — Net Loss Attributable to Common Shareholders	$ (0.31)	$ (1.03)	$ (6.96)	$ (0.83)

Equity Method Investments - Add

Equity Method Investments - Additional Information (Details) - RW Gathering, LLC	6 Months Ended
	Jun. 30, 2018USD ($)Well	Dec. 31, 2017USD ($)
Schedule Of Equity Method Investments [Line Items]
Ownership percentage	40.00%
Ownership interest percentage sold	40.00%
Number of wells sold | Well	61
Due to or from related party		$ 0
Oil and Gas
Schedule Of Equity Method Investments [Line Items]
Production and Lease Operating Expense	$ 200,000

Impairment Expense - Additional

Impairment Expense - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense	$ 4,334	$ 3,032	$ 12,503	$ 4,577
Butler County, Pennsylvania, and Warrior County, Ohio
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense			11,300	3,800
Westmoreland, Centre and Clearfield Counties, Pennsylvania | Proved Properties
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense			1,200
Marcellus and Utica Shale
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Undeveloped properties, cost	$ 174,600		$ 174,600
Butler County | Proved Properties
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense				$ 800

Exploration Expense - Additiona

Exploration Expense - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Exploration Expense [Line Items]
Exploration Expense	$ 122	$ 99	$ 350	$ 319
Geological and Geophysical Type Expenditures
Exploration Expense [Line Items]
Exploration Expense			200	200
Delay Rentals for Non Operated Properties
Exploration Expense [Line Items]
Exploration Expense			$ 100	$ 100

Condensed Consolidating Finan77

Condensed Consolidating Financial Information - Additional Information (Details) $ in Millions	Jun. 30, 2018USD ($)
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Senior Notes, Principal amount	$ 600.3

Condensed Consolidating Balance

Condensed Consolidating Balance Sheets (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017
Current Assets
Cash and Cash Equivalents	$ 28,780	$ 15,247	$ 12,855
Restricted Cash	33,106
Accounts Receivable	28,588	25,974
Taxes Receivable	48	2,049
Short-Term Derivative Instruments	4,796	8,008
Inventory, Prepaid Expenses and Other	3,389	4,614
Total Current Assets	98,707	55,892
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties	1,062,986	1,086,625
Unevaluated Oil and Gas Properties	174,608	186,523
Other Property and Equipment	20,066	19,640
Wells and Facilities in Progress	2,552	38,660
Pipelines	16,528	16,803
Total Property and Equipment	1,276,740	1,348,251
Less: Accumulated Depreciation, Depletion and Amortization	(384,556)	(463,899)
Net Property and Equipment	892,184	884,352
Other Assets	35	44
Long-Term Derivative Instruments	1,463	1,719
Deferred Tax Assets - Long Term	130	130
Total Assets	992,519	942,137
Current Liabilities
Accounts Payable	82,679	62,354
Current Maturities of Long-Term Debt	261,315	834,325
Debtor-in Possession Term Loan Payable	35,000
Accrued Liabilities	30,936	45,218
Short-Term Derivative Instruments	19,095	14,892
Total Current Liabilities	429,025	956,789
Long-Term Derivative Instruments	12,075	14,249
Other Long-Term Debt		8,156
Other Deposits and Liabilities		7,153
Future Abandonment Cost	8,626	9,352
Liabilities Subject to Compromise	667,624
Total Liabilities	1,117,350	995,699
Stockholders’ Equity
Preferred Stock	1	1
Common Stock	11	10
Additional Paid-In Capital	654,721	652,917
Accumulated Deficit	(779,564)	(706,490)
Total Stockholders’ Equity	(124,831)	(53,562)
Total Liabilities and Stockholders’ Equity	992,519	942,137
Eliminations
Property and Equipment (Successful Efforts Method)
Intercompany Receivables	(1,118,701)	(1,072,637)
Investment in Subsidiaries – Net	290,013	274,745
Total Assets	(828,688)	(797,892)
Current Liabilities
Intercompany Payables	(1,118,701)	(1,072,637)
Total Liabilities	(1,118,701)	(1,072,637)
Stockholders’ Equity
Additional Paid-In Capital	(177,143)	(177,144)
Accumulated Deficit	467,156	451,889
Total Stockholders’ Equity	290,013	274,745
Total Liabilities and Stockholders’ Equity	(828,688)	(797,892)
Guarantor Subsidiaries
Current Assets
Cash and Cash Equivalents	28,777	15,244
Accounts Receivable	26,961	25,974
Short-Term Derivative Instruments	2,346	8,008
Inventory, Prepaid Expenses and Other	3,389	2,106
Total Current Assets	61,473	51,332
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties	1,062,986	1,086,625
Unevaluated Oil and Gas Properties	174,608	186,523
Other Property and Equipment	20,066	19,640
Wells and Facilities in Progress	2,552	38,660
Pipelines	16,528	16,803
Total Property and Equipment	1,276,740	1,348,251
Less: Accumulated Depreciation, Depletion and Amortization	(384,556)	(463,899)
Net Property and Equipment	892,184	884,352
Other Assets	35	44
Investment in Subsidiaries – Net	(2,805)	(2,484)
Long-Term Derivative Instruments	1,463	(2)
Total Assets	952,350	933,242
Current Liabilities
Accounts Payable	32,679	62,354
Current Maturities of Long-Term Debt		1,926
Accrued Liabilities	18,074	32,214
Short-Term Derivative Instruments	19,095	14,892
Total Current Liabilities	69,848	111,386
Long-Term Derivative Instruments	12,075	14,249
Other Long-Term Debt		8,156
Other Deposits and Liabilities		7,153
Future Abandonment Cost	8,626	9,352
Liabilities Subject to Compromise	37,230
Intercompany Payables	1,114,295	1,068,231
Total Liabilities	1,242,074	1,218,527
Stockholders’ Equity
Additional Paid-In Capital	177,143	177,144
Accumulated Deficit	(466,867)	(462,429)
Total Stockholders’ Equity	(289,724)	(285,285)
Total Liabilities and Stockholders’ Equity	952,350	933,242
Non-Guarantor Subsidiaries
Current Liabilities
Intercompany Payables	4,406	4,406
Total Liabilities	4,406	4,406
Stockholders’ Equity
Accumulated Deficit	(4,406)	(4,406)
Total Stockholders’ Equity	(4,406)	(4,406)
Parent Company
Current Assets
Cash and Cash Equivalents	3	3
Restricted Cash	33,106
Accounts Receivable	1,627
Taxes Receivable	48	2,049
Short-Term Derivative Instruments	2,450
Inventory, Prepaid Expenses and Other		2,508
Total Current Assets	37,234	4,560
Property and Equipment (Successful Efforts Method)
Intercompany Receivables	1,118,701	1,072,637
Investment in Subsidiaries – Net	(287,208)	(272,261)
Long-Term Derivative Instruments		1,721
Deferred Tax Assets - Long Term	130	130
Total Assets	868,857	806,787
Current Liabilities
Accounts Payable	50,000
Current Maturities of Long-Term Debt	261,315	832,399
Debtor-in Possession Term Loan Payable	35,000
Accrued Liabilities	12,862	13,004
Total Current Liabilities	359,177	845,403
Liabilities Subject to Compromise	630,394
Total Liabilities	989,571	845,403
Stockholders’ Equity
Preferred Stock	1	1
Common Stock	11	10
Additional Paid-In Capital	654,721	652,917
Accumulated Deficit	(775,447)	(691,544)
Total Stockholders’ Equity	(120,714)	(38,616)
Total Liabilities and Stockholders’ Equity	$ 868,857	$ 806,787

Condensed Consolidating Stateme

Condensed Consolidating Statements of Operations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$ 75,155	$ 47,457	$ 140,180	$ 99,522
Other Operating Revenue (Expense)	3	5	7	11
TOTAL OPERATING REVENUE	75,158	47,462	140,187	99,533
OPERATING EXPENSES
Production and Lease Operating Expense	36,756	29,374	70,602	58,308
General and Administrative Expense	4,422	4,294	10,946	8,828
Loss (Gain) on Disposal of Assets		(124)	647	(1,959)
Impairment Expense	4,334	3,032	12,503	4,577
Exploration Expense	122	99	350	319
Depreciation, Depletion, Amortization and Accretion	16,953	15,501	32,081	30,969
Other Operating (Income) Expense	1,492	(98)	1,695	(118)
TOTAL OPERATING EXPENSES	64,079	52,078	128,824	100,924
INCOME (LOSS) FROM OPERATIONS	11,079	(4,616)	11,363	(1,391)
OTHER INCOME (EXPENSE)
Interest Expense	(14,118)	(12,122)	(36,765)	(21,266)
(Loss) Gain on Derivatives, Net	(14,328)	10,386	(60,754)	18,766
Other (Expense) Income	(13,952)	20	(14,955)	(7)
Reorganization Items, Net	28,635		28,635
Loss on Extinguishments of Debt		(3,271)		(3,022)
TOTAL OTHER EXPENSE	(13,763)	(4,987)	(83,839)	(5,529)
LOSS BEFORE INCOME TAX	(2,684)	(9,603)	(72,476)	(6,920)
Income Tax Benefit			0	0
NET INCOME (LOSS)	(2,684)	(9,603)	(72,476)	(6,920)
Preferred Stock Dividends	(598)	(598)	(1,196)	(1,196)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(3,282)	(10,201)	(73,672)	(8,116)
Eliminations
OTHER INCOME (EXPENSE)
Loss from Equity in Consolidated Subsidiaries	9,070	(6,345)	4,115	(19,047)
TOTAL OTHER EXPENSE	9,070	(6,345)	4,115	(19,047)
LOSS BEFORE INCOME TAX	9,070	(6,345)	4,115	(19,047)
NET INCOME (LOSS)	9,070	(6,345)	4,115	(19,047)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	9,070	(6,345)	4,115	(19,047)
Guarantor Subsidiaries
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	75,155	47,457	140,180	99,522
Other Operating Revenue (Expense)	3	5	7	11
TOTAL OPERATING REVENUE	75,158	47,462	140,187	99,533
OPERATING EXPENSES
Production and Lease Operating Expense	36,756	29,374	70,602	58,308
General and Administrative Expense	4,235	3,771	9,739	8,232
Loss (Gain) on Disposal of Assets		(124)	647	(1,959)
Impairment Expense	4,334	3,032	12,503	4,577
Exploration Expense	122	99	350	319
Depreciation, Depletion, Amortization and Accretion	16,953	15,501	32,081	30,969
Other Operating (Income) Expense	1,492	(99)	1,695	(119)
TOTAL OPERATING EXPENSES	63,892	51,554	127,617	100,327
INCOME (LOSS) FROM OPERATIONS	11,266	(4,092)	12,570	(794)
OTHER INCOME (EXPENSE)
Interest Expense	(662)	(442)	(1,333)	(809)
(Loss) Gain on Derivatives, Net	(18,413)	10,861	(13,088)	20,659
Other (Expense) Income	53	20	(951)	(7)
Reorganization Items, Net	(1,314)		(1,313)
Loss from Equity in Consolidated Subsidiaries		(1)		(1)
TOTAL OTHER EXPENSE	(20,336)	10,438	(16,685)	19,842
LOSS BEFORE INCOME TAX	(9,070)	6,346	(4,115)	19,048
NET INCOME (LOSS)	(9,070)	6,346	(4,115)	19,048
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(9,070)	6,346	(4,115)	19,048
Non-Guarantor Subsidiaries
OPERATING EXPENSES
Other Operating (Income) Expense		1		1
TOTAL OPERATING EXPENSES		1		1
INCOME (LOSS) FROM OPERATIONS		(1)		(1)
OTHER INCOME (EXPENSE)
LOSS BEFORE INCOME TAX		(1)		(1)
NET INCOME (LOSS)		(1)		(1)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS		(1)		(1)
Parent Company
OPERATING EXPENSES
General and Administrative Expense	187	523	1,207	596
TOTAL OPERATING EXPENSES	187	523	1,207	596
INCOME (LOSS) FROM OPERATIONS	(187)	(523)	(1,207)	(596)
OTHER INCOME (EXPENSE)
Interest Expense	(13,456)	(11,680)	(35,432)	(20,457)
(Loss) Gain on Derivatives, Net	4,085	(475)	(47,666)	(1,893)
Other (Expense) Income	(14,005)		(14,004)
Reorganization Items, Net	29,949		29,948
Loss on Extinguishments of Debt		(3,271)		(3,022)
Loss from Equity in Consolidated Subsidiaries	(9,070)	6,346	(4,115)	19,048
TOTAL OTHER EXPENSE	(2,497)	(9,080)	(71,269)	(6,324)
LOSS BEFORE INCOME TAX	(2,684)	(9,603)	(72,476)	(6,920)
NET INCOME (LOSS)	(2,684)	(9,603)	(72,476)	(6,920)
Preferred Stock Dividends	(598)	(598)	(1,196)	(1,196)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (3,282)	$ (10,201)	$ (73,672)	$ (8,116)

Condensed Consolidating State80

Condensed Consolidating Statements of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net (Loss) Income	$ (2,684)	$ (9,603)	$ (72,476)	$ (6,920)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided (Used) by Operating Activities
Depreciation, Depletion, Amortization and Accretion	16,953	15,501	32,081	30,969
Loss (Gain) on Derivatives	14,328	(10,386)	60,754	(18,766)
Cash Settlement of Derivatives			(6,862)	(5,525)
Equity-based Compensation Expense			1,200	571
Impairment Expense	4,334	3,032	12,503	4,577
Non-cash Interest Expense			2,881	12,431
Non-cash Exploration Expenses				13
Loss (Gain) on Disposal of Assets		(124)	647	(1,959)
Loss on Extinguishments of Debt				3,022
Non-cash Reorganization Items, Net			(43,509)
Other Non-cash Expenses			566	41
Changes in operating assets and liabilities
Accounts Receivable			(342)	7,229
Taxes Receivable			2,001	163
Inventory, Prepaid Expenses and Other Assets			336	52
Accounts Payable and Accrued Liabilities			41,478	(1,484)
Other Assets and Liabilities			(147)	(1,104)
NET CASH PROVIDED BY OPERATING ACTIVITIES			31,111	23,310
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets			16,384	24,513
Acquisitions of Undeveloped Acreage			(871)	(1,783)
Capital Expenditures for Development of Oil & Gas Properties and Equipment			(100,136)	(54,004)
NET CASH USED IN INVESTING ACTIVITIES			(84,623)	(31,274)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Line of Credit, net of Discounts			69,846	171,000
Repayments of Long-Term Debt and Line of Credit				(145,170)
Proceeds from Debtor-In-Possession Financing			35,000
Repayments of Loans and Other Notes Payable			(945)	(319)
Debt Issuance Costs				(7,791)
Payment of Preferred Dividends in Arrears				(598)
Reorganization Item - Debtor-In-Possession Financing Fee			(3,750)
NET CASH PROVIDED BY FINANCING ACTIVITIES			100,151	17,122
Net Increase in Cash, Cash Equivalents and Restricted Cash			46,639	9,158
Beginning Cash, Cash Equivalents and Restricted Cash			15,247	3,697
Ending Cash, Cash Equivalents and Restricted Cash	61,886	12,855	61,886	12,855
Eliminations
CASH FLOWS FROM OPERATING ACTIVITIES
Net (Loss) Income			4,115	(19,047)
Changes in operating assets and liabilities
NET CASH PROVIDED BY OPERATING ACTIVITIES			4,115	(19,047)
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries			(4,115)	19,047
NET CASH USED IN INVESTING ACTIVITIES			(4,115)	19,047
Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES
Net (Loss) Income			(4,115)	19,048
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided (Used) by Operating Activities
Depreciation, Depletion, Amortization and Accretion	16,953	15,501	32,081	30,969
Loss (Gain) on Derivatives	18,413	(10,861)	13,088	(20,659)
Cash Settlement of Derivatives			(6,862)	(5,525)
Equity-based Compensation Expense			(7)
Impairment Expense	4,334	3,032	12,503	4,577
Non-cash Exploration Expenses				13
Loss (Gain) on Disposal of Assets		(124)	647	(1,959)
Other Non-cash Expenses			588	41
Changes in operating assets and liabilities
Accounts Receivable			(342)	7,232
Inventory, Prepaid Expenses and Other Assets			(2,173)	638
Accounts Payable and Accrued Liabilities			7,778	(1,484)
Other Assets and Liabilities			(147)	(1,104)
NET CASH PROVIDED BY OPERATING ACTIVITIES			53,039	31,787
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries			46,062	4,063
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets			16,384	24,513
Acquisitions of Undeveloped Acreage			(871)	(1,783)
Capital Expenditures for Development of Oil & Gas Properties and Equipment			(100,136)	(54,004)
NET CASH USED IN INVESTING ACTIVITIES			(38,561)	(27,211)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Loans and Other Notes Payable			(945)	(319)
NET CASH PROVIDED BY FINANCING ACTIVITIES			(945)	(319)
Net Increase in Cash, Cash Equivalents and Restricted Cash			13,533	4,257
Beginning Cash, Cash Equivalents and Restricted Cash			15,244	3,694
Ending Cash, Cash Equivalents and Restricted Cash	28,777	7,951	28,777	7,951
Non-Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES
Net (Loss) Income				(1)
Changes in operating assets and liabilities
NET CASH PROVIDED BY OPERATING ACTIVITIES				(1)
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries				1
NET CASH USED IN INVESTING ACTIVITIES				1
Parent Company
CASH FLOWS FROM OPERATING ACTIVITIES
Net (Loss) Income			(72,476)	(6,920)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided (Used) by Operating Activities
Loss (Gain) on Derivatives	(4,085)	475	47,666	1,893
Equity-based Compensation Expense			1,207	571
Non-cash Interest Expense			2,881	12,431
Loss on Extinguishments of Debt				3,022
Non-cash Reorganization Items, Net			(43,509)
Other Non-cash Expenses			(22)
Changes in operating assets and liabilities
Accounts Receivable				(3)
Taxes Receivable			2,001	163
Inventory, Prepaid Expenses and Other Assets			2,509	(586)
Accounts Payable and Accrued Liabilities			33,700
NET CASH PROVIDED BY OPERATING ACTIVITIES			(26,043)	10,571
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries			(41,947)	(23,111)
NET CASH USED IN INVESTING ACTIVITIES			(41,947)	(23,111)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Line of Credit, net of Discounts			69,846	171,000
Repayments of Long-Term Debt and Line of Credit				(145,170)
Proceeds from Debtor-In-Possession Financing			35,000
Debt Issuance Costs				(7,791)
Payment of Preferred Dividends in Arrears				(598)
Reorganization Item - Debtor-In-Possession Financing Fee			(3,750)
NET CASH PROVIDED BY FINANCING ACTIVITIES			101,096	17,441
Net Increase in Cash, Cash Equivalents and Restricted Cash			33,106	4,901
Beginning Cash, Cash Equivalents and Restricted Cash			3	3
Ending Cash, Cash Equivalents and Restricted Cash	$ 33,109	$ 4,904	$ 33,109	$ 4,904

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - USD ($)	Jul. 11, 2018	Jun. 30, 2018
Subsequent Event [Line Items]
Debtor-in-possession financing,drawan amount		$ 35,000,000
Subsequent Event
Subsequent Event [Line Items]
Bankruptcy court final order issued date	Jul. 11, 2018
Secured Delayed Draw Term Loan Facility | First Lien Credit Agreement | Maximum | Subsequent Event
Subsequent Event [Line Items]
Debtor-in-possession financing, aggregate principal amount	$ 411,315,322
Prior Term Loan | First Lien Credit Agreement | Subsequent Event
Subsequent Event [Line Items]
Debtor-in-possession financing, aggregate principal amount	261,315,322
Make Whole Amount | First Lien Credit Agreement | Subsequent Event
Subsequent Event [Line Items]
Debtor-in-possession financing, aggregate principal amount	50,000,000
Finance Post Petition Operations Chapter 11 Process (Additional Borrowing Capacity) | First Lien Credit Agreement
Subsequent Event [Line Items]
Debtor-in-possession financing,drawan amount		$ 35,000,000
Finance Post Petition Operations Chapter 11 Process (Additional Borrowing Capacity) | First Lien Credit Agreement | Subsequent Event
Subsequent Event [Line Items]
Debtor-in-possession financing, aggregate principal amount	$ 100,000,000