Rex Energy 10-Q 5 Aug 16 2016 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Aug. 03, 2016
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2,016
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	Accelerated Filer
Entity Common Stock, Shares Outstanding		95,331,629

Consolidated Balance Sheets (Un

Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands		Jun. 30, 2016	Dec. 31, 2015
Current Assets
Cash and Cash Equivalents		$ 3,438	$ 1,091
Accounts Receivable		31,644	17,274
Taxes Receivable		48	18
Short-Term Derivative Instruments		4,760	34,260
Inventory, Prepaid Expenses and Other		1,688	3,059
Assets Held for Sale		46,549	60,451
Total Current Assets		88,127	116,153
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,020,936	943,092
Unevaluated Oil and Gas Properties		232,674	262,992
Other Property and Equipment		21,444	20,363
Wells and Facilities in Progress		75,992	141,100
Pipelines		14,144	14,024
Total Property and Equipment		1,365,190	1,381,571
Less: Accumulated Depreciation, Depletion and Amortization		(459,427)	(437,828)
Net Property and Equipment		905,763	943,743
Other Assets		2,490	2,501
Long-Term Derivative Instruments		1,526	9,534
Total Assets		997,906	1,071,931
Current Liabilities
Accounts Payable		51,915	36,785
Current Maturities of Long-Term Debt		172	402
Accrued Liabilities		30,346	40,608
Short-Term Derivative Instruments		15,902	2,486
Liabilities Related to Assets Held for Sale		39,935	36,320
Total Current Liabilities		138,270	116,601
Noncurrent Liabilities
Long-Term Derivative Instruments		10,091	5,556
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs		141,237	109,386
Senior Notes, Net of Issuance Costs	[1]	637,314	663,089
Premium on Senior Notes, Net		1,524	2,344
Other Deposits and Liabilities		2,860	3,156
Future Abandonment Cost		7,731	11,568
Total Liabilities		939,027	911,700
Commitments and Contingencies (See Note 12)
Stockholders’ Equity
Preferred Stock		1	1
Common Stock		77	54
Additional Paid-In Capital		637,223	623,863
Accumulated Deficit		(578,422)	(463,687)
Total Stockholders’ Equity		58,879	160,231
Total Liabilities and Stockholders’ Equity		$ 997,906	$ 1,071,931
[1]	Includes unamortized debt issuance costs of approximately $9.1 million and $11.9 million as of June 30, 2016 and December 31, 2015, respectively.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) (Unaudited) - $ / shares	Jun. 30, 2016	Dec. 31, 2015
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	4,087	16,100
Preferred Stock, shares outstanding	4,087	16,100
Common Stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	200,000,000	200,000,000
Common Stock, shares issued	78,440,589	55,741,229
Common Stock, shares outstanding	78,440,589	55,741,229

Consolidated Statements of Oper

Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$ 31,271	$ 35,772	$ 56,944	$ 81,696
Other Revenue (Expense)	(6)	12	7	22
TOTAL OPERATING REVENUE	31,265	35,784	56,951	81,718
OPERATING EXPENSES
Production and Lease Operating Expense	25,221	24,270	49,672	47,387
General and Administrative Expense	4,837	7,394	10,121	15,745
Gain on Disposal of Assets	(4,307)	(373)	(4,295)	(309)
Impairment Expense	25,139	117,839	35,780	124,687
Exploration Expense	803	755	1,738	1,194
Depreciation, Depletion, Amortization and Accretion	14,750	24,698	31,262	46,537
Other Operating (Income) Expense	704	(66)	1,030	5,138
TOTAL OPERATING EXPENSES	67,147	174,517	125,308	240,379
LOSS FROM OPERATIONS	(35,882)	(138,733)	(68,357)	(158,661)
OTHER INCOME (EXPENSE)
Interest Expense	(11,439)	(12,181)	(24,469)	(24,193)
Gain (Loss) on Derivatives, Net	(29,169)	(281)	(25,120)	16,838
Other Income	12	61	12	92
Debt Exchange Expense	(533)		(9,014)
Gain on Extinguishment of Debt	23,707		23,707
Loss on Equity Method Investments		(208)		(411)
TOTAL OTHER INCOME (EXPENSE)	(17,422)	(12,609)	(34,884)	(7,674)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(53,304)	(151,342)	(103,241)	(166,335)
Income Tax (Expense) Benefit	393		(2,321)
NET LOSS FROM CONTINUING OPERATIONS	(52,911)	(151,342)	(105,562)	(166,335)
Loss From Discontinued Operations, Net of Income Taxes	(1,683)	(461)	(9,173)	(1,985)
NET LOSS	(54,594)	(151,803)	(114,735)	(168,320)
Net Income Attributable to Noncontrolling Interests		949		2,246
NET LOSS ATTRIBUTABLE TO REX ENERGY	(54,594)	(152,752)	(114,735)	(170,566)
Preferred Stock Dividends	(1,723)	(2,415)	(3,828)	(4,830)
Effect of Preferred Stock Conversions	72,316		72,316
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 15,999	$ (155,167)	$ (46,247)	$ (175,396)
Earnings per common share:
Basic – Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders	$ 0.24	$ (2.84)	$ (0.58)	$ (3.16)
Basic – Net Loss From Discontinued Operations Attributable to Rex Energy Common Shareholders	(0.02)	(0.03)	(0.14)	(0.08)
Basic – Net Income (Loss) Attributable to Rex Energy Common Shareholders	$ 0.22	$ (2.87)	$ (0.72)	$ (3.24)
Basic – Weighted Average Shares of Common Stock Outstanding	71,804	54,118	64,044	54,090
Diluted – Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders	$ 0.24	$ (2.84)	$ (0.58)	$ (3.16)
Diluted – Net Loss From Discontinued Operations Attributable to Rex Energy Common Shareholders	(0.02)	(0.03)	(0.14)	(0.08)
Diluted – Net Income (Loss) Attributable to Rex Energy Common Shareholders	$ 0.22	$ (2.87)	$ (0.72)	$ (3.24)
Diluted – Weighted Average Shares of Common Stock Outstanding	71,804	54,118	64,044	54,090

Consolidated Statement of Chang

Consolidated Statement of Changes in Stockholders' Equity (Unaudited) - 6 months ended Jun. 30, 2016 - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Preferred Stock	Additional Paid-in Capital	Accumulated Deficit
Balance at Dec. 31, 2015	$ 160,231	$ 54	$ 1	$ 623,863	$ (463,687)
Balance (in shares) at Dec. 31, 2015		55,741	16
Non-Cash Compensation	1,275			1,275
Issuance of Common Stock in Debt Exchange	6,413	$ 9		6,404
Issuance of Common Stock in Debt Exchange (in shares)		8,413
Issuance of Common Stock for Debt Extinguishments	5,695	$ 5		5,690
Issuance of Common Stock for Debt Extinguishments (in shares)		5,227
Issuance of Restricted Stock, Net of Forfeitures (in shares)		48
Conversion of Preferred Stock to Common Stock		$ 9		(9)
Conversion of Preferred Stock to Common Stock (in shares)		9,012	(12)
Net Loss	(114,735)				(114,735)
Balance at Jun. 30, 2016	$ 58,879	$ 77	$ 1	$ 637,223	$ (578,422)
Balance (in shares) at Jun. 30, 2016		78,441	4

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$ (114,735)	$ (168,320)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss from Equity Method Investments		411
Non-cash Expenses	10,100	5,884
Depreciation, Depletion, Amortization and Accretion	36,345	55,740
Gain on Derivatives	25,120	(16,838)
Cash Settlements of Derivatives	30,340	25,020
Dry Hole Expense	870	289
Impairment Expense	39,323	124,867
Gain on Extinguishment of Debt	(23,757)
Gain on Sale of Assets	(4,338)	(277)
Changes in operating assets and liabilities
Accounts Receivable	(14,772)	16,951
Inventory, Prepaid Expenses and Other Assets	1,118	1,024
Accounts Payable and Accrued Liabilities	10,425	(23,984)
Other Assets and Liabilities	(676)	(961)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	(4,637)	19,806
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management		43
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	190	4,533
Proceeds from Joint Venture for Reimbursement of Capital Costs	19,461	16,611
Acquisitions of Undeveloped Acreage	(5,900)	(21,114)
Capital Expenditures for Development of Oil & Gas Properties and Equipment	(37,738)	(125,645)
NET CASH USED IN INVESTING ACTIVITIES	(23,987)	(125,572)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Long-Term Debt and Line of Credit	(15,230)	(56,443)
Proceeds from Long-Term Debt and Line of Credit	50,400	157,960
Repayments of Loans and Other Notes Payable	(361)	(1,153)
Debt Issuance Costs	(3,838)	(572)
Dividends Paid on Preferred Stock		(4,830)
Distributions by the Partners of Consolidated Joint Ventures		(830)
NET CASH PROVIDED BY FINANCING ACTIVITIES	30,971	94,132
NET INCREASE (DECREASE) IN CASH	2,347	(11,634)
CASH – BEGINNING	1,091	18,096
CASH – ENDING	3,438	6,462
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO CONTINUING OPERATIONS	3,438	6,113
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO ASSETS HELD FOR SALE		349
SUPPLEMENTAL DISCLOSURES
Interest Paid, net of capitalized interest	24,260	24,832
Cash Paid (Received) for Income Taxes	29	(502)
Capital Expenditures for Development of Oil & Gas Properties and Equipment Attributable to Discontinued Operations	(991)	(8,848)
NON-CASH ACTIVITIES
Decrease in Accrued Liabilities for Capital Expenditures	(1,688)	$ (9,044)
Decrease in Senior Notes, Net of Issuance Costs due to Debt to Equity Conversions	(28,082)
Decrease in Bond Interest Payable due to Debt to Equity Conversions	(719)
Decrease in Premium on Senior Notes, Net due to Debt to Equity Conversions	(653)
Increase in Common Stock outstanding due to Debt to Equity Conversions	$ 5,696

Basis of Presentation and Princ

Basis of Presentation and Principles of Consolidation	6 Months Ended
	Jun. 30, 2016
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 oil, natural gas liquid (“NGL”) and natural gas company with operations currently focused in the Appalachian Basin. We are focused on Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) 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 oil, NGL and natural gas 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 financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. For purposes of compliance with Accounting Standards Update (“ASU”) 2015-3, which we adopted on January 1, 2016, we have reclassified approximately $2.1 million from Other Assets to Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs and approximately $11.9 million from Other Assets to Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets as of December 31, 2015. In addition, we adopted ASU 2015-17 on January 1, 2016, which eliminates the need to show deferred tax liabilities and assets as current and noncurrent. Our Consolidated Balance Sheet as of December 31, 2015 included $12.5 million in Long-Term Tax Assets and $12.5 million in Current Deferred Tax Liability. Reclassifying our Current Deferred Tax Liability to noncurrent allowed us to net our noncurrent asset and noncurrent liability together resulting in a net deferred tax balance of zero (see Note 5, Recently Issued Accounting Pronouncements 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 crude oil, NGLs and natural gas, 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 oil, NGL and natural gas 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 (“SEC”). 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, 2015. Discontinued Operations In June 2016, we entered into a purchase and sale agreement to divest all of our Illinois Basin assets and operations. The sale is currently expected to close in August 2016, with an effective date of July 1, 2016. As a result of this transaction, we have classified all assets of the Illinois Basin as “Held for Sale” as they represent a significant component of our operations, and our assets and operations in the Illinois Basin are reported as Discontinued Operations in the accompanying consolidated financial statements. Unless otherwise noted, all disclosures and tables reflect the results of continuing operations and exclude any assets, liabilities or results from our discontinued operations. For additional information see Note 3, Discontinued Operations/Assets Held for Sale

Future Abandonment Cost

Future Abandonment Cost	6 Months Ended
	Jun. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
Future Abandonment Cost	2. 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 $0.1 million and $0.4 million for the three and six months ended June 30, 2016, respectively, and $0.3 million and $0.5 million for the three and six months ended June 30, 2015, respectively. These amounts are recorded as depreciation, depletion, amortization and accretion (“DD&A”) expense on our Consolidated Statements of Operations. We account for future abandonment costs that relate to wells that are drilled jointly based on our working interest in those wells. ($ in Thousands) June 30, 2016 Beginning Balance at January 1, 2016 $ 11,934 Future Abandonment Obligation Incurred 282 Future Abandonment Obligation Settled (4 ) Future Abandonment Obligation Cancelled or Sold (4,568 ) Future Abandonment Obligation Revision of Estimated Obligation — Future Abandonment Obligation Accretion Expense 365 Total Future Abandonment Cost 1 $ 8,009 1

Discontinued Operations_Assets

Discontinued Operations/Assets Held For Sale	6 Months Ended
	Jun. 30, 2016
Discontinued Operations And Disposal Groups [Abstract]
Discontinued Operations/Assets Held For Sale	3. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE Water Solutions Holdings, LLC In December 2014, our board of directors approved a formal plan to sell Water Solutions Holdings, LLC (“Water Solutions”), of which we owned a 60% interest. In June 2015, we entered into a purchase and sale agreement with American Water Works Company, Inc. (“American Water”) pursuant to which American Water acquired Water Solutions for consideration of approximately $130.0 million, inclusive of cash and debt and subject to other customary adjustments. The sale closed in July 2015, and we received approximately $66.8 million in net proceeds, resulting in a gain of approximately $57.8 million. The transaction was recorded as Discontinued Operations in 2015. Summarized financial information for Discontinued Operations related to Water Solutions is set forth in the table below, and does not reflect the costs of certain services provided. Such indirect costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support. Three Months Ended June 30, Six Months Ended June 30, ($ in Thousands) 2016 2015 2016 2015 Revenues: Field Services Revenue $ — $ 16,643 $ — $ 31,607 Total Operating Revenue — 16,643 — 31,607 Costs and Expenses: General and Administrative Expense — 902 — 1,879 Depreciation, Depletion, Amortization and Accretion — 37 — 76 Field Services Operating Expense — 13,464 — 24,753 Gain on Sale of Asset — (10 ) — (42 ) Interest Expense — 240 — 431 Other Expense — 17 — 120 Total Costs and Expenses — 14,650 — 27,217 Income from Discontinued Operations Before Income Taxes — 1,993 — 4,390 Income Tax (Expense) Benefit — 101 — (242 ) Income from Discontinued Operations, net of taxes $ — $ 2,094 $ — $ 4,148 Illinois Basin Operations 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”). Pursuant to the Agreement, Campbell has agreed to purchase, subject to certain parameters and provisions for adjustment customary for transactions of this type, all of Rex’s oil and gas-related properties and assets, both operated and non-operated, in the Illinois Basin on an as-is, where-is basis. Closing is expected to occur on or about August 16, 2016, with an effective date for the transaction of July 1, 2016. We received a purchase deposit of $2.5 million from Campbell in June, and we expect to receive the remaining proceeds of approximately $37.5 million at closing (subject to customary closing and post-closing adjustments). An additional agreement executed in conjunction with the Sales Agreement allows for Rex to receive from Campbell potential additional proceeds of up $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 West Texas Intermediate (“WTI”) as published by the New York Mercantile Exchange must be in excess of the amount shown in the table below for each specific quarter. Calendar Quarter Ending West Texas Intermediate ("WTI") Average Price per Bbl (a) 12/31/2016 $ 54.25 3/31/2017 $ 56.25 6/30/2017 $ 58.25 9/30/2017 $ 60.25 12/31/2017 $ 60.75 3/31/2018 $ 61.25 6/30/2018 $ 61.75 9/30/2018 $ 62.25 12/31/2018 $ 62.75 3/31/2019 $ 63.25 6/30/2019 $ 63.75 (a) Calculated as the sum of the closing spot price of the West Texas Intermediate of the New York Mercantile Exchange for each day during the quarter (excluding weekends and holidays), divided by the number of days on which those prices are published (excluding weekends and holidays). Included in the sale are approximately 76,000 net acres in Illinois, Indiana and Kentucky; the assets are currently producing approximately 1,700 net barrels per day. This Purchase and Sale Agreement results in a full divestiture of our Illinois Basin assets, and an exit from our Illinois Basin operations. As of June 14, 2016, the Illinois Basin assets became classified as “Held for Sale”, and our assets and operations in the Illinois Basin are reported as Discontinued Operations. The carrying value of assets and liabilities of our Illinois Basin operations that are classified as Held for Sale in the accompanying Consolidated Balance Sheets at June 30, 2016 and December 31, 2015 are as follows: June 30, December 31, ($ in Thousands) 2016 2015 Assets: Accounts Receivable 2,367 2,209 Inventory, Prepaid Expenses and Other 1,023 770 Total Current Assets 3,390 2,979 Evaluated Oil & Gas Properties 297,222 296,338 Unevaluated Oil & Gas Properties 37 — Other Property and Equipment 19,354 19,749 Wells and Facilities in Progress 3,401 3,456 Accumulated Depreciation, Depletion, and Amortization (276,855 ) (262,071 ) Total Long-Term Assets 43,159 57,472 Total Assets Held for Sale $ 46,549 $ 60,451 Liabilities: Accounts Payable $ 4,831 $ 1,089 Current Maturities of Long-Term Debt 85 188 Accrued Liabilities 3,285 3,718 Total Current Liabilities 8,201 4,995 Long-Term Debt — 10 Future Abandonment Cost 31,734 31,315 Total Long-Term Liabilities 31,734 31,325 Total Liabilities Related to Assets Held for Sale $ 39,935 $ 36,320 Net Assets Held for Sale $ 6,614 $ 24,131 Summarized financial information for Discontinued Operations related to our Illinois Basin operations is set forth in the tables below, and does not reflect the costs of certain services provided. Such indirect costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support. The sale of our Illinois assets and operations does not include any of our derivative contracts or positions related to our Illinois basin revenues or production. No derivative positions or activity has been attributed to or included in Discontinued Operations for the three and six months periods ended June 30, 2016 and 2015. Three Months Ended June 30, Six Months Ended June 30, ($ in Thousands) 2016 2015 2016 2015 Revenues: Oil Sales $ 6,393 $ 9,989 $ 11,213 $ 18,176 Total Operating Revenue 6,393 9,989 11,213 18,176 Costs and Expenses: Production and Lease Operating Expense 5,029 6,372 10,725 12,307 General and Administrative Expense 659 1,086 1,437 2,385 (Gain) Loss on Disposal of Assets (2 ) 72 (43 ) 73 Impairment Expense — 3 3,543 178 Exploration Expense 85 162 143 241 Depreciation, Depletion, Amortization and Accretion 2,186 4,840 5,083 9,127 Interest Expense 1 13 3 17 Other Income (2 ) (4 ) (3 ) (19 ) Total Costs and Expenses 7,956 12,544 20,888 24,309 Loss from Discontinued Operations Before Income Taxes (1,563 ) (2,555 ) (9,675 ) (6,133 ) Income Tax (Expense) Benefit (120 ) — 502 — Loss from Discontinued Operations, net of taxes $ (1,683 ) $ (2,555 ) $ (9,173 ) $ (6,133 ) Production: Crude Oil (Bbls) 150,980 182,724 308,720 362,541

Business and Oil and Gas Proper

Business and Oil and Gas Property Dispositions	6 Months Ended
	Jun. 30, 2016
Business Combinations [Abstract]
Business and Oil and Gas Property Dispositions	4. BUSINESS AND OIL AND GAS PROPERTY DISPOSITIONS Water Solutions As described in Note 3 Discontinued Operations/Assets Held for Sale ArcLight Capital Partners, LLC On March 31, 2015, we entered into a joint venture agreement with an affiliate of ArcLight Capital Partners, LLC (“ArcLight”) to jointly develop 32 specifically designated wells in our Butler County, Pennsylvania operated area. ArcLight will participate in and fund 35.0% of the estimated well costs for the designated wells. We expect to receive consideration for the transaction of approximately $67.0 million, with $16.6 million received at closing for wells that had previously been completed or were at that time in the process of being drilled and completed. The remainder of the proceeds will be received as additional wells are drilled and completed. Upon the attainment of certain return on investment and internal rate of return thresholds, 50.0% of ArcLight’s 35.0% working interest will revert back to us, leaving ArcLight with a 17.5% working interest. As of June 30, 2016, ArcLight had paid approximately $61.4 million for their interest in wells that have been drilled. As of June 30, 2016, all wells to be developed with ArcLight had been drilled and completed with four wells remaining to be placed into service. The ArcLight 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 ArcLight. Due to the uncertainty that exists on the recoverability of costs associated with our retained interest, proceeds received from ArcLight are considered a recovery of costs and no gain or loss is recognized. 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 will participate in and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, 12 of which have already been drilled, completed, placed in sales and paid for by BSP. The remaining four wells are expected to be placed in sales and paid for by BSP during the fourth quarter of 2016. BSP will also 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 for which final payment from BSP is expected during the third quarter of 2016. BSP also has the option to participate in the development of 36 additional wells in 2016 and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. During second quarter 2016, BSP exercised their option to participate in 16 of these additional wells, including four that were already drilled. We expect total consideration for this transaction to be $175.0 million with approximately $110.0 million committed as of June 30, 2016. BSP has paid approximately $24.6 million for their interest in elected wells as of June 30, 2016. The remainder of the proceeds will be received 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 they participate. As of June 30, 2016, 18 of the 38 elected wells were in line and producing, seven wells were drilled and awaiting completion and four wells were awaiting pipeline connection. 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. Diversified Oil & Gas, LLC On May 20, 2016, we entered into a Purchase and Sale Agreement (“PSA”) with Diversified Oil and Gas, LLC (“DOG”). Pursuant to the PSA, DOG purchased all of our conventional operated oil and gas-related properties and related pipeline assets located in Pennsylvania and assumed all future abandonment liability associated with the assets. Closing occurred on May 20, 2016, with an effective date for the transaction of May 1, 2016. We received proceeds at closing of approximately $51,000. Included in the sale are approximately 300 wells, pipelines and support equipment . The sale of well properties generated Gain on Disposal of Assets Illinois Basin Operations As described in Note 3, Discontinued Operations/Assets Held for Sale

Recently Issued Accounting Pron

Recently Issued Accounting Pronouncements	6 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Recently Issued Accounting Pronouncements	5. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers Revenue Recognition 1) Identify the contract(s) with a customer. 2) Identify the performance obligations in the contract. 3) Determine the transaction price. 4) Allocate the transaction price to the performance obligations in the contract. 5) Recognize revenue when (or as) the entity satisfies a performance obligation. An entity should apply the amendments in this ASU using one of the following two methods: 1) Retrospectively to each prior reporting period presented. 2) Retrospectively with the cumulative effect of initially applying this ASU recognized at the date of the initial applications. In July 2015, the FASB approved a one-year deferral of the effective date of this new standard so the guidance is effective for the reporting period beginning January 1, 2018, with early adoption permitted in the first quarter 2017. We are currently evaluating the new guidance and have not determined the impact this standard may have on our Consolidated Financial Statements or decided upon the method of adoption. In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes In February 2016, the FASB issued 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 this guidance and do not believe it will have a material impact due to our minimal number of operating leases. In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting

Concentrations of Credit Risk

Concentrations of Credit Risk	6 Months Ended
	Jun. 30, 2016
Risks And Uncertainties [Abstract]
Concentrations of Credit Risk	6. 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 and lenders in our Senior Credit Facility (see Note 7, Long-Term Debt Derivative Instruments and Fair Value Measurements We also depend on a relatively small number of purchasers for a substantial portion of our revenue. For the six months ended June 30, 2016, approximately 95.3% of our commodity sales came from five purchasers, with the largest single purchaser accounting for 49.7% of commodity sales.

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Long-Term Debt	7. LONG-TERM DEBT Senior Credit Facility We maintain a revolving credit facility evidenced by a credit agreement, dated March 27, 2013 and most recently amended on July 1, 2016 (the “Senior Credit Facility”). As of June 30, 2016, the borrowing base under the Senior Credit Facility was $190.0 million. The Senior Credit Facility may be increased to up to $400.0 million upon redeterminations of the borrowing base, consent of the lenders and other conditions prescribed by the agreement. Within the Senior Credit Facility, a sub-facility exists for up to $60.0 million of letters of credit. Effective July 1, 2016, our borrowing base was reaffirmed at $190.0 million in connection with our scheduled redetermination. As of June 30, 2016, loans made under the Senior Credit Facility were set to mature on September 12, 2019. Our borrowing base is redetermined at least twice per year with the next redetermination scheduled to occur on or about October 1, 2016. In certain circumstances, we may be required to prepay the loans. Management does not believe that a prepayment will be required within the next twelve months. As of June 30, 2016, we had $146.7 million borrowings outstanding, and approximately $43.3 million in outstanding undrawn letters of credit. There were $111.5 million borrowings outstanding as of December 31, 2015. Our Senior Credit Facility restricts the amount of cash and cash equivalents that we can hold on our Consolidated Balance Sheet to a maximum of $15.0 million, with any excess to be used to pay down the outstanding Senior Credit Facility balance; however we retain the right to draw on the Senior Credit Facility so long as there are amounts available under our borrowing base. The Senior Credit Facility requires we meet, on a quarterly basis, financial requirements including a minimum consolidated current ratio and maximum net senior secured debt to EBITDAX ratio. EBITDAX is a non-GAAP financial measure used by our management team and by other users of our financial statements, such as our commercial bank lenders, which adds to or subtracts from net income the following expenses or income for a given period to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, depletion, amortization, unrealized gains and losses from derivatives, exploration expense and other similar non-cash activity. The Senior Credit Facility requires that as of the last day of any fiscal quarter, our ratio of consolidated current assets, including the unused portion of our borrowing base, as of such day to consolidated current liabilities as of such day, known as our current ratio, must not be less than 1.0 to 1.0. Our current ratio as of June 30, 2016 was approximately 0.8 to 1.0. Due to our expectation that we would not be in compliance with the current ratio, we received a waiver of this requirement from our lenders for the period ended June 30, 2016 in conjunction with the most recent redetermination. We expect to be in compliance with the current ratio covenant at September 30, 2016 and beyond. Additionally, as of the last day of any fiscal quarter, our ratio of net senior secured debt to EBITDAX for the trailing twelve months must not exceed 2.75 to 1.0. Our ratio of net senior secured debt to EBITDAX as of June 30, 2016 was approximately 2.4 to 1.0. In conjunction with the most recent redetermination, our lenders also added a requirement that beginning September 30, 2016, our ratio of “Total PDP PV-9” at the “Forward Strip Commodity Price” as of each date of determination to “Net Senior Secured Debt” (all terms in quotations as defined in the credit agreement) (the “PDP Coverage Ratio”) be at least 1.65 to 1.0. Additionally, requirements were added that limit our aggregate net capital expenditures during fiscal years 2016 and 2017 to $65 million on a rolling 12 month basis unless our PDP Coverage Ratio exceeds 2.0 to 1.0. Management currently anticipates being in compliance with these covenants at September 30, 2016 and beyond. In order to improve our liquidity positions to meet the financial requirements under our Senior Credit Facility and to meet other outstanding obligations, we are currently pursuing or considering a number of actions, which in certain cases may involve current investors, affiliates of the Company, or other financing or strategic counterparties, including (i) debt-for-debt or debt-for-equity exchanges, (ii) joint venture opportunities, (iii) minimizing capital expenditures, (iv) asset sales, (v) improving cash flows from operations, (vi) effectively managing working capital, (vii) adding hedging positions, and (viii) in- and out-of-court restructuring transactions. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions or that these transactions can be consummated within the period needed to meet our obligations. 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”). 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 Senior Secured Second Lien Notes (the “New Notes”) and (ii) 10.1 million shares of our common stock (the “Shares”). We accounted for these transactions as troubled debt restructurings. As a result of the troubled debt exchanges, the future undiscounted cash flows of the New Notes are greater than the net carrying value of the Existing Notes. As such, no gain has been recognized within our GAAP basis financial statements and a new effective interest rate has been established. See Note 9, Income Taxes In exchange for $324.0 million in aggregate principal amount of the 2020 Notes, representing approximately 92.6% of the outstanding aggregate principal amount of the 2020 Notes, and $309.1 million in aggregate principal amount of the 2022 Notes, representing approximately 95.1% of the outstanding aggregate principal amount of the 2022 Notes, we issued (i) $633.2 million aggregate principal amount of New Notes and (ii) 8.4 million shares, which had a fair value of $6.5 million upon issuance. An additional $0.5 million aggregate principal amount of New Notes were issued to holders who were ineligible to accept Shares. In addition, upon closing, we paid in cash accrued and unpaid interest on the Existing Notes accepted in the Exchange from the applicable last interest payment date totaling approximately $12.8 million. The remaining Existing Notes will continue to accrue interest at their historical rates. The New Notes will bear interest at a rate of 1.0% per annum for the first three semi-annual interest payments after issuance and 8.0% per annum thereafter, payable in cash. Interest payments are due on April 1 and October 1 of each year, beginning October 1, 2016 and ending October 1, 2020. In connection with the Exchange, we incurred approximately $0.5 million and $9.0 million in third-party debt issuance costs, in the three and six-month periods ending June 30, 2016, respectively. These costs were recorded as Debt Exchange Expense in our Consolidated Statement of Operations. Following the completion of the Exchange, we entered into debt-for equity exchanges with certain holders of our Existing Notes, as well as holders of our New Notes, in exchange for unrestricted shares of our common stock. These exchanges resulted in the retirement of $26.9 million of our outstanding Existing Notes and $2.2 million of our outstanding New Notes, in exchange for the issuance of a total of approximately 5.2 million shares of unrestricted common stock. The exchanged notes were subsequently cancelled, resulting in a gain to the company of approximately $23.7 million, presented as Gain on Extinguishment of Debt in our Consolidated Statement of Operations for the three and six month periods ending June 30, 2016. We may redeem, at specified redemption prices, some or all of the New Notes at any time on or after April 1, 2018. We may also redeem up to 35% of the New Notes using the proceeds of certain equity offerings completed before April 1, 2018. If we sell certain of our assets or experience specific kinds of changes in control, we may be required to offer to purchase the Existing Notes and the New Notes from the holders. Our Existing Notes and New Notes (collectively, the “Senior Notes”) are recorded as Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets. The Senior Notes are represented 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 Senior Notes or are otherwise excepted or permitted. Certain of the limitations in the Indentures, including our ability to incur debt, pay dividends or make other restricted payments, become more restrictive in the event our ratio of consolidated cash flow to fixed charges for the most recent trailing four quarters (the “Fixed Charge Coverage Ratio”) is less than 2.25 to 1.00. As of June 30, 2016, our Fixed Charge Coverage Ratio was 1.16 to 1.00. We expect our Fixed Charge Coverage Ratio to improve in 2016 based on our projections of decreased interest expense related to the New Notes. As of June 30, 2016, we were limited to incurring an additional $148.6 million in debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default. In certain circumstances, the individual Trustees or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately. As of June 30, 2016 and December 31, 2015, we had recorded on our Consolidated Balance Sheets approximately $1.5 million and $2.3 million, respectively, of a net premium related to the Senior Notes. The amortization of our net premium during the three and six-month periods ended June 30, 2016, which follows the effective interest method, was approximately $0.1 million and $0.2 million, respectively, and was recorded as a credit to Interest Expense on our Consolidated Statements of Operations. . In addition to the Senior Credit Facility and the Senior Notes, we may, from time to time in the normal course of business finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and other obligations consisted of the following at June 30, 2016 and December 31, 2015: ($ in Thousands) June 30, 2016 (Unaudited) December 31, 2015 Senior Notes, Net of Issuance Costs (a) $ 637,314 $ 663,089 Premium on Senior Notes, Net 1,524 2,344 Senior Line of Credit, Net of Issuance Costs (b)(c) 141,237 109,396 Capital Leases and Other Obligations(c) 172 419 Total Debt 780,247 775,248 Less Current Portion of Long-Term Debt (172 ) (402 ) Total Long-Term Debt $ 780,075 $ 774,846 (a) Includes unamortized debt issuance costs of approximately $9.1 million and $11.9 million as of June 30, 2016 and December 31, 2015, respectively. (b) Includes unamortized debt issuance costs of approximately $5.4 million and $2.1 million as of June 30, 2016 and December 31, 2015, respectively. (c) The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. The weighted average interest rate on borrowings under our Senior Credit Facility for the six months ended June 30, 2016 and the year ended December 31, 2015, was approximately 3.2 % and 1.7%, respectively. The average interest rate on our capital leases and other obligations for the six months ended June 30, 2016 and the year ended December 31, 2015, was approximately 4.5% The following is the principal maturity schedule for debt outstanding as of June 30, 2016: 2016 $ 165 2017 7 2018 — 2019 146,670 2020 640,251 Thereafter 6,160 Total (a) $ 793,253 (a) Excludes $1.5 million net premium on Senior Notes and $14.5 million in debt issuance costs

Derivative Instruments And Fair

Derivative Instruments And Fair Value Measurements	6 Months Ended
	Jun. 30, 2016
Fair Value Of Financial Instruments And Derivative Instruments [Abstract]
Derivative Instruments And Fair Value Measurements	8. 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 oil, natural gas and NGL 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, 2016 and December 31, 2015, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, swaptions, deferred put spreads, cap swaps, calls, 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. We enter into the majority of our derivative arrangements with five 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 received net cash settlements of $17.4 As of June 30, 2016, we had over 100.0% of our annualized condensate production hedged through the remainder of 2016, over 90.0% and 50.0% of our annualized natural gas production hedged through the remainder of 2016 and 2017, respectively, and over 50.0% of our annualized NGL production hedged through the remainder of 2016. These percentages exclude the effects of our Illinois Basin production and basis swaps and do not include any estimated impact of increased production from future drilling and completion or the natural decline of our natural gas, condensate and NGL production. Interest Rate Derivatives We are exposed to interest rate risk on our long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in the market interest rates which are lower than our current fixed rate. Variable rate debt, where the interest rate fluctuates, exposes us to changes in market interest rates, which may increase over time. As of June 30, 2016, and December 31, 2015, we had $146.7 million and $111.5 million outstanding under our Senior Credit Facility, respectively, which is subject to variable rates of interest and $646.4 million of Senior Notes outstanding subject to fixed interest rates. See Note 7, Long-Term Debt As of June 30, 2016 and December 31, 2015, we did not have any interest rate derivatives outstanding. We utilize the mark-to-market accounting method to account for interest rate swap and swaptions. We recognize all gains and losses related to interest rate derivatives in the Consolidated Statements of Operations as Gain on Derivatives, Net under Other Expense. During the three and six months ended June 30, 2015, we received cash payments of approximately $0.4 million and $0.9 million, respectively, related to our interest rate swaps and swaptions. The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three and six months ended June 30, 2016 and 2015: For the Three Months Ended June 30, For the Six Months Ended June 30, ($ in Thousands) 2016 2015 2016 2015 Oil $ (2,494 ) $ (2,828 ) $ (2,169 ) $ 50 Natural Gas (18,666 ) 3,036 (13,302 ) 16,635 NGLs (8,093 ) (60 ) (9,714 ) 374 Refined Products 84 50 65 (6 ) Interest Rate — (479 ) — (215 ) Gain (Loss) on Derivatives, Net $ (29,169 ) $ (281 ) $ (25,120 ) $ 16,838 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 $19.7 million and a net asset of approximately $35.8 million at June 30, 2016 and December 31, 2015, respectively. Our open asset/(liability) financial commodity derivative instrument positions at June 30, 2016 consisted of: Period Volume Put Option Floor Ceiling Swap Fair Market Value ($ in Thousands) Oil 2016 - Collars 272,000 Bbls $ — $ 38.05 $ 49.15 $ — $ (956 ) 2016 - Three-Way Collars 150,000 Bbls 31.20 41.40 49.60 — (442 ) 2016 - Cap Swaps 60,000 Bbls 30.00 — — 44.00 (361 ) 482,000 Bbls $ (1,759 ) Natural Gas 2016 - Swaps 8,155,000 Mcf — — — 2.54 $ (3,475 ) 2016 - Swaptions 600,000 Mcf — — — 3.15 79 2016 - Cap Swaps 2,400,000 Mcf 2.59 — — 3.07 (612 ) 2016 - Collars 2,110,000 Mcf — 2.63 3.03 — (409 ) 2016 - Three-Way Collars 1,505,000 Mcf 2.11 2.68 3.30 — (377 ) 2016 - Put Spreads 6,015,000 Mcf 2.51 3.27 — — 760 2016 - Basis Swaps - Dominion South 11,113,000 Mcf — — — (0.88 ) (139 ) 2017 - Swaps 2,460,000 Mcf — — — 3.21 178 2017 - Swaptions 0 Mcf — — — — (670 ) 2017 - Cap Swaps 3,900,000 Mcf 2.35 — — 2.81 (1,559 ) 2017 - Three-Way Collars 16,900,000 Mcf 2.32 3.01 3.87 — 594 2017 - Calls 3,000,000 Mcf — — 3.64 — (1,277 ) 2017 - Collars 1,400,000 Mcf — 2.40 3.10 — (348 ) 2017 - Basis Swaps - Dominion South 4,550,000 Mcf — — — (0.83 ) (1,073 ) 2017 - Basis Swaps - Texas Gas 14,600,000 Mcf — — — (0.13 ) (372 ) 2018 - Swaps 960,000 Mcf — — — 3.25 495 2018 - Swaptions 0 Mcf — — — — (320 ) 2018 - Three-Way Collars 7,875,000 Mcf 2.29 2.88 3.56 — (755 ) 2018 - Calls 5,810,000 Mcf — — 3.97 — (485 ) 2018 - Basis Swaps - Dominion South 6,400,000 Mcf — — — (0.83 ) (1,073 ) 2018 - Basis Swaps - Texas Gas 14,600,000 Mcf — — — (0.13 ) (372 ) 2019 - Basis Swaps - Dominion South 7,300,000 Mcf — — — (0.83 ) (1,073 ) 2020 - Basis Swaps - Dominion South 7,320,000 Mcf — — — (0.83 ) (1,073 ) 128,973,000 Mcf $ (13,356 ) NGLs 2016 - C3+ NGL Swaps 714,000 Bbls — — — 26.04 $ (261 ) 2016 - Ethane Swaps 330,000 Bbls — — — 8.40 (766 ) 2017 - C3+ NGL Swaps 468,000 Bbls — — — 20.16 (2,228 ) 2017 - Ethane Swaps 540,000 Bbls — — — 10.08 (1,220 ) 2,052,000 Bbls $ (4,475 ) Refined Product (Heating Oil) 2016 - Swaps 6,000 Bbls $ — $ — $ — $ 84.00 $ (117 ) 6,000 Bbls $ (117 ) 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, 2016 and December 31, 2015 is summarized below: June 30, December 31, ($ in Thousands) 2016 2015 Short-Term Derivative Assets: Crude Oil—Collars $ — $ 1,078 Crude Oil—Deferred Put Spread — 852 Crude Oil—Three-Way Collars 355 577 NGL—Swaps 1,127 10,250 Natural Gas—Swaps 879 9,010 Natural Gas—Cap Swaps 334 1,977 Natural Gas—Basis Swaps 397 70 Natural Gas—Three-Way Collars 783 6,183 Natural Gas—Collars — 1,728 Natural Gas—Swaption 79 798 Natural Gas—Put Spread 806 1,737 Total Short-Term Derivative Assets $ 4,760 $ 34,260 Long-Term Derivative Assets: NGL—Swaps $ — $ 344 Natural Gas—Cap Swaps — 2,294 Natural Gas—Swaps 743 1,593 Natural Gas—Basis Swaps — 195 Natural Gas—Three-Way Collars 783 5,108 Total Long-Term Derivative Assets $ 1,526 $ 9,534 Total Derivative Assets $ 6,286 $ 43,794 Short-Term Derivative Liabilities: Crude Oil—Three-Way Collars (797 ) — Crude Oil—Collars (956 ) — Crude Oil—Deferred Put Spread (361 ) — NGL—Swaps (3,878 ) — Refined Product—Swaps (117 ) (376 ) Natural Gas—Three-Way Collars (973 ) (31 ) Natural Gas—Collars (558 ) — Natural Gas—Basis Swaps (1,258 ) (1,585 ) Natural Gas—Put Spread (46 ) — Natural Gas—Call (639 ) — Natural Gas—Swaption (326 ) (202 ) Natural Gas—Swaps (4,323 ) (292 ) Natural Gas—Cap Swaps (1,670 ) — Total Short - Term Derivative Liabilities $ (15,902 ) $ (2,486 ) Long-Term Derivative Liabilities: NGL—Swaps (1,724 ) — Natural Gas—Swaps (101 ) — Natural Gas—Swaption (664 ) (297 ) Natural Gas—Basis Swaps (4,314 ) (4,186 ) Natural Gas—Collars (199 ) — Natural Gas—Call (1,123 ) (989 ) Natural Gas—Cap Swaps (835 ) — Natural Gas—Three-Way Collars (1,131 ) (84 ) Total Long-Term Derivative Liabilities $ (10,091 ) $ (5,556 ) Total Derivative Liabilities $ (25,993 ) $ (8,042 ) 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 comprised of our derivative contracts, excluding our basis swap derivatives, and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, interest rates and discount rates, or can be confirmed from other active markets. The fair values recorded as of June 30, 2016 and December 31, 2015, were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party. Our Level 3 fair value measurements are comprised of our natural gas basis swap contracts. The fair values recorded as of June 30, 2016 and December 31, 2015, were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party. The significant unobservable input used in the fair value measurement of our natural gas basis swaps was the estimate of future natural gas basis differentials. Significant variations in price differentials could result in a significantly different fair value measurement. The significant unobservable inputs and the range and weighted average of these inputs used in the fair value measurements of our natural gas basis swaps as of June 30, 2016 and December 31, 2015 are included in the table below. As of June 30, 2016 Range (price per Mcf) Weighted Average (price per Mcf) Fair Value (in thousands) Natural Gas Basis Differential Forward Curve - Dominion South ($0.34) - ($1.17) $ (0.72 ) $ (4,431 ) Natural Gas Basis Differential Forward Curve - Texas Gas ($0.08) - ($0.12) $ (0.10 ) $ (744 ) As of December 31, 2015 Range (price per Mcf) Weighted Average (price per Mcf) Fair Value (in thousands) Natural Gas Basis Differential Forward Curve - Dominion South ($0.27) - ($1.08) $ (0.74 ) $ (5,468 ) Natural Gas Basis Differential Forward Curve - Texas Gas ($0.05) - ($0.17) $ (0.12 ) $ (38 ) 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, 2016 and for the year ended December 31, 2015, 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, 2016 Using: ($ in Thousands) Total Carrying Value as of June 30, 2016 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ (19,707 ) $ — $ (14,532 ) $ (5,175 ) Fair Value Measurements at December 31, 2015 Using: ($ in Thousands) Total Carrying Value as of December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ 35,752 $ — $ 41,258 $ (5,506 ) 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 comprised 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, 2016 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 comprised 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, 2016 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 comprised 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, 2016 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. The table below sets forth a reconciliation of our commodity derivative contracts at fair value on a recurring basis using significant unobservable inputs (Level 3) during the six months ended June 30, 2016 and 2015: Six Months Ended June 30, ($ in Thousands) 2016 2015 Beginning Balance of Level 3 $ (5,506 ) $ 1,341 Changes in Fair Value (1,376 ) 3,367 Purchases — — Settlements Paid (Received) 1,707 (1,673 ) Ending Balance of Level 3 $ (5,175 ) $ 3,035 Changes in fair value on our Level 3 commodity derivative contracts outstanding for the six months ended June 30, 2016 and 2015, resulted in a decrease of approximately $1.4 million and an increase of approximately $3.4 million, respectively. These amounts have been included in Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations. Future Abandonment Cost We report the fair value of asset retirement obligations on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 2, Future Abandonment Costs, Financial Instruments Not Recorded at Fair Value The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements: June 30, 2016 December 31, 2015 ($ in Thousands) Carrying Amount Fair Value Carrying Amount Fair Value Senior Notes, Net of Issuance Costs $ 637,314 $ 113,721 $ 663,089 $ 137,402 Secured Line of Credit, Net of Issuance Costs 141,237 141,237 109,396 109,396 Capital Leases and Other Obligations 172 172 419 411 Total $ 778,723 $ 255,130 $ 772,904 $ 247.209 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, 2016, we recorded an other than temporary impairment of $35.8 million related to proved and unproved properties. We utilize quoted futures prices and other observable market data in determining the fair value. The inputs used in determining fair value as a part of the impairment expense calculation are considered to be Level 2 within the fair value hierarchy. For additional information on our impairment expense, see Note 15, Impairment Expense

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Income Taxes	9. 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) 2016 2015 2016 2015 Income Tax (Expense) Benefit $ 393 $ - $ (2,321 ) $ - Effective Tax Rate 0.7 % 0.0 % -2.2 % 0.0 % For the six months ended June 30, 2016 and 2015, our overall effective tax rate on pre-tax income from continuing operations was different than the statutory rate of 35% due to the recording of a valuation allowance. As of June 30, 2016 and 2015, we had a significant level of estimated future tax benefits that, given our past and future expectations of net losses, we do not expect to be able to fully utilize, thus limiting our ability to recognize future tax benefits. As a result of the Senior Note Exchange completed on March 31, 2016, we generated approximately $543.2 million of taxable Cancellation of Debt Income (“CODI”) income, which is calculated by comparing the fair value of the New Notes and the face value of the Existing Notes exchanged. In the second quarter of 2016, we completed debt-to-equity exchanges with certain holders of our Senior Notes, resulting in taxable losses and reductions of our current year CODI income of approximately $2.0 million. See Note 7, Long-Term Debt Income tax payments made during the six months ended June 30, 2016 and 2015 were negligible. Tax refunds received during the six months ended June 30, 2016 were negligible, and refunds of approximately $0.5 million were received during the six months ended June 30, 2015.

Capital Stock

Capital Stock	6 Months Ended
	Jun. 30, 2016
Equity [Abstract]
Capital Stock	10. CAPITAL STOCK Common Stock On May 27, 2016, the Company’s common shareholders approved an increase in the number of authorized shares from 100,000,000 to 200,000,000 common shares. As of June 30, 2016, we have authorized capital stock of 200,000,000 shares of common stock and 100,000 shares of preferred stock. As of June 30, 2016 and December 31, 2015, shares of common stock issued and outstanding totaled 78,440,589 and 55,741,229, respectively. During the six-month period ending June 30, 2016, we issued approximately 8.4 million shares of our common stock in conjunction with the Exchange completed on March 31, 2016, and approximately 5.2 million shares of our common stock in debt-to-equity exchanges with certain holders of our Senior Notes. See Note 7, Long-Term Debt Preferred Stock As of June 30, 2016 and December 31, 2015, shares of our 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (“Series A Preferred Stock”) issued and outstanding totaled 4,087 and 16,100, respectively. During the six months ended June 30, 2016, 12,013 shares of Series A Preferred Stock were converted into approximately 9.0 million shares of common stock pursuant to the terms of the Series A Preferred Stock, and through negotiated exchanges with certain holders of the Series A Preferred Shares. See Note 13, Earnings Per Common Share 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. No dividend has been declared by our board of directors in 2016. As of June 30, 2016 accumulated dividends in arrears totaled $3.8 million. While the accumulation does not result in the presentation of a liability on the Consolidated Balance Sheets, the accumulated dividends are added to our Net Loss in the determination of Loss Attributable to Common Shareholders and related loss per share calculations. In 2015, we paid quarterly cash dividends of $150.00 per share for the periods of November 15, 2014 to February 15, 2015, February 15, 2015 to May 15, 2015, May 15, 2015 to August 15, 2015, and August 15, 2015 to November 15, 2015, respectively, each in the aggregate amount of $2.4 million. If we do not pay dividends for an aggregate of six quarterly periods, 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.

Employee Benefit and Equity Pla

Employee Benefit and Equity Plans	6 Months Ended
	Jun. 30, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Employee Benefit and Equity Plans	11. 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-month period ended June 30, 2016, we issued 888,922 options to purchase shares of our common stock to 34 employees. During the six-month period ended June 30, 2015, we issued 80,000 options to purchase shares of our common stock to 3 employees. Stock-based compensation expense relating to stock options outstanding for each of the three and six months ended June 30, 2016 and 2015 was $0.1 million. Stock-based compensation relating to stock options outstanding for the three and six month periods ended June 30, 2015 was negligible. 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 for the six months ended June 30, 2016. There was no tax benefit related to stock option exercises for each of the six-month periods ended June 30, 2016 and 2015. A summary of the status of our issued and outstanding stock options as of June 30, 2016 is as follows: Outstanding Exercisable Exercise Price Number Outstanding At 6/30/16 Weighted-Average Exercise Price Number Exercisable At 6/30/16 Weighted-Average Exercise Price $ 0.97 37,500 $ 0.97 — $ 0.97 $ 1.69 826,800 $ 1.69 — $ 1.69 $ 4.05 40,000 $ 4.05 — $ 4.05 $ 4.90 40,000 $ 4.90 3,333 $ 4.90 $ 5.04 46,041 $ 5.04 46,041 $ 5.04 $ 9.50 75,000 $ 9.50 75,000 $ 9.50 $ 9.99 129,583 $ 9.99 129,583 $ 9.99 $ 10.42 29,548 $ 10.42 29,548 $ 10.42 $ 13.19 50,000 $ 13.19 50,000 $ 13.19 $ 22.34 30,000 $ 22.34 30,000 $ 22.34 1,304,472 $ 4.35 363,505 $ 10.71 The weighted average remaining contractual term for options outstanding at June 30, 2016 was 5.2 years and there was no aggregate intrinsic value. The weighted average remaining contractual term for options exercisable at June 30, 2016 was 1.5 years and there was no aggregate intrinsic value. As of June 30, 2016, unrecognized compensation expense related to stock options was $0.5 million. Restricted Stock Awards During the six-month period ended June 30, 2016, the Compensation Committee approved the issuance of an aggregate of 428,826 shares of restricted common stock to 25 employees. During the six-month period ended June 30, 2015, the Compensation Committee approved the issuance of an aggregate of 1,351,497 shares of restricted stock to 127 employees, one director and one non-employee contractor. 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 December 31, 2015 was $2.56 per share. Year Ended December 31, 2015 Expected Dividend Yield 0.0 % Risk-Free Interest Rate 1.0 % Expected Volatility – Rex Energy 58.6 % Expected Volatility – Peer Group 29.8%-85.0% Market Index 35.6 % Expected Life Three Years Compensation expense from restricted stock awards associated with our continuing operations totaled $1.1 million and $0.9 million for the three and six-month periods ended June 30, 2016, respectively, and $1.8 million and $4.6 million for the three and six-month periods ended June 30, 2015, respectively. During the first quarter of 2016, 235,573 performance stock awards were forfeited due to not meeting specified targets, which resulted in a one-time reduction to expense of approximately $1.5 million. During the first quarter of 2015, the board of directors approved a waiver to certain performance factors for restricted stock awards that vested in March 2015. This waiver resulted in the vesting of 189,872 restricted stock awards with associated expense of approximately $2.5 million. As of June 30, 2016, total unrecognized compensation cost related to restricted common stock grants was approximately $2.8 million, which will be recognized over a weighted average period of 1.3 years. A summary of the restricted stock activity for the six months ended June 30, 2016 is as follows: Number of Shares Weighted-Average Grant Date Fair Value Restricted stock awards, as of December 31, 2015 2,479,408 $ 6.27 Awards 428,826 1.65 Forfeitures (381,437 ) 7.44 Vested (245,468 ) 10.67 Restricted stock awards, as of June 30, 2016 2,281,329 $ 4.74

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2016
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	12. 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. Other then as set forth below, there have been no significant changes with respect to the legal matters disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015. In October 2011, we were named as defendants in a proposed class action lawsuit filed in the Court of Common Pleas of Clearfield County, Pennsylvania (the “Cardinale case”). The named plaintiffs are two individuals who have sued on behalf of themselves and all persons who are alleged to be similarly situated. The complaint in the Cardinale case generally asserts that a binding contract to lease oil and gas interests was formed between the Company and each proposed class member when representatives of Western Land Services, Inc. (“Western”), a leasing agent that we engaged, presented a form of proposed oil and gas lease and an order for payment to each person in 2008, and each person signed the proposed oil and gas lease form and order for payment and delivered the documents to representatives of Western. We rejected these leases and never signed them on behalf of the Company. The plaintiffs seek a judgment declaring the rights of the parties with respect to those proposed leases, as well as damages and other relief as may be established by plaintiffs at trial, together with interest, costs, expenses and attorneys’ fees. We filed affirmative defenses and preliminary objections to the plaintiff’s claims, and the parties each made various responsive filings throughout the first quarter of 2012. In May 2012, the trial court dismissed the Cardinale case with prejudice on the grounds that there was no contract formed between us and the plaintiffs. The plaintiffs appealed the dismissal during the second half of 2012. In May 2013, the Superior Court reversed the decision of the Common Pleas Court and remanded the case for further proceedings. In July 2012, while the Cardinale case was in the midst of the appeals process, counsel for the plaintiffs in the Cardinale case filed two additional lawsuits against us in the Court of Common Pleas of Clearfield County, Pennsylvania: one a proposed class action lawsuit with a different named plaintiff (the “Billotte case”) and another on behalf of a group of individually named plaintiffs (the “Meeker case”). The complaint for the Billotte case contained the same claims as those set forth in the Cardinale case. The Meeker case is not a class action, but the claims are similar to those in Cardinale and the plaintiffs would be included in a class under Cardinale and Billotte if one were certified. These two additional lawsuits were filed for procedural reasons in light of the dismissal of the Cardinale case and the pendency of the appeal. Proceedings in both the Billotte and Meeker cases were stayed pending the outcome of the appeal in the Cardinale case. When the Cardinale case was remanded, we agreed to consolidate the Billotte and Cardinale cases; the cases have proceeded as Cardinale. The Meeker case remains stayed, and has not been consolidated. In June 2015, the trial court conducted a hearing on plaintiff’s motion for certification of a class in the Cardinale case. In July 2015, the trial court denied plaintiffs’ motion for class certification. Plaintiffs served notice of their appeal of that decision in August 2015 and filed the appeal in September 2015. In June 2016, we and the plaintiffs each presented our arguments on the appeal before a three-judge panel of the Pennsylvania Superior Court. To date, the court has not ruled on the appeal. We expect to receive the court’s ruling on the appeal in the second half of 2016. We continue to vigorously defend against each of these claims. At this time we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses, if any. 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, 2016, we know of no significant probable or possible environmental contingent liabilities. Letters of Credit At June 30, 2016, we had posted $43.3 million in various letters of credit to secure our drilling and related operations. Lease Commitments As of June 30, 2016, 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, 2016, was approximately $0.3 million and $0.6 million, respectively, and $0.3 million and $0.5 million for the three and six months ended June 30, 2015, respectively. Lease commitments by year for each of the next five years are presented in the table below: ($ in Thousands) 2016 $ 506 2017 997 2018 565 2019 563 2020 422 Thereafter — Total $ 3,053 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 $7.3 million in 2016, $16.5 million in 2017, $16.5 million in 2018, $16.5 million in 2019, $16.5 million in 2020 and $97.6 million thereafter, assuming our average net revenue interest in the region of approximately 53%. Charges incurred for unutilized processing capacity with MarkWest during the three and six-month periods ended June 30, 2016 were $0.8 million and $1.4 million, respectively, and $0.2 million and $0.4 million for the three and six-month periods ended June 30, 2015, respectively. Operational Commitments We have contracted drilling rig services on one rig to support our Appalachian Basin operations. The minimum cost to retain this rig would require gross payments of approximately $1.1 million in 2016, $2.3 million in 2017 and $0.3 million in 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 $414.0 million through 2029. For the three and six months ended June 30, 2016 and 2015, we incurred expenses related to the transportation, processing and marketing of our natural gas, condensate and NGLs of approximately $21.8 million and $43.3 million in 2016, respectively, and $20.5 million and $39.4 million in 2015, 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, 2016 and 2015, we incurred approximately $0.7 million and $1.0 million in 2016, respectively, and $0.2 million and $0.4 million in 2015, respectively, in fees related to unutilized capacity commitments. The unutilized commitment fees are related to undeveloped properties that we acquired during 2014. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows: ($ in Thousands) Total 2016 $ 15,342 2017 43,885 2018 47,328 2019 47,216 2020 46,060 Thereafter 528,816 Total $ 728,647 Pennsylvania Impact Fee In 2012, Pennsylvania state legislators 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. The fee for each unconventional gas well is determined using the following matrix, with vertical unconventional gas wells being charged 20% of the applicable rates: <$2.25(a) $2.26 - $2.99(a) $3.00 - $4.99(a) $5.00 - $5.99(a) >$5.99(a) Year One $ 40,200 $ 45,300 $ 50,300 $ 55,300 $ 60,400 Year Two $ 30,200 $ 35,200 $ 40,200 $ 45,300 $ 55,300 Year Three $ 25,200 $ 30,200 $ 30,200 $ 40,200 $ 50,300 Year 4 – 10 $ 10,100 $ 15,100 $ 20,100 $ 20,100 $ 20,100 Year 11 – 15 $ 5,000 $ 5,000 $ 10,100 $ 10,100 $ 10,100 (a ) All fees owed are due on April 1 of each year. For the three and six months ended June 30, 2016 and 2015, we recorded expense of approximately $0.8 million and $1.3 million in 2016, respectively, and $0.8 million and $1.5 million in 2015, respectively.

Earnings Per Common Share

Earnings Per Common Share	6 Months Ended
	Jun. 30, 2016
Earnings Per Share [Abstract]
Earnings Per Common Share	13. 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 each of the three and six months ended June 30, 2016 and 2015, we excluded stock options to purchase 1.3 million shares and 0.5 million shares of our common stock, respectively, due to our Net Loss from Continuing Operations. For the three and six months ended June 30, 2016 and 2015, we excluded performance-based restricted stock of 0.7 million shares and 1.3 million 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: 2016 2015 2016 2015 Net Loss From Continuing Operations $ (52,911 ) $ (151,342 ) $ (105,562 ) $ (166,335 ) Net Loss From Discontinued Operations, Less Noncontrolling Interests (1,683 ) (1,410 ) (9,173 ) (4,231 ) Less: Preferred Stock Dividends (1,723 ) (2,415 ) (3,828 ) (4,830 ) Effect of Preferred Stock Conversions 72,316 — 72,316 — Net Income (Loss) Attributable to Common Shareholders $ 15,999 $ (155,167 ) $ (46,247 ) $ (175,396 ) Denominator: Weighted Average Common Shares Outstanding - Basic 71,804 54,118 64,044 54,090 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 71,804 54,118 64,044 54,090 Earnings per Common Share Attributable to Rex Energy Common Shareholders: Basic — Net Income (Loss) From Continuing Operations $ 0.24 $ (2.84 ) $ (0.58 ) $ (3.16 ) — Net Loss From Discontinued Operations (0.02 ) (0.03 ) (0.14 ) (0.08 ) — Net Income (Loss) Attributable to Rex Energy Common Shareholders $ 0.22 $ (2.87 ) $ (0.72 ) $ (3.24 ) Diluted — Net Income (Loss) From Continuing Operations $ 0.24 $ (2.84 ) $ (0.58 ) $ (3.16 ) — Net Loss From Discontinued Operations (0.02 ) (0.03 ) (0.14 ) (0.08 ) — Net Income (Loss) Attributable to Rex Energy Common Shareholders $ 0.22 $ (2.87 ) $ (0.72 ) $ (3.24 )

Equity Method Investments

Equity Method Investments	6 Months Ended
	Jun. 30, 2016
Equity Method Investments And Joint Ventures [Abstract]
Equity Method Investments	14. EQUITY METHOD INVESTMENTS RW Gathering, LLC We own a 40% non-operated interest in RW Gathering, LLC (“RW Gathering”), which owns gas-gathering assets to facilitate development in our natural gas operations. During the second quarter of 2015 we incurred a 100% impairment charge of $17.5 million related to RW Gathering. We did not make any capital contributions to RW Gathering during the first six months of 2016 and 2015. RW Gathering recorded net losses from continuing operations of $0.5 million and $1.0 million during the three and six-month periods ended June 30, 2016, respectively, as compared to losses of $0.5 million and $1.0 million for the comparable periods in 2015. The losses incurred were due to insurance fees, bank fees, rent expenses and depreciation expense. Historically, we recorded our share of the net losses on the Statements of Operations as Loss on Equity Method Investments. As of June 30, 2015, we discontinued applying the equity method of accounting for our share of net losses due to our investment being reduced to zero. During the three and six-month periods ended June 30, 2016 we incurred approximately $0.1 million and $0.3 million, respectively, as compared to $0.2 million and $0.4 million for the three and six-month periods ended June 30, 2015, respectively, 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 June 30, 2016 and December 31, 2015, there were no receivables or payables due between RW Gathering and us.

Impairment Expense

Impairment Expense	6 Months Ended
	Jun. 30, 2016
Goodwill And Intangible Assets Disclosure [Abstract]
Impairment Expense	15. IMPAIRMENT EXPENSE For the three and six months ended June 30, 2016, impairment expenses incurred were approximately $25.1 million and $35.8 million, respectively, and impairment expenses incurred for the three and six-month periods ended June 30, 2015 were approximately $117.8 million and $124.7 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 2016 included approximately $34.8 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 Butler County operations totaled approximately $1.0 million during the first six months of 2016. 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, 2016, we continued to carry the costs of undeveloped properties of approximately $232.7 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale and for which we have development, trade or lease extension plans. The expense incurred during the first six months of 2015 included proved properties in our non-operated dry gas regions of Clearfield County, Pennsylvania and Westmoreland County, Pennsylvania for approximately $73.4 million. In addition to the proved properties, we also incurred approximately $31.6 million in impairment related to unproved properties, the majority of which are also found in our non-operated dry gas regions of Clearfield and Westmoreland Counties, Pennsylvania, and $17.5 million related to our equity method investment in RW Gathering. The remaining 2015 impairments are primarily related to acreage expirations and pipelines in non-core areas.

Exploration Expense

Exploration Expense	6 Months Ended
	Jun. 30, 2016
Extractive Industries [Abstract]
Exploration Expense	16. EXPLORATION EXPENSE For the three and six months ended June 30, 2016, we incurred approximately $0.8 million and $1.7 million, respectively, in exploration expenses as compared to $0.8 million and $1.2 million in exploration expenses for the same periods in 2015, respectively. Approximately $0.9 million of the expense incurred in 2016 was due to geological and geophysical type expenditures and the remaining $0.8 million was due to costs associated with exploratory wells that were abandoned at various stages resulting in dry hole expense. Approximately $0.5 million of the expense incurred in 2015 was due to geological and geophysical type expenditures. An additional $0.5 million of expense was incurred through the payment of delay rentals, and the remaining 2015 expense of $0.2 million was due to costs associated with exploratory wells that were abandoned at various stages resulting in dry hole expense.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	6 Months Ended
	Jun. 30, 2016
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Financial Information	17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION As of June 30, 2016, we had an aggregate of $646.4 million of outstanding Senior Notes, as shown in Note 7, Long-Term Debt — Rex Energy I, LLC — Rex Energy Operating Corporation — Rex Energy IV, LLC — PennTex Resources Illinois, Inc. — R.E. Gas Development, LLC The non-guarantor subsidiaries include certain consolidated subsidiaries, including R.E. Disposal, LLC, Rex Energy Marketing, LLC and R.E. Ventures Holdings, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of June 30, 2016, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries. The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the notes, (ii) the combined Guarantors, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of June 30, 2016 and December 31, 2015, the condensed consolidating statements of operations for each of the three and six-month periods ended June 30, 2016 and 2015, and the condensed consolidating statements of cash flows for each of the six-month periods ended June 30, 2016 and 2015. REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF JUNE 30, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 3,435 $ — $ 3 $ — $ 3,438 Accounts Receivable 27,694 — 3,950 — 31,644 Taxes Receivable — — 48 — 48 Short-Term Derivative Instruments 4,760 — — — 4,760 Inventory, Prepaid Expenses and Other 1,688 — — — 1,688 Assets Held for Sale 45,466 1,083 — — 46,549 Total Current Assets 83,043 1,083 4,001 — 88,127 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,020,936 — — 1,020,936 Unevaluated Oil and Gas Properties 232,674 — — — 232,674 Other Property and Equipment 21,444 — — — 21,444 Wells and Facilities in Progress 75,992 — — — 75,992 Pipelines 14,144 — — — 14,144 Total Property and Equipment 1,365,190 — — — 1,365,190 Less: Accumulated Depreciation, Depletion and Amortization (459,427 ) — — — (459,427 ) Net Property and Equipment 905,763 — — — 905,763 Other Assets 2,490 — — — 2,490 Intercompany Receivables — — 1,071,155 (1,071,155 ) — Investment in Subsidiaries – Net (2,388 ) — (127,974 ) 130,362 — Long-Term Derivative Instruments 1,526 — — — 1,526 Total Assets $ 990,434 $ 1,083 $ 947,182 $ (940,793 ) $ 997,906 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 51,915 $ — $ — $ — $ 51,915 Current Maturities of Long-Term Debt 172 — — — 172 Accrued Liabilities 24,498 — 5,848 30,346 Short-Term Derivative Instruments 15,902 — — — 15,902 Liabilities Related to Assets Held for Sale 39,903 32 — — 39,935 Total Current Liabilities 132,390 32 5,848 — 138,270 Long-Term Derivative Instruments 10,091 — — — 10,091 Senior Secured Line of Credit and Other Long-Term Debt, Net of Issuance Costs — — 141,237 — 141,237 Senior Notes, Net of Issuance Costs — — 637,314 — 637,314 Premium on Senior Notes – Net — — 1,524 — 1,524 Other Deposits and Liabilities 2,860 — — — 2,860 Future Abandonment Cost 7,313 418 — — 7,731 Intercompany Payables 1,066,506 4,649 — (1,071,155 ) — Total Liabilities 1,219,160 5,099 785,923 (1,071,155 ) 939,027 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 77 — 77 Additional Paid-In Capital 177,144 — 637,223 (177,144 ) 637,223 Accumulated Earnings (Deficit) (405,870 ) (4,016 ) (476,042 ) 307,506 (578,422 ) Total Stockholders’ Equity (228,726 ) (4,016 ) 161,259 130,362 58,879 Total Liabilities and Stockholders’ Equity $ 990,434 $ 1,083 $ 947,182 $ (940,793 ) $ 997,906 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, Condensate and NGL Sales $ 31,271 $ — $ — $ — $ 31,271 Other Revenue (Expense) (6 ) — — — (6 ) TOTAL OPERATING REVENUE 31,265 — — — 31,265 OPERATING EXPENSES Production and Lease Operating Expense 25,221 — — — 25,221 General and Administrative Expense 3,661 — 1,176 — 4,837 Gain on Disposal of Assets (4,307 ) — — — (4,307 ) Impairment Expense 25,139 — — — 25,139 Exploration Expense 803 — — — 803 Depreciation, Depletion, Amortization and Accretion 14,747 3 — — 14,750 Other Operating Expense 704 — — — 704 TOTAL OPERATING EXPENSES 65,968 3 1,176 — 67,147 LOSS FROM OPERATIONS (34,703 ) (3 ) (1,176 ) — (35,882 ) OTHER INCOME (EXPENSE) Interest Expense (269 ) — (11,170 ) — (11,439 ) Loss on Derivatives, Net (29,169 ) — — — (29,169 ) Other Income 12 — — — 12 Debt Exchange Expense — — (533 ) — (533 ) Gain on Extinguishment of Debt — — 23,707 — 23,707 Income (Loss) From Equity in Consolidated Subsidiaries (54 ) 54 (65,341 ) 65,341 — TOTAL OTHER INCOME (EXPENSE) (29,480 ) 54 (53,337 ) 65,341 (17,422 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (64,183 ) 51 (54,513 ) 65,341 (53,304 ) Income Tax (Expense) Benefit 473 — (80 ) — 393 NET INCOME (LOSS) FROM CONTINUING OPERATIONS (63,710 ) 51 (54,593 ) 65,341 (52,911 ) Loss From Discontinued Operations, Net of Income Taxes (1,629 ) (54 ) — — (1,683 ) NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY (65,339 ) (3 ) (54,593 ) 65,341 (54,594 ) Preferred Stock Dividends — — (1,723 ) — (1,723 ) Effect of Preferred Stock Conversions — — 72,316 72,316 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (65,339 ) $ (3 ) $ 16,000 $ 65,341 $ 15,999 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, Condensate and NGL Sales $ 56,944 $ — $ — $ — $ 56,944 Other Revenue 7 — — — 7 TOTAL OPERATING REVENUE 56,951 — — — 56,951 OPERATING EXPENSES Production and Lease Operating Expense 49,671 1 — — 49,672 General and Administrative Expense 9,080 — 1,041 — 10,121 Gain on Disposal of Assets (4,295 ) — — — (4,295 ) Impairment Expense 35,780 — — — 35,780 Exploration Expense 1,737 1 — — 1,738 Depreciation, Depletion, Amortization and Accretion 31,249 13 — — 31,262 Other Operating Expense 1,030 — — — 1,030 TOTAL OPERATING EXPENSES 124,252 15 1,041 — 125,308 LOSS FROM OPERATIONS (67,301 ) (15 ) (1,041 ) — (68,357 ) OTHER INCOME (EXPENSE) Interest Expense (539 ) — (23,930 ) — (24,469 ) Loss on Derivatives, Net (25,120 ) — — — (25,120 ) Other Income 12 — — — 12 Debt Exchange Expense — — (9,014 ) — (9,014 ) Gain on Extinguishment of Debt — — 23,707 — 23,707 Income (Loss) From Equity in Consolidated Subsidiaries 79 (79 ) (104,226 ) 104,226 — TOTAL OTHER INCOME (EXPENSE) (25,568 ) (79 ) (113,463 ) 104,226 (34,884 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (92,869 ) (94 ) (114,504 ) 104,226 (103,241 ) Income Tax Expense (2,090 ) — (231 ) — (2,321 ) INCOME (LOSS) FROM CONTINUING OPERATIONS (94,959 ) (94 ) (114,735 ) 104,226 (105,562 ) Loss From Discontinued Operations, Net of Income Tax (9,106 ) (67 ) — — (9,173 ) NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ (104,065 ) $ (161 ) $ (114,735 ) $ 104,226 $ (114,735 ) Preferred Stock Dividends — — (3,828 ) — (3,828 ) Effect of Preferred Stock Conversions — — 72,316 — 72,316 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (104,065 ) $ (161 ) $ (46,247 ) $ 104,226 $ (46,247 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDING JUNE 30, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (104,065 ) $ (161 ) $ (114,735 ) $ 104,226 $ (114,735 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Non-Cash Expenses (Income) (100 ) — 10,200 — 10,100 Depreciation, Depletion, Amortization and Accretion 36,293 52 — — 36,345 Gain on Derivatives 25,120 — — — 25,120 Cash Settlements of Derivatives 30,340 — — — 30,340 Dry Hole Expense 870 — — — 870 Gain on Sale of Asset (4,338 ) — — — (4,338 ) Gain on Extinguishment Debt — — (23,757 ) — (23,757 ) Impairment Expense 39,330 (7 ) 39,323 (39,323 ) 39,323 Changes in operating assets and liabilities Accounts Receivable (14,452 ) 103 (423 ) — (14,772 ) Inventory, Prepaid Expenses and Other Assets 1,093 — 25 — 1,118 Accounts Payable and Accrued Liabilities 15,148 — (4,723 ) — 10,425 Other Assets and Liabilities (651 ) (25 ) — — (676 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 24,588 (38 ) (94,090 ) 64,903 (4,637 ) CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 2,035 109 62,759 (64,903 ) — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 190 — — — 190 Proceeds from Joint Venture 19,461 — — — 19,461 Acquisitions of Undeveloped Acreage (5,863 ) (37 ) — — (5,900 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (37,704 ) (34 ) — — (37,738 ) NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (21,881 ) 38 62,759 (64,903 ) (23,987 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — — 50,400 — 50,400 Repayments of Long-Term Debt and Lines of Credit — — (15,230 ) — (15,230 ) Repayments of Loans and Other Long-Term Debt (361 ) — — — (361 ) Debt Issuance Costs — — (3,838 ) — (3,838 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (361 ) — 31,332 — 30,971 NET INCREASE IN CASH 2,346 — 1 — 2,347 CASH – BEGINNING 1,089 — 2 — 1,091 CASH - ENDING $ 3,435 $ — $ 3 $ — $ 3,438 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF DECEMBER 31, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 1,089 $ — $ 2 $ — $ 1,091 Accounts Receivable 17,225 — 49 — 17,274 Taxes Receivable — — 18 — 18 Short-Term Derivative Instruments 34,260 — — — 34,260 Inventory, Prepaid Expenses and Other 3,034 — 25 — 3,059 Assets Held for Sale 59,411 1,040 — — 60,451 Total Current Assets 115,019 1,040 94 — 116,153 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 950,062 — — (6,970 ) 943,092 Unevaluated Oil and Gas Properties 262,992 — — — 262,992 Other Property and Equipment 20,363 — — — 20,363 Wells and Facilities in Progress 141,370 — — (270 ) 141,100 Pipelines 16,161 — — (2,137 ) 14,024 Total Property and Equipment 1,390,948 — — (9,377 ) 1,381,571 Less: Accumulated Depreciation, Depletion and Amortization (441,346 ) — — 3,518 (437,828 ) Net Property and Equipment 949,602 — — (5,859 ) 943,743 Deferred Financing Costs and Other Assets—Net 2,501 — — — 2,501 Intercompany Receivables — — 1,070,548 (1,070,548 ) — Investment in Subsidiaries – Net (1,907 ) — 243,331 (241,424 ) — Long-Term Derivative Instruments 9,534 — — — 9,534 Total Assets $ 1,074,749 $ 1,040 $ 1,313,973 $ (1,317,831 ) $ 1,071,931 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 36,785 $ — $ — $ — $ 36,785 Current Maturities of Long-Term Debt 402 — — — 402 Accrued Liabilities 28,883 — 11,725 — 40,608 Short-Term Derivative Instruments 2,486 — — — 2,486 Liabilities Related to Assets Held for Sale 36,289 31 — — 36,320 Total Current Liabilities 104,845 31 11,725 — 116,601 Long-Term Derivative Instruments 5,556 — — — 5,556 Senior Secured Line of Credit and Other Long-Term Debt, Net of Issuance Costs 28 — 109,358 — 109,386 Senior Notes, Net of Issuance Costs — — 663,089 — 663,089 Premium on Senior Notes – Net — — 2,344 — 2,344 Other Deposits and Liabilities 3,156 — — — 3,156 Future Abandonment Cost 11,159 409 — — 11,568 Intercompany Payables 1,070,096 452 — (1,070,548 ) — Total Liabilities 1,194,840 892 786,516 (1,070,548 ) 911,700 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 54 — 54 Additional Paid-In Capital 177,143 — 619,777 (173,057 ) 623,863 Accumulated Earnings (Deficit) (297,234 ) 148 (92,375 ) (74,226 ) (463,687 ) Total Stockholders’ Equity (120,091 ) 148 527,457 (247,283 ) 160,231 Total Liabilities and Stockholders’ Equity $ 1,074,749 $ 1,040 $ 1,313,973 $ (1,317,831 ) $ 1,071,931 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, Condensate and NGL Sales $ 35,772 $ — $ — $ — $ 35,772 Other Revenue 12 — — — 12 TOTAL OPERATING REVENUE 35,784 — — — 35,784 OPERATING EXPENSES Production and Lease Operating Expense 24,270 — — — 24,270 General and Administrative Expense 5,576 — 1,818 — 7,394 Gain on Disposal of Asset (373 ) — — — (373 ) Impairment Expense 117,839 — — — 117,839 Exploration Expense 760 — — (5 ) 755 Depreciation, Depletion, Amortization and Accretion 24,962 — — (264 ) 24,698 Other Operating Income (66 ) — — — (66 ) TOTAL OPERATING EXPENSES 172,968 — 1,818 (269 ) 174,517 INCOME (LOSS) FROM OPERATIONS (137,184 ) — (1,818 ) 269 (138,733 ) OTHER INCOME (EXPENSE) Interest Expense (71 ) — (12,110 ) — (12,181 ) Gain (Loss) on Derivatives, Net 198 — (479 ) — (281 ) Other Income 61 — — — 61 Loss From Equity Method Investments (208 ) — — — (208 ) Income (Loss) From Equity in Consolidated Subsidiaries 3 (3 ) (138,226 ) 138,226 — TOTAL OTHER INCOME (EXPENSE) (17 ) (3 ) (150,815 ) 138,226 (12,609 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (137,201 ) (3 ) (152,633 ) 138,495 (151,342 ) Income Tax (Expense) Benefit 119 — (119 ) — — INCOME (LOSS) FROM CONTINUING OPERATIONS (137,082 ) (3 ) (152,752 ) 138,495 (151,342 ) Income From Discontinued Operations, Net of Income Tax (2,033 ) 2,824 — (1,252 ) (461 ) Net Income (Loss) (139,115 ) 2,821 (152,752 ) 137,243 (151,803 ) Net Income Attributable to Noncontrolling Interests of Discontinued Operations — 949 — — 949 NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ (139,115 ) $ 1,872 $ (152,752 ) $ 137,243 $ (152,752 ) Preferred Stock Dividends — — (2,415) — (2,415) NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (139,115 ) $ 1,872 $ (155,167 ) $ 137,243 $ (155,167 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, Condensate and NGL Sales $ 81,696 $ — $ — $ — $ 81,696 Other Revenue 22 — — — 22 TOTAL OPERATING REVENUE 81,718 — — — 81,718 OPERATING EXPENSES Production and Lease Operating Expense 47,387 — — — 47,387 General and Administrative Expense 11,082 — 4,663 — 15,745 Gain on Disposal of Asset (309 ) — — — (309 ) Impairment Expense 124,687 — — — 124,687 Exploration Expense 1,198 1 — (5 ) 1,194 Depreciation, Depletion, Amortization and Accretion 47,035 1 — (499 ) 46,537 Other Operating Expense 5,138 — — — 5,138 TOTAL OPERATING EXPENSES 236,218 2 4,663 (504 ) 240,379 INCOME (LOSS) FROM OPERATIONS (154,500 ) (2 ) (4,663 ) 504 (158,661 ) OTHER INCOME (EXPENSE) Interest Expense (124 ) — (24,069 ) — (24,193 ) Gain (Loss) on Derivatives, Net 17,054 — (216 ) — 16,838 Other Income 92 — — — 92 Loss From Equity Method Investments (411 ) — — — (411 ) Income (Loss) From Equity in Consolidated Subsidiaries (20 ) 20 (141,440 ) 141,440 — TOTAL OTHER INCOME (EXPENSE) 16,591 20 (165,725 ) 141,440 (7,674 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (137,909 ) 18 (170,388 ) 141,944 (166,335 ) Income Tax (Expense) Benefit 178 — (178 ) — — INCOME (LOSS) FROM CONTINUING OPERATIONS (137,731 ) 18 (170,566 ) 141,944 (166,335 ) Income (Loss) From Discontinued Operations, Net of Income Tax (5,498 ) 4,765 — (1,252 ) (1,985 ) NET INCOME (LOSS) (143,229 ) 4,783 (170,566 ) 140,692 (168,320 ) Net Income Attributable to Noncontrolling Interests of Discontinued Operations — 2,246 — — 2,246 NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ (143,229 ) $ 2,537 $ (170,566 ) $ 140,692 $ (170,566 ) Preferred Stock Dividends — — (4,830 ) — (4,830) NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (143,229 ) $ 2,537 $ (175,396 ) $ 140,692 $ (175,396 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDING JUNE 30, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (143,229 ) $ 4,783 $ (170,566 ) $ 140,692 $ (168,320 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Loss From Equity Method Investments 411 — — — 411 Non-Cash Expenses (Income) (92 ) 100 5,876 — 5,884 Depreciation, Depletion, Amortization and Accretion 56,057 3,061 — (3,378 ) 55,740 Gain (Loss) on Derivatives (17,054 ) — 216 — (16,838 ) Cash Settlements of Derivatives 24,117 — 903 — 25,020 Dry Hole Expense 198 96 — (5 ) 289 Gain on Sale of Asset (235 ) (42 ) — — (277 ) Impairment Expense 124,856 11 — — 124,867 Changes in operating assets and liabilities Accounts Receivable 18,987 (1,707 ) 328 (657 ) 16,951 Inventory, Prepaid Expenses and Other Assets 1,376 (278 ) (74 ) — 1,024 Accounts Payable and Accrued Liabilities (21,251 ) (2,492 ) (898 ) 657 (23,984 ) Other Assets and Liabilities (915 ) (73 ) 27 — (961 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 43,226 3,459 (164,188 ) 137,309 19,806 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 65,125 (3,184 ) 76,592 (138,533 ) — Proceeds from Joint Venture Acreage Management 43 — — — 43 Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 3,979 554 — — 4,533 Proceeds from Joint Venture 16,611 — — — 16,611 Acquisitions of Undeveloped Acreage (21,109 ) (5 ) — — (21,114 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (119,054 ) (7,815 ) — 1,224 (125,645 ) NET CASH USED IN INVESTING ACTIVITIES (54,405 ) (10,450 ) 76,592 (137,309 ) (125,572 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — 33,960 124,000 — 157,960 Repayments of Long-Term Debt and Lines of Credit — (25,443 ) (31,000 ) — (56,443 ) Repayments of Loans and Other Long-Term Debt (633 ) (520 ) — — (1,153 ) Debt Issuance Costs — (3 ) (569 ) — (572 ) Dividends Paid — — (4,830 ) — (4,830 ) Distributions by the Partners of Consolidated Subsidiaries — (830 ) — — (830 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (633 ) 7,164 87,601 — 94,132 NET INCREASE (DECREASE) IN CASH (11,812 ) 173 5 — (11,634 ) CASH – BEGINNING 17,978 118 — — 18,096 CASH - ENDING $ 6,166 $ 291 $ 5 $ — $ 6,462

Subsequent Events

Subsequent Events	6 Months Ended
	Jun. 30, 2016
Subsequent Events [Abstract]
Subsequent Events	18. SUBSEQUENT EVENTS Debt For Equity Exchange During July 2016, we completed a privately negotiated exchanges of shares of our common stock for outstanding New Notes. In total, we exchanged $43.5 million of our New Notes for approximately 16.8 million shares of our common stock. The shares of our common stock were issued in reliance on the exemption provided in Section 3(a)(9) of the Securities Act of 1933, as amended. Amendment to Senior Credit Agreement Effective as of July 1, 2016, we entered into an Eleventh Amendment (the “Eleventh Amendment”) to the Amended and Restated Credit Agreement dated as of March 27, 2013 (as amended, modified or supplemented, the “Credit Agreement”) among us; each of the guarantors; Royal Bank of Canada, as administrative agent for the lenders; and the other lenders signatory thereto. The Eleventh Amendment amends certain provisions of the Credit Agreement to, among other things, (i) re-affirm our current borrowing base level of $190.0 million, and provide that there will be no further adjustment to the borrowing base upon the completion of the anticipated sale of assets in the Illinois Basin; (ii) provide flexibility with respect to our use of proceeds from the anticipated sale of assets in the Illinois Basin; (iii) waive our compliance with the current ratio test in the Credit Agreement for the fiscal quarter ending June 30, 2016, and revise the future calculation method for the current ratio to address timing and inclusion of certain reimbursements from joint development partners; and (iv) add a new PDP coverage ratio with a minimum coverage of 1.65 to 1.00. The PDP coverage ratio will be calculated as of the last day of each fiscal quarter, effective with the quarter ending September 30, 2016. For additional information regarding our Senior Credit Facility, see Note 7, Long-Term Debt

Recently Issued Accounting Pr25

Recently Issued Accounting Pronouncements (Policies)	6 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Recently Issued Accounting Pronouncements	In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers Revenue Recognition 1) Identify the contract(s) with a customer. 2) Identify the performance obligations in the contract. 3) Determine the transaction price. 4) Allocate the transaction price to the performance obligations in the contract. 5) Recognize revenue when (or as) the entity satisfies a performance obligation. An entity should apply the amendments in this ASU using one of the following two methods: 1) Retrospectively to each prior reporting period presented. 2) Retrospectively with the cumulative effect of initially applying this ASU recognized at the date of the initial applications. In July 2015, the FASB approved a one-year deferral of the effective date of this new standard so the guidance is effective for the reporting period beginning January 1, 2018, with early adoption permitted in the first quarter 2017. We are currently evaluating the new guidance and have not determined the impact this standard may have on our Consolidated Financial Statements or decided upon the method of adoption. In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes In February 2016, the FASB issued 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 this guidance and do not believe it will have a material impact due to our minimal number of operating leases. In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting

Future Abandonment Cost (Tables

Future Abandonment Cost (Tables)	6 Months Ended
	Jun. 30, 2016
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, 2016 Beginning Balance at January 1, 2016 $ 11,934 Future Abandonment Obligation Incurred 282 Future Abandonment Obligation Settled (4 ) Future Abandonment Obligation Cancelled or Sold (4,568 ) Future Abandonment Obligation Revision of Estimated Obligation — Future Abandonment Obligation Accretion Expense 365 Total Future Abandonment Cost 1 $ 8,009 1

Discontinued Operations_Asset27

Discontinued Operations/Assets Held For Sale (Tables)	6 Months Ended
	Jun. 30, 2016
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Summary of Financial Information for Discontinued Operations	The carrying value of assets and liabilities of our Illinois Basin operations that are classified as Held for Sale in the accompanying Consolidated Balance Sheets at June 30, 2016 and December 31, 2015 are as follows: June 30, December 31, ($ in Thousands) 2016 2015 Assets: Accounts Receivable 2,367 2,209 Inventory, Prepaid Expenses and Other 1,023 770 Total Current Assets 3,390 2,979 Evaluated Oil & Gas Properties 297,222 296,338 Unevaluated Oil & Gas Properties 37 — Other Property and Equipment 19,354 19,749 Wells and Facilities in Progress 3,401 3,456 Accumulated Depreciation, Depletion, and Amortization (276,855 ) (262,071 ) Total Long-Term Assets 43,159 57,472 Total Assets Held for Sale $ 46,549 $ 60,451 Liabilities: Accounts Payable $ 4,831 $ 1,089 Current Maturities of Long-Term Debt 85 188 Accrued Liabilities 3,285 3,718 Total Current Liabilities 8,201 4,995 Long-Term Debt — 10 Future Abandonment Cost 31,734 31,315 Total Long-Term Liabilities 31,734 31,325 Total Liabilities Related to Assets Held for Sale $ 39,935 $ 36,320 Net Assets Held for Sale $ 6,614 $ 24,131
Average Spot Price	For the proceeds to become payable by Campbell in any of the eleven individual quarters, the average spot price of West Texas Intermediate (“WTI”) as published by the New York Mercantile Exchange must be in excess of the amount shown in the table below for each specific quarter. Calendar Quarter Ending West Texas Intermediate ("WTI") Average Price per Bbl (a) 12/31/2016 $ 54.25 3/31/2017 $ 56.25 6/30/2017 $ 58.25 9/30/2017 $ 60.25 12/31/2017 $ 60.75 3/31/2018 $ 61.25 6/30/2018 $ 61.75 9/30/2018 $ 62.25 12/31/2018 $ 62.75 3/31/2019 $ 63.25 6/30/2019 $ 63.75 (a) Calculated as the sum of the closing spot price of the West Texas Intermediate of the New York Mercantile Exchange for each day during the quarter (excluding weekends and holidays), divided by the number of days on which those prices are published (excluding weekends and holidays).
Water Solutions Holdings, LLC
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Summary of Financial Information for Discontinued Operations	Summarized financial information for Discontinued Operations related to Water Solutions is set forth in the table below, and does not reflect the costs of certain services provided. Such indirect costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support. Three Months Ended June 30, Six Months Ended June 30, ($ in Thousands) 2016 2015 2016 2015 Revenues: Field Services Revenue $ — $ 16,643 $ — $ 31,607 Total Operating Revenue — 16,643 — 31,607 Costs and Expenses: General and Administrative Expense — 902 — 1,879 Depreciation, Depletion, Amortization and Accretion — 37 — 76 Field Services Operating Expense — 13,464 — 24,753 Gain on Sale of Asset — (10 ) — (42 ) Interest Expense — 240 — 431 Other Expense — 17 — 120 Total Costs and Expenses — 14,650 — 27,217 Income from Discontinued Operations Before Income Taxes — 1,993 — 4,390 Income Tax (Expense) Benefit — 101 — (242 ) Income from Discontinued Operations, net of taxes $ — $ 2,094 $ — $ 4,148
Illinois Basin Operations
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Summary of Financial Information for Discontinued Operations	Summarized financial information for Discontinued Operations related to our Illinois Basin operations is set forth in the tables below, and does not reflect the costs of certain services provided. Such indirect costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support. The sale of our Illinois assets and operations does not include any of our derivative contracts or positions related to our Illinois basin revenues or production. No derivative positions or activity has been attributed to or included in Discontinued Operations for the three and six months periods ended June 30, 2016 and 2015. Three Months Ended June 30, Six Months Ended June 30, ($ in Thousands) 2016 2015 2016 2015 Revenues: Oil Sales $ 6,393 $ 9,989 $ 11,213 $ 18,176 Total Operating Revenue 6,393 9,989 11,213 18,176 Costs and Expenses: Production and Lease Operating Expense 5,029 6,372 10,725 12,307 General and Administrative Expense 659 1,086 1,437 2,385 (Gain) Loss on Disposal of Assets (2 ) 72 (43 ) 73 Impairment Expense — 3 3,543 178 Exploration Expense 85 162 143 241 Depreciation, Depletion, Amortization and Accretion 2,186 4,840 5,083 9,127 Interest Expense 1 13 3 17 Other Income (2 ) (4 ) (3 ) (19 ) Total Costs and Expenses 7,956 12,544 20,888 24,309 Loss from Discontinued Operations Before Income Taxes (1,563 ) (2,555 ) (9,675 ) (6,133 ) Income Tax (Expense) Benefit (120 ) — 502 — Loss from Discontinued Operations, net of taxes $ (1,683 ) $ (2,555 ) $ (9,173 ) $ (6,133 ) Production: Crude Oil (Bbls) 150,980 182,724 308,720 362,541

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Components of Long-Term Debt and Lines of Credit	In addition to the Senior Credit Facility and the Senior Notes, we may, from time to time in the normal course of business finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and other obligations consisted of the following at June 30, 2016 and December 31, 2015: ($ in Thousands) June 30, 2016 (Unaudited) December 31, 2015 Senior Notes, Net of Issuance Costs (a) $ 637,314 $ 663,089 Premium on Senior Notes, Net 1,524 2,344 Senior Line of Credit, Net of Issuance Costs (b)(c) 141,237 109,396 Capital Leases and Other Obligations(c) 172 419 Total Debt 780,247 775,248 Less Current Portion of Long-Term Debt (172 ) (402 ) Total Long-Term Debt $ 780,075 $ 774,846 (a) Includes unamortized debt issuance costs of approximately $9.1 million and $11.9 million as of June 30, 2016 and December 31, 2015, respectively. (b) Includes unamortized debt issuance costs of approximately $5.4 million and $2.1 million as of June 30, 2016 and December 31, 2015, respectively. (c) The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. The weighted average interest rate on borrowings under our Senior Credit Facility for the six months ended June 30, 2016 and the year ended December 31, 2015, was approximately 3.2 % and 1.7%, respectively. The average interest rate on our capital leases and other obligations for the six months ended June 30, 2016 and the year ended December 31, 2015, was approximately 4.5%
Principal Maturity Schedule for Total Debt Outstanding	The following is the principal maturity schedule for debt outstanding as of June 30, 2016: 2016 $ 165 2017 7 2018 — 2019 146,670 2020 640,251 Thereafter 6,160 Total (a) $ 793,253 (a) Excludes $1.5 million net premium on Senior Notes and $14.5 million in debt issuance costs

Derivative Instruments And Fa29

Derivative Instruments And Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2016
Fair Value Of Financial Instruments And Derivative Instruments [Abstract]
Schedule of Location and Amounts of Gains and Losses on Derivative Instruments	The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, 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, 2016 and 2015: For the Three Months Ended June 30, For the Six Months Ended June 30, ($ in Thousands) 2016 2015 2016 2015 Oil $ (2,494 ) $ (2,828 ) $ (2,169 ) $ 50 Natural Gas (18,666 ) 3,036 (13,302 ) 16,635 NGLs (8,093 ) (60 ) (9,714 ) 374 Refined Products 84 50 65 (6 ) Interest Rate — (479 ) — (215 ) Gain (Loss) on Derivatives, Net $ (29,169 ) $ (281 ) $ (25,120 ) $ 16,838
Asset or Liability Financial Commodity Derivative Instrument Positions	Our open asset/(liability) financial commodity derivative instrument positions at June 30, 2016 consisted of: Period Volume Put Option Floor Ceiling Swap Fair Market Value ($ in Thousands) Oil 2016 - Collars 272,000 Bbls $ — $ 38.05 $ 49.15 $ — $ (956 ) 2016 - Three-Way Collars 150,000 Bbls 31.20 41.40 49.60 — (442 ) 2016 - Cap Swaps 60,000 Bbls 30.00 — — 44.00 (361 ) 482,000 Bbls $ (1,759 ) Natural Gas 2016 - Swaps 8,155,000 Mcf — — — 2.54 $ (3,475 ) 2016 - Swaptions 600,000 Mcf — — — 3.15 79 2016 - Cap Swaps 2,400,000 Mcf 2.59 — — 3.07 (612 ) 2016 - Collars 2,110,000 Mcf — 2.63 3.03 — (409 ) 2016 - Three-Way Collars 1,505,000 Mcf 2.11 2.68 3.30 — (377 ) 2016 - Put Spreads 6,015,000 Mcf 2.51 3.27 — — 760 2016 - Basis Swaps - Dominion South 11,113,000 Mcf — — — (0.88 ) (139 ) 2017 - Swaps 2,460,000 Mcf — — — 3.21 178 2017 - Swaptions 0 Mcf — — — — (670 ) 2017 - Cap Swaps 3,900,000 Mcf 2.35 — — 2.81 (1,559 ) 2017 - Three-Way Collars 16,900,000 Mcf 2.32 3.01 3.87 — 594 2017 - Calls 3,000,000 Mcf — — 3.64 — (1,277 ) 2017 - Collars 1,400,000 Mcf — 2.40 3.10 — (348 ) 2017 - Basis Swaps - Dominion South 4,550,000 Mcf — — — (0.83 ) (1,073 ) 2017 - Basis Swaps - Texas Gas 14,600,000 Mcf — — — (0.13 ) (372 ) 2018 - Swaps 960,000 Mcf — — — 3.25 495 2018 - Swaptions 0 Mcf — — — — (320 ) 2018 - Three-Way Collars 7,875,000 Mcf 2.29 2.88 3.56 — (755 ) 2018 - Calls 5,810,000 Mcf — — 3.97 — (485 ) 2018 - Basis Swaps - Dominion South 6,400,000 Mcf — — — (0.83 ) (1,073 ) 2018 - Basis Swaps - Texas Gas 14,600,000 Mcf — — — (0.13 ) (372 ) 2019 - Basis Swaps - Dominion South 7,300,000 Mcf — — — (0.83 ) (1,073 ) 2020 - Basis Swaps - Dominion South 7,320,000 Mcf — — — (0.83 ) (1,073 ) 128,973,000 Mcf $ (13,356 ) NGLs 2016 - C3+ NGL Swaps 714,000 Bbls — — — 26.04 $ (261 ) 2016 - Ethane Swaps 330,000 Bbls — — — 8.40 (766 ) 2017 - C3+ NGL Swaps 468,000 Bbls — — — 20.16 (2,228 ) 2017 - Ethane Swaps 540,000 Bbls — — — 10.08 (1,220 ) 2,052,000 Bbls $ (4,475 ) Refined Product (Heating Oil) 2016 - Swaps 6,000 Bbls $ — $ — $ — $ 84.00 $ (117 ) 6,000 Bbls $ (117 )
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, 2016 and December 31, 2015 is summarized below: June 30, December 31, ($ in Thousands) 2016 2015 Short-Term Derivative Assets: Crude Oil—Collars $ — $ 1,078 Crude Oil—Deferred Put Spread — 852 Crude Oil—Three-Way Collars 355 577 NGL—Swaps 1,127 10,250 Natural Gas—Swaps 879 9,010 Natural Gas—Cap Swaps 334 1,977 Natural Gas—Basis Swaps 397 70 Natural Gas—Three-Way Collars 783 6,183 Natural Gas—Collars — 1,728 Natural Gas—Swaption 79 798 Natural Gas—Put Spread 806 1,737 Total Short-Term Derivative Assets $ 4,760 $ 34,260 Long-Term Derivative Assets: NGL—Swaps $ — $ 344 Natural Gas—Cap Swaps — 2,294 Natural Gas—Swaps 743 1,593 Natural Gas—Basis Swaps — 195 Natural Gas—Three-Way Collars 783 5,108 Total Long-Term Derivative Assets $ 1,526 $ 9,534 Total Derivative Assets $ 6,286 $ 43,794 Short-Term Derivative Liabilities: Crude Oil—Three-Way Collars (797 ) — Crude Oil—Collars (956 ) — Crude Oil—Deferred Put Spread (361 ) — NGL—Swaps (3,878 ) — Refined Product—Swaps (117 ) (376 ) Natural Gas—Three-Way Collars (973 ) (31 ) Natural Gas—Collars (558 ) — Natural Gas—Basis Swaps (1,258 ) (1,585 ) Natural Gas—Put Spread (46 ) — Natural Gas—Call (639 ) — Natural Gas—Swaption (326 ) (202 ) Natural Gas—Swaps (4,323 ) (292 ) Natural Gas—Cap Swaps (1,670 ) — Total Short - Term Derivative Liabilities $ (15,902 ) $ (2,486 ) Long-Term Derivative Liabilities: NGL—Swaps (1,724 ) — Natural Gas—Swaps (101 ) — Natural Gas—Swaption (664 ) (297 ) Natural Gas—Basis Swaps (4,314 ) (4,186 ) Natural Gas—Collars (199 ) — Natural Gas—Call (1,123 ) (989 ) Natural Gas—Cap Swaps (835 ) — Natural Gas—Three-Way Collars (1,131 ) (84 ) Total Long-Term Derivative Liabilities $ (10,091 ) $ (5,556 ) Total Derivative Liabilities $ (25,993 ) $ (8,042 )
Significant Unobservable Inputs Used in Fair Value Measurements of Natural Gas Basis Swaps	The significant unobservable inputs and the range and weighted average of these inputs used in the fair value measurements of our natural gas basis swaps as of June 30, 2016 and December 31, 2015 are included in the table below. As of June 30, 2016 Range (price per Mcf) Weighted Average (price per Mcf) Fair Value (in thousands) Natural Gas Basis Differential Forward Curve - Dominion South ($0.34) - ($1.17) $ (0.72 ) $ (4,431 ) Natural Gas Basis Differential Forward Curve - Texas Gas ($0.08) - ($0.12) $ (0.10 ) $ (744 ) As of December 31, 2015 Range (price per Mcf) Weighted Average (price per Mcf) Fair Value (in thousands) Natural Gas Basis Differential Forward Curve - Dominion South ($0.27) - ($1.08) $ (0.74 ) $ (5,468 ) Natural Gas Basis Differential Forward Curve - Texas Gas ($0.05) - ($0.17) $ (0.12 ) $ (38 )
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, 2016 Using: ($ in Thousands) Total Carrying Value as of June 30, 2016 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ (19,707 ) $ — $ (14,532 ) $ (5,175 ) Fair Value Measurements at December 31, 2015 Using: ($ in Thousands) Total Carrying Value as of December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ 35,752 $ — $ 41,258 $ (5,506 )
Reconciliation of Commodity Derivative Contracts Measured at Fair Value on Recurring Basis Using Significant Unobservable Inputs (Level 3)	The table below sets forth a reconciliation of our commodity derivative contracts at fair value on a recurring basis using significant unobservable inputs (Level 3) during the six months ended June 30, 2016 and 2015: Six Months Ended June 30, ($ in Thousands) 2016 2015 Beginning Balance of Level 3 $ (5,506 ) $ 1,341 Changes in Fair Value (1,376 ) 3,367 Purchases — — Settlements Paid (Received) 1,707 (1,673 ) Ending Balance of Level 3 $ (5,175 ) $ 3,035
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, 2016 December 31, 2015 ($ in Thousands) Carrying Amount Fair Value Carrying Amount Fair Value Senior Notes, Net of Issuance Costs $ 637,314 $ 113,721 $ 663,089 $ 137,402 Secured Line of Credit, Net of Issuance Costs 141,237 141,237 109,396 109,396 Capital Leases and Other Obligations 172 172 419 411 Total $ 778,723 $ 255,130 $ 772,904 $ 247.209

Income Taxes (Tables)

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2016
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) 2016 2015 2016 2015 Income Tax (Expense) Benefit $ 393 $ - $ (2,321 ) $ - Effective Tax Rate 0.7 % 0.0 % -2.2 % 0.0 %

Employee Benefit And Equity P31

Employee Benefit And Equity Plans (Tables)	6 Months Ended
	Jun. 30, 2016
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, 2016 is as follows: Outstanding Exercisable Exercise Price Number Outstanding At 6/30/16 Weighted-Average Exercise Price Number Exercisable At 6/30/16 Weighted-Average Exercise Price $ 0.97 37,500 $ 0.97 — $ 0.97 $ 1.69 826,800 $ 1.69 — $ 1.69 $ 4.05 40,000 $ 4.05 — $ 4.05 $ 4.90 40,000 $ 4.90 3,333 $ 4.90 $ 5.04 46,041 $ 5.04 46,041 $ 5.04 $ 9.50 75,000 $ 9.50 75,000 $ 9.50 $ 9.99 129,583 $ 9.99 129,583 $ 9.99 $ 10.42 29,548 $ 10.42 29,548 $ 10.42 $ 13.19 50,000 $ 13.19 50,000 $ 13.19 $ 22.34 30,000 $ 22.34 30,000 $ 22.34 1,304,472 $ 4.35 363,505 $ 10.71
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: Year Ended December 31, 2015 Expected Dividend Yield 0.0 % Risk-Free Interest Rate 1.0 % Expected Volatility – Rex Energy 58.6 % Expected Volatility – Peer Group 29.8%-85.0% Market Index 35.6 % Expected Life Three Years
Summary of Nonvested Restricted Stock Activity	A summary of the restricted stock activity for the six months ended June 30, 2016 is as follows: Number of Shares Weighted-Average Grant Date Fair Value Restricted stock awards, as of December 31, 2015 2,479,408 $ 6.27 Awards 428,826 1.65 Forfeitures (381,437 ) 7.44 Vested (245,468 ) 10.67 Restricted stock awards, as of June 30, 2016 2,281,329 $ 4.74

Commitments and Contingencies (

Commitments and Contingencies (Tables)	6 Months Ended
	Jun. 30, 2016
Commitments And Contingencies Disclosure [Abstract]
Lease Commitments for Each of Next Five Years	As of June 30, 2016, 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, 2016, was approximately $0.3 million and $0.6 million, respectively, and $0.3 million and $0.5 million for the three and six months ended June 30, 2015, respectively. Lease commitments by year for each of the next five years are presented in the table below: ($ in Thousands) 2016 $ 506 2017 997 2018 565 2019 563 2020 422 Thereafter — Total $ 3,053
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) Total 2016 $ 15,342 2017 43,885 2018 47,328 2019 47,216 2020 46,060 Thereafter 528,816 Total $ 728,647
Fee for Unconventional Gas Wells	The fee for each unconventional gas well is determined using the following matrix, with vertical unconventional gas wells being charged 20% of the applicable rates: <$2.25(a) $2.26 - $2.99(a) $3.00 - $4.99(a) $5.00 - $5.99(a) >$5.99(a) Year One $ 40,200 $ 45,300 $ 50,300 $ 55,300 $ 60,400 Year Two $ 30,200 $ 35,200 $ 40,200 $ 45,300 $ 55,300 Year Three $ 25,200 $ 30,200 $ 30,200 $ 40,200 $ 50,300 Year 4 – 10 $ 10,100 $ 15,100 $ 20,100 $ 20,100 $ 20,100 Year 11 – 15 $ 5,000 $ 5,000 $ 10,100 $ 10,100 $ 10,100 (a )

Earnings Per Common Share (Tabl

Earnings Per Common Share (Tables)	6 Months Ended
	Jun. 30, 2016
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: 2016 2015 2016 2015 Net Loss From Continuing Operations $ (52,911 ) $ (151,342 ) $ (105,562 ) $ (166,335 ) Net Loss From Discontinued Operations, Less Noncontrolling Interests (1,683 ) (1,410 ) (9,173 ) (4,231 ) Less: Preferred Stock Dividends (1,723 ) (2,415 ) (3,828 ) (4,830 ) Effect of Preferred Stock Conversions 72,316 — 72,316 — Net Income (Loss) Attributable to Common Shareholders $ 15,999 $ (155,167 ) $ (46,247 ) $ (175,396 ) Denominator: Weighted Average Common Shares Outstanding - Basic 71,804 54,118 64,044 54,090 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 71,804 54,118 64,044 54,090 Earnings per Common Share Attributable to Rex Energy Common Shareholders: Basic — Net Income (Loss) From Continuing Operations $ 0.24 $ (2.84 ) $ (0.58 ) $ (3.16 ) — Net Loss From Discontinued Operations (0.02 ) (0.03 ) (0.14 ) (0.08 ) — Net Income (Loss) Attributable to Rex Energy Common Shareholders $ 0.22 $ (2.87 ) $ (0.72 ) $ (3.24 ) Diluted — Net Income (Loss) From Continuing Operations $ 0.24 $ (2.84 ) $ (0.58 ) $ (3.16 ) — Net Loss From Discontinued Operations (0.02 ) (0.03 ) (0.14 ) (0.08 ) — Net Income (Loss) Attributable to Rex Energy Common Shareholders $ 0.22 $ (2.87 ) $ (0.72 ) $ (3.24 )

Condensed Consolidating Finan34

Condensed Consolidating Financial Information (Tables)	6 Months Ended
	Jun. 30, 2016
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Balance Sheets	REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF JUNE 30, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 3,435 $ — $ 3 $ — $ 3,438 Accounts Receivable 27,694 — 3,950 — 31,644 Taxes Receivable — — 48 — 48 Short-Term Derivative Instruments 4,760 — — — 4,760 Inventory, Prepaid Expenses and Other 1,688 — — — 1,688 Assets Held for Sale 45,466 1,083 — — 46,549 Total Current Assets 83,043 1,083 4,001 — 88,127 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,020,936 — — 1,020,936 Unevaluated Oil and Gas Properties 232,674 — — — 232,674 Other Property and Equipment 21,444 — — — 21,444 Wells and Facilities in Progress 75,992 — — — 75,992 Pipelines 14,144 — — — 14,144 Total Property and Equipment 1,365,190 — — — 1,365,190 Less: Accumulated Depreciation, Depletion and Amortization (459,427 ) — — — (459,427 ) Net Property and Equipment 905,763 — — — 905,763 Other Assets 2,490 — — — 2,490 Intercompany Receivables — — 1,071,155 (1,071,155 ) — Investment in Subsidiaries – Net (2,388 ) — (127,974 ) 130,362 — Long-Term Derivative Instruments 1,526 — — — 1,526 Total Assets $ 990,434 $ 1,083 $ 947,182 $ (940,793 ) $ 997,906 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 51,915 $ — $ — $ — $ 51,915 Current Maturities of Long-Term Debt 172 — — — 172 Accrued Liabilities 24,498 — 5,848 30,346 Short-Term Derivative Instruments 15,902 — — — 15,902 Liabilities Related to Assets Held for Sale 39,903 32 — — 39,935 Total Current Liabilities 132,390 32 5,848 — 138,270 Long-Term Derivative Instruments 10,091 — — — 10,091 Senior Secured Line of Credit and Other Long-Term Debt, Net of Issuance Costs — — 141,237 — 141,237 Senior Notes, Net of Issuance Costs — — 637,314 — 637,314 Premium on Senior Notes – Net — — 1,524 — 1,524 Other Deposits and Liabilities 2,860 — — — 2,860 Future Abandonment Cost 7,313 418 — — 7,731 Intercompany Payables 1,066,506 4,649 — (1,071,155 ) — Total Liabilities 1,219,160 5,099 785,923 (1,071,155 ) 939,027 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 77 — 77 Additional Paid-In Capital 177,144 — 637,223 (177,144 ) 637,223 Accumulated Earnings (Deficit) (405,870 ) (4,016 ) (476,042 ) 307,506 (578,422 ) Total Stockholders’ Equity (228,726 ) (4,016 ) 161,259 130,362 58,879 Total Liabilities and Stockholders’ Equity $ 990,434 $ 1,083 $ 947,182 $ (940,793 ) $ 997,906 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF DECEMBER 31, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 1,089 $ — $ 2 $ — $ 1,091 Accounts Receivable 17,225 — 49 — 17,274 Taxes Receivable — — 18 — 18 Short-Term Derivative Instruments 34,260 — — — 34,260 Inventory, Prepaid Expenses and Other 3,034 — 25 — 3,059 Assets Held for Sale 59,411 1,040 — — 60,451 Total Current Assets 115,019 1,040 94 — 116,153 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 950,062 — — (6,970 ) 943,092 Unevaluated Oil and Gas Properties 262,992 — — — 262,992 Other Property and Equipment 20,363 — — — 20,363 Wells and Facilities in Progress 141,370 — — (270 ) 141,100 Pipelines 16,161 — — (2,137 ) 14,024 Total Property and Equipment 1,390,948 — — (9,377 ) 1,381,571 Less: Accumulated Depreciation, Depletion and Amortization (441,346 ) — — 3,518 (437,828 ) Net Property and Equipment 949,602 — — (5,859 ) 943,743 Deferred Financing Costs and Other Assets—Net 2,501 — — — 2,501 Intercompany Receivables — — 1,070,548 (1,070,548 ) — Investment in Subsidiaries – Net (1,907 ) — 243,331 (241,424 ) — Long-Term Derivative Instruments 9,534 — — — 9,534 Total Assets $ 1,074,749 $ 1,040 $ 1,313,973 $ (1,317,831 ) $ 1,071,931 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 36,785 $ — $ — $ — $ 36,785 Current Maturities of Long-Term Debt 402 — — — 402 Accrued Liabilities 28,883 — 11,725 — 40,608 Short-Term Derivative Instruments 2,486 — — — 2,486 Liabilities Related to Assets Held for Sale 36,289 31 — — 36,320 Total Current Liabilities 104,845 31 11,725 — 116,601 Long-Term Derivative Instruments 5,556 — — — 5,556 Senior Secured Line of Credit and Other Long-Term Debt, Net of Issuance Costs 28 — 109,358 — 109,386 Senior Notes, Net of Issuance Costs — — 663,089 — 663,089 Premium on Senior Notes – Net — — 2,344 — 2,344 Other Deposits and Liabilities 3,156 — — — 3,156 Future Abandonment Cost 11,159 409 — — 11,568 Intercompany Payables 1,070,096 452 — (1,070,548 ) — Total Liabilities 1,194,840 892 786,516 (1,070,548 ) 911,700 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 54 — 54 Additional Paid-In Capital 177,143 — 619,777 (173,057 ) 623,863 Accumulated Earnings (Deficit) (297,234 ) 148 (92,375 ) (74,226 ) (463,687 ) Total Stockholders’ Equity (120,091 ) 148 527,457 (247,283 ) 160,231 Total Liabilities and Stockholders’ Equity $ 1,074,749 $ 1,040 $ 1,313,973 $ (1,317,831 ) $ 1,071,931
Condensed Consolidating Statements of Operations	REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, Condensate and NGL Sales $ 31,271 $ — $ — $ — $ 31,271 Other Revenue (Expense) (6 ) — — — (6 ) TOTAL OPERATING REVENUE 31,265 — — — 31,265 OPERATING EXPENSES Production and Lease Operating Expense 25,221 — — — 25,221 General and Administrative Expense 3,661 — 1,176 — 4,837 Gain on Disposal of Assets (4,307 ) — — — (4,307 ) Impairment Expense 25,139 — — — 25,139 Exploration Expense 803 — — — 803 Depreciation, Depletion, Amortization and Accretion 14,747 3 — — 14,750 Other Operating Expense 704 — — — 704 TOTAL OPERATING EXPENSES 65,968 3 1,176 — 67,147 LOSS FROM OPERATIONS (34,703 ) (3 ) (1,176 ) — (35,882 ) OTHER INCOME (EXPENSE) Interest Expense (269 ) — (11,170 ) — (11,439 ) Loss on Derivatives, Net (29,169 ) — — — (29,169 ) Other Income 12 — — — 12 Debt Exchange Expense — — (533 ) — (533 ) Gain on Extinguishment of Debt — — 23,707 — 23,707 Income (Loss) From Equity in Consolidated Subsidiaries (54 ) 54 (65,341 ) 65,341 — TOTAL OTHER INCOME (EXPENSE) (29,480 ) 54 (53,337 ) 65,341 (17,422 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (64,183 ) 51 (54,513 ) 65,341 (53,304 ) Income Tax (Expense) Benefit 473 — (80 ) — 393 NET INCOME (LOSS) FROM CONTINUING OPERATIONS (63,710 ) 51 (54,593 ) 65,341 (52,911 ) Loss From Discontinued Operations, Net of Income Taxes (1,629 ) (54 ) — — (1,683 ) NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY (65,339 ) (3 ) (54,593 ) 65,341 (54,594 ) Preferred Stock Dividends — — (1,723 ) — (1,723 ) Effect of Preferred Stock Conversions — — 72,316 72,316 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (65,339 ) $ (3 ) $ 16,000 $ 65,341 $ 15,999 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, Condensate and NGL Sales $ 56,944 $ — $ — $ — $ 56,944 Other Revenue 7 — — — 7 TOTAL OPERATING REVENUE 56,951 — — — 56,951 OPERATING EXPENSES Production and Lease Operating Expense 49,671 1 — — 49,672 General and Administrative Expense 9,080 — 1,041 — 10,121 Gain on Disposal of Assets (4,295 ) — — — (4,295 ) Impairment Expense 35,780 — — — 35,780 Exploration Expense 1,737 1 — — 1,738 Depreciation, Depletion, Amortization and Accretion 31,249 13 — — 31,262 Other Operating Expense 1,030 — — — 1,030 TOTAL OPERATING EXPENSES 124,252 15 1,041 — 125,308 LOSS FROM OPERATIONS (67,301 ) (15 ) (1,041 ) — (68,357 ) OTHER INCOME (EXPENSE) Interest Expense (539 ) — (23,930 ) — (24,469 ) Loss on Derivatives, Net (25,120 ) — — — (25,120 ) Other Income 12 — — — 12 Debt Exchange Expense — — (9,014 ) — (9,014 ) Gain on Extinguishment of Debt — — 23,707 — 23,707 Income (Loss) From Equity in Consolidated Subsidiaries 79 (79 ) (104,226 ) 104,226 — TOTAL OTHER INCOME (EXPENSE) (25,568 ) (79 ) (113,463 ) 104,226 (34,884 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (92,869 ) (94 ) (114,504 ) 104,226 (103,241 ) Income Tax Expense (2,090 ) — (231 ) — (2,321 ) INCOME (LOSS) FROM CONTINUING OPERATIONS (94,959 ) (94 ) (114,735 ) 104,226 (105,562 ) Loss From Discontinued Operations, Net of Income Tax (9,106 ) (67 ) — — (9,173 ) NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ (104,065 ) $ (161 ) $ (114,735 ) $ 104,226 $ (114,735 ) Preferred Stock Dividends — — (3,828 ) — (3,828 ) Effect of Preferred Stock Conversions — — 72,316 — 72,316 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (104,065 ) $ (161 ) $ (46,247 ) $ 104,226 $ (46,247 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, Condensate and NGL Sales $ 35,772 $ — $ — $ — $ 35,772 Other Revenue 12 — — — 12 TOTAL OPERATING REVENUE 35,784 — — — 35,784 OPERATING EXPENSES Production and Lease Operating Expense 24,270 — — — 24,270 General and Administrative Expense 5,576 — 1,818 — 7,394 Gain on Disposal of Asset (373 ) — — — (373 ) Impairment Expense 117,839 — — — 117,839 Exploration Expense 760 — — (5 ) 755 Depreciation, Depletion, Amortization and Accretion 24,962 — — (264 ) 24,698 Other Operating Income (66 ) — — — (66 ) TOTAL OPERATING EXPENSES 172,968 — 1,818 (269 ) 174,517 INCOME (LOSS) FROM OPERATIONS (137,184 ) — (1,818 ) 269 (138,733 ) OTHER INCOME (EXPENSE) Interest Expense (71 ) — (12,110 ) — (12,181 ) Gain (Loss) on Derivatives, Net 198 — (479 ) — (281 ) Other Income 61 — — — 61 Loss From Equity Method Investments (208 ) — — — (208 ) Income (Loss) From Equity in Consolidated Subsidiaries 3 (3 ) (138,226 ) 138,226 — TOTAL OTHER INCOME (EXPENSE) (17 ) (3 ) (150,815 ) 138,226 (12,609 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (137,201 ) (3 ) (152,633 ) 138,495 (151,342 ) Income Tax (Expense) Benefit 119 — (119 ) — — INCOME (LOSS) FROM CONTINUING OPERATIONS (137,082 ) (3 ) (152,752 ) 138,495 (151,342 ) Income From Discontinued Operations, Net of Income Tax (2,033 ) 2,824 — (1,252 ) (461 ) Net Income (Loss) (139,115 ) 2,821 (152,752 ) 137,243 (151,803 ) Net Income Attributable to Noncontrolling Interests of Discontinued Operations — 949 — — 949 NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ (139,115 ) $ 1,872 $ (152,752 ) $ 137,243 $ (152,752 ) Preferred Stock Dividends — — (2,415) — (2,415) NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (139,115 ) $ 1,872 $ (155,167 ) $ 137,243 $ (155,167 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Natural Gas, Condensate and NGL Sales $ 81,696 $ — $ — $ — $ 81,696 Other Revenue 22 — — — 22 TOTAL OPERATING REVENUE 81,718 — — — 81,718 OPERATING EXPENSES Production and Lease Operating Expense 47,387 — — — 47,387 General and Administrative Expense 11,082 — 4,663 — 15,745 Gain on Disposal of Asset (309 ) — — — (309 ) Impairment Expense 124,687 — — — 124,687 Exploration Expense 1,198 1 — (5 ) 1,194 Depreciation, Depletion, Amortization and Accretion 47,035 1 — (499 ) 46,537 Other Operating Expense 5,138 — — — 5,138 TOTAL OPERATING EXPENSES 236,218 2 4,663 (504 ) 240,379 INCOME (LOSS) FROM OPERATIONS (154,500 ) (2 ) (4,663 ) 504 (158,661 ) OTHER INCOME (EXPENSE) Interest Expense (124 ) — (24,069 ) — (24,193 ) Gain (Loss) on Derivatives, Net 17,054 — (216 ) — 16,838 Other Income 92 — — — 92 Loss From Equity Method Investments (411 ) — — — (411 ) Income (Loss) From Equity in Consolidated Subsidiaries (20 ) 20 (141,440 ) 141,440 — TOTAL OTHER INCOME (EXPENSE) 16,591 20 (165,725 ) 141,440 (7,674 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (137,909 ) 18 (170,388 ) 141,944 (166,335 ) Income Tax (Expense) Benefit 178 — (178 ) — — INCOME (LOSS) FROM CONTINUING OPERATIONS (137,731 ) 18 (170,566 ) 141,944 (166,335 ) Income (Loss) From Discontinued Operations, Net of Income Tax (5,498 ) 4,765 — (1,252 ) (1,985 ) NET INCOME (LOSS) (143,229 ) 4,783 (170,566 ) 140,692 (168,320 ) Net Income Attributable to Noncontrolling Interests of Discontinued Operations — 2,246 — — 2,246 NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ (143,229 ) $ 2,537 $ (170,566 ) $ 140,692 $ (170,566 ) Preferred Stock Dividends — — (4,830 ) — (4,830) NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (143,229 ) $ 2,537 $ (175,396 ) $ 140,692 $ (175,396 )
Condensed Consolidating Statements of Cash Flows	REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDING JUNE 30, 2016 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (104,065 ) $ (161 ) $ (114,735 ) $ 104,226 $ (114,735 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Non-Cash Expenses (Income) (100 ) — 10,200 — 10,100 Depreciation, Depletion, Amortization and Accretion 36,293 52 — — 36,345 Gain on Derivatives 25,120 — — — 25,120 Cash Settlements of Derivatives 30,340 — — — 30,340 Dry Hole Expense 870 — — — 870 Gain on Sale of Asset (4,338 ) — — — (4,338 ) Gain on Extinguishment Debt — — (23,757 ) — (23,757 ) Impairment Expense 39,330 (7 ) 39,323 (39,323 ) 39,323 Changes in operating assets and liabilities Accounts Receivable (14,452 ) 103 (423 ) — (14,772 ) Inventory, Prepaid Expenses and Other Assets 1,093 — 25 — 1,118 Accounts Payable and Accrued Liabilities 15,148 — (4,723 ) — 10,425 Other Assets and Liabilities (651 ) (25 ) — — (676 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 24,588 (38 ) (94,090 ) 64,903 (4,637 ) CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 2,035 109 62,759 (64,903 ) — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 190 — — — 190 Proceeds from Joint Venture 19,461 — — — 19,461 Acquisitions of Undeveloped Acreage (5,863 ) (37 ) — — (5,900 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (37,704 ) (34 ) — — (37,738 ) NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (21,881 ) 38 62,759 (64,903 ) (23,987 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — — 50,400 — 50,400 Repayments of Long-Term Debt and Lines of Credit — — (15,230 ) — (15,230 ) Repayments of Loans and Other Long-Term Debt (361 ) — — — (361 ) Debt Issuance Costs — — (3,838 ) — (3,838 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (361 ) — 31,332 — 30,971 NET INCREASE IN CASH 2,346 — 1 — 2,347 CASH – BEGINNING 1,089 — 2 — 1,091 CASH - ENDING $ 3,435 $ — $ 3 $ — $ 3,438 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDING JUNE 30, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (143,229 ) $ 4,783 $ (170,566 ) $ 140,692 $ (168,320 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Loss From Equity Method Investments 411 — — — 411 Non-Cash Expenses (Income) (92 ) 100 5,876 — 5,884 Depreciation, Depletion, Amortization and Accretion 56,057 3,061 — (3,378 ) 55,740 Gain (Loss) on Derivatives (17,054 ) — 216 — (16,838 ) Cash Settlements of Derivatives 24,117 — 903 — 25,020 Dry Hole Expense 198 96 — (5 ) 289 Gain on Sale of Asset (235 ) (42 ) — — (277 ) Impairment Expense 124,856 11 — — 124,867 Changes in operating assets and liabilities Accounts Receivable 18,987 (1,707 ) 328 (657 ) 16,951 Inventory, Prepaid Expenses and Other Assets 1,376 (278 ) (74 ) — 1,024 Accounts Payable and Accrued Liabilities (21,251 ) (2,492 ) (898 ) 657 (23,984 ) Other Assets and Liabilities (915 ) (73 ) 27 — (961 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 43,226 3,459 (164,188 ) 137,309 19,806 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 65,125 (3,184 ) 76,592 (138,533 ) — Proceeds from Joint Venture Acreage Management 43 — — — 43 Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 3,979 554 — — 4,533 Proceeds from Joint Venture 16,611 — — — 16,611 Acquisitions of Undeveloped Acreage (21,109 ) (5 ) — — (21,114 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (119,054 ) (7,815 ) — 1,224 (125,645 ) NET CASH USED IN INVESTING ACTIVITIES (54,405 ) (10,450 ) 76,592 (137,309 ) (125,572 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — 33,960 124,000 — 157,960 Repayments of Long-Term Debt and Lines of Credit — (25,443 ) (31,000 ) — (56,443 ) Repayments of Loans and Other Long-Term Debt (633 ) (520 ) — — (1,153 ) Debt Issuance Costs — (3 ) (569 ) — (572 ) Dividends Paid — — (4,830 ) — (4,830 ) Distributions by the Partners of Consolidated Subsidiaries — (830 ) — — (830 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (633 ) 7,164 87,601 — 94,132 NET INCREASE (DECREASE) IN CASH (11,812 ) 173 5 — (11,634 ) CASH – BEGINNING 17,978 118 — — 18,096 CASH - ENDING $ 6,166 $ 291 $ 5 $ — $ 6,462

Basis of Presentation and Pri35

Basis of Presentation and Principles of Consolidation - Additional Information (Details) - USD ($)		6 Months Ended
		Jun. 30, 2016	Dec. 31, 2015
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Senior secured line of credit and long term debt, net issuance costs		$ 141,237,000	$ 109,386,000
Senior notes, net of issuance costs	[1]	$ 637,314,000	$ 663,089,000
8.875% Senior Notes
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Interest rate		8.875%	8.875%
Debt instrument maturity date		Dec. 1, 2020
6.25% Senior Notes
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Interest rate		6.25%	6.25%
Debt instrument maturity date		Aug. 1, 2022
Accounting Standards Update201503
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Senior secured line of credit and long term debt, net issuance costs			$ 2,100,000
Senior notes, net of issuance costs			11,900,000
Accounting Standards Update201503 | 8.875% Senior Notes
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Senior notes, net of issuance costs			350,000,000
Accounting Standards Update201503 | 6.25% Senior Notes
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Senior notes, net of issuance costs			325,000,000
Accounting Standards Update201517
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Long-term tax assets			12,500,000
Current deferred tax liability			12,500,000
Net deferred tax			$ 0
[1]	Includes unamortized debt issuance costs of approximately $9.1 million and $11.9 million as of June 30, 2016 and December 31, 2015, respectively.

Future Abandonment Cost - Addit

Future Abandonment Cost - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Accretion expense	$ 100	$ 300	$ 365	$ 500

Future Abandonment Cost (Detail

Future Abandonment Cost (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Beginning Balance at January 1, 2016				$ 11,934
Future Abandonment Obligation Incurred				282
Future Abandonment Obligation Settled				(4)
Future Abandonment Obligation Cancelled or Sold				(4,568)
Future Abandonment Obligation Accretion Expense		$ 100	$ 300	365	$ 500
Total Future Abandonment Cost	[1]	$ 8,009		$ 8,009
[1]	Includes approximately $0.3 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) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Asset Retirement Obligations [Line Items]
Accrued Liabilities	$ 30,346	$ 40,608
Remediation Property for Sale, Abandonment or Disposal
Asset Retirement Obligations [Line Items]
Accrued Liabilities	$ 300

Discontinued Operations_ Assets

Discontinued Operations/ Assets Held for Sale - Additional Information (Details)	Jun. 14, 2016USD ($)	Jul. 31, 2015USD ($)	Jun. 30, 2016USD ($)a	Jun. 30, 2015USD ($)	Jun. 30, 2016USD ($)abbl	Jun. 30, 2015USD ($)	Dec. 31, 2014
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gain on asset held for sale		$ 66,800,000
Gain classified as other (income) expense			$ (12,000)	$ (61,000)	$ (12,000)	$ (92,000)
Proceeds from sale of oil and gas-related properties and assets	$ 37,500,000
Received purchase from deposits	2,500,000
Proceeds receivable quarterly installments.	$ 900,000
Proceeds receivable quarterly installments beginning period.	Dec. 31, 2016
Proceeds receivable quarterly installments ending period.	Jun. 30, 2019
Area of land held for sale | a			76,000		76,000
Number of barrels net production per day | bbl					1,700
Maximum
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Additional proceeds from sale of oil and gas property and equipment	$ 9,900,000
Water Solutions Holdings, LLC
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Ownership percentage by parent							60.00%
American Water Works Company, Inc.
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Aggregate consideration of Water Solutions				130,000,000		130,000,000
Discontinued Operations Assets Held For Sale | Water Solutions Holdings, LLC
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gain classified as other (income) expense		$ 57,800,000		$ 17,000		$ 120,000

Summary of Financial Informatio

Summary of Financial Information for Discontinued Operations (Details) $ in Thousands	1 Months Ended	3 Months Ended		6 Months Ended
	Jul. 31, 2015USD ($)	Jun. 30, 2016USD ($)bbl	Jun. 30, 2015USD ($)bbl	Jun. 30, 2016USD ($)bbl	Jun. 30, 2015USD ($)bbl
Revenues:
TOTAL OPERATING REVENUE		$ 31,265	$ 35,784	$ 56,951	$ 81,718
Costs and Expenses:
Production and Lease Operating Expense		25,221	24,270	49,672	47,387
General and Administrative Expense		4,837	7,394	10,121	15,745
Impairment Expense		25,139	117,839	35,780	124,687
Exploration Expense		803	755	1,738	1,194
Depreciation, Depletion, Amortization and Accretion		14,750	24,698	31,262	46,537
(Gain) Loss on Disposal of Assets		(4,307)	(373)	(4,295)	(309)
Interest Expense		11,439	12,181	24,469	24,193
Other (Income) Expense		(12)	(61)	(12)	(92)
Income (Loss) from Discontinued Operations, net of taxes		(1,683)	(461)	(9,173)	(1,985)
Discontinued Operations Assets Held For Sale | Water Solutions Holdings, LLC
Revenues:
Field Services Revenue			16,643		31,607
TOTAL OPERATING REVENUE			16,643		31,607
Costs and Expenses:
General and Administrative Expense			902		1,879
Depreciation, Depletion, Amortization and Accretion			37		76
Field Services Operating Expense			13,464		24,753
(Gain) Loss on Disposal of Assets			(10)		(42)
Interest Expense			240		431
Other (Income) Expense	$ 57,800		17		120
Total Costs and Expenses			14,650		27,217
Income (Loss) from Discontinued Operations Before Income Taxes			1,993		4,390
Income Tax (Expense) Benefit			101		(242)
Income (Loss) from Discontinued Operations, net of taxes			2,094		4,148
Discontinued Operations Assets Held For Sale | Illinois Basin Operations
Revenues:
Oil Sales		6,393	9,989	11,213	18,176
TOTAL OPERATING REVENUE		6,393	9,989	11,213	18,176
Costs and Expenses:
Production and Lease Operating Expense		5,029	6,372	10,725	12,307
General and Administrative Expense		659	1,086	1,437	2,385
Impairment Expense			3	3,543	178
Exploration Expense		85	162	143	241
Depreciation, Depletion, Amortization and Accretion		2,186	4,840	5,083	9,127
(Gain) Loss on Disposal of Assets		(2)	72	(43)	73
Interest Expense		1	13	3	17
Other (Income) Expense		(2)	(4)	(3)	(19)
Total Costs and Expenses		7,956	12,544	20,888	24,309
Income (Loss) from Discontinued Operations Before Income Taxes		(1,563)	(2,555)	(9,675)	(6,133)
Income Tax (Expense) Benefit		(120)		502
Income (Loss) from Discontinued Operations, net of taxes		$ (1,683)	$ (2,555)	$ (9,173)	$ (6,133)
Production:
Crude Oil (Bbls) | bbl		150,980	182,724	308,720	362,541

Average Spot Price (Details)

Average Spot Price (Details)	6 Months Ended
	Jun. 30, 2016$ / bbl
12/31/2016
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	54.25
3/31/2017
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	56.25
6/30/2017
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	58.25
9/30/2017
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	60.25
12/31/2017
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	60.75
3/31/2018
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	61.25
6/30/2018
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	61.75
9/30/2018
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	62.25
12/31/2018
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	62.75
3/31/2019
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	63.25
6/30/2019
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Average Price	63.75

Summary of Carrying Value of As

Summary of Carrying Value of Assets and Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Assets:
Total Current Assets	$ 46,549	$ 60,451
Liabilities:
Total Liabilities Related to Assets Held for Sale	39,935	36,320
Illinois Basin Operations
Assets:
Accounts Receivable	2,367	2,209
Inventory, Prepaid Expenses and Other	1,023	770
Total Current Assets	3,390	2,979
Evaluated Oil & Gas Properties	297,222	296,338
Unevaluated Oil & Gas Properties	37
Other Property and Equipment	19,354	19,749
Wells and Facilities in Progress	3,401	3,456
Accumulated Depreciation, Depletion, and Amortization	(276,855)	(262,071)
Total Long-Term Assets	43,159	57,472
Total Assets Held for Sale	46,549	60,451
Liabilities:
Accounts Payable	4,831	1,089
Current Maturities of Long-Term Debt	85	188
Accrued Liabilities	3,285	3,718
Total Current Liabilities	8,201	4,995
Long-Term Debt		10
Future Abandonment Cost	31,734	31,315
Total Long-Term Liabilities	31,734	31,325
Total Liabilities Related to Assets Held for Sale	39,935	36,320
Net Assets Held for Sale	$ 6,614	$ 24,131

Business and Oil and Gas Prop43

Business and Oil and Gas Property Dispositions - Additional Information (Details)	Jun. 14, 2016USD ($)	May 20, 2016USD ($)Well	Mar. 01, 2016Well	Mar. 31, 2015USD ($)Well	Jun. 30, 2016USD ($)Well	Jun. 30, 2016USD ($)Well	Jun. 30, 2016USD ($)Well	Jun. 30, 2015USD ($)
Business Acquisition And Dispositions [Line Items]
Payments for interest in wells that have been drilled or in process of being drilled | $							$ 37,738,000	$ 125,645,000
Proceeds from sale of oil and gas-related properties and assets | $	$ 37,500,000
Arc Light Capital Partners Limited Liability Corporation
Business Acquisition And Dispositions [Line Items]
Percentage of estimated well costs				35.00%
Consideration for the transaction | $				$ 67,000,000
Amount received at closing of wells | $				$ 16,600,000
Payments for interest in wells that have been drilled or in process of being drilled | $					$ 61,400,000
Percentage of working interest attained through return on investment and internal rate of return				50.00%
Percentage of working interest				35.00%
Percentage of remaining working interest				17.50%
Number of drilled and completed wells to be placed into service					4	4	4
Arc Light Capital Partners Limited Liability Corporation | Butler County, Pennsylvania
Business Acquisition And Dispositions [Line Items]
Number of specifically designated wells for development				32
Benefit Street Partners Limited Liability Corporation
Business Acquisition And Dispositions [Line Items]
Consideration for the transaction | $						$ 175,000,000
Amount received at closing of wells | $						110,000,000
Payments for interest in wells that have been drilled or in process of being drilled | $						$ 24,600,000
Percentage of working interest			65.00%
Number of drilled and completed wells to be placed into service					4	4	4
Number of wells in which BSP Options to Participate in development					36	36	36
Number of wells in which BSP Options exercised to Participate in development					16
Number of producing wells					18	18	18
Number of wells elected for line and producing					38	38	38
Number of drilled well that is awaiting completion					7	7	7
Number of wells awaiting pipeline connection					4	4	4
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 | Maximum
Business Acquisition And Dispositions [Line Items]
Percentage of working interest earned in acreage			20.00%
Benefit Street Partners Limited Liability Corporation | Butler County, Pennsylvania
Business Acquisition And Dispositions [Line Items]
Number of specifically designated wells for development			16
Percentage of estimated well costs			15.00%
Number of drilled and completed wells to be placed into service					12	12	12
Benefit Street Partners Limited Liability Corporation | Moraine East and Warrior North
Business Acquisition And Dispositions [Line Items]
Number of specifically designated wells for development			58
Benefit Street Partners Limited Liability Corporation | Warrior North Ohio
Business Acquisition And Dispositions [Line Items]
Number of specifically designated wells for development			6
Percentage of estimated well costs			65.00%
Number of drilled and completed wells to be placed into service					6	6	6
Diversified Oil and Gas LLC
Business Acquisition And Dispositions [Line Items]
Proceeds from sale of oil and gas-related properties and assets | $		$ 51,000
Number of wells sold including pipelines and support equipment		300
Gain on disposition of oil and gas property | $					$ 4,600,000
Uncollectible accounts receivable written off | $					$ 200,000

Recently Issued Accounting Pr44

Recently Issued Accounting Pronouncements - Additional Information (Details) - USD ($)		Jun. 30, 2016	Dec. 31, 2015
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Senior secured line of credit and long term debt, net issuance costs		$ 141,237,000	$ 109,386,000
Senior notes, net of issuance costs	[1]	$ 637,314,000	663,089,000
Accounting Standards Update201503
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Senior secured line of credit and long term debt, net issuance costs			2,100,000
Senior notes, net of issuance costs			11,900,000
ASU 2015-17, Income Taxes
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Long-term deferred tax assets			12,500,000
Current deferred tax liability			12,500,000
Net deferred tax			$ 0
[1]	Includes unamortized debt issuance costs of approximately $9.1 million and $11.9 million as of June 30, 2016 and December 31, 2015, respectively.

Concentrations of Credit Risk -

Concentrations of Credit Risk - Additional Information (Details) - Sales - Customer Concentration Risk	6 Months Ended
	Jun. 30, 2016Customer
Purchaser
Concentration Risk [Line Items]
Percentage of revenue from major customers	95.30%
Number of major customers	5
Largest single purchaser
Concentration Risk [Line Items]
Percentage of revenue from major customers	49.70%

Long-Term Debt - Senior Credit

Long-Term Debt - Senior Credit Facility - Additional Information (Details) - USD ($)	6 Months Ended
	Jun. 30, 2016	Jul. 01, 2016	Dec. 31, 2015	Jun. 30, 2015
Debt Instrument [Line Items]
Line of credit facility, amount outstanding	$ 146,700,000		$ 111,500,000
Cash and Cash Equivalents	3,438,000		$ 1,091,000	$ 6,113,000
Letter Of Credit
Debt Instrument [Line Items]
Line of credit facility, remaining borrowing capacity	43,300,000
Senior Credit Facility
Debt Instrument [Line Items]
Line of credit facility, current borrowing capacity	$ 190,000,000
Line of credit facility, maturity date	Sep. 12, 2019
Current ratio	80.00%
Net senior secured debt to EBITDAX	240.00%
Expected capital expenditure for current fiscal year	$ 65,000,000
Expected capital expenditure for next fiscal year	$ 65,000,000
Expected senior secured debt to PDP coverage ratio up to next fiscal year	200.00%
Senior Credit Facility | Subsequent Event
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity		$ 190,000,000
Senior Credit Facility | Maximum
Debt Instrument [Line Items]
Cash and Cash Equivalents	$ 15,000,000
Criteria of net senior secured debt to EBITDAX	275.00%
Senior Credit Facility | Minimum
Debt Instrument [Line Items]
Criteria Current ratio	100.00%
Criteria senior secured debt to PDP coverage ratio	165.00%
Senior Credit Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 400,000,000
Senior Credit Facility | Letter Of Credit
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 60,000,000

Long-Term Debt - Senior Notes -

Long-Term Debt - Senior Notes - Additional Information (Details) - USD ($) shares in Millions	Mar. 31, 2016	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Debt Instrument [Line Items]
Share of common stock			10.1
Gain recognized due to troubled debt exchanges		$ (533,000)		$ (9,014,000)
Shares issued	8.4			8.4
Fair value of stock issued	$ 6,500,000		$ 6,500,000
Accrued and unpaid interest	$ 12,800,000		12,800,000
Third-party debt issuance costs				$ 3,838,000	$ 572,000
Issuance of unrestricted common stock shares	5.2			5.2
Gain on Extinguishment of Debt		23,707,000		$ 23,707,000
Trailing quarters fixed charge coverage ratio						225.00%
Fixed charge coverage ratio				116.00%
Senior Notes additional borrowings		148,600,000		$ 148,600,000
Premium on Senior Notes, Net		1,524,000		1,524,000		$ 2,344,000
Amortization of net premium		100,000		$ 200,000
Maximum
Debt Instrument [Line Items]
Senior notes offered for exchange			675,000,000
Interest Payments One Through Three
Debt Instrument [Line Items]
Debt Instrument, Frequency of Periodic Payment				semi-annual
New Notes
Debt Instrument [Line Items]
Gain recognized due to troubled debt exchanges			0
Aggregate principal amount	$ 633,200,000		$ 633,200,000
Additional issuance of debt	500,000
Debt instrument initial interest payment date				Oct. 1, 2016
Debt instrument maturity date				Oct. 1, 2020
Third-party debt issuance costs		$ 500,000		$ 9,000,000
Debt amount for conversion	$ 2,200,000
Debt instrument redemption date				Apr. 1, 2018
Latest date for equity proceeds to be applied to optional Note redemption				Apr. 1, 2018
Percentage of notes that can be redeemed				35.00%
New Notes | Interest Payments One Through Three
Debt Instrument [Line Items]
Interest rate	1.00%		1.00%
New Notes | Interest Payments Four And Thereafter
Debt Instrument [Line Items]
Interest rate	8.00%		8.00%
2020 Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount	$ 324,000,000		$ 324,000,000
Percentage of senior notes exchanged for new notes	92.60%
Debt instrument redemption amount	$ 26,900,000
2022 Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount	$ 309,100,000		$ 309,100,000
Percentage of senior notes exchanged for new notes	95.10%
8.875% Senior Notes
Debt Instrument [Line Items]
Interest rate		8.875%		8.875%		8.875%
Debt instrument maturity date				Dec. 1, 2020
6.25% Senior Notes
Debt Instrument [Line Items]
Interest rate		6.25%		6.25%		6.25%
Debt instrument maturity date				Aug. 1, 2022

Components of Long-Term Debt an

Components of Long-Term Debt and Lines of Credit (Details) - USD ($) $ in Thousands		Jun. 30, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Senior Notes, Net of Issuance Costs	[1]	$ 637,314	$ 663,089
Premium on Senior Notes, Net		1,524	2,344
Senior Line of Credit, Net of Issuance Costs	[2],[3]	141,237	109,396
Capital Leases and Other Obligations	[3]	172	419
Total Debt		780,247	775,248
Less Current Portion of Long-Term Debt		(172)	(402)
Total Long-Term Debt		780,075	774,846
Total Debt		$ 778,723	$ 772,904
[1]	Includes unamortized debt issuance costs of approximately $9.1 million and $11.9 million as of June 30, 2016 and December 31, 2015, respectively.
[2]	Includes unamortized debt issuance costs of approximately $5.4 million and $2.1 million as of June 30, 2016 and December 31, 2015, respectively.
[3]	The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. The weighted average interest rate on borrowings under our Senior Credit Facility for the six months ended June 30, 2016 and the year ended December 31, 2015, was approximately 3.2 % and 1.7%, respectively. The average interest rate on our capital leases and other obligations for the six months ended June 30, 2016 and the year ended December 31, 2015, was approximately 4.5% and 5.5%, respectively.

Components of Long-Term Debt 49

Components of Long-Term Debt and Lines of Credit (Parenthetical) (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Senior Notes
Debt Instrument [Line Items]
Unamortized debt issuance expense	$ 9.1	$ 11.9
Senior Line of Credit
Debt Instrument [Line Items]
Unamortized debt issuance expense	$ 5.4	$ 2.1
Senior Credit Facility
Debt Instrument [Line Items]
Average interest rate	3.20%	1.70%
Capital Leases and Other Obligations
Debt Instrument [Line Items]
Average interest rate	4.50%	5.50%

Principal Maturity Schedule for

Principal Maturity Schedule for Debt Outstanding (Details) $ in Thousands	Jun. 30, 2016USD ($)
Debt Disclosure [Abstract]
2,016	$ 165
2,017	7
2,019	146,670
2,020	640,251
Thereafter	6,160
Total	$ 793,253	[1]
[1]	Excludes $1.5 million net premium on Senior Notes and $14.5 million in debt issuance costs

Principal Maturity Schedule f51

Principal Maturity Schedule for Debt Outstanding (Parenthetical) (Details) $ in Millions	Jun. 30, 2016USD ($)
Debt Instrument [Line Items]
Senior notes, net premium	$ 1.5
New Notes
Debt Instrument [Line Items]
Debt issuance costs	$ 14.5

Derivative Instruments and Fa52

Derivative Instruments and Fair Value Measurements - Additional Information (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives			$ (30,340,000)	$ (25,020,000)
Senior Line of Credit	$ 146,700,000		146,700,000		$ 111,500,000
Senior Notes	646,400,000		646,400,000
Derivative interest rate outstanding	0		0		0
Derivatives asset (liability)	(19,700,000)		(19,700,000)		$ 35,800,000
Unrealized gain (loss) on commodity derivative contracts			1,400,000	3,400,000
Impairment Expense	$ 25,139,000	$ 117,839,000	35,780,000	124,687,000
Other Than Temporary Impairment
Derivatives Fair Value [Line Items]
Impairment Expense			$ 35,800,000
Crude Oil | Minimum
Derivatives Fair Value [Line Items]
Commodity hedged on annualized basis hedge through 2016	100.00%		100.00%
Natural Gas | Minimum
Derivatives Fair Value [Line Items]
Commodity hedged on annualized basis hedge through 2016	90.00%		90.00%
Commodity hedged on annualized basis hedge through 2017	50.00%		50.00%
Natural Gas Liquids | Minimum
Derivatives Fair Value [Line Items]
Commodity hedged on annualized basis hedge through 2016	50.00%		50.00%
Commodity derivatives
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives	$ 17,400,000	13,500,000	$ 30,500,000	24,100,000
Interest Rate Swap
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives		$ 400,000
Interest Rate Swaption
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives				$ 900,000

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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	$ (29,169)	$ (281)	$ (25,120)	$ 16,838
Crude Oil
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	(2,494)	(2,828)	(2,169)	50
Refined Products
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	84	50	65	(6)
Natural Gas
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	(18,666)	3,036	(13,302)	16,635
Natural Gas Liquids
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	$ (8,093)	(60)	$ (9,714)	374
Interest Rate Swap
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net		$ (479)		$ (215)

Asset or Liability Financial Co

Asset or Liability Financial Commodity Derivative Instrument Positions (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2016USD ($)$ / bbl$ / Mcf$ / galbblMcf	Dec. 31, 2015USD ($)
2016 | Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	2,110,000
Floor | $ / Mcf	2.63
Ceiling | $ / Mcf	3.03
Derivatives asset (liability)	$ (409)
2016 | Cap Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	60,000
Put Option | $ / bbl	30
Swap | $ / bbl	44
Derivatives asset (liability)	$ (361)
Crude Oil | 2016
Derivatives Fair Value [Line Items]
Volume | bbl	482,000
Derivatives asset (liability)	$ (1,759)
Crude Oil | 2016 | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	272,000
Floor | $ / bbl	38.05
Ceiling | $ / bbl	49.15
Derivatives asset (liability)	$ (956)
Crude Oil | 2016 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	150,000
Put Option | $ / bbl	31.20
Floor | $ / bbl	41.40
Ceiling | $ / bbl	49.60
Derivatives asset (liability)	$ (442)
Refined Product (Heating Oil)
Derivatives Fair Value [Line Items]
Volume | bbl	6,000
Derivatives asset (liability)	$ (117)
Refined Product (Heating Oil) | 2016 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	6,000
Swap | $ / gal	84
Derivatives asset (liability)	$ (117)
Natural Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	128,973,000
Derivatives asset (liability)	$ (13,356)
Natural Gas | Basis Swaps Dominion South
Derivatives Fair Value [Line Items]
Derivatives asset (liability)	(4,431)	$ (5,468)
Natural Gas | Basis Swaps Texas Gas
Derivatives Fair Value [Line Items]
Derivatives asset (liability)	$ (744)	$ (38)
Natural Gas | 2016 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	1,505,000
Put Option | $ / Mcf	2.11
Floor | $ / Mcf	2.68
Ceiling | $ / Mcf	3.30
Derivatives asset (liability)	$ (377)
Natural Gas | 2016 | Cap Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	2,400,000
Put Option | $ / Mcf	2.59
Swap | $ / Mcf	3.07
Derivatives asset (liability)	$ (612)
Natural Gas | 2016 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	8,155,000
Swap | $ / Mcf	2.54
Derivatives asset (liability)	$ (3,475)
Natural Gas | 2016 | Swaptions
Derivatives Fair Value [Line Items]
Volume | Mcf	600,000
Swap | $ / Mcf	3.15
Derivatives asset (liability)	$ 79
Natural Gas | 2016 | Put Spreads
Derivatives Fair Value [Line Items]
Volume | Mcf	6,015,000
Put Option | $ / Mcf	2.51
Floor | $ / Mcf	3.27
Derivatives asset (liability)	$ 760
Natural Gas | 2016 | Basis Swaps Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	11,113,000
Swap | $ / Mcf	(0.88)
Derivatives asset (liability)	$ (139)
Natural Gas | 2017 | Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	1,400,000
Floor | $ / Mcf	2.40
Ceiling | $ / Mcf	3.10
Derivatives asset (liability)	$ (348)
Natural Gas | 2017 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	16,900,000
Put Option | $ / Mcf	2.32
Floor | $ / Mcf	3.01
Ceiling | $ / Mcf	3.87
Derivatives asset (liability)	$ 594
Natural Gas | 2017 | Cap Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	3,900,000
Put Option | $ / Mcf	2.35
Swap | $ / Mcf	2.81
Derivatives asset (liability)	$ (1,559)
Natural Gas | 2017 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	2,460,000
Swap | $ / Mcf	3.21
Derivatives asset (liability)	$ 178
Natural Gas | 2017 | Swaptions
Derivatives Fair Value [Line Items]
Volume | Mcf	0
Derivatives asset (liability)	$ (670)
Natural Gas | 2017 | Basis Swaps Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	4,550,000
Swap | $ / Mcf	(0.83)
Derivatives asset (liability)	$ (1,073)
Natural Gas | 2017 | Calls
Derivatives Fair Value [Line Items]
Volume | Mcf	3,000,000
Ceiling | $ / Mcf	3.64
Derivatives asset (liability)	$ (1,277)
Natural Gas | 2017 | Basis Swaps Texas Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	14,600,000
Swap | $ / Mcf	(0.13)
Derivatives asset (liability)	$ (372)
Natural Gas | 2018 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	7,875,000
Put Option | $ / Mcf	2.29
Floor | $ / Mcf	2.88
Ceiling | $ / Mcf	3.56
Derivatives asset (liability)	$ (755)
Natural Gas | 2018 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	960,000
Swap | $ / Mcf	3.25
Derivatives asset (liability)	$ 495
Natural Gas | 2018 | Swaptions
Derivatives Fair Value [Line Items]
Volume | Mcf	0
Derivatives asset (liability)	$ (320)
Natural Gas | 2018 | Basis Swaps Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	6,400,000
Swap | $ / Mcf	(0.83)
Derivatives asset (liability)	$ (1,073)
Natural Gas | 2018 | Calls
Derivatives Fair Value [Line Items]
Volume | Mcf	5,810,000
Ceiling | $ / Mcf	3.97
Derivatives asset (liability)	$ (485)
Natural Gas | 2018 | Basis Swaps Texas Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	14,600,000
Swap | $ / Mcf	(0.13)
Derivatives asset (liability)	$ (372)
Natural Gas | 2019 | Basis Swaps Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	7,300,000
Swap | $ / Mcf	(0.83)
Derivatives asset (liability)	$ (1,073)
Natural Gas | 2020 | Basis Swaps Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	7,320,000
Swap | $ / Mcf	(0.83)
Derivatives asset (liability)	$ (1,073)
Natural Gas Liquids
Derivatives Fair Value [Line Items]
Volume | bbl	2,052,000
Derivatives asset (liability)	$ (4,475)
Natural Gas Liquids | 2016 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	714,000
Swap | $ / bbl	26.04
Derivatives asset (liability)	$ (261)
Natural Gas Liquids | 2016 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	330,000
Swap | $ / bbl	8.40
Derivatives asset (liability)	$ (766)
Natural Gas Liquids | 2017 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	468,000
Swap | $ / bbl	20.16
Derivatives asset (liability)	$ (2,228)
Natural Gas Liquids | 2017 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	540,000
Swap | $ / bbl	10.08
Derivatives asset (liability)	$ (1,220)

Combined Fair Value of Derivati

Combined Fair Value of Derivatives (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	$ 4,760	$ 34,260
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	1,526	9,534
Total Derivative Assets	6,286	43,794
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(15,902)	(2,486)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(10,091)	(5,556)
Total Derivative Liabilities	(25,993)	(8,042)
Natural Gas Liquids | Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	1,127	10,250
Long-Term Derivative Assets:
Total Long-Term Derivative Assets		344
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(3,878)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(1,724)
Natural Gas
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(10,091)	(5,556)
Natural Gas | Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets		1,728
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(558)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(199)
Natural Gas | Three Way Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	783	6,183
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	783	5,108
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(973)	(31)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(1,131)	(84)
Natural Gas | Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	879	9,010
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	743	1,593
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(4,323)	(292)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(101)
Natural Gas | Cap Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	334	1,977
Long-Term Derivative Assets:
Total Long-Term Derivative Assets		2,294
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(1,670)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(835)
Natural Gas | Basis Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	397	70
Long-Term Derivative Assets:
Total Long-Term Derivative Assets		195
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(1,258)	(1,585)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(4,314)	(4,186)
Natural Gas | Swaptions
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	79	798
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(326)	(202)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(664)	(297)
Natural Gas | Put Spreads
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	806	1,737
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(46)
Natural Gas | Calls
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(639)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(1,123)	(989)
Crude Oil | Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets		1,078
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(956)
Crude Oil | Deferred Put Spreads
Short-Term Derivative Assets:
Total Short-Term Derivative Assets		852
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(361)
Crude Oil | Three Way Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	355	577
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(797)
Refined Product (Heating Oil) | Swaps
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	$ (117)	$ (376)

Significant Unobservable Inputs

Significant Unobservable Inputs Used in Fair Value Measurements of Natural Gas Basis Swaps (Details) - Natural Gas $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2016USD ($)$ / Mcf	Dec. 31, 2015USD ($)$ / Mcf
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Derivatives asset (liability) | $	$ (13,356)
Basis Swaps Dominion South
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Weighted Average (price per Mcf)	(0.72)	(0.74)
Derivatives asset (liability) | $	$ (4,431)	$ (5,468)
Basis Swaps Dominion South | Minimum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)	(0.34)	(0.27)
Basis Swaps Dominion South | Maximum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)	(1.17)	(1.08)
Basis Swaps Texas Gas
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Weighted Average (price per Mcf)	(0.10)	(0.12)
Derivatives asset (liability) | $	$ (744)	$ (38)
Basis Swaps Texas Gas | Minimum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)	(0.08)	(0.05)
Basis Swaps Texas Gas | Maximum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)	(0.12)	(0.17)

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, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	$ (19,707)	$ 35,752
Significant Other Observable Inputs (Level 2)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	(14,532)	41,258
Significant Unobservable Inputs (Level 3)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	$ (5,175)	$ (5,506)

Reconciliation of Commodity Der

Reconciliation of Commodity Derivative Contracts Measured at Fair Value on Recurring Basis Using Significant Unobservable Inputs (Level 3) (Details) - Commodity derivatives - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Fair Value Net Derivative Asset Liability Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance of Level 3	$ (5,506)	$ 1,341
Changes in Fair Value	(1,376)	3,367
Settlements Paid (Received)	1,707	(1,673)
Ending Balance of Level 3	$ (5,175)	$ 3,035

Financial Instruments Not Recor

Financial Instruments Not Recorded at Fair Value (Details) - USD ($)		Jun. 30, 2016	Dec. 31, 2015
Derivatives Fair Value [Line Items]
Senior Notes, Net of Issuance Costs	[1]	$ 637,314,000	$ 663,089,000
Secured Line of Credit, Net of Issuance Costs		141,237,000	109,396,000
Capital Leases and Other Obligations	[2]	172,000	419,000
Total Debt		778,723,000	772,904,000
Fair Value
Derivatives Fair Value [Line Items]
Senior Notes, Net of Issuance Costs		113,721,000	137,402,000
Secured Line of Credit, Net of Issuance Costs		141,237,000	109,396,000
Capital Leases and Other Obligations		172,000	411,000
Total		$ 255,130,000	$ 247,209
[1]	Includes unamortized debt issuance costs of approximately $9.1 million and $11.9 million as of June 30, 2016 and December 31, 2015, respectively.
[2]	The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. The weighted average interest rate on borrowings under our Senior Credit Facility for the six months ended June 30, 2016 and the year ended December 31, 2015, was approximately 3.2 % and 1.7%, respectively. The average interest rate on our capital leases and other obligations for the six months ended June 30, 2016 and the year ended December 31, 2015, was approximately 4.5% and 5.5%, respectively.

Schedule of Income Tax Included

Schedule of Income Tax Included in Continuing Operations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Income Tax (Expense) Benefit	$ 393		$ (2,321)
Effective Tax Rate	0.70%	0.00%	(2.20%)	0.00%

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2016	Jun. 30, 2015
Income Tax Disclosure [Line Items]
Statutory rate		35.00%	35.00%
Cancellation of debt income	$ 23,707	$ 23,707
Net operating loss carryforwards alternative minimum tax payment	2,100	2,100
State income taxes payable	200	200
Income tax refunds			$ 500
Senior Notes
Income Tax Disclosure [Line Items]
Cancellation of debt income		$ 543,200
Income on taxable losses and reduction of cancellation of debt income	$ 2,000

Capital Stock - Additional Info

Capital Stock - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	Mar. 31, 2016	Feb. 29, 2016	Mar. 31, 2016	Nov. 15, 2015	Aug. 15, 2015	May 15, 2015	Feb. 15, 2015	Jun. 30, 2016	May 27, 2016	Dec. 31, 2015
Schedule Of Capitalization Equity [Line Items]
Common stock, shares authorized	100,000,000		100,000,000					200,000,000	200,000,000	200,000,000
Preferred Stock, shares authorized								100,000		100,000
Common Stock, shares issued								78,440,589		55,741,229
Common Stock, shares outstanding								78,440,589		55,741,229
Issuance of common stock	8,400,000							8,400,000
Debt converted to common stock	5,200,000							5,200,000
Preferred Stock, par value								$ 0.001		$ 0.001
Preferred Stock, shares issued								4,087		16,100
Preferred Stock, shares outstanding								4,087		16,100
Preferred stock shares converted			10,100,000
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								4,087		16,100
Preferred Stock, shares outstanding								4,087		16,100
Preferred stock shares converted								12,013
Dividend per share in amount								$ 600
Dividend per share percentage								6.00%
Quarterly cash dividend paid per share		$ 0		$ 150	$ 150	$ 150	$ 150
Accumulated dividends in arrears								$ 3.8
Quarterly cash dividend amount paid				$ 2.4	$ 2.4	$ 2.4	$ 2.4
Depositary shares
Schedule Of Capitalization Equity [Line Items]
Liquidation preference per share								$ 10,000
Common Stock
Schedule Of Capitalization Equity [Line Items]
Preferred stock convertible preferred stock								9,000,000

Employee Benefit and Equity P63

Employee Benefit and Equity Plans - Additional Information (Details)	3 Months Ended				6 Months Ended		12 Months Ended
	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)shares	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)shares	Jun. 30, 2016USD ($)EmployeesPerson$ / sharesshares	Jun. 30, 2015USD ($)EmployeesPersonshares	Dec. 31, 2015$ / shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of option issued to purchase common stock | shares					888,922	80,000
Share-based compensation	$ 100,000		$ 100,000		$ 100,000	$ 100,000
Stock options exercised | shares					0
Tax benefit related to stock option exercises					$ 0	$ 0
Outstanding weighted average remaining term (in years)					5 years 2 months 12 days
Weighted average remaining term of options exercisable (in years)					1 year 6 months
Aggregate intrinsic value of options outstanding	0				$ 0
Aggregate intrinsic value of options exercisable	0				0
Unrecognized compensation expense	500,000				$ 500,000
Restricted Stock or Unit Expense		$ 1,500,000		$ 2,500,000
Stock Options
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of employees | Employees					34	3
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	1,100,000		$ 1,800,000		$ 900,000	$ 4,600,000
Unrecognized compensation expense	$ 2,800,000				$ 2,800,000
Common stock issued by compensation committee | shares					428,826	1,351,497
Number of employees subjected to issuance of common stock | Person					25	127
Number of non employee contractor subject to issuance of common stock | Person						1
Fair value of TSR awards of per share estimated on date of grant | $ / shares					$ 1.65
Unrecognized compensation expense weighted average period, in years					1 year 3 months 18 days
Vested stock | shares					245,468
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		235,573		189,872
Restricted Stock | Director
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of employees subjected to issuance of common stock | Person						1

Summary of Issued and Outstandi

Summary of Issued and Outstanding Stock Options (Details)	Jun. 30, 2016$ / sharesshares
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Number Outstanding | shares	1,304,472
Weighted-Average Exercise Price, Outstanding	$ 4.35
Number Exercisable | shares	363,505
Weighted-Average Exercise Price, Exercisable	$ 10.71
Exercise Price Range 0.97
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 0.97
Number Outstanding | shares	37,500
Weighted-Average Exercise Price, Outstanding	$ 0.97
Weighted-Average Exercise Price, Exercisable	0.97
Exercise Price Range 1.69
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 1.69
Number Outstanding | shares	826,800
Weighted-Average Exercise Price, Outstanding	$ 1.69
Weighted-Average Exercise Price, Exercisable	1.69
Exercise Price Range 4.05
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 4.05
Number Outstanding | shares	40,000
Weighted-Average Exercise Price, Outstanding	$ 4.05
Weighted-Average Exercise Price, Exercisable	4.05
Exercise Price Range 4.90
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 4.90
Number Outstanding | shares	40,000
Weighted-Average Exercise Price, Outstanding	$ 4.90
Number Exercisable | shares	3,333
Weighted-Average Exercise Price, Exercisable	$ 4.90
Exercise Price Range 5.04
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 5.04
Number Outstanding | shares	46,041
Weighted-Average Exercise Price, Outstanding	$ 5.04
Number Exercisable | shares	46,041
Weighted-Average Exercise Price, Exercisable	$ 5.04
Exercise Price Range 9.50
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 9.50
Number Outstanding | shares	75,000
Weighted-Average Exercise Price, Outstanding	$ 9.50
Number Exercisable | shares	75,000
Weighted-Average Exercise Price, Exercisable	$ 9.50
Exercise Price Range 9.99
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 9.99
Number Outstanding | shares	129,583
Weighted-Average Exercise Price, Outstanding	$ 9.99
Number Exercisable | shares	129,583
Weighted-Average Exercise Price, Exercisable	$ 9.99
Exercise Price Range 10.42
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 10.42
Number Outstanding | shares	29,548
Weighted-Average Exercise Price, Outstanding	$ 10.42
Number Exercisable | shares	29,548
Weighted-Average Exercise Price, Exercisable	$ 10.42
Exercise Price Range 13.19
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 13.19
Number Outstanding | shares	50,000
Weighted-Average Exercise Price, Outstanding	$ 13.19
Number Exercisable | shares	50,000
Weighted-Average Exercise Price, Exercisable	$ 13.19
Exercise Price Range 22.34
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 22.34
Number Outstanding | shares	30,000
Weighted-Average Exercise Price, Outstanding	$ 22.34
Number Exercisable | shares	30,000
Weighted-Average Exercise Price, Exercisable	$ 22.34

Monte Carlo Simulation Model As

Monte Carlo Simulation Model Assumptions Used to Estimate Fair Value of Restricted Stock (Details)	12 Months Ended
	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected Dividend Yield	0.00%
Risk-Free Interest Rate	1.00%
Expected Volatility	58.60%
Market Index	35.60%
Expected Life	3 years
Peer Group
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected Volatility Rate Minimum	29.80%
Expected Volatility Rate Maximum	85.00%

Summary of Nonvested Stock Acti

Summary of Nonvested Stock Activity (Details) - Restricted Stock - $ / shares	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock awards, beginning balance, Number of Shares	2,479,408
Awards, Number of Shares	428,826	1,351,497
Forfeitures, Number of Shares	(381,437)
Vested, Number of Shares	(245,468)
Stock awards, ending balance, Number of Shares	2,281,329
Stock awards, beginning balance, Weighted Average Grant Date Fair Value	$ 6.27
Awards, Weighted Average Grant Date Fair Value	1.65
Forfeitures, Weighted Average Grant Date Fair Value	7.44
Vested, Weighted Average Grant Date Fair Value	10.67
Stock awards, ending balance, Weighted Average Grant Date Fair Value	$ 4.74

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details)	1 Months Ended			3 Months Ended		6 Months Ended
	Jan. 31, 2016USD ($)	Jan. 31, 2015USD ($)	Oct. 31, 2011Plaintiff	Jun. 30, 2016USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2016USD ($)	Jun. 30, 2015USD ($)Rigs	Dec. 31, 2015USD ($)	Sep. 30, 2015Rigs
Loss Contingencies [Line Items]
Number of plaintiffs | Plaintiff			2
Case dismissed period						2012-05
Case revised decision period						2013-05
Significant probable or possible environmental contingent liabilities				$ 0		$ 0
Letters of credit				43,300,000		43,300,000
Rent expense				300,000	$ 300,000	600,000	$ 500,000
Termination fees incurred							4,800,000
Loss on Contract Termination	$ 2,500,000	$ 2,500,000
Maximum guarantee of payment of obligations				414,000,000		$ 414,000,000
Guarantee obligations period						2,029
Transportation, processing and marketing expenses of natural gas, condensate and natural gas liquids				21,800,000	20,500,000	$ 43,300,000	39,400,000
Fees related to unutilized capacity commitments				700,000	200,000	1,000,000	400,000
Production and Lease Operating Expense				25,221,000	24,270,000	49,672,000	47,387,000
Accrued Liabilities				$ 30,346,000		$ 30,346,000		$ 40,608,000
Capacity Reservation
Loss Contingencies [Line Items]
Estimated working interest				53.00%		53.00%
Charges incurred for unutilized processing capacity				$ 800,000	200,000	$ 1,400,000	$ 400,000
Capacity Reservation | 2016
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed				7,300,000		7,300,000
Capacity Reservation | 2017
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed				16,500,000		16,500,000
Capacity Reservation | 2018
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed				16,500,000		16,500,000
Capacity Reservation | 2019
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed				16,500,000		16,500,000
Capacity Reservation | 2020
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed				16,500,000		16,500,000
Capacity Reservation | Thereafter
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed				97,600,000		97,600,000
Drilling Commitments
Loss Contingencies [Line Items]
Number of rigs to support Appalachian Basin operations | Rigs									1
Number of contracts terminated | Rigs							2
Drilling Commitments | 2016
Loss Contingencies [Line Items]
Minimum cost to retain drilling rigs						1,100,000
Minimum gross cost to retain the completion services						500,000
Drilling Commitments | 2017
Loss Contingencies [Line Items]
Minimum cost to retain drilling rigs						2,300,000
Drilling Commitments | 2018
Loss Contingencies [Line Items]
Minimum cost to retain drilling rigs						$ 300,000
Pennsylvania Impact Fee
Loss Contingencies [Line Items]
Rate in which unconventional wells are charged						20.00%
Production and Lease Operating Expense				800,000	$ 800,000	$ 1,300,000	$ 1,500,000
Accrued Liabilities				$ 1,300,000		$ 1,300,000

Lease Commitments for Each of N

Lease Commitments for Each of Next Five Years (Details) $ in Thousands	Jun. 30, 2016USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,016	$ 506
2,017	997
2,018	565
2,019	563
2,020	422
Total	$ 3,053

Minimum Net Obligations under S

Minimum Net Obligations under Sales, Gathering and Transportation Agreements (Details) $ in Thousands	Jun. 30, 2016USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,016	$ 15,342
2,017	43,885
2,018	47,328
2,019	47,216
2,020	46,060
Thereafter	528,816
Total	$ 728,647

Fee for Unconventional Gas Well

Fee for Unconventional Gas Wells (Details) - Pennsylvania Impact Fee	6 Months Ended
	Jun. 30, 2016USD ($)	[1]
Less than $2.25
Unconventional Gas Wells [Line Items]
Year One	$ 40,200
Year Two	30,200
Year Three	25,200
Year 4 – 10	10,100
Year 11 – 15	5,000
$2.26 - $2.99
Unconventional Gas Wells [Line Items]
Year One	45,300
Year Two	35,200
Year Three	30,200
Year 4 – 10	15,100
Year 11 – 15	5,000
$3.00 - $4.99
Unconventional Gas Wells [Line Items]
Year One	50,300
Year Two	40,200
Year Three	30,200
Year 4 – 10	20,100
Year 11 – 15	10,100
$5.00 - $5.99
Unconventional Gas Wells [Line Items]
Year One	55,300
Year Two	45,300
Year Three	40,200
Year 4 – 10	20,100
Year 11 – 15	10,100
More than $5.99
Unconventional Gas Wells [Line Items]
Year One	60,400
Year Two	55,300
Year Three	50,300
Year 4 – 10	20,100
Year 11 – 15	$ 10,100
[1]	Pricing utilized for determining annual fee is based on the arithmetic mean of the NYMEX settled price for the near-month contract as reported by the Wall Street Journal for the last trading day of each month of a calendar year for the 12-month period ending December 31.

Earnings Per Common Share - Add

Earnings Per Common Share - Additional Information (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
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	2.3	8.9	2.3	8.9
Increase (decrease) in net income (loss) attributable to common shareholders.	$ 72.3		$ 72.3
Stock Options
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share	1.3	0.5	1.3	0.5
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	0.7	1.3	0.7	1.3

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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Numerator:
Net Loss From Continuing Operations	$ (52,911)	$ (151,342)	$ (105,562)	$ (166,335)
Net Loss From Discontinued Operations, Less Noncontrolling Interests	(1,683)	(1,410)	(9,173)	(4,231)
Preferred Stock Dividends	(1,723)	(2,415)	(3,828)	(4,830)
Effect of Preferred Stock Conversions	72,316		72,316
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 15,999	$ (155,167)	$ (46,247)	$ (175,396)
Denominator:
Weighted Average Common Shares Outstanding - Basic	71,804	54,118	64,044	54,090
Effect of Dilutive Securities:
Weighted Average Common Shares Outstanding - Diluted	71,804	54,118	64,044	54,090
Earnings per Common Share Attributable to Rex Energy Common Shareholders:
Basic — Net Income (Loss) From Continuing Operations	$ 0.24	$ (2.84)	$ (0.58)	$ (3.16)
Basic — Net Loss From Discontinued Operations	(0.02)	(0.03)	(0.14)	(0.08)
Basic – Net Income (Loss) Attributable to Rex Energy Common Shareholders	0.22	(2.87)	(0.72)	(3.24)
Diluted — Net Income (Loss) From Continuing Operations	0.24	(2.84)	(0.58)	(3.16)
Diluted — Net Loss From Discontinued Operations	(0.02)	(0.03)	(0.14)	(0.08)
Diluted – Net Income (Loss) Attributable to Rex Energy Common Shareholders	$ 0.22	$ (2.87)	$ (0.72)	$ (3.24)

Equity Method Investments - Add

Equity Method Investments - Additional Information (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Schedule Of Equity Method Investments [Line Items]
Impairment Expense	$ 25,139,000	$ 117,839,000	$ 35,780,000	$ 124,687,000
Loss on Equity Method Investments		(208,000)		(411,000)
Equity Method Investments		0		0
Production and Lease Operating Expense	$ 25,221,000	24,270,000	$ 49,672,000	47,387,000
RW Gathering, LLC
Schedule Of Equity Method Investments [Line Items]
Ownership percentage	40.00%		40.00%
Impairment Expense		17,500,000		17,500,000
Contributions to Equity Method Investments			$ 0	0
Loss on Equity Method Investments	$ (500,000)	$ (500,000)	(1,000,000)	(1,000,000)
Impairment charge in percentage		100.00%
Production and Lease Operating Expense	100,000	$ 200,000	300,000	$ 400,000
Receivables	0		0		$ 0
Payables	$ 0		$ 0		$ 0

Impairment Expense - Additional

Impairment Expense - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense	$ 25,139	$ 117,839	$ 35,780	$ 124,687
Undeveloped properties, cost	$ 232,700		232,700
RW Gathering, LLC
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense		$ 17,500		17,500
Butler County, Pennsylvania, and Warrior County, Ohio
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense			34,800
Butler County | Proved Properties
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense			$ 1,000
Clearfield and Westmoreland Counties, Pennsylvania | Proved Properties
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense				73,400
Clearfield and Westmoreland Counties, Pennsylvania | Unproved Property Impairments
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense				$ 31,600

Exploration Expense - Additiona

Exploration Expense - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Exploration Expense [Line Items]
Exploration Expense	$ 803	$ 755	$ 1,738	$ 1,194
Geological and Geophysical Type Expenditures
Exploration Expense [Line Items]
Exploration Expense			900	500
Payment of Delay Rentals
Exploration Expense [Line Items]
Exploration Expense				500
Dry Hole Expense For Non Operated Properties
Exploration Expense [Line Items]
Exploration Expense			$ 800	$ 200

Condensed Consolidating Finan76

Condensed Consolidating Financial Information - Additional Information (Details) $ in Millions	Jun. 30, 2016USD ($)
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Senior Notes, Gross	$ 646.4

Condensed Consolidating Balance

Condensed Consolidating Balance Sheets (Details) - USD ($)		Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015
Current Assets
Cash and Cash Equivalents		$ 3,438,000	$ 1,091,000	$ 6,113,000
Accounts Receivable		31,644,000	17,274,000
Taxes Receivable		48,000	18,000
Short-Term Derivative Instruments		4,760,000	34,260,000
Inventory, Prepaid Expenses and Other		1,688,000	3,059,000
Assets Held for Sale		46,549,000	60,451,000
Total Current Assets		88,127,000	116,153,000
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,020,936,000	943,092,000
Unevaluated Oil and Gas Properties		232,674,000	262,992,000
Other Property and Equipment		21,444,000	20,363,000
Wells and Facilities in Progress		75,992,000	141,100,000
Pipelines		14,144,000	14,024,000
Total Property and Equipment		1,365,190,000	1,381,571,000
Less: Accumulated Depreciation, Depletion and Amortization		(459,427,000)	(437,828,000)
Net Property and Equipment		905,763,000	943,743,000
Deferred Financing Costs and Other Assets—Net			2,501,000
Equity Method Investments				$ 0
Other Assets		2,490,000	2,501,000
Long-Term Derivative Instruments		1,526,000	9,534,000
Total Assets		997,906,000	1,071,931,000
Current Liabilities
Accounts Payable		51,915,000	36,785,000
Current Maturities of Long-Term Debt		172,000	402,000
Accrued Liabilities		30,346,000	40,608,000
Short-Term Derivative Instruments		15,902,000	2,486,000
Liabilities Related to Assets Held for Sale		39,935,000	36,320,000
Total Current Liabilities		138,270,000	116,601,000
Long-Term Derivative Instruments		10,091,000	5,556,000
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs		141,237,000	109,386,000
Senior Notes, Net of Issuance Costs	[1]	637,314,000	663,089,000
Premium on Senior Notes, Net		1,524,000	2,344,000
Other Deposits and Liabilities		2,860,000	3,156,000
Future Abandonment Cost		7,731,000	11,568,000
Total Liabilities		939,027,000	911,700,000
Stockholders’ Equity
Preferred Stock		1,000	1,000
Common Stock		77,000	54,000
Additional Paid-In Capital		637,223,000	623,863,000
Accumulated Earnings (Deficit)		(578,422,000)	(463,687,000)
Total Stockholders’ Equity		58,879,000	160,231,000
Total Liabilities and Stockholders’ Equity		997,906,000	1,071,931,000
Eliminations
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties			(6,970,000)
Wells and Facilities in Progress			(270,000)
Pipelines			(2,137,000)
Total Property and Equipment			(9,377,000)
Less: Accumulated Depreciation, Depletion and Amortization			3,518,000
Net Property and Equipment			(5,859,000)
Intercompany Receivables		(1,071,155,000)	(1,070,548,000)
Investment in Subsidiaries – Net		130,362,000	(241,424,000)
Total Assets		(940,793,000)	(1,317,831,000)
Current Liabilities
Intercompany Payables		(1,071,155,000)	(1,070,548,000)
Total Liabilities		(1,071,155,000)	(1,070,548,000)
Stockholders’ Equity
Additional Paid-In Capital		(177,144,000)	(173,057,000)
Accumulated Earnings (Deficit)		307,506,000	(74,226,000)
Total Stockholders’ Equity		130,362,000	(247,283,000)
Total Liabilities and Stockholders’ Equity		(940,793,000)	(1,317,831,000)
Guarantor Subsidiaries
Current Assets
Cash and Cash Equivalents		3,435,000	1,089,000
Accounts Receivable		27,694,000	17,225,000
Short-Term Derivative Instruments		4,760,000	34,260,000
Inventory, Prepaid Expenses and Other		1,688,000	3,034,000
Assets Held for Sale		45,466,000	59,411,000
Total Current Assets		83,043,000	115,019,000
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,020,936,000	950,062,000
Unevaluated Oil and Gas Properties		232,674,000	262,992,000
Other Property and Equipment		21,444,000	20,363,000
Wells and Facilities in Progress		75,992,000	141,370,000
Pipelines		14,144,000	16,161,000
Total Property and Equipment		1,365,190,000	1,390,948,000
Less: Accumulated Depreciation, Depletion and Amortization		(459,427,000)	(441,346,000)
Net Property and Equipment		905,763,000	949,602,000
Deferred Financing Costs and Other Assets—Net			2,501,000
Other Assets		2,490,000
Investment in Subsidiaries – Net		(2,388,000)	(1,907,000)
Long-Term Derivative Instruments		1,526,000	9,534,000
Total Assets		990,434,000	1,074,749,000
Current Liabilities
Accounts Payable		51,915,000	36,785,000
Current Maturities of Long-Term Debt		172,000	402,000
Accrued Liabilities		24,498,000	28,883,000
Short-Term Derivative Instruments		15,902,000	2,486,000
Liabilities Related to Assets Held for Sale		39,903,000	36,289,000
Total Current Liabilities		132,390,000	104,845,000
Long-Term Derivative Instruments		10,091,000	5,556,000
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs			28,000
Other Deposits and Liabilities		2,860,000	3,156,000
Future Abandonment Cost		7,313,000	11,159,000
Intercompany Payables		1,066,506,000	1,070,096,000
Total Liabilities		1,219,160,000	1,194,840,000
Stockholders’ Equity
Additional Paid-In Capital		177,144,000	177,143,000
Accumulated Earnings (Deficit)		(405,870,000)	(297,234,000)
Total Stockholders’ Equity		(228,726,000)	(120,091,000)
Total Liabilities and Stockholders’ Equity		990,434,000	1,074,749,000
Non-Guarantor Subsidiaries
Current Assets
Assets Held for Sale		1,083,000	1,040,000
Total Current Assets		1,083,000	1,040,000
Property and Equipment (Successful Efforts Method)
Total Assets		1,083,000	1,040,000
Current Liabilities
Liabilities Related to Assets Held for Sale		32,000	31,000
Total Current Liabilities		32,000	31,000
Future Abandonment Cost		418,000	409,000
Intercompany Payables		4,649,000	452,000
Total Liabilities		5,099,000	892,000
Stockholders’ Equity
Accumulated Earnings (Deficit)		(4,016,000)	148,000
Total Stockholders’ Equity		(4,016,000)	148,000
Total Liabilities and Stockholders’ Equity		1,083,000	1,040,000
Parent Company
Current Assets
Cash and Cash Equivalents		3,000	2,000
Accounts Receivable		3,950,000	49,000
Taxes Receivable		48,000	18,000
Inventory, Prepaid Expenses and Other			25,000
Total Current Assets		4,001,000	94,000
Property and Equipment (Successful Efforts Method)
Intercompany Receivables		1,071,155,000	1,070,548,000
Investment in Subsidiaries – Net		(127,974,000)	243,331,000
Total Assets		947,182,000	1,313,973,000
Current Liabilities
Accrued Liabilities		5,848,000	11,725,000
Total Current Liabilities		5,848,000	11,725,000
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs		141,237,000	109,358,000
Senior Notes, Net of Issuance Costs		637,314,000	663,089,000
Premium on Senior Notes, Net		1,524,000	2,344,000
Total Liabilities		785,923,000	786,516,000
Stockholders’ Equity
Preferred Stock		1,000	1,000
Common Stock		77,000	54,000
Additional Paid-In Capital		637,223,000	619,777,000
Accumulated Earnings (Deficit)		(476,042,000)	(92,375,000)
Total Stockholders’ Equity		161,259,000	527,457,000
Total Liabilities and Stockholders’ Equity		$ 947,182,000	$ 1,313,973,000
[1]	Includes unamortized debt issuance costs of approximately $9.1 million and $11.9 million as of June 30, 2016 and December 31, 2015, respectively.

Condensed Consolidating Stateme

Condensed Consolidating Statements of Operations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$ 31,271	$ 35,772	$ 56,944	$ 81,696
Other Revenue (Expense)	(6)	12	7	22
TOTAL OPERATING REVENUE	31,265	35,784	56,951	81,718
OPERATING EXPENSES
Production and Lease Operating Expense	25,221	24,270	49,672	47,387
General and Administrative Expense	4,837	7,394	10,121	15,745
Gain on Disposal of Assets	(4,307)	(373)	(4,295)	(309)
Impairment Expense	25,139	117,839	35,780	124,687
Exploration Expense	803	755	1,738	1,194
Depreciation, Depletion, Amortization and Accretion	14,750	24,698	31,262	46,537
Other Operating (Income) Expense	704	(66)	1,030	5,138
TOTAL OPERATING EXPENSES	67,147	174,517	125,308	240,379
LOSS FROM OPERATIONS	(35,882)	(138,733)	(68,357)	(158,661)
OTHER INCOME (EXPENSE)
Interest Expense	(11,439)	(12,181)	(24,469)	(24,193)
Gain (Loss) on Derivatives, Net	(29,169)	(281)	(25,120)	16,838
Other Income	12	61	12	92
Debt Exchange Expense	(533)		(9,014)
Gain on Extinguishment of Debt	23,707		23,707
Loss on Equity Method Investments		(208)		(411)
TOTAL OTHER INCOME (EXPENSE)	(17,422)	(12,609)	(34,884)	(7,674)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(53,304)	(151,342)	(103,241)	(166,335)
Income Tax (Expense) Benefit	393		(2,321)
NET LOSS FROM CONTINUING OPERATIONS	(52,911)	(151,342)	(105,562)	(166,335)
Income (Loss) From Discontinued Operations, Net of Income Tax	(1,683)	(461)	(9,173)	(1,985)
NET LOSS	(54,594)	(151,803)	(114,735)	(168,320)
Net Income Attributable to Noncontrolling Interests		949		2,246
NET LOSS ATTRIBUTABLE TO REX ENERGY	(54,594)	(152,752)	(114,735)	(170,566)
Preferred Stock Dividends	(1,723)	(2,415)	(3,828)	(4,830)
Effect of Preferred Stock Conversions	72,316		72,316
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	15,999	(155,167)	(46,247)	(175,396)
Eliminations
OPERATING EXPENSES
Exploration Expense		(5)		(5)
Depreciation, Depletion, Amortization and Accretion		(264)		(499)
TOTAL OPERATING EXPENSES		(269)		(504)
LOSS FROM OPERATIONS		269		504
OTHER INCOME (EXPENSE)
Income (Loss) From Equity in Consolidated Subsidiaries	65,341	138,226	104,226	141,440
TOTAL OTHER INCOME (EXPENSE)	65,341	138,226	104,226	141,440
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	65,341	138,495	104,226	141,944
NET LOSS FROM CONTINUING OPERATIONS	65,341	138,495	104,226	141,944
Income (Loss) From Discontinued Operations, Net of Income Tax		(1,252)		(1,252)
NET LOSS		137,243	104,226	140,692
NET LOSS ATTRIBUTABLE TO REX ENERGY	65,341	137,243	104,226	140,692
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	65,341	137,243	104,226	140,692
Guarantor Subsidiaries
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	31,271	35,772	56,944	81,696
Other Revenue (Expense)	(6)	12	7	22
TOTAL OPERATING REVENUE	31,265	35,784	56,951	81,718
OPERATING EXPENSES
Production and Lease Operating Expense	25,221	24,270	49,671	47,387
General and Administrative Expense	3,661	5,576	9,080	11,082
Gain on Disposal of Assets	(4,307)	(373)	(4,295)	(309)
Impairment Expense	25,139	117,839	35,780	124,687
Exploration Expense	803	760	1,737	1,198
Depreciation, Depletion, Amortization and Accretion	14,747	24,962	31,249	47,035
Other Operating (Income) Expense	704	(66)	1,030	5,138
TOTAL OPERATING EXPENSES	65,968	172,968	124,252	236,218
LOSS FROM OPERATIONS	(34,703)	(137,184)	(67,301)	(154,500)
OTHER INCOME (EXPENSE)
Interest Expense	(269)	(71)	(539)	(124)
Gain (Loss) on Derivatives, Net	(29,169)	198	(25,120)	17,054
Other Income	12	61	12	92
Loss on Equity Method Investments		(208)		(411)
Income (Loss) From Equity in Consolidated Subsidiaries	(54)	3	79	(20)
TOTAL OTHER INCOME (EXPENSE)	(29,480)	(17)	(25,568)	16,591
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(64,183)	(137,201)	(92,869)	(137,909)
Income Tax (Expense) Benefit	473	119	(2,090)	178
NET LOSS FROM CONTINUING OPERATIONS	(63,710)	(137,082)	(94,959)	(137,731)
Income (Loss) From Discontinued Operations, Net of Income Tax	(1,629)	(2,033)	(9,106)	(5,498)
NET LOSS		(139,115)	(104,065)	(143,229)
NET LOSS ATTRIBUTABLE TO REX ENERGY	(65,339)	(139,115)	(104,065)	(143,229)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	(65,339)	(139,115)	(104,065)	(143,229)
Non-Guarantor Subsidiaries
OPERATING EXPENSES
Production and Lease Operating Expense			1
Exploration Expense			1	1
Depreciation, Depletion, Amortization and Accretion	3		13	1
TOTAL OPERATING EXPENSES	3		15	2
LOSS FROM OPERATIONS	(3)		(15)	(2)
OTHER INCOME (EXPENSE)
Income (Loss) From Equity in Consolidated Subsidiaries	54	(3)	(79)	20
TOTAL OTHER INCOME (EXPENSE)	54	(3)	(79)	20
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	51	(3)	(94)	18
NET LOSS FROM CONTINUING OPERATIONS	51	(3)	(94)	18
Income (Loss) From Discontinued Operations, Net of Income Tax	(54)	2,824	(67)	4,765
NET LOSS		2,821	(161)	4,783
Net Income Attributable to Noncontrolling Interests		949		2,246
NET LOSS ATTRIBUTABLE TO REX ENERGY	(3)	1,872	(161)	2,537
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	(3)	1,872	(161)	2,537
Parent Company
OPERATING EXPENSES
General and Administrative Expense	1,176	1,818	1,041	4,663
TOTAL OPERATING EXPENSES	1,176	1,818	1,041	4,663
LOSS FROM OPERATIONS	(1,176)	(1,818)	(1,041)	(4,663)
OTHER INCOME (EXPENSE)
Interest Expense	(11,170)	(12,110)	(23,930)	(24,069)
Gain (Loss) on Derivatives, Net		(479)		(216)
Debt Exchange Expense	(533)		(9,014)
Gain on Extinguishment of Debt	23,707		23,707
Income (Loss) From Equity in Consolidated Subsidiaries	(65,341)	(138,226)	(104,226)	(141,440)
TOTAL OTHER INCOME (EXPENSE)	(53,337)	(150,815)	(113,463)	(165,725)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(54,513)	(152,633)	(114,504)	(170,388)
Income Tax (Expense) Benefit	(80)	(119)	(231)	(178)
NET LOSS FROM CONTINUING OPERATIONS	(54,593)	(152,752)	(114,735)	(170,566)
NET LOSS		(152,752)	(114,735)	(170,566)
NET LOSS ATTRIBUTABLE TO REX ENERGY	(54,593)	(152,752)	(114,735)	(170,566)
Preferred Stock Dividends	(1,723)	(2,415)	(3,828)	(4,830)
Effect of Preferred Stock Conversions	72,316		72,316
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 16,000	$ (155,167)	$ (46,247)	$ (175,396)

Condensed Consolidating State79

Condensed Consolidating Statements of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$ (54,594)	$ (151,803)	$ (114,735)	$ (168,320)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss from Equity Method Investments		208		411
Non-Cash Expenses (Income)			10,100	5,884
Depreciation, Depletion, Amortization and Accretion			36,345	55,740
Gain on Derivatives	29,169	281	25,120	(16,838)
Cash Settlements of Derivatives			30,340	25,020
Dry Hole Expense			870	289
Gain on Sale of Asset			(4,338)	(277)
Gain on Extinguishment of Debt			(23,757)
Impairment Expense			39,323	124,867
Changes in operating assets and liabilities
Accounts Receivable			(14,772)	16,951
Inventory, Prepaid Expenses and Other Assets			1,118	1,024
Accounts Payable and Accrued Liabilities			10,425	(23,984)
Other Assets and Liabilities			(676)	(961)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES			(4,637)	19,806
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management				43
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets			190	4,533
Proceeds from Joint Venture			19,461	16,611
Acquisitions of Undeveloped Acreage			(5,900)	(21,114)
Capital Expenditures for Development of Oil & Gas Properties and Equipment			(37,738)	(125,645)
NET CASH USED IN INVESTING ACTIVITIES			(23,987)	(125,572)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit			50,400	157,960
Repayments of Long-Term Debt and Line of Credit			(15,230)	(56,443)
Repayments of Loans and Other Notes Payable			(361)	(1,153)
Debt Issuance Costs			(3,838)	(572)
Dividends Paid				(4,830)
Distributions by the Partners of Consolidated Joint Ventures				(830)
NET CASH PROVIDED BY FINANCING ACTIVITIES			30,971	94,132
NET INCREASE (DECREASE) IN CASH			2,347	(11,634)
CASH – BEGINNING			1,091	18,096
CASH – ENDING	3,438	6,462	3,438	6,462
Eliminations
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss		137,243	104,226	140,692
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Depreciation, Depletion, Amortization and Accretion				(3,378)
Dry Hole Expense				(5)
Impairment Expense			(39,323)
Changes in operating assets and liabilities
Accounts Receivable				(657)
Accounts Payable and Accrued Liabilities				657
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES			64,903	137,309
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries			(64,903)	(138,533)
Capital Expenditures for Development of Oil & Gas Properties and Equipment				1,224
NET CASH USED IN INVESTING ACTIVITIES			(64,903)	(137,309)
Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss		(139,115)	(104,065)	(143,229)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss from Equity Method Investments		208		411
Non-Cash Expenses (Income)			(100)	(92)
Depreciation, Depletion, Amortization and Accretion			36,293	56,057
Gain on Derivatives	29,169	(198)	25,120	(17,054)
Cash Settlements of Derivatives			30,340	24,117
Dry Hole Expense			870	198
Gain on Sale of Asset			(4,338)	(235)
Impairment Expense			39,330	124,856
Changes in operating assets and liabilities
Accounts Receivable			(14,452)	18,987
Inventory, Prepaid Expenses and Other Assets			1,093	1,376
Accounts Payable and Accrued Liabilities			15,148	(21,251)
Other Assets and Liabilities			(651)	(915)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES			24,588	43,226
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries			2,035	65,125
Proceeds from Joint Venture Acreage Management				43
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets			190	3,979
Proceeds from Joint Venture			19,461	16,611
Acquisitions of Undeveloped Acreage			(5,863)	(21,109)
Capital Expenditures for Development of Oil & Gas Properties and Equipment			(37,704)	(119,054)
NET CASH USED IN INVESTING ACTIVITIES			(21,881)	(54,405)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Loans and Other Notes Payable			(361)	(633)
NET CASH PROVIDED BY FINANCING ACTIVITIES			(361)	(633)
NET INCREASE (DECREASE) IN CASH			2,346	(11,812)
CASH – BEGINNING			1,089	17,978
CASH – ENDING	3,435	6,166	3,435	6,166
Non-Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss		2,821	(161)	4,783
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Non-Cash Expenses (Income)				100
Depreciation, Depletion, Amortization and Accretion			52	3,061
Dry Hole Expense				96
Gain on Sale of Asset				(42)
Impairment Expense			(7)	11
Changes in operating assets and liabilities
Accounts Receivable			103	(1,707)
Inventory, Prepaid Expenses and Other Assets				(278)
Accounts Payable and Accrued Liabilities				(2,492)
Other Assets and Liabilities			(25)	(73)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES			(38)	3,459
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries			109	(3,184)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets				554
Acquisitions of Undeveloped Acreage			(37)	(5)
Capital Expenditures for Development of Oil & Gas Properties and Equipment			(34)	(7,815)
NET CASH USED IN INVESTING ACTIVITIES			38	(10,450)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit				33,960
Repayments of Long-Term Debt and Line of Credit				(25,443)
Repayments of Loans and Other Notes Payable				(520)
Debt Issuance Costs				(3)
Distributions by the Partners of Consolidated Joint Ventures				(830)
NET CASH PROVIDED BY FINANCING ACTIVITIES				7,164
NET INCREASE (DECREASE) IN CASH				173
CASH – BEGINNING				118
CASH – ENDING		291		291
Parent Company
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss		(152,752)	(114,735)	(170,566)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Non-Cash Expenses (Income)			10,200	5,876
Gain on Derivatives		479		216
Cash Settlements of Derivatives				903
Gain on Extinguishment of Debt			(23,757)
Impairment Expense			39,323
Changes in operating assets and liabilities
Accounts Receivable			(423)	328
Inventory, Prepaid Expenses and Other Assets			25	(74)
Accounts Payable and Accrued Liabilities			(4,723)	(898)
Other Assets and Liabilities				27
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES			(94,090)	(164,188)
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries			62,759	76,592
NET CASH USED IN INVESTING ACTIVITIES			62,759	76,592
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit			50,400	124,000
Repayments of Long-Term Debt and Line of Credit			(15,230)	(31,000)
Debt Issuance Costs			(3,838)	(569)
Dividends Paid				(4,830)
NET CASH PROVIDED BY FINANCING ACTIVITIES			31,332	87,601
NET INCREASE (DECREASE) IN CASH			1	5
CASH – BEGINNING			2
CASH – ENDING	$ 3	$ 5	$ 3	$ 5

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - USD ($) shares in Millions	Jul. 31, 2016	Mar. 31, 2016	Jun. 30, 2016	Jun. 30, 2016	Jul. 01, 2016
Subsequent Event [Line Items]
Debt converted to common stock		5.2		5.2
Minimum | Senior Credit Facility
Subsequent Event [Line Items]
PDP coverage ratio			1.65%
Eleventh Amendment
Subsequent Event [Line Items]
Date of credit agreement				Jul. 1, 2016
Subsequent Event
Subsequent Event [Line Items]
Debt converted to common stock	16.8
Subsequent Event | Senior Credit Facility
Subsequent Event [Line Items]
Line of credit facility, maximum borrowing capacity					$ 190,000,000
New Notes | Subsequent Event
Subsequent Event [Line Items]
Debt amount for conversion	$ 43,500,000