Rex Energy Operating S-4/A 13 May 16 Registration of securities issued in business combination transactions (amended) Financial data

Document and Entity Information

Document and Entity Information	3 Months Ended
	Mar. 31, 2016
Document And Entity Information [Abstract]
Document Type	S-4/A
Amendment Flag	false
Document Period End Date	Mar. 31, 2016
Trading Symbol	REXX
Entity Registrant Name	REX ENERGY CORP
Entity Central Index Key	1,397,516
Entity Filer Category	Accelerated Filer

Consolidated Balance Sheets (Un

Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands		Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash and Cash Equivalents		$ 24,891	$ 1,091	$ 17,978
Accounts Receivable		24,315	19,483	43,936
Taxes Receivable		18	18	504
Short-Term Derivative Instruments		29,012	34,260	29,265
Inventory, Prepaid Expenses and Other		3,168	3,829	3,403
Assets Held for Sale				34,257
Total Current Assets		81,404	58,681	129,343
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,301,479	1,239,430	1,079,039
Unevaluated Oil and Gas Properties		257,697	262,992	322,413
Other Property and Equipment		41,028	40,112	46,361
Wells and Facilities in Progress		75,514	144,556	127,655
Pipelines		16,780	14,024	15,657
Total Property and Equipment		1,692,498	1,701,114	1,591,125
Less: Accumulated Depreciation, Depletion and Amortization		(720,998)	(699,899)	(366,917)
Net Property and Equipment		971,500	1,001,215	1,224,208
Deferred Financing Costs and Other Assets - Net			16,544	17,070
Other Assets		2,489	2,501
Equity Method Investments				17,895
Long-Term Derivative Instruments		8,460	9,534	4,904
Long-Term Deferred Tax Asset			12,532	8,301
Total Assets		1,063,853	1,071,931	1,401,721
Current Liabilities
Accounts Payable		42,818	37,874	53,340
Current Maturities of Long-Term Debt		9,934	590	1,176
Accrued Liabilities		44,296	44,326	59,478
Short-Term Derivative Instruments		3,758	2,486	421
Current deferred tax liability			12,532	8,301
Liabilities Related to Assets Held For Sale				25,115
Total Current Liabilities		100,806	85,276	147,831
Noncurrent Liabilities
Premium on Senior Notes, Net		2,245	2,344	2,725
Senior Secured Line of Credit and Long-Term Debt		143,294	109,396	251
Long-Term Derivative Instruments		6,908	5,556	2,377
Senior Notes	[1]	657,511	663,089
Other Deposits and Liabilities		3,140	3,156	4,018
Future Abandonment Cost		43,412	42,883	38,146
Total Liabilities		$ 957,316	$ 911,700	$ 870,348
Commitments and Contingencies
Stockholders' Equity
Preferred Stock		$ 1	$ 1	$ 1
Common Stock		63	54	54
Additional Paid-In Capital		630,301	623,863	617,826
Accumulated Deficit		(523,828)	(463,687)	(90,749)
Rex Energy Stockholders' Equity			160,231	527,132
Noncontrolling Interests of Discontinued Operations				4,241
Total Stockholders' Equity		106,537	160,231	531,373
Total Liabilities and Stockholders' Equity		$ 1,063,853	1,071,931	1,401,721
Scenario, Previously Reported [Member]
Property and Equipment (Successful Efforts Method)
Deferred Financing Costs and Other Assets - Net			2,501
Total Assets			1,098,506
Current Liabilities
Total Current Liabilities			97,808
Noncurrent Liabilities
Senior Secured Line of Credit and Long-Term Debt			111,528
Total Liabilities			938,275
Stockholders' Equity
Total Liabilities and Stockholders' Equity			1,098,506
8.875% Senior Notes
Noncurrent Liabilities
Senior Notes			350,000	350,000
6.25% Senior Notes
Noncurrent Liabilities
Senior Notes			$ 325,000	$ 325,000
[1]	Includes unamortized debt issuance costs of approximately $11.1 million and $11.9 million as of March 31, 2016 and December 31, 2015, respectively.

Consolidated Balance Sheets (U3

Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Preferred Stock, par value	$ 0.001	$ 0.001	$ 0.001
Preferred Stock, shares authorized	100,000	100,000	100,000
Preferred Stock, shares issued	12,836	16,100	16,100
Preferred Stock, shares outstanding	12,836	16,100	16,100
Common Stock, par value	$ 0.001	$ 0.001	$ 0.001
Common stock, shares authorized	100,000,000	100,000,000	100,000,000
Common Stock, shares issued	66,041,227	55,741,229	54,174,763
Common Stock, shares outstanding	66,041,227	55,741,229	54,174,763
8.875% Senior Notes
Interest rate	8.875%	8.875%	8.875%
6.25% Senior Notes
Interest rate	6.25%	6.25%	6.25%

Consolidated Statements of Oper

Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended									12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$ 30,494				$ 54,111					$ 171,951		$ 297,869		$ 213,919
Other Revenue	13				11					42		118		200
TOTAL OPERATING REVENUE	30,507	$ 34,526	$ 37,573	$ 45,772	54,122	$ 70,245	$ 73,466	$ 72,933	$ 81,343	171,993		297,987		214,119
OPERATING EXPENSES
Production and Lease Operating Expense	30,146				29,052					118,999		100,282		62,150
General and Administrative Expense	6,063				9,651					29,435		36,137		30,839
(Gain) Loss on Disposal of Asset	(30)				65					(477)		644		1,602
Impairment Expense	14,184	81,098	139,812	117,842	7,023	132,576	1	16	25	345,775		132,618		32,072
Exploration Expense	993				518					3,011		9,446		11,408
Depreciation, Depletion, Amortization and Accretion	19,408				26,126					104,744		94,467		62,386
Other Operating Expense	329				5,191					5,595		134		592
TOTAL OPERATING EXPENSES	71,093				77,626					607,082		373,728		201,049
LOSS FROM OPERATIONS	(40,586)				(23,504)					(435,089)		(75,741)		13,070
OTHER EXPENSE
Interest Expense	(13,032)				(12,017)					(47,806)		(36,977)		(22,676)
Gain on Derivatives, Net	4,049				17,119					60,176		38,876		(2,908)
Other Income					34					(115)		90		6,739
Debt Exchange Expense	(8,480)
Loss on Equity Method Investments					(203)					(411)		(813)		(763)
TOTAL OTHER INCOME (EXPENSE)	(17,463)				4,933					11,844		1,176		(19,608)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(58,049)				(18,571)					(423,245)		(74,565)		(6,538)
Income Tax (Expense) Benefit	(2,092)				92					24,227		26,915		4,154
NET LOSS FROM CONTINUING OPERATIONS	(60,141)	(97,873)	(129,293)	(153,373)	(18,479)	(69,668)	5,619	7,643	8,756	(399,018)		(47,650)		(2,384)
Income From Discontinued Operations, Net of Income Taxes					1,962					37,985		5,000		1,811
NET INCOME (LOSS)	(60,141)	(98,037)	(94,676)	(151,803)	(16,517)	(68,631)	6,589	8,955	10,437	(361,033)		(42,650)		(573)
Net Income Attributable to Noncontrolling Interests			(1)	949	1,297	698	895	877	1,569	2,245		4,039		1,557
NET LOSS ATTRIBUTABLE TO REX ENERGY	(60,141)	(98,037)	(94,675)	(152,752)	(17,814)	(69,329)	5,694	8,078	8,868	(363,278)		(46,689)		(2,130)
Preferred Stock Dividends	2,105	2,415	2,415	2,415	2,415	2,335				9,660		2,335
Net Loss Attributable to Common Shareholders	$ (62,246)	$ (100,452)	$ (97,090)	$ (155,167)	$ (20,229)	$ (71,664)	$ 5,694	$ 8,078	$ 8,868	$ (372,938)		$ (49,024)		$ (2,130)
Earnings per common share:
Basic - Net Loss From Continuing Operations Attributable to Rex Energy Common Shareholders	$ (1.11)	$ (1.85)	$ (2.44)	$ (2.88)	$ (0.38)	$ (1.35)	$ 0.11	$ 0.14	$ 0.17	$ (7.51)	[1]	$ (0.94)	[1]	$ (0.05)	[1]
Basic - Net Income From Discontinued Operations Attributable to Rex Energy Common Shareholders			0.64	0.01	0.01			0.01		0.66	[1]	0.02	[1]	0.01	[1]
Basic - Net Loss Attributable to Rex Energy Common Shareholders	$ (1.11)	$ (1.85)	$ (1.80)	$ (2.87)	$ (0.37)	$ (1.35)	$ 0.11	$ 0.15	$ 0.17	$ (6.85)	[1]	$ (0.92)	[1]	$ (0.04)	[1]
Basic - Weighted Average Shares of Common Stock Outstanding	56,003	54,342	53,936	54,118	54,370	53,261	53,214	53,164	52,984	54,392		53,150		52,572
Diluted - Net Loss From Continuing Operations Attributable to Rex Energy Common Shareholders	$ (1.11)	$ (1.85)	$ (2.44)	$ (2.88)	$ (0.38)	$ (1.35)	$ 0.10	$ 0.14	$ 0.17	$ (7.51)	[1]	$ (0.94)	[1]	$ (0.05)	[1]
Diluted - Net Income From Discontinued Operations Attributable to Rex Energy Common Shareholders			0.64	0.01	0.01			0.01		0.66	[1]	0.02	[1]	0.01	[1]
Diluted - Net Loss Attributable to Rex Energy Common Shareholders	$ (1.11)	$ (1.85)	$ (1.80)	$ (2.87)	$ (0.37)	$ (1.35)	$ 0.10	$ 0.15	$ 0.17	$ (6.85)	[1]	$ (0.92)	[1]	$ (0.04)	[1]
Diluted - Weighted Average Shares of Common Stock Outstanding	56,003	54,342	53,936	54,118	54,370	53,261	57,991	53,509	53,503	54,392		53,150		52,572
[1]	All earnings per share amounts are attributable to Rex common shareholders.

Consolidated Statement of Chang

Consolidated Statement of Changes in Stockholders' Equity (Unaudited) - USD ($) $ in Thousands	Total	Common Stock	Preferred Stock	Additional Paid-in Capital	Accumulated Deficit	Parent	Noncontrolling Interest
Balance at Dec. 31, 2012	$ 412,294	$ 52		$ 451,062	$ (39,595)	$ 411,519	$ 775
Balance (in shares) at Dec. 31, 2012		53,213,000
Non-Cash Compensation	5,418			5,418		5,418
Issuance of Restricted Stock, Net of Forfeitures (in shares)		924,000
Stock Option Exercise	$ 536	$ 2		534		536
Stock Option Exercise (in shares)	49,166	49,000
Capital Distributions	$ (886)						(886)
Change in Ownership of Noncontrolling Interests	136			(460)		(460)	596
Net Income (Loss)	(573)				(2,130)	(2,130)	1,557
Balance at Dec. 31, 2013	416,925	$ 54		456,554	(41,725)	414,883	2,042
Balance (in shares) at Dec. 31, 2013		54,186,000
Non-Cash Compensation	5,769			5,769		5,769
Issuance of Restricted Stock, Net of Forfeitures (in shares)		(58,000)
Stock Option Exercise	$ 515			515		515
Stock Option Exercise (in shares)	46,526	47,000
Capital Distributions	$ (1,840)						(1,840)
Issuance of stock, net of issuance costs	154,989		$ 1	154,988		154,989
Issuance of stock, net of issuance costs (in shares)			16,000
Dividends Declared on Preferred Stock	(2,335)				(2,335)	(2,335)
Net Income (Loss)	(42,650)				(46,689)	(46,689)	4,039
Balance at Dec. 31, 2014	531,373	$ 54	$ 1	617,826	(90,749)	527,132	4,241
Balance (in shares) at Dec. 31, 2014		54,175,000	16,000
Non-Cash Compensation	6,469			6,469		6,469
Issuance of Restricted Stock, Net of Forfeitures (in shares)		1,566,000
Capital Distributions	(830)						(830)
Dividends Declared on Preferred Stock	(6,088)			(432)		(432)	(5,656)
Change in Ownership of Noncontrolling Interests	(9,660)				(9,660)	(9,660)
Net Income (Loss)	(361,033)				(363,278)	(363,278)	$ 2,245
Balance at Dec. 31, 2015	160,231	$ 54	$ 1	623,863	(463,687)	$ 160,231
Balance (in shares) at Dec. 31, 2015		55,741,000	16,000
Non-Cash Compensation	(29)			(29)
Issuance of Common Stock in Exchange for Debt	$ 6,476	$ 8		6,468
Issuance Of Common Stock In Exchange For Debt (in shares)		8,413,000
Issuance of Restricted Stock, Net of Forfeitures (in shares)		74,000
Conversion of Preferred Stock to Common Stock		$ 1		(1)
Conversion of Preferred Stock to Common Stock (in shares)		1,813,000	(3,000)
Stock Option Exercise (in shares)	0
Issuance of stock, net of issuance costs (in shares)	8,400,000
Net Income (Loss)	$ (60,141)				(60,141)
Balance at Mar. 31, 2016	$ 106,537	$ 63	$ 1	$ 630,301	$ (523,828)
Balance (in shares) at Mar. 31, 2016		66,041,000	13,000

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$ (60,141)	$ (16,517)	$ (361,033)	$ (42,650)	$ (573)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss from Equity Method Investments		203	411	813	763
Non-cash Expenses	497	3,377	7,649	6,789	6,230
Depreciation, Depletion, Amortization and Accretion	19,408	26,165	104,822	98,171	63,944
Gain on Derivatives	(4,049)	(17,119)	(60,176)	(38,876)	2,908
Cash Settlements of Derivatives	12,994	11,079	55,793	7,281	7,128
Dry Hole Expense	843	(1)	330	4,064	2,993
Deferred Income Tax Expense	2,092			(25,992)	2,279
Impairment Expense	14,184	7,023	345,775	132,684	32,072
(Gain) Loss on Sale of Assets	(30)	33	(521)	589	(6,211)
Gain on Sale of Water Solutions			(57,778)
Changes in operating assets and liabilities
Accounts Receivable	(4,873)	10,029	21,679	(13,620)	(12,726)
Inventory, Prepaid Expenses and Other Assets	660	328	(568)	(1,359)	(885)
Accounts Payable and Accrued Liabilities	(308)	(12,929)	(22,955)	37,274	12,891
Other Assets and Liabilities	(170)	(305)	(2,543)	(2,462)	(2,497)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	(18,893)	11,366	30,885	162,706	108,316
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management		39	58	263	458
Contributions to Equity Method Investments					(2,493)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	71	672	77,226	546	11,305
Proceeds from Joint Venture for Reimbursement of Capital Costs	19,461	16,611	16,611
Acquisitions of Undeveloped Acreage	(5,266)	(17,459)	(28,242)	(169,423)	(41,784)
Acquisitions of Oil and Gas Properties and Equipment			(221,099)	(391,422)	(281,004)
Capital Expenditures for Development of Oil & Gas Properties and Equipment	(15,068)	(67,013)	(221,099)	(391,422)	(281,004)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(802)	(67,150)	(155,446)	(560,036)	(313,518)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Line of Credit	46,500	72,826	229,314	209,895	72,249
Repayments of Long-Term Debt and Line of Credit		(25,761)	(108,335)	(263,152)	(8,480)
Repayments of Loans and Other Notes Payable	(184)	(686)	(1,519)	(2,721)	(2,005)
Proceeds from Senior Notes, net of Discounts and Premiums				325,000	105,000
Debt Issuance Costs	(2,821)	(459)	(1,414)	(6,824)	(3,134)
Proceeds from the Issuance of Preferred Stock, Net				154,988
Proceeds from the Exercise of Stock Options				515	533
Purchase of Noncontrolling Interests				(1,840)	(150)
Distributions by the Partners of Consolidated Joint Ventures		(531)	(830)	(1,840)	(886)
Dividends Paid on Preferred Stock		(2,415)	(9,660)	(2,335)
NET CASH PROVIDED BY FINANCING ACTIVITIES	43,495	42,974	107,556	413,526	163,127
NET INCREASE (DECREASE) IN CASH	23,800	(12,810)	(17,005)	16,196	(42,075)
CASH - BEGINNING	1,091	18,096	18,096	1,900	43,975
CASH - ENDING	24,891	5,286	1,091	18,096	1,900
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO CONTINUING OPERATIONS	24,891	4,964	1,091	17,978	1,307
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO ASSETS HELD FOR SALE		322		118	593
SUPPLEMENTAL DISCLOSURES
Interest Paid, net of capitalized interest	22,479	9,895	47,628	26,874	23,605
Cash Paid for Income Taxes		(502)	(502)	(4,643)	(6,390)
NON-CASH ACTIVITIES
Increase (Decrease) in Accrued Liabilities for Capital Expenditures	$ 2,830	$ (602)	$ (11,703)	$ 3,477	$ 22,138

Consolidated Statement of Chan7

Consolidated Statement of Changes in Stockholders' Equity (Unaudited) (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Statement of Stockholders' Equity [Abstract]
Dividend declared, per preferred share	$ 600	$ 145

Basis of Presentation and Princ

Basis of Presentation and Principles of Consolidation	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
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 and Illinois Basin. In the Appalachian Basin, we are focused on our Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and exploration activities. In the Illinois Basin, we are focused on developmental oil drilling on our properties. 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 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	1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION We are an independent oil, natural gas liquid (“NGL”) and natural gas company with operations currently focused in the Appalachian and Illinois Basins. In the Appalachian Basin, we are focused on our Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and exploration activities. In the Illinois Basin, we are focused on developmental oil drilling on our properties. 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. All material 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. Our revolving credit facility requires we meet, on a quarterly basis, financial requirements of a minimum consolidated current ratio and a maximum net senior secured debt to EBITDAX ratio. EBITDAX is a non-GAAP measure used by our management team and by other users of our financial statements. For a definition of EBITDAX and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Item 6. Selected Financial Data – Non-GAAP Financial Measures.” If we are unable to comply with these financial requirements, an event of default could result which would permit acceleration of outstanding debt and could permit our lenders to foreclose on our mortgaged properties. In order to improve our liquidity position to meet the financial requirements under our revolving credit facility and to meet other outstanding obligations, we are currently pursuing or considering a number of actions including (i) debt-for-debt exchanges, (ii) joint venture opportunities, (iii) minimizing our capital expenditures, (iv) improving our cash flows from operations, (v) effectively managing our working capital (vi) adding additional hedging positions (vii) and in- and out-of-court restructuring. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions or that these transaction can be consummated within the period needed to meet certain obligations. Discontinued Operations 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 4, Discontinued Operations/Assets Held for Sale During December 2011, our board of directors approved a formal plan to sell our DJ Basin assets located in the states of Wyoming and Colorado. Pursuant to the rules for discontinued operations, the results of operations are reflected as Discontinued Operations in our Consolidated Statements of Operations for the year ended December 31, 2013. During December 2014, our board of directors approved and committed to a plan to sell Water Solutions Holdings, LLC and its related subsidiaries (“Water Solutions”), of which we owned a 60% interest. The sale of Water Solutions closed in July 2015. As a result, the assets and liabilities of Water Solutions have been classified as held for sale in the accompanying Consolidated Balance Sheets as of December 31, 2014 and the results of operations have been classified as discontinued operations in the accompanying Consolidated Statements of Operations as of December 31, 2015, 2014 and 2013.

Future Abandonment Cost

Future Abandonment Cost	3 Months Ended
	Mar. 31, 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 for each of the three-month periods ended March 31, 2016 and 2015 totaled approximately $0.9 million. These amounts are recorded as depreciation, depletion, amortization and accretion (“DD&A”) expense on our Consolidated Statements of Operations. We account for future abandonment costs that relate to wells that are drilled jointly based on our working interest in those wells. ($ in Thousands) March 31, 2016 Beginning Balance at January 1, 2016 $ 45,074 Future Abandonment Obligation Incurred 402 Future Abandonment Obligation Settled (361 ) Future Abandonment Obligation Cancelled or Sold (189 ) Future Abandonment Obligation Revision of Estimated Obligation — Future Abandonment Obligation Accretion Expense 856 Total Future Abandonment Cost 1 $ 45,782 1 Includes approximately $2.4 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

Discontinued Operations_Assets

Discontinued Operations/Assets Held For Sale	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE	3. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE 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 $57.8 million. The transaction is recorded as Discontinued Operations. Summarized financial information for Discontinued Operations related to Water Solutions is set forth in the table below, and does not reflect the costs of certain services provided. Such indirect costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support. Three Months Ended March 31, ($ in Thousands) 2016 2015 Revenues: Field Services Revenue $ — $ 14,964 Total Operating Revenue — 14,964 Costs and Expenses: General and Administrative Expense — 977 Depreciation, Depletion, Amortization and Accretion — 39 Field Services Operating Expense — 11,289 Gain on Sale of Asset — (32 ) Interest Expense — 191 Other Expense — 103 Total Costs and Expenses — 12,567 Income from Discontinued Operations Before Income Taxes — 2,397 Income Tax Expense — (435 ) Income from Discontinued Operations, net of taxes $ — $ 1,962	4. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE DJ Basin During December 2011, our board of directors approved a formal plan to sell our DJ Basin assets located in the states of Wyoming and Colorado. During 2012, we sold various parcels of acreage throughout our DJ Basin. During the first quarter of 2013, we entered an agreement to sell our remaining DJ Basin assets for $3.1 million. This transaction closed during the second quarter of 2013 and resulted in a gain of approximately $1.0 million. As of December 31, 2015 and 2014, we had no assets or liabilities related to the DJ Basin or continuing cash flows from this region. Summarized financial information for Discontinued Operations related to our DJ Basin assets is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support. December 31, ($ in Thousands) 2015 2014 2013 Revenues: Oil, Natural Gas and NGL Sales $ — $ — $ 25 Total Operating Revenue — — 25 Costs and Expenses: Production and Lease Operating Expense — — 104 General and Administrative Expense — — 23 Exploration Expense — — 97 Other Operating Income — — (3 ) Gain on Disposal of Asset — — (969 ) Total Income — — (748 ) Income from Discontinued Operations Before Income Taxes — — 773 Income Tax Expense — — (1,005 ) Loss from Discontinued Operations, net of taxes $ — $ — $ (232 ) Production: Crude Oil (Bbls) — — 356 Water Solutions Holdings, LLC As described in Note 3 above, we sold Water Solutions pursuant to a purchase and sale agreement with American Water. The carrying value of the assets and liabilities of Water Solutions Holdings, LLC that are classified as held for sale in the accompanying Consolidated Balance Sheet at December 31, 2014 are as follows: December 31, ($ in Thousands) 2014 Assets: Cash and Cash Equivalents $ 118 Accounts Receivable 13,226 Inventory, Prepaid Expenses and Other 163 Total Current Assets 13,507 Other Property and Equipment, Net 19,690 Wells and Facilities in Progress 688 Intangible Assets, Net 372 Total Long-Term Assets 20,750 Total Assets Held for Sale $ 34,257 Liabilities: Accounts Payable 3,694 Current Maturities of Long-Term Debt 6,236 Accrued Liabilities 6,304 Total Current Liabilities 16,234 Senior Secured Line of Credit and Long-Term Debt 8,881 Long-Term Liabilities 8,881 Total Liabilities Related to Assets Held for Sale $ 25,115 Net Assets Held for Sale: $ 9,142 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 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. December 31, ($ in Thousands) 2015 2014 2013 Revenues: Field Services Revenue $ 33,086 $ 58,627 $ 23,812 Total Operating Revenue 33,086 58,627 23,812 Costs and Expenses: General and Administrative Expense 1,961 4,081 2,287 Depreciation, Depletion, Amortization and Accretion 78 3,703 1,559 Impairment Expense — 67 — Field Service Operating Expense 25,981 44,369 17,318 (Gain) Loss on Disposal of Asset (44 ) (55 ) 46 Interest Expense 487 628 106 Other (Income) Expense (57,589 ) 66 84 Total Costs and Expenses (Income) (29,126 ) 52,859 21,400 Income from Discontinued Operations Before Income Taxes 62,212 5,768 2,412 Income Tax Expense (24,227 ) (768 ) (369 ) Income from Discontinued Operations, net of taxes 37,985 $ 5,000 $ 2,043 During 2015, Water Solutions spent approximately $8.6 million in capital expenditures on facilities and equipment to support its business growth. In addition to its cash capital expenditures, Water Solutions incurred approximately $1.0 million in non-cash vehicle acquisitions primarily related to its capital lease program.

Business and Oil and Gas Proper

Business and Oil and Gas Property Acquisitions and Dispositions	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Business Combinations [Abstract]
BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS AND DISPOSITIONS	4. BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS AND DISPOSITIONS Water Solutions As described in Note 3 above, we sold Water Solutions pursuant to a purchase and sale agreement with American Water. 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 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 March 31, 2016, ArcLight had paid approximately $52.2 million for their interest in wells that have been drilled or are in the process of being drilled. As of March 31, 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 and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, 12 of which have already been drilled and completed and fund 65.0% of the estimated well costs for six designated wells in Warrior North, Ohio, three of which have already been drilled and completed. We expect total consideration for this transaction to be $175.0 million with $37.1 million committed at closing. As of March 31, 2016, BSP had paid approximately $19.5 million for their interest in wells that had previously been completed. The remainder of the proceeds will be received as additional wells are completed. 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. In addition, BSP earns an assignment of 15%-20% working interest in acreage located within each of the units they participate. As of March 31, 2016, 15 of the initial 22 wells were in line and producing, three wells were drilled and awaiting completion and four wells were awaiting pipeline connection. In April 2016, BSP exercised their option to participate in four additional wells to be drilled and completed later in 2016. 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.	3. BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS AND DISPOSITIONS Acquisitions On September 9, 2014, we completed the acquisition of approximately 208,000 gross (207,000 net) acres prospective for the Marcellus, Upper Devonian/Burkett and Utica Shales from SWEPI, LP, an affiliate of Royal Dutch Shell, plc (“Shell”), for approximately $120.6 million in cash, after customary closing adjustments. Included in the acquisition were several producing wells and properties in various stages of development. The assets acquired are located in Armstrong, Beaver, Butler, Lawrence, Mercer and Venango counties in Pennsylvania and Columbiana and Mahoning counties in Ohio. The acquisition does not meet the definition of a business combination and, therefore, has been accounted for as an asset acquisition. The acquisition price was allocated as follows: ($ in Thousands) December 31, 2014 Evaluated Oil and Gas Properties $ 6,968 Unevaluated Oil and Gas Properties 88,351 Wells and Facilities in Progress 25,244 Purchase Price $ 120,563 Dispositions Water Solutions In December 2014, our board of directors approved a formal plan to sell 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 is recorded as Discontinued Operations. 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 and fund 35.0% of the estimated well costs for the designated wells. We expect to receive total consideration for the transaction of approximately $67.0 million, of which $16.6 million was received at closing for wells that had previously been completed or were at that time in the process of being drilled and completed. As of December 31, 2015, ArcLight had paid approximately $39.8 million for their interest in wells that have been drilled or are in the process of being drilled. The remainder of the proceeds will be received as additional wells are and completed and placed into service. 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. 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. Due to the fixed payment per well structure of the transaction, payments by ArcLight are treated as gains or losses, as appropriate, on a well-by-well basis for tax purposes. Keystone Midstream Services, LLC On May 29, 2012, we closed the sale of our ownership in Keystone Midstream Services, LLC (“Keystone Midstream”), which we had accounted for as an equity method investment. The base consideration for the sale was $483.2 million after adjustments for closing cash, working capital and outstanding debt. Our net proceeds at closing totaled $121.4 million, net of $3.3 million for our share of transactional costs which we recorded as Gain (Loss) on Equity Method Investments on our Consolidated Statement of Operations. During the third quarter of 2012, we recorded $0.5 million of post-closing settlement charges, effectively decreasing our net proceeds to approximately $120.9 million. We have used the proceeds to pay down amounts outstanding under our Senior Credit Facility and for working capital. The amount received at closing excluded approximately $14.3 million held in escrow to be paid out over the course of the 12 months following closing. During 2012, we received approximately $7.2 million of the outstanding escrow amount and during 2013 we received final distributions from the escrow of approximately $6.9 million, with the remaining amounts funding claims made by the purchaser. Also included in the proceeds at closing was approximately $3.8 million funded by other sellers in the transaction as consideration for our entry into an amendment to one of our gas gathering, compression and processing agreements. This consideration is recorded as Other Deposits and Liabilities on our Consolidated Balance Sheet and will be recognized in earnings over the term of the gas gathering, compression and processing agreement. We recognized a gain on the sale of our investment of Keystone Midstream, including the post-closing adjustment of $0.5 million and the receipt of the escrow funds of $7.2 million, of $99.4 million, in 2012 and a gain of approximately $6.9 million in 2013, all of which were recorded as Other Income (Expense) in our Consolidated Statement of Operations. See Note 5, Equity Method Investments

Recently Issued Accounting Pron

Recently Issued Accounting Pronouncements	3 Months Ended
	Mar. 31, 2016
Accounting Changes and Error Corrections [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	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
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 three months ended March 31, 2016, approximately 93.5% of our commodity sales came from five purchasers, with the largest single purchaser accounting for 46.0% of commodity sales. We believe the continued growth in our Appalachian Basin operations will help us to minimize our future risks by diversifying our ratio of oil, NGLs and natural gas sales as well as the quantity of purchasers.	6. CONCENTRATIONS OF CREDIT RISK At times during the years ended December 31, 2015 and 2014, our cash balance may have exceeded the Federal Deposit Insurance Corporation’s limit of $250,000. There were no losses incurred due to such concentrations. 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 counterparty 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 five high-quality counterparties. Our counterparties are investment grade financial institutions, and lenders in our Senior Credit Facility. We have a master netting agreement in place with our counterparties that provides for the offsetting of payables against receivables from separate derivative contracts. None of our derivative contracts have a collateral provision that would require funding prior to the scheduled settlement date. For additional information, see Note 2, Summary of Significant Accounting Policies, Fair Value of Financial Instruments and Derivative Instruments, We also depend on a relatively small number of purchasers for a substantial portion of our revenue. At December 31, 2015, we carried approximately $12.1 million in production receivables, of which approximately $10.5 million were production receivables due from four purchasers. At December 31, 2014, we carried approximately $25.2 million in production receivables, of which approximately $21.4 million were production receivables due from four purchasers. We believe the growth in our Appalachian estimated proved reserves will help us to minimize our future risks by diversifying our ratio of oil and gas sales as well as the quantity of purchasers.

Long-Term Debt

Long-Term Debt	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
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 March 13, 2016 (the “Senior Credit Facility”). As of March 31, 2016, the borrowing base under the Senior Credit Facility was $200.0 million; however, the Senior Credit Facility may be increased to up to $500.0 million upon re-determinations of the borrowing base, consent of the lenders and other conditions prescribed by the agreement. Within the Senior Credit Facility, a subfacility exists for up to $60.0 million of letters of credit. Effective April 1, 2016, our borrowing base was further reduced to $190.0 million in connection with our senior note exchange described below. As of March 31, 2016, loans made under the Senior Credit Facility were set to mature on September 12, 2019. Our borrowing base is re-determined at least twice per year with the next re-determination scheduled to occur on or about July 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 March 31, 2016, we had $158.0 million outstanding, approximately $41.0 million in outstanding undrawn letters of credit and approximately $1.0 million available to borrow. 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 of a minimum consolidated current ratio and maximum net senior secured debt to EBITDAX. 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, which includes 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 March 31, 2016 was approximately 0.6 to 1.0. Due to our expectation that we would not be in compliance with the current ratio we previously received a waiver of this requirement from the lenders for the period ended March 31, 2016. We expect to be in compliance with the current ratio covenant at June 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 maximum net senior secured debt to EBITDAX ratio was lowered to 2.75 to 1.0 from 3.0 to 1.0 in connection with our senior note exchange described below. Our ratio of net senior secured debt to EBITDAX as of March 31, 2016 was approximately 2.1 to 1.0. In order to improve our liquidity positions to meet the financial requirements under our revolving 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-equity or debt-for debt exchanges, (ii) joint venture opportunities, (iii) minimizing our capital expenditures, (iv) improving our cash flows from operations, (v) effectively managing our working capital, (vi) adding hedging positions, (vii) and 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 and a new effective interest rate has been established. In exchange for $324.0 million in aggregate principal amount of the 2022 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) $633.7 million aggregate principal amount of New Notes and (ii) issued 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 the 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 payable in cash thereafter. Interest payments are due on April 1 and October 1 of each year, beginning on October 1, 2016 and ending on October 1, 2020. In connection with the Exchange, we incurred approximately $8.5 million in third-party debt issuance costs. These costs were recorded as Debt Exchange Expense in our Statement of Operations for the three-month period ended March 31, 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 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 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 2.25:1. As of March 31, 2016, our Fixed Charge Coverage Ratio was 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 March 31, 2016, we were limited to incurring an additional $68.9 million in debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default. In certain circumstances, the Trustee or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately. As of March 31, 2016 and December 31, 2015, we had recorded on our Consolidated Balance Sheets approximately $2.2 million and $2.3 million, respectively, of a net premium related to the Senior Notes. The amortization of our net premium during the three months ended March 31, 2016, which follows the effective interest method, was approximately $0.1 million and was recorded as a credit to Interest Expense on our Consolidated Statement of Operations. Interest is payable semi-annually on our Existing Notes. Interest on the 2020 Notes is paid at a rate of 8.875% per annum on June 1 and December 1 of each year while interest on the 2022 Notes is paid at a rate of 6.25% per annum on February 1 and August 1 of each year. In addition to the Senior Credit Facility and the Senior Notes, we may, from time to time in the normal course of business finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and other obligations consisted of the following at March 31, 2016 and December 31, 2015: ($ in Thousands) March 31, 2016 December 31, Senior Notes, Net of Issuance Costs (a) $ 657,511 $ 663,089 Premium on Senior Notes, Net 2,245 2,344 Senior Line of Credit, Net of Issuance Costs (b)(c) 152,794 109,396 Capital Leases and Other Obligations(c) 434 618 Total Debt 812,984 775,447 Less Current Portion of Long-Term Debt (9,934 ) (590 ) Total Long-Term Debt $ 803,050 $ 774,857 (a) Includes unamortized debt issuance costs of approximately $11.1 million and $11.9 million as of March 31, 2016 and December 31, 2015, respectively. (b) Includes unamortized debt issuance costs of approximately $5.2 million and $2.1 million as of March 31, 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 three months ended March 31, 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 three months ended March 31, 2016 and the year ended December 31, 2015, was approximately 4.5% and 5.5%, respectively. The following is the principal maturity schedule for debt outstanding as of March 31, 2016: 2016 $ 9,906 2017 28 2018 — 2019 148,500 2020 652,658 Thereafter 15,865 Total(a) $ 826,957 (a) Excludes $2.2 million net premium on Senior Notes and $16.2 million in debt issuance costs	9. LONG-TERM DEBT Senior Credit Facility We maintain a revolving credit facility evidenced by the Credit Agreement, dated March 27, 2013, with Royal Bank of Canada, as Administrative Agent and lenders from time to time parties thereto (as amended from time to time, the “Senior Credit Facility”). Borrowings under the Senior Credit Facility are limited by a borrowing base that is determined in regard to our oil and gas properties. The borrowing base under the Senior Credit Facility as of December 31, 2015 was $350.0 million; however, the revolving credit facility may be increased to up to $500.0 million upon re-determinations of the borrowing base, consent of the lenders and other conditions prescribed in the agreement. Within the Senior Credit Facility, a letter of credit subfacility exists of up to $60.0 million of letters of credit. As of December 31, 2015, we had $41.0 million in undrawn letters of credit outstanding. In conjunction with our offer to exchange senior unsecured notes, on February 3, 2016, our Senior Credit Facility was amended to lower our borrowing base to $200.0 million. Effective April 1, 2016, our borrowing base will be further reduced to $190.0 million. For additional information on our most recent Senior Credit Facility amendments, see Note 26, Subsequent Events Subsequent to our February 3, 2016 amendment, and at our election, borrowings under the Senior Credit Facility bear interest at a rate per annum equal to the “Adjusted LIBO Rate” or the “Alternate Base Rate,” plus, in each case, an applicable per annum margin. The “Adjusted LIBO Rate” is equal to the product of (i) the rate per annum as determined by the administrative agent by reference to the rate set by ICE Benchmark Administration for deposits in dollars for a period equal to the applicable interest period (the “LIBO Rate”), multiplied by (ii) the statutory reserve rate. The Alternate Base Rate is equal to the greatest of (a) Royal Bank of Canada’s prime rate in effect at its principal office in Toronto, Canada, (b) the weighted average of the rates on overnight Federal funds transactions published on the next succeeding business day by the Federal Reserve Bank of New York (the “Federal Funds Effective Rate”), plus 0.5%, and (c) the Adjusted LIBO Rate for a one month interest period plus 1.0%. The applicable per annum margin, in the case of loans bearing interest at the Adjusted LIBO Rate, ranges from 225 to 325 basis points, and in the case of loans bearing interest at the Alternate Base Rate, ranges from 125 to 225 basis points, in each case, determined based upon our borrowing base utilization at such date of determination. Upon the occurrence and continuance of an event of default, all outstanding loans shall bear interest at a per annum rate equal to 200 basis points plus the then effective rate of interest. Interest is payable on the last day of each applicable interest period. Under the Senior Credit Facility, we may enter into commodity swap agreements with counterparties approved by the lenders, provided that the notional volumes for such agreements, when aggregated with other commodity swap agreements then in effect (other than basis differential swaps on volumes already hedged pursuant to other swap agreements), do not exceed, as of the date the swap agreement is executed, 85% of the reasonably anticipated projected production from our proved developed producing reserves for the 36 months following the date such agreement is entered into, and 75% thereafter, for each of crude oil and natural gas, calculated separately. As of December 31, 2015, we were in compliance with these swap agreement restrictions. We may also enter into interest rate swap agreements with counterparties approved by the lenders that convert interest rates from floating to fixed provided that the notional amounts of those agreements, when aggregated with all other similar interest rate swap agreements then in effect, do not exceed the greater of $20 million or 75% of the then outstanding principal amount of our debt for borrowed money which bears interest at a floating rate. The Senior Credit Facility contains covenants that restrict our ability to, among other things, materially change our business; approve and distribute dividends; enter into transactions with affiliates; create or acquire additional subsidiaries; incur indebtedness; sell assets; make loans to others; make investments; enter into mergers; incur liens; and enter into agreements regarding swap and other derivative transactions (for further information, see Note 2, Summary of Significant Accounting Policies Concentrations of Credit Risk Fair Value of Financial Instruments and Derivative Instruments The Senior Credit Facility requires we meet, on a quarterly basis, financial requirements of a minimum consolidated current ratio and a 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, which includes 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 December 31, 2015 was approximately 2.3 to 1.0. We do not anticipate being in compliance with our current ratio requirement at March 31, 2016; however, we have received a waiver of this covenant for the period ending March 31, 2016 from the lenders under our revolving credit facility. Subsequent to March 31, 2016, we expect proceeds from our joint venture operations will bring us back in compliance with the current ratio requirement of 1.0 to 1.0. 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 3.0 to 1.0. Our ratio of total debt to EBITDAX as of December 31, 2015 was approximately 1.7 to 1.0. As a result of the March 14, 2016 amendment, in the event that at least 80% of our Senior Notes exchange such notes for new second lien notes, our required net senior secured debt to EBITDAX ratio will decrease to 2.75 to 1.0. See Note 26, Subsequent Events 2020 Senior Notes and 2022 Senior Notes On December 12, 2012, we issued a $250.0 million aggregate principal amount of 8.875% senior notes in a private offering at an issue price of 99.3% due to mature on December 1, 2020 (the “2020 Senior Notes”). The net proceeds of the 2020 Senior Notes, after discounts and expenses, were approximately $242.2 million. Debt issuance costs of $6.4 million were recorded as Deferred Financing Costs and Other Assets – Net on our Consolidated Balance Sheet and are being amortized over the term of the 2020 Senior Notes as Interest Expense on our Consolidated Statements of Operations using the effective interest method. Interest is payable semi-annually at a rate of 8.875% per annum on June 1 and December 1 of each year, with the first interest payment made on June 1, 2013. On April 26, 2013, we issued an additional $100.0 million in aggregate principal amount of the 2020 Senior Notes in a private offering at an issue price to the initial purchasers of 105% of par plus accrued interest from December 12, 2012. Net proceeds after discounts and offering expenses were approximately $102.8 million plus accrued interest of approximately $3.3 million. Debt issuance costs of $2.3 million were recorded as Deferred Financing Costs and Other Assets – Net on our Consolidated Balance Sheet and are being amortized over the term of the 2020 Senior Notes as Interest Expense on our Consolidated Statements of Operations using the effective interest method. We may redeem, at specified redemption prices, some or all of the 2020 Senior Notes at any time on or after December 1, 2016. If we sell certain of our assets or experience specific kinds of changes in control, we may be required to offer to purchase the 2020 Senior Notes from the holders. On July 17, 2014, we issued a $325.0 million aggregate principal amount of 6.25% senior notes (the “2022 Senior Notes”) in a private offering at an issue price of 100.0% due to mature on August 1, 2022. The net proceeds of the 2022 Senior Notes, after discounts and expenses, were approximately $318.8 million. Debt issuance costs of $6.3 million were recorded as Deferred Financing Costs and Other Assets – Net on our Consolidated Balance Sheet and are being amortized over the term of the notes as Interest Expense on our Consolidated Statements of Operations. Interest is payable semi-annually at a rate of 6.25% per annum on February 1 and August 1 of each year, with the first interest payment made on February 1, 2015. We may redeem, at specified redemption prices, some or all of the 2022 Senior Notes at any time on or after August 1, 2017. We may also redeem up to 35% of the notes using the proceeds of certain equity offerings completed before August 1, 2017. If we sell certain of our assets or experience specific kinds of changes of control, we may be required to offer to purchase the 2022 Senior Notes from the holders. The Senior Notes due 2020 and the Senior Notes due 2022 (collectively, the “Senior Notes”) are fully and unconditionally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries. In addition, there are no significant restrictions on our ability, or the ability of any subsidiary guarantor, to receive funds from our subsidiaries through dividends, loans, advances or otherwise. For additional information on our guarantor and non-guarantor subsidiaries, see Note 25, Condensed Consolidating Financial Information As of December 31, 2015 and 2014, we had recorded on our Consolidated Balance Sheets approximately $677.3 million and $677.7 million of Senior Notes, which is inclusive of a net premium of $2.3 million and $2.7 million, respectively. The amortization of our net premium in 2015 and 2014, which follows the effective interest method, was approximately $0.4 million in each year and was recorded as a credit to Interest Expense on our Consolidated Statement of Operations. Our Senior Notes are governed by indentures with substantially similar terms and provisions (the “Indentures”). The Indentures contain affirmative and negative covenants that are customary for instruments of this nature, including restrictions or limitations on the 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 sell substantially all of its assets, unless those actions satisfy the terms and conditions of the Indentures or are otherwise excepted or permitted. Certain of the limitations in the Indentures, including the 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 2.25:1. As of December 31, 2015, the Company’s Fixed Charge Coverage Ratio was 1.3. We expect our Fixed Charge Coverage Ratio to be less than 2.25:1 for the remainder of 2016. As a result, we anticipate that our ability to incur debt, pay dividends or make certain other restricted payments will be subject to the more restrictive provisions of the Indentures for those periods. As of December 31, 2015, we were limited to incurring an additional $213.6 million in additional debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default, including cross-default features with any other indebtedness. In certain circumstances, the trustee or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately. On February 3, 2016, we announced the commencement of an exchange offer related to our Senior Notes. For additional information on the exchange offer, see Note 26, Subsequent Events, In addition to the Senior Credit Facility and the Senior Notes, we may, from time to time in the normal course of business finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and other obligations consisted of the following at December 31, 2015 and December 31, 2014: ($ in Thousands) December 31, 2015 December 31, 2014 8.875% Senior Notes Due 2020 $ 350,000 $ 350,000 6.25% Senior Notes Due 2022 325,000 325,000 Premium on Senior Notes, Net 2,344 2,725 Senior Line of Credit(a) 111,500 — Capital Leases and Other Obligations(a) 618 1,427 Total Debt 789,462 679,152 Less Current Portion of Long-Term Debt (590 ) (1,176 ) Total Long-Term Debt $ 788,872 $ 677,976 (a) The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2015, 2014 and 2013 was approximately 1.7%, 2.2 % and 1.9%, respectively. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2015, 2014 and 2013 was approximately 5.5%, 4.0% and 5.3%, respectively. The following is the principal maturity schedule for total debt outstanding as of December 31, 2015: ($ in thousands) Year Ended December 31, 2016 $ 590 2017 28 2018 — 2019 111,500 2020 350,000 Thereafter 325,000 Total 1 $ 787,118 1 Does not include $2.3 million net premium on Senior Notes.

Derivative Instruments And Fair

Derivative Instruments And Fair Value Measurements	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Fair Value Disclosures [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 March 31, 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 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 on Derivatives, Net under Other Expense. We received net cash settlements of $13.0 million and $10.6 million in relation to our commodity derivatives during the three months ended March 31, 2016 and 2015, respectively. As of March 31, 2016, we had approximately 100.0% of our annualized oil production hedged through the remainder of 2016, over 100.0% and 50.0% of our annualized natural gas production hedged through the remainder of 2016 and 2017, respectively, and over 40.0% our annualized NGL production hedged through the remainder of 2016. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future drilling and completion or the natural decline of our oil and gas 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 March 31, 2016, and December 31, 2015, we had $158.0 million and $111.5 million outstanding under our Senior Credit Facility, respectively, which is subject to variable rates of interest and $675.0 million of Senior Notes outstanding subject to fixed interest rates. See Note 7, Long-Term Debt As of March 31, 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 months ended March 31, 2015, we received cash payments of approximately $0.5 million related to our interest rate swaptions. The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three months ended March 31, 2016 and 2015: For the Three Months ($ in Thousands) 2016 2015 Oil $ 325 $ 2,876 Natural Gas 5,363 13,600 NGLs (1,621 ) 435 Refined Products (18 ) (55 ) Interest Rate — 263 Gain on Derivatives, Net $ 4,049 $ 17,119 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 asset of approximately $26.8 million and $35.8 million at March 31, 2016 and December 31, 2015, respectively. Our open asset/(liability) financial commodity derivative instrument positions at March 31, 2016 consisted of: Period Volume Put Option Floor Ceiling Swap Fair Market Oil 2016 – Collars 445,750 Bbls $ — $ 38.72 $ 50.28 $ — $ 662 2016 – Three-Way Collars 225,000 Bbls 31.20 41.40 49.60 — 340 2016 – Cap Swaps 60,000 Bbls 30.00 — — 44.00 42 730,750 Bbls $ 1,044 Natural Gas 2016 – Swaps 14,090,000 Mcf — — — 2.95 $ 10,341 2016 – Swaptions 900,000 Mcf — — — 3.15 767 2016 – Cap Swaps 4,050,000 Mcf 2.90 — — 3.48 1,102 2016 – Collars 2,250,000 Mcf — 2.70 3.10 — 973 2016 – Three-Way Collars 8,480,000 Mcf 2.31 2.95 3.55 — 5,054 2016 – Put Spreads 9,470,000 Mcf 2.50 3.26 — — 808 2016 – Basis Swaps – Dominion South 17,665,000 Mcf — — — (0.89 ) (1,879 ) 2017 – Swaps 960,000 Mcf — — — 3.60 903 2017 – Swaptions 0 Mcf — — — — (263 ) 2017 – Cap Swaps 5,700,000 Mcf 2.65 — — 3.20 951 2017 – Three-Way Collars 16,300,000 Mcf 2.33 3.02 3.89 — 5,066 2017 – Calls 3,000,000 Mcf — — 3.64 — (753 ) 2017 – Basis Swaps – Dominion South 4,550,000 Mcf — — — (0.83 ) (1,092 ) 2017 – Basis Swaps – Texas Gas 14,600,000 Mcf — — — (0.13 ) (513 ) 2018 – Swaps 960,000 Mcf — — — 3.60 903 2018 – Swaptions 0 Mcf — — — — (191 ) 2018 – Cap Swaps 1,800,000 Mcf 3.30 — — 4.05 1,060 2018 – Three-Way Collars 7,875,000 Mcf 2.29 2.88 3.56 — 1,046 2018 – Calls 5,810,000 Mcf — — 3.97 — (328 ) 2018 – Basis Swaps – Dominion South 6,400,000 Mcf — — — (0.83 ) (1,092 ) 2018 – Basis Swaps – Texas Gas 14,600,000 Mcf — — — (0.13 ) (513 ) 2019 – Basis Swaps – Dominion South 7,300,000 Mcf — — — (0.83 ) (1,092 ) 2020 – Basis Swaps – Dominion South 7,320,000 Mcf — — — (0.83 ) (1,092 ) 154,080,000 Mcf $ 20,166 NGLs 2016 – C3+ NGL Swaps 1,038,000 Bbls — — — 30.66 $ 6,006 2016 – Ethane Swaps 165,000 Bbls — — — 8.82 155 2017 – C3+ NGL Swaps 468,000 Bbls — — — 20.16 (287 ) 1,671,000 Bbls $ 5,874 Refined Product (Heating Oil) 2016 – Swaps 9,000 Bbls $ — $ — $ — $ 84.00 $ (278 ) 9,000 Bbls $ (278 ) The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015 is summarized below: ($ in Thousands) March 31, December 31, Short-Term Derivative Assets: Crude Oil – Collars $ 662 $ 1,078 Crude Oil – Deferred Put Spread 42 852 Crude Oil – Three-Way Collars 616 577 NGL – Swaps 6,579 10,250 Natural Gas – Swaps 10,576 9,010 Natural Gas – Cap Swaps 1,638 1,977 Natural Gas – Basis Swaps — 70 Natural Gas – Three-Way Collars 6,326 6,183 Natural Gas – Collars 973 1,728 Natural Gas – Swaption 792 798 Natural Gas – Put Spread 808 1,737 Total Short-Term Derivative Assets $ 29,012 $ 34,260 Long-Term Derivative Assets: NGL – Swaps $ 185 $ 344 Natural Gas – Cap Swaps 1,855 2,294 Natural Gas – Swaps 1,580 1,593 Natural Gas – Basis Swaps — 195 Natural Gas – Three-Way Collars 4,840 5,108 Total Long-Term Derivative Assets $ 8,460 $ 9,534 Total Derivative Assets $ 37,472 $ 43,794 Short-Term Derivative Liabilities: Crude Oil – Three-Way Collars (276 ) — NGL – Swaps (490 ) — Refined Product – Swaps (278 ) (376 ) Natural Gas – Three-Way Collars — (31 ) Natural Gas – Basis Swaps (2,280 ) (1,585 ) Natural Gas – Call (189 ) — Natural Gas – Swaption (46 ) (202 ) Natural Gas – Swaps (9 ) (292 ) Natural Gas – Cap Swaps (190 ) — Total Short – Term Derivative Liabilities $ (3,758 ) $ (2,486 ) Long-Term Derivative Liabilities: NGL – Swaps (400 ) — Natural Gas – Swaption (433 ) (297 ) Natural Gas – Basis Swaps (4,993 ) (4,186 ) Natural Gas – Call (892 ) (989 ) Natural Gas – Cap Swaps (190 ) — Natural Gas – Three-Way Collars — (84 ) Total Long-Term Derivative Liabilities $ (6,908 ) $ (5,556 ) Total Derivative Liabilities $ (10,666 ) $ (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 March 31, 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 March 31, 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 March 31, 2016 and December 31, 2015 are included in the table below. As of March 31, 2016 Range (price per Mcf) Weighted (price per Mcf) Fair Value (in thousands) Natural Gas Basis Differential Forward Curve – Dominion South ($ 0.30) – ($1.02) $ (0.85 ) $ (6,247 ) Natural Gas Basis Differential Forward Curve – Texas Gas ($ 0.09) – ($0.13) $ (0.13 ) $ (1,026 ) As of December 31, 2015 Range (price per Mcf) Weighted (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 months ended March 31, 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 March 31, ($ in Thousands) Total Quoted Significant Significant Commodity Derivatives $ 26,806 $ — $ 34,079 $ (7,273 ) Fair Value Measurements at December 31, ($ in Thousands) Total Quoted Significant Significant (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 March 31, 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 March 31, 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 March 31, 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 three months ended March 31, 2016 and 2015: Three Months Ended March 31, ($ in Thousands) 2016 2015 Beginning Balance of Level 3 $ (5,506 ) $ 1,341 Changes in Fair Value (2,037 ) (1,955 ) Purchases — — Settlements Received 270 409 Ending Balance of Level 3 $ (7,273 ) $ (205 ) Changes in fair value on our Level 3 commodity derivative contracts outstanding for each of the three months ended March 31, 2016 and 2015, resulted in decreases of approximately $2.0 million. This amount has been included in Gain on Derivatives, Net in our Consolidated Statements of Operations. Future Abandonment Cost We report the fair value of asset retirement obligations on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 2, Future Abandonment Costs, Financial Instruments Not Recorded at Fair Value The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements: March 31, 2016 December 31, 2015 ($ in Thousands) Carrying Fair Value Carrying Fair Value Senior Notes, Net of Issuance Costs $ 657,511 $ 78,715 $ 663,089 $ 137,402 Secured Line of Credit 152,794 152,794 109,396 109,396 Capital Leases and Other Obligations 434 427 618 606 Total $ 810,739 $ 231,936 $ 773,103 $ 247,404 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 three months ended March 31, 2016, we recorded an other than temporary impairment of $14.2 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	10. FAIR VALUE OF FINANCIAL INSTRUMENTS AND DERIVATIVE INSTRUMENTS Natural Gas, Oil and NGL Derivatives We enter derivative financial instruments with the primary objective of managing our exposure to commodity price fluctuations and providing more predictable cash flows. 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 December 31, 2015, 2014 and 2013, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, swaptions, deferred put spreads, cap swaps, call protected swaps, 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. For additional information, see Note 2, Summary of Significant Accounting Policies Swap contracts provide a fixed price for a notional amount of sales volumes. Collars contain a fixed floor price (“put”) and ceiling price (“call”). The put options are purchased from the counterparty by our payment of a cash premium. If the put strike price is greater than the market price for a settlement period, then the counterparty pays us an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty, for which we receive a cash premium. If the market price is greater than the call strike price for a settlement period, then we pay the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price. A three-way collar is a combination of options, a sold call, a purchased put and a sold put. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the settlement price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price we will receive for the volumes under contract. Deferred put spread contracts are similar to three-way collars except that there is no maximum price ceiling established. Swaption agreements provide options to counterparties to extend swaps into subsequent years. Similar to a deferred put spread and a three-way collar, a cap swap provides a sold put in combination with a swap. Should prices fall below the sold put, we would receive the settlement price plus the differential between the sold put and the swap. Basis swaps are arrangements that guarantee a price differential from a specified delivery point. Currently, our basis swaps provide basis protection between Henry Hub and Dominion Appalachia pricing. We enter into the majority of our derivative arrangements with five counterparties and have a netting agreement in place with these counterparties, however the fair value of our derivative contracts are reported on a gross basis. 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 Income (Expense). We received net cash settlements of $54.9 million, $6.0 million and $7.1 million in relation to our commodity derivatives for the years ended December 31, 2015, 2014 and 2013 respectively. As of December 31, 2015, we had over 45.0% of our 2015 oil production volumes hedged through 2016, over 100.0% of our 2015 natural gas production volumes hedged through 2016 and over 40.0% of our 2015 NGL production volumes hedged through 2016. Including the effects of derivatives added since December 31, 2015, we have over 70.0% of our 2015 oil production hedged through 2016, over 100.0% of our 2015 natural gas production hedged through 2016 and over 45.0% of our 2015 NGL production hedged through 2016. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future development or the natural decline of our oil and gas 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 December 31, 2015, we had approximately $111.5 million in borrowings outstanding under our Senior Credit Facility, which is subject to variable rates of interest, and had $675.0 million of Senior Notes outstanding subject to a fixed interest rate. See Note 9, Long-Term Debt We did enter into fixed-to-variable interest rate swaps during 2015 and 2014, however there were no arrangements in place as of December 31, 2015 and 2014. We utilize the mark-to-market accounting method to account for our interest rate swaps. We recognize all gains and losses related to these contracts in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Income (Expense). During the years ended December 31, 2015 and 2014, we received cash payments of approximately $0.9 million and $1.3 million, respectively, related to our interest rate swaps. The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the years ended December 31, 2015, 2014 and 2013: For the Year Ended December 31, ($ in Thousands) 2015 2014 2013 Oil $ 7,132 $ 8,613 $ (2,798 ) Natural Gas 37,647 18,406 1,807 NGLs 14,463 10,340 (1,711 ) Interest Rate 934 1,517 (206 ) Gain (Loss) on Derivatives, Net $ 60,176 $ 38,876 $ (2,908 ) We account for our derivatives in accordance with ASC 815, which requires that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at its fair value. The fair value associated with our derivative instruments was a net asset of $35.8 million as of December 31, 2015, and a net asset of $31.4 million at December 31, 2014. Our open asset/(liability) financial commodity derivative instrument positions at December 31, 2015 consisted of the following: Period Volume Put Floor Ceiling Swap Fair Market Value ($ in Thousands) Oil 2016 – Deferred Put Spreads 120,000 Bbls $ 50.00 $ 65.00 $ — $ — $ 852 2016 – Collars 379,500 Bbls — 39.17 52.67 — 1,078 2016 – Three-Way Collars 45,000 Bbls 50.00 65.00 70.00 — 577 544,500 Bbls $ 2,507 Natural Gas 2016 – Swaps 12,900,000 Mcf $ — $ — $ — $ 3.19 $ 8,717 2016 – Swaptions 1,200,000 Mcf — — — 3.15 596 2016 – Cap Swaps 3,600,000 Mcf 3.45 — — 4.11 1,977 2016 – Three-Way Collars 18,570,000 Mcf 2.34 3.04 3.86 — 5,941 2016 – Put Spread 4,500,000 Mcf 2.93 3.59 — — 1,737 2016 – Basis Swaps – Dominion South 16,630,000 Mcf — — — (0.94 ) (1,634 ) 2016 – Collars 3,900,000 Mcf — 2.82 3.32 — 1,728 2017 – Swaps 960,000 Mcf — — — 3.60 797 2017 – Swaptions 0 Mcf — — — — (297 ) 2017 – Cap Swaps 2,100,000 Mcf 3.34 — — 4.07 1,225 2017 – Three-Way Collars 16,300,000 Mcf 2.33 3.02 3.89 — 4,319 2017 – Basis Swaps – Dominion South 4,550,000 Mcf — — — (0.83 ) (665 ) 2017 – Basis Swaps – Texas Gas 14,600,000 Mcf — — — (0.13 ) (19 ) 2017 – Calls 3,000,000 Mcf — — 3.64 — (380 ) 2018 – Swaps 960,000 Mcf — — — 3.60 797 2018 – Cap Swaps 1,800,000 Mcf 3.30 — — 4.05 1,069 2018 – Three-Way Collars 7,875,000 Mcf 2.29 2.88 3.56 — 916 2018 – Calls 5,810,000 Mcf — — 3.97 — (609 ) 2018 – Basis Swaps – Dominion South 6,400,000 Mcf — — — (0.83 ) (960 ) 2018 – Basis Swaps – Texas Gas 14,600,000 Mcf — — — (0.13 ) (19 ) 2019 – Basis Swaps – Dominion South 7,300,000 Mcf — — — (0.83 ) (1,103 ) 2020 – Basis Swaps – Dominion South 7,320,000 Mcf — — — (0.83 ) (1,106 ) 154,875,000 Mcf $ 23,027 NGLs 2016 C3 + NGL Swaps 1,131,000 Bbls $ — $ — $ — $ 32.76 $ 9,888 2016 Ethane Swaps 240,000 Bbls — — — 8.82 362 2017 C3 + NGL Swaps 180,000 Bbls — — — 21.42 344 1,551,000 Bbls $ 10,594 Refined Product (Heating Oil) 2016 – Swaps 12,000 Bbls $ — $ — $ — $ 84.00 $ (376 ) 12,000 Bbls $ (376 ) The combined fair value of our derivatives included in our Consolidated Balance Sheets as of December 31, 2015 and December 31, 2014 is summarized below. ($ in Thousands) December 31, December 31, Short-Term Derivative Assets: Crude Oil – Collars $ 1,078 $ — Crude Oil – Call Protected Swap — 1,227 Crude Oil – Deferred Put Spread 852 1,413 Crude Oil – Three-Way Collars 577 4,596 NGL – Swaps 10,250 6,181 Natural Gas – Swaps 9,010 4,522 Natural Gas – Cap Swaps 1,977 3,430 Natural Gas – Basis Swaps 70 2,815 Natural Gas – Three-Way Collars 6,183 5,081 Natural Gas – Collars 1,728 — Natural Gas – Swaption 798 — Natural Gas – Put Spread 1,737 — Total Short-Term Derivative Assets $ 34,260 $ 29,265 Long-Term Derivative Assets: NGL – Swaps $ 344 $ — Natural Gas – Cap Swaps 2,294 1,617 Natural Gas – Swaps 1,593 1,554 Natural Gas – Basis Swaps 195 — Natural Gas – Three-Way Collars 5,108 1,733 Total Long-Term Derivative Assets $ 9,534 $ 4,904 Total Derivative Assets $ 43,794 $ 34,169 Short-Term Derivative Liabilities: Refined Product – Swaps (376 ) — Natural Gas – Three-Way Collars (31 ) — Natural Gas – Basis Swaps (1,585 ) (193 ) Natural Gas – Call — (74 ) Natural Gas – Swaption (202 ) (154 ) Natural Gas – Swaps (292 ) — Total Short – Term Derivative Liabilities $ (2,486 ) $ (421 ) Long-Term Derivative Liabilities: Natural Gas – Swaption (297 ) — Natural Gas – Basis Swaps (4,186 ) (1,281 ) Natural Gas – Call (989 ) (1,096 ) Natural Gas – Three-Way Collars (84 ) — Total Long-Term Derivative Liabilities $ (5,556 ) $ (2,377 ) Total Derivative Liabilities $ (8,042 ) $ (2,798 ) 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 December 31, 2015 and 2014, 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 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 December 31, 2015 and 2014 are included in the table below. 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 ) As of December 31, 2014 Range (price per Mcf) Weighted Fair Value Natural Gas Basis Differential Forward Curve ($0.27) – ($1.39 ) $ (0.84 ) $ 1,341 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 years ended December 31, 2015 and 2014, 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 December 31, 2015 Using: ($ in Thousands) Total Carrying Value as of December 31, 2015 Quoted in Active Markets for Identical (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ 35,752 $ — $ 41,258 $ (5,506 ) Fair Value Measurements at December 31, ($ in Thousands) Total Value as of December 31, 2014 Quoted in Active Markets for Identical (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ 31,371 $ — $ 30,030 $ 1,341 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 value of our oil derivatives as of December 31, 2015 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, swaption, three way collar, basis swap, cap swap, call and deferred put spreads contracts for notional volumes of gas contracted at NYMEX Henry Hub (“HH”). The fair values attributable to our gas derivative contracts as of December 31, 2015 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 December 31, 2015 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 years ended December 31, 2015 and 2014 (in thousands): For the Year Ended December 31, ($ in Thousands) 2015 2014 Beginning Balance of Level 3 $ 1,341 $ 4,323 Changes in Fair Value (2,548 ) (1,670 ) Purchases — — Settlements Received (4,299 ) (1,312 ) Ending Balance of Level 3 $ (5,506 ) $ 1,341 Changes in fair value on our Level 3 commodity derivative contracts outstanding for the years ended December 31, 2015 and 2014, resulted in a gain of approximately $2.5 million and $1.7 million, respectively. These amounts have been included in Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations. Asset Retirement Obligations We report the fair value of asset retirement obligations on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 2, Summary of Significant Accounting Policies, Financial Instruments Not Recorded at Fair Value The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements: December 31, 2015 December 31, 2014 ($ in Thousands) Carrying Amount Fair Value Carrying Amount Fair Value 8.875% Senior Notes due 2020 $ 350,000 $ 77,000 $ 350,000 $ 311,955 6.25% Senior Notes due 2022 325,000 72,313 325,000 241,313 Secured Lines of Credit 111,500 111,500 — — Capital Leases and Other Obligations 618 606 1,427 1,393 Total $ 787,118 $ 261,419 $ 676,427 $ 554,661 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 2 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 We recorded an other than temporary impairment of $345.8 million related to proved properties, unproved properties and other non-revenue producing equipment. 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 calculation are considered to be Level 2 within the fair value hierarchy. For additional information on our impairment, see Note 16, Impairment Expense

Income Taxes

Income Taxes	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
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 ($ in Thousands) 2016 2015 Income (Expense) Benefit $ (2,092 ) $ 92 Effective Tax Rate -3.6 % 0.5 % For the three months ended March 31, 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 March 31, 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 Exchange, we generated approximately $543.2 million in cancellation of debt income as calculated by comparing the fair value of the New Notes and the face value of the Existing Notes. We expect to offset this income by utilizing our net operating loss carryforwards, resulting in a projected alternative minimum tax payment of approximately $5.5 million. Income tax payments made during the three months ended March 31, 2016 and 2015 were negligible. We received tax refunds during the three months ended March 31, 2015 of approximately $0.5 million.	11. INCOME TAXES We recognize deferred tax liabilities and assets for the expected future tax consequences of events that may be recognized in our financial statements or tax returns. Using this method, deferred tax liabilities and assets are determined based on the difference between the financial carrying amounts and tax basis of assets and liabilities using enacted tax rates. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Our income tax expense (benefit) from continuing operations consisted of the following: For the Years Ended December 31, ($ in Thousands) 2015 2014 2013 Current: Federal $ — $ — $ (1,936 ) State — 6 (4,105 ) Deferred: Federal (20,993 ) (23,691 ) 509 State (3,234 ) (3,230 ) 1,378 Income Tax Benefit $ (24,227 ) $ (26,915 ) $ (4,154 ) A reconciliation of income tax expense (benefit) using the statutory U.S. income tax rate compared with actual income tax expense is as follows: ($ in Thousands) Year Ended December 31, 2015 Year Ended December 31, 2014 Year Ended December 31, 2013 Loss from continuing operations before noncontrolling interests and income taxes $ (423,245 ) $ (74,565 ) $ (6,538 ) Statutory U.S. income tax rate 35.0 % 35.0 % 35.0 % Tax expense recognized using statutory U.S. income tax rate $ (148,136 ) $ (26,098 ) $ (2,288 ) State income taxes, net of federal income tax benefit (20,446 ) (3,144 ) (805 ) Change in estimated future state rates (212 ) (1,015 ) (484 ) Permanent differences 1,609 970 83 Change in valuation allowances 143,566 2,450 (160 ) Other (608 ) (78 ) (500 ) Total income tax benefit $ (24,227 ) $ (26,915 ) $ (4,154 ) Effective income tax rate 5.7 % 36.1 % 63.5 % Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. Deferred tax assets (liabilities) are comprised of the following at December 31, 2015 and 2014: For the Years Ended December 31, ($ in Thousands) 2015 2014 Tax effects of temporary differences for: Current: Assets: Asset retirement obligation $ 866 $ 772 Deferred compensation plans 2,028 695 Compensation Accruals 767 2,087 Valuation allowances (3,478 ) (71 ) Other 93 68 Total gross current deferred tax assets 276 3,551 Liabilities: Unrealized gain on derivatives (12,570 ) (11,410 ) Other (238 ) (442 ) Total gross current deferred tax liabilities (12,808 ) (11,852 ) Net total current deferred tax liability $ (12,532 ) $ (8,301 ) Long-Term: Assets: Timing differences – tax partnerships $ 4,166 $ — Tax basis of oil and gas properties in excess of book basis 8,965 — Asset retirement obligation 16,965 15,091 Deferred compensation plans 1,083 2,218 Net operating loss carryforward 123,488 73,531 Organization costs 456 525 Deferred revenue 1,098 1,209 Percentage depletion carryforward 2,673 2,155 AMT credits 292 292 Valuation allowances (144,681 ) (4,318 ) Other 280 269 Total gross long-term deferred tax assets 14,785 88,817 Liabilities: Timing differences – tax partnerships — (7,135 ) Book basis of oil and gas properties in excess of tax basis — (73,557 ) Unrealized gain on derivatives (1,574 ) (999 ) Other (679 ) $ (980 ) Total gross long-term deferred tax liabilities (2,253 ) (80,516 ) Net total long-term deferred tax asset $ 12,532 $ 8,301 (a) As a result of certain realization requirements of FASB ASC 718, the table of deferred tax assets and liabilities does not include $1.3 million at December 31, 2015 and 2014, of excess tax benefits that arose directly from tax deductions related to stock-based compensation greater than compensation recognized for financial reporting. Total stockholders’ equity will be increased by $1.3 million if and when such excess tax benefits are ultimately realized. Management continuously evaluates the facts and circumstances representing positive and negative evidence in the determination of our ability to realize our inventory of deferred tax assets. The company’s deferred tax assets consist primarily of net operating losses and deductible temporary differences. For the year ended December 31, 2015, management determined, based on positive and negative evidence, including our three-year cumulative loss position that it was necessary to provide a valuation allowance of approximately $148.2 million for deferred tax assets for which the company may be unable to realize the tax benefit. For the year ended December 31, 2014, management determined, based on positive and negative evidence examined and anticipated future taxable income, that it was necessary to provide a valuation allowance of approximately $4.3 million for deferred tax assets for which the company may be unable to realize the tax benefit. Our management will continue, in future periods, to assess the likely realization of the deferred tax assets. The valuation allowance may change based on future changes in circumstances. At December 31, 2015, we had available unused gross federal net operating loss carryforwards of $308.1 million and gross state net operating loss carryforwards of $264.7 million that may be applied against future taxable income that expire from 2020 through 2035. The following table shows expirations by year for federal and state net operating loss carryforwards (all figures presented are tax effected): Year of Expiration Net Operating Loss Carryforwards (in thousands) 2020 $ 134 2021 175 2022 — 2023 899 2024 — 2025 531 2026 405 2027 1,003 2028 3,333 2029 767 2030 751 2031 19,746 2032 253 2033 19,703 2034 18,670 2035 57,118 Total 123,488 Due to a change of ownership, as defined under the provisions of the Tax Reform Act of 1986, which occurred during 2014, a portion of our domestic net operating loss and tax credit carryforwards may be limited in future periods. Internal Revenue Code Section 382 places limitations on the amount of taxable income which may be offset by tax carryforward attributes, such as net operating losses or tax credits after a change of ownership event. As a result of this ownership change, certain of our accumulated net operating losses may be subject to an annual limitation regarding their utilization against taxable income in future periods. The 2014 change creates an annual utilization limit of approximately $34.8 million on our ability to utilize net operating losses generated prior to the ownership change event. If we were to experience another ownership change in future periods, our net operating loss carryforwards may be subject to additional utilization limits. FASB ASC 740-10 sets forth a two-step process for evaluating tax positions. The first step is financial statement recognition of the tax position based on whether it is more likely than not that the position will be sustained upon examination by taxing authorities and resolution through related appeals or litigation, based on the technical merits of the case. FASB ASC 740-10 mandates certain assumptions in applying the more likely than not judgment, including the presupposition of an examination where the taxing authorities are fully informed of all relevant information for evaluation of the tax position. In other words, FASB ASC 740-10 precludes factoring the likelihood of a tax examination into the evaluation of the outcome so that the evaluation is to focus solely on the technical merits of the position. Our management has concluded that, as of December 31, 2015, we have not taken any tax positions that would require disclosure as “unrecognized positions” and that no liability balance is required to offset any unsustainable positions. We did not have any accrued interest or penalties as of December 31, 2015 and 2014. We file a consolidated federal income tax return and separate or consolidated state income tax returns in the United States federal jurisdiction and in many state jurisdictions. We are subject to U.S. federal income tax examinations and to various state tax examinations for periods after August 1, 2007.

Capital Stock

Capital Stock	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Equity [Abstract]
Capital Stock	10. CAPITAL STOCK Common Stock We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of March 31, 2016 and December 31, 2015, shares of common stock issued and outstanding totaled 66,041,227 and 55,741,229, respectively. Preferred Stock As of March 31, 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 12,836 and 16,100, respectively. During the first quarter of 2016, approximately 3,264 shares of Series A Preferred Stock were converted into approximately 1.8 million shares of common stock pursuant to the terms of the Series A Preferred Stock. 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 March 31, 2016 accumulated dividends in arrears totaled $2.1 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 six consecutive 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.	13. CAPITAL STOCK Common Stock Currently, our common stock is traded on the NASDAQ Global Select Market under the trading symbol “REXX”. We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of December 31, 2015 and 2014, we had 55,741,229 and 54,174,763 shares of common stock outstanding, respectively. Preferred Stock On August 18, 2014, we completed a registered offering of 16,100 shares of 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (the “Series A Preferred Stock”) that are represented by 1,610,000 depositary shares. The net proceeds of the offering were approximately $155.0 million, after deducting underwriting discounts, commissions and other offering expenses. We utilized a portion of the net proceeds to fund the acquisition of assets from Shell and used the remaining proceeds to fund our capital expenditures program and for general corporate purposes. 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 each February 15, May 15, August 15 and November 15 of each year, commencing on November 15, 2014. During the first quarter of 2016, we suspended the payment of these dividends. 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. For the years ended December 31, 2015 and 2014, we declared quarterly cash dividends totaling approximately $9.7 million and $2.3 million, respectively. The Series A Preferred Stock is convertible at the option of the holder at an initial conversion rate of 555.56 shares of our common stock per share (5.5556 shares of our common stock per depositary share), equivalent to an initial conversion price of $18.00 per share of common stock. The conversion price represents a premium of approximately 25.2% relative to the NASDAQ Global Market closing sale price of our common stock on August 12, 2014 or $14.38 per share. At any time on or after August 30, 2019, we may at our option cause all outstanding shares of the Series A Preferred Stock to be automatically converted into common stock at the then-applicable conversion price if the closing sale price of our common stock exceeds 130% of the then-prevailing conversion price for a specified period prior to the conversion. If a holder elects to convert shares of Series A Preferred Stock upon the occurrence of certain specified fundamental changes, we may be obligated to deliver an additional number of shares above the applicable conversion rate to the converting holder. Except as required by law or our Certificate of Incorporation, holders of the Series A Preferred Stock will have no voting rights unless dividends fall into arrears for six or more quarterly periods (whether or not consecutive). Until such arrearage is paid in full, the holders will be entitled to elect two directors and the number of directors on our board of directors will increase by that same number.

Employee Benefit and Equity Pla

Employee Benefit and Equity Plans	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based 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 three-month period ended March 31, 2016, we issued 851,422 options to purchase shares of our common stock to 29 employees. We issued 80,000 options to purchase shares of our common stock for the three months ended March 31, 2015. Stock-based compensation expense relating to stock options outstanding for the three months ended March 31, 2016 and 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 three months ended March 31, 2016 and 2015. There was no tax benefit for the three-month periods ended March 31, 2016 and 2015. A summary of the status of our issued and outstanding stock options as of March 31, 2016 is as follows: Outstanding Exercisable Exercise Price Number Outstanding At 3/31/16 Weighted-Average Number Exercisable At 3/31/16 Weighted-Average $1.69 851,422 $ 1.69 — $ — $4.05 40,000 $ 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 $11.87 3,500 $ 11.87 3,500 $ 11.87 $13.19 50,000 $ 13.19 50,000 $ 13.19 $22.34 30,000 $ 22.34 30,000 $ 22.34 1,295,094 $ 4.41 367,005 $ 10.72 The weighted average remaining contractual term for options outstanding at March 31, 2016 was 5.5 years and there was no aggregate intrinsic value. The weighted average remaining contractual term for options exercisable at March 31, 2016 was 1.9 years and there was no aggregate intrinsic value. As of March 31, 2016, unrecognized compensation expense related to stock options was $0.5 million. Restricted Stock Awards During the three-month period ended March 31, 2016, the Compensation Committee approved the issuance of an aggregate of 420,901 shares of restricted common stock to 22 employees. During the three-month period ended March 31, 2015, the Compensation Committee approved the issuance of an aggregate of 1,336,295 shares of restricted stock to 126 employees 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 of December 31, 2015 was $2.56 per share. There were no TSR awards granted as of March 31, 2016. 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 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 associated with restricted stock awards was negligible and $3.0 million for the three-month period ended March 31, 2016 and 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 March 31, 2016, total unrecognized compensation cost related to restricted common stock grants was approximately $3.6 million, which will be recognized over a weighted average period of 1.5 years. A summary of the restricted stock activity for the three months ended March 31, 2016 is as follows: Number of Weighted- Restricted stock awards, as of December 31, 2015 2,479,408 $ 6.27 Awards 420,901 1.67 Forfeitures (346,876 ) 7.83 Vested (142,516 ) 12.76 Restricted stock awards, as of March 31, 2016 2,410,917 $ 4.86	15. EMPLOYEE BENEFIT AND EQUITY PLANS 401(k) Plan We sponsor a 401(k) Plan for eligible employees who have satisfied age and service requirements. Employees can make contributions to the plan up to allowable limits. Our contributions to the plan are discretionary. Our contributions to the plan attributable to continuing operations were approximately $0.8 million, $0.9 million and $0.7 million for the years ended December 31, 2015, 2014 and 2013, respectively. 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 the vesting period. We report any benefits of income tax deductions in excess of recognized financial accounting compensation as a financing cash flow, rather than as an operating cash flow. 2007 Long-Term Incentive Plan We have granted stock options and restricted stock awards to various employees, non-employee directors and non-employee contractors under the terms of our Amended and Restated 2007 Long-Term Incentive Plan (the “Plan”). The Plan is administered by the Compensation Committee of our board of directors (the “Compensation Committee”). Among the Compensation Committee’s responsibilities are selecting participants to receive awards, determining the form, amount and other terms and conditions of awards, interpreting the provisions of the Plan or any award agreement and adopting such rules, forms, instruments and guidelines for administering the Plan as it deems necessary or proper. All actions, interpretations and determinations by the Compensation Committee are final and binding. The composition of the Compensation Committee is intended to permit the awards under the Plan to qualify for exemption under Rule 16b-3 of the Exchange Act. In addition, awards under the Plan, including annual incentive awards paid to executive officers subject to section 162(m) of the Code or covered employees may be designed, at the Compensation Committee’s discretion, to satisfy the requirements of section 162(m) to permit the deduction by us of the associated expenses for federal income tax purposes. The Compensation Committee has authorized the issuance of 5,979,470 shares under the Plan, with 1,144,297 and 2,825,260 still available as of December 31, 2015 and 2014, respectively. All awards granted under the Plan have been issued at the prevailing market price at the time of the grant. All outstanding stock options have been awarded with five or ten year expiration at an exercise price equal to our closing price on the NASDAQ Global Select Market on the day of the award. A forfeiture rate based on a blended average of individual participant terminations and number of awards cancelled is used to estimate forfeitures prospectively. Stock Options Stock options represent the right to purchase shares of stock in the future at the fair market value of the stock on the date of grant. In the event that any outstanding award expires, is forfeited, cancelled or otherwise terminated without the issuance of shares of our common stock or is otherwise settled in cash, shares of our common stock allocable to such award, including the unexercised portion of such award, shall again be available for the purposes of the Plan. If any award is exercised by tendering shares of our common stock to us, either as full or partial payment, in connection with the exercise of such award under the Plan or to satisfy our withholding obligation with respect to an award, only the number of shares of our common stock issued net of such shares tendered will be deemed delivered for purposes of determining the maximum number of shares of our common stock then available for delivery under the Plan. During the year ended December 31, 2015, we issued 80,000 options to purchase shares of our common stock to three employees. During the year ended December 31, 2014, we did not issue options to purchase shares of our common stock. A summary of the stock option activity is as follows: Number of Shares Weighted- Exercise Weighted- Remaining (in years) Aggregate Value (in Options outstanding December 31, 2012 502,253 $ 10.95 Granted — — Exercised (49,166 ) 10.85 Cancelled/Forfeited (4,000 ) 23.28 Options outstanding December 31, 2013 449,087 $ 10.85 Granted — — Exercised (46,526 ) 11.09 Cancelled/Forfeited — — Options outstanding December 31, 2014 402,561 $ 10.82 Granted 80,000 4.48 Exercised — — Cancelled/Forfeited (38,889 ) 11.23 Options Outstanding December 31, 2015 443,672 $ 9.64 2.8 $ — Options Exercisable December 31, 2015 363,672 $ 10.77 2.1 $ — Stock-based compensation expense from continuing operations relating to stock options for the year ended December 31, 2015, was negligible and for the years ended December 31, 2014 and 2013 totaled $0.1 million and $0.2 million, respectively. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative expense. No stock options were exercised for the year ended December 31, 2015. The intrinsic value of stock options exercised for the years ended December 31, 2014 and 2013 was $0.3 million and $0.4 million, respectively. The total tax benefit for the years ended December 31, 2015 was negligible and for the years ended December 31, 2014 and 2013 was approximately $0.1 million and $0.2 million, respectively. A summary of the status of our issued and outstanding stock options as of December 31, 2015 is as follows: Outstanding Exercisable Exercise Price Number Outstanding At 12/31/15 Weighted-Average Exercise Price Number Exercisable At 12/31/15 Weighted-Average Exercise Price $4.05 40,000 $ 4.05 — $ — $4.90 40,000 $ 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 $11.89 3,500 $ 11.89 3,500 $ 11.89 $13.19 50,000 $ 13.19 50,000 $ 13.19 $22.34 30,000 $ 22.34 30,000 $ 22.34 443,672 $ 9.64 363,672 $ 10.77 The weighted average remaining contractual term for options exercisable at December 31, 2015 was 2.1 years and the aggregate intrinsic value was negligible. The weighted average remaining contractual term and the aggregate intrinsic value for options outstanding at December 31, 2014 were 2.9 years and negligible, respectively. As of December 31, 2015, unrecognized compensation expense related to stock options was $0.1 million. Restricted Stock Awards During the year ended December 31, 2015, the Compensation Committee issued 2,236,839 shares of restricted common stock to selected employees, non-employee directors and non-employee contractors. During the year ended December 31, 2014, the Compensation Committee issued 131,610 shares of restricted common stock to selected employees, non-employee directors and non-employee contractors. The shares granted in 2015 and 2014 are subject to time vesting and, in some cases, performance-based vesting. The shares will vest on the date on which the Compensation Committee certifies that the performance goals have been satisfied, provided that the recipient has been in continuous employment with us from the grant date until the date upon which the shares are released. Restrictions on the transfer associated with vesting schedules were determined by the Compensation Committee on an individual award basis. The restricted common stock is valued at the closing price of our common stock on the NASDAQ Global Select Market on the date of the grant. Upon a “change in control” of us, as such term is defined in the Plan, all restrictions will immediately lapse for performance-based awards to varying degrees based on performance metrics at the time of the change in control. For awards that do not contain a performance-based condition, all restrictions immediately lapse upon a change in control. Compensation expense associated with the restricted stock award is recognized on a straight-line basis over the vesting period. Certain of the restricted common stock awards in 2015, 2014 and 2013 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 of 13 to 15 companies over a three-year period. The number of shares ultimately awarded will correspond with the final TSR rank amongst the peer group in accordance with the following schedule: TSR Rank Percentage of Awards to Vest 1-3 100 % 4-6 75 % 7-10 50 % 11-13 25 % 14-16 0 % The weighted average fair value of the TSR awards as of December 31, 2015, 2014 and 2013 were $2.56, $10.15 and $12.59 per share, respectively. 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 Year Ended December 31, Expected Dividend Yield 0.0% 0.0% Risk-Free Interest Rate 1.0% 0.8% Expected Volatility – Rex Energy 58.6% 50.4% Expected Volatility – Peer Group 29.8%-85.0% 28.4%-65.7% Market Index 35.6% 35.3% Expected Life Three Years Three Years The dividend yield of zero reflects the fact that we have never paid cash dividends on our common stock and have no present intentions of doing so. The risk-free interest rate reflects the U.S. Treasury Constant Maturity rates as of the measurement date, converted into an implied “spot rate” yield. Our expected volatility estimates are based on observed historical volatility of daily stock returns for the three-year period preceding the grant date. Market index is an equal-weight index of the companies in the peer group. Expected life is measured as the grant date through the end of the performance period. Performance and market shares will vest on the date on which the Compensation Committee certifies that the performance goals have been satisfied, provided that the recipient has been in continuous employment with us from the grant date through the third anniversary of the grant date. Compensation expense for the TSR awards is recognized on a straight-line basis over the vesting period. We recorded compensation expense related to restricted common stock awards of $6.4 million, $5.8 million and $5.1 million for the years ended December 31, 2015, 2014 and 2013, respectively. 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 approximately 189,872 restricted stock awards with associated expense of approximately $2.5 million. As of December 31, 2015, total unrecognized compensation cost related to the restricted common stock grants was approximately $4.5 million to be recognized over a weighted average of 1.7 years. The total fair value of restricted common stock awards that vested in 2015 was approximately $2.0 million as compared to $7.7 million for restricted common stock awards that vested in 2014. A summary of the restricted stock activity for the years ended December 31, 2015, 2014 and 2013 is as follows: Number of Shares Weighted-Average Grant Date Fair Value Restricted stock awards, as of January 1, 2013 1,431,573 $ 12.45 Awards 981,544 16.03 Vested (182,994 ) 11.59 Forfeitures (57,484 ) 11.84 Restricted stock awards, as of December 31, 2013 2,172,639 $ 14.16 Awards 131,610 8.76 Vested (595,085 ) 13.09 Forfeitures (189,863 ) 14.60 Restricted stock awards, as of December 31, 2014 1,519,301 $ 14.05 Awards 2,236,839 3.35 Vested (606,359 ) 9.39 Forfeitures (670,373 ) 11.33 Restricted stock awards, as of December 31, 2015 2,479,408 $ 6.27

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
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. 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. 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 March 31, 2016, we know of no significant probable or possible environmental contingent liabilities. Letters of Credit At March 31, 2016, we had posted $41.0 million in various letters of credit to secure our drilling and related operations. Lease Commitments As of March 31, 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 months ended March 31, 2016 and 2015, was approximately $0.3 million and $0.2 million, respectively. Lease commitments by year for each of the next five years are presented in the table below: ($ in Thousands) 2016 $ 766 2017 991 2018 565 2019 563 2020 422 Thereafter — Total $ 3,307 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 process any gas through the cryogenic gas processing plants, we may be obligated to pay approximately $10.9 million in 2016, $16.5 million in 2017, $16.5 million in 2018, $16.5 million in 2019, $16.6 million in 2020 and $97.9 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-month period ended March 31, 2016 and 2015 were $0.6 million and $0.2 million, 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 $1.7 million in 2016, $2.3 million in 2017 and $0.3 million in 2018, which would be partially offset by other working interest owners, which vary from well to well. During the first quarter of 2015, we terminated two rig contracts earlier than their original term. To satisfy the early release, we incurred approximately $4.8 million in early termination fees, which were classified as Other Operating Expense in our Consolidated Statement of Operations for the three months ended March 31, 2015. Approximately $2.3 million of this amount was paid in January 2015 and $2.5 million in January 2016. We also have agreements for contracted completion services in the Appalachian Basin. The minimum gross cost to retain the completion services is approximately $4.0 million in 2016, which would be partially offset by other working interest owners, which vary from well to well. 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 oil, natural gas and NGLs. 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 $418.0 million through 2021. For the three months ended March 31, 2016 and 2015, we incurred expenses related to the transportation, processing and marketing of our oil, natural gas and NGLs of approximately $21.5 million and $18.9 million, 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 months ended March 31, 2016 and 2015, we incurred approximately $0.4 million and $0.9 million, respectively, in fees related to unutilized capacity commitments. The unutilized commitment fees are related to undeveloped properties that we acquired during 2014. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows: ($ in Thousands) Total 2016 $ 24,715 2017 49,357 2018 53,456 2019 52,904 2020 51,697 Thereafter 458,695 Total $ 690,824 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) 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. All fees owed are due on April 1 of each year. For the three months ended March 31, 2016 and 2015, we recorded expense of approximately $0.5 million and $0.6 million, respectively. We record expenses related to the impact fees as Production and Lease Operating Expense. As of March 31, 2016, approximately $3.6 million was accrued for the 2015 impact fees and a portion of 2016 impact fees.	7. 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. As of December 31, 2015 and 2014, we did not have any reserves established for future legal obligations. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and the subjective judgment of management. While we currently believe that no reserve is needed, 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 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 future losses that are not currently accrued. Based on currently available information, we believe that it is remote that future costs, if any, 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 might be incurred. Environmental Due to the nature of the natural gas and oil 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 to identify changes our environmental risk profile. These reviews 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 salaries and wages 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 conducting evaluations (both internal and using consultants) to identify existing problems and assessing the potential liability. Except for contingent liabilities associated with the consent decree with the U.S. EPA relating to alleged H 2 S emissions in the Lawrence Field, we know of no significant probable or possible environmental contingent liabilities. Letters of Credit As of December 31, 2015 and 2014, we had posted $41.0 million and $6.0 million, respectively, in various letters of credit to secure our drilling and related operations. Approximately $39.8 million of the letters of credit outstanding at December 31, 2015 are related to firm natural gas transportation agreements. Lease Commitments At December 31, 2015 we had lease commitments for various real estate leases. Rent expense from continuing operations has been recorded in General and Administrative expense as $1.0 million, $0.8 million and $0.6 million for the years ended December 31, 2015, 2014 and 2013, respectively. Lease commitments by year for each of the next five years are presented in the table below. ($ in Thousands) 2016 $ 1,058 2017 991 2018 565 2019 563 2020 422 Thereafter — Total $ 3,599 Capacity Reservation We are a party to 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 to process our produced natural gas. In the event that we do not process any gas through the cryogenic gas processing plants, we may be obligated to pay approximately $14.4 million in 2016, $16.4 million in 2017, $16.4 million in 2018, $16.4 million in 2019, $16.5 million in 2020 and $97.2 million thereafter, assuming our average working interest in the region of approximately 52.6%. For the years ended December 31, 2015, 2014 and 2013, we incurred capacity reservation charges of $0.6 million, $0.2 million and $0.3 million, respectively. Charges for the capacity reservation are recorded as Production and Lease Operating Expense on our Consolidated Statements of Operations. 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 $2.3 million in 2016 and $2.3 million in 2017, which would be partially offset by other working interest owners, which vary from well to well. During the first quarter of 2015, we terminated two rig contracts earlier than their original term. To satisfy the early release, we incurred approximately $4.8 million in early termination fees, which were classified as Other Operating Expense in our Consolidated Statement of Operations as of December 31, 2015. Approximately $2.5 million of this amount was paid in January 2015 with the remaining amount paid in January 2016. We also have agreements for contracted completion services in the Appalachian Basin. The minimum gross cost to retain the completion services is approximately $4.0 million in 2016, which would be partially offset by other working interest owners, which vary from well to well. 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 oil, natural gas and NGLs. 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 $421.8 million. For the years ended December 31, 2015, 2014 and 2013, we incurred expenses related to the transportation, processing and marketing our oil, natural gas and natural gas liquids of approximately $79.5 million, $55.4 million and $26.4 million, respectively. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows: ($ in Thousands) Total 2016 $ 23,836 2017 38,434 2018 39,993 2019 39,017 2020 37,744 Thereafter 395,980 Total $ 575,004 Pennsylvania Impact Fee In 2012, Pennsylvania instituted a natural gas impact fee on producers of unconventional natural gas. The fee will is imposed on every producer of unconventional natural gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. Unconventional gas wells that were spud prior to 2012 are considered to be spud in 2011 for purposes of determining the fee, which is considered year one for those wells. The fee for each unconventional natural gas well is determined using the following matrix with vertical unconventional natural gas wells being charged 20%: <$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) Pricing utilized for determining annual fees 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 year ending December 31. For the years ended December 31, 2015, 2014 and 2013, we incurred approximately $3.0 million, $4.1 million and $3.2 million, respectively, in fees related to the natural gas impact fee. We have recorded these fees as Production and Lease Operating Expense on our Consolidated Statement of Operations.

Earnings Per Common Share

Earnings Per Common Share	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings Per Common Share	13. EARNINGS PER COMMON SHARE Basic loss per common share is calculated based on the weighted average number of common shares outstanding at the end of the period, excluding restricted stock with performance-based and market-based vesting criteria. Diluted income per common share includes the speculative exercise of stock options and performance-based restricted stock which contain conditions that are not earnings or market-based, given that the hypothetical effect is not anti-dilutive. For the three months ended March 31, 2016 and March 31, 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 months ended March 31, 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 2016 2015 Numerator: Net Loss From Continuing Operations $ (60,141 ) $ (18,479 ) Net Income From Discontinued Operations, Less Noncontrolling Interests — 665 Less: Preferred Stock Dividends (2,105 ) (2,415 ) Net Loss Attributable to Common Shareholders $ (62,246 ) $ (20,229 ) Denominator: Weighted Average Common Shares Outstanding – Basic 56,003 54,370 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 56,003 54,370 Earnings per Common Share Attributable to Rex Energy Common Shareholders: Basic – Net Loss From Continuing Operations $ (1.11 ) $ (0.38 ) – Net Income From Discontinued Operations — 0.01 – Net Loss Attributable to Rex Energy Common Shareholders $ (1.11 ) $ (0.37 ) Diluted – Net Loss From Continuing Operations $ (1.11 ) $ (0.38 ) – Net Income From Discontinued Operations — 0.01 – Net Loss Attributable to Rex Energy Common Shareholders $ (1.11 ) $ (0.37 )	12. EARNINGS PER COMMON SHARE Basic 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 years ended December 31, 2015, 2014 and 2013, we excluded stock options to purchase 0.4 million shares of our common stock due to our Net Loss from Continuing Operations. For the years ended December 31, 2015, 2014 and 2013, we excluded performance-based restricted stock of 1.1 million shares, 0.8 million shares and 1.3 million shares, respectively, due to our Net Loss from Continuing Operations (for additional information on our non-cash compensation plans, see Note 15, Employee Benefit and Equity Plans Year Ended December 31, Year Ended December 31, Year Ended December 31, (in thousands, except per share amounts) 2015 2014 2013 Numerator: Net Loss From Continuing Operations $ (399,018 ) $ (47,650 ) $ (2,384 ) Net Income From Discontinued Operations, Less Noncontrolling Interests 35,740 961 254 Less: Preferred Stock Dividends 9,660 2,335 — Net Loss Attributable to Common Shareholders $ (372,938 ) $ (49,024 ) $ (2,130 ) Denominator: Weighted Average Common Shares Outstanding – Basic 54,392 53,150 52,572 Weighted Average Common Shares Outstanding – Diluted 54,392 53,150 52,572 Earnings per Common Share Attributable to Rex Energy Common Shareholders(a): Basic – Net Loss From Continuing Operations $ (7.51 ) $ (0.94 ) $ (0.05 ) – Net Income From Discontinued Operations 0.66 0.02 0.01 – Net Loss Attributable to Rex Energy Common Shareholders $ (6.85 ) $ (0.92 ) $ (0.04 ) Diluted – Net Loss From Continuing Operations $ (7.51 ) $ (0.94 ) $ (0.05 ) – Net Income From Discontinued Operations 0.66 0.02 0.01 – Net Loss Attributable to Rex Energy Common Shareholders $ (6.85 ) $ (0.92 ) $ (0.04 ) (a) All earnings per share amounts are attributable to Rex common shareholders.

Equity Method Investments

Equity Method Investments	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
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 Appalachian Basin 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 three months of 2016 and 2015. During each of the three months ended March 31, 2016 and March 31, 2015, RW Gathering incurred net losses from continuing operations of $0.5 million. The loss incurred was 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 each of the three-month periods ended March 31, 2016 and 2015, we incurred approximately $0.2 million in compression expenses that were charged to us from Williams Production Appalachia, LLC. These costs are in relation to compression costs incurred by RW Gathering and are recorded as Production and Lease Operating Expense on our Consolidated Statement of Operations. As of March 31, 2016 and December 31, 2015, there were no receivables or payables due between RW Gathering and us.	5. EQUITY METHOD INVESTMENTS RW Gathering RW Gathering, LLC (“RW Gathering”) is a Delaware limited liability company that we jointly own with WPX Energy Inc. (“WPX”) and Sumitomo, with our ownership equaling 40%. RW Gathering owns gas-gathering and other midstream assets that service jointly owned properties in Westmoreland and Clearfield Counties, Pennsylvania. Our investment in RW Gathering totaled approximately $17.9 million as of December 31, 2014, and was recorded on our Consolidated Balance Sheet as Equity Method Investments. During the second quarter of 2015 we incurred a 100% impairment charge of $17.5 million related to RW Gathering (for additional information, see Note 16, Impairment Expense

IMPAIRMENT EXPENSE

IMPAIRMENT EXPENSE	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
IMPAIRMENT EXPENSE	15. IMPAIRMENT EXPENSE For the three months ended March 31, 2016 and 2015, impairment expenses incurred were approximately $14.2 million and $7.0 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 three months of 2016 included proved property impairments of approximately $3.5 million attributable to conventional oil properties in the Illinois Basin. In addition to the proved properties, we also incurred unproved property impairments of approximately $10.7 million related to unconventional assets in the Appalachian Basin. 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. The primary reason for the decrease in estimated future cash flows of our assets is attributable to the continued depression of current and estimated future commodity prices as of March 31, 2016. Our estimates of future cash flows attributable to our oil and gas properties could decline further if commodity prices continue to decline, which may result in our incurrence of additional impairment expense. As of March 31, 2016, we continued to carry the costs of undeveloped properties of approximately $257.7 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale in the Appalachian Basin and for which we have development, trade or lease extension plans. The expenses incurred during the first quarter of 2015 included approximately $4.0 million related to proved properties in our non-operated dry gas region of Clearfield County, Pennsylvania. The remaining $3.0 million of impairment expense in the first quarter of 2015 was incurred in relation to undeveloped leases that expired or were expected to expire without being developed, primarily in the Appalachian Basin.	16. IMPAIRMENT EXPENSE For the years ended December 31, 2015, 2014 and 2013, we incurred impairment expense from continuing operations of approximately $345.8 million, $132.6 million and $32.1 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 (for additional information see Note 2, Summary of Significant Accounting Policies During 2014, we recorded impairment expense of $132.6 million. Approximately $113.4 million of the impairment incurred during 2014 was attributable to proved properties and other fixed assets, of which approximately $103.9 million was attributable to the Illinois Basin and $9.5 million was attributable to the Appalachian Basin. In the Illinois Basin, which is 100% oil producing, the estimated future decline in oil prices as of December 31, 2014, caused the estimated future cash flows of certain properties to decrease below a level at which the carrying value that is expected to be recovered. In the Appalachian Basin, approximately $5.9 million of impairment was incurred for our salt water disposal well in Ohio due to the regulatory and environmental climate and the uncertainty of future viability of the disposal well. We also incurred approximately $3.6 million of impairment related to shallow conventional gas properties in the Appalachian Basin, which is attributable to the estimated future decrease in natural gas pricing as of December 31, 2014. In addition to our proved property and fixed asset impairments, we also incurred approximately $18.9 million in unproved property impairments. In the Appalachian Basin, we incurred approximately $10.4 million in unproved property impairments related to expiring leases that will not be developed. In the Illinois Basin, we incurred approximately $8.5 million of unproved property impairment primarily due to the estimated future economics of the properties at the depressed commodity price environment at December 31, 2014. During 2013, we recorded impairment expense of $32.1 million. Approximately $29.3 million of expense incurred during 2013 was related to the impairment of conventional oil properties in the Illinois Basin. The impairment in Illinois was focused in two areas where extensive development activity occurred during 2013. In addition to the development activity, future estimated prices for the sale of crude oil as of December 31, 2013 decreased to a level which did not support the recovery of the full carrying value of the properties.

Exploration Expense

Exploration Expense	3 Months Ended
	Mar. 31, 2016
Text Block [Abstract]
Exploration Expense	16. EXPLORATION EXPENSE For the three months ended March 31, 2016 and 2015, we incurred approximately $1.0 million and $0.5 million, respectively, in exploration expenses. Approximately $0.2 million of the expense incurred in 2016 was due to geological and geophysical type expenditures and the remaining $0.8 million was due to two exploratory wells that were abandoned at various stages that resulted in dry hole expense in the Appalachian Basin. The expense incurred in 2015 was due to geological and geophysical type expenditures.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Condensed Consolidating Financial Information	17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION As of March 31, 2016, we had an aggregate of $675.0 million of outstanding Senior Notes, as shown in Note 7, Long-Term Debt • Rex Energy I, LLC • Rex Energy Operating Corporation • Rex Energy IV, LLC • PennTex Resources Illinois, Inc. • R.E. Gas Development, LLC The non-guarantor subsidiaries include certain consolidated subsidiaries, including Water Solutions, R.E. Disposal, LLC, Rex Energy Marketing, LLC and R.E. Ventures Holdings, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of March 31, 2016, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries. The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the notes, (ii) the combined Guarantors, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of March 31, 2016 and December 31, 2015, the condensed consolidating statements of operations for each of the three-month periods ended March 31, 2016 and 2015, and the condensed consolidating statements of cash flows for each of the three-month periods ended March 31, 2016 and 2015. REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF MARCH 31, 2016 ($ in Thousands) Guarantor Non-Guarantor Rex Energy Eliminations Consolidated ASSETS Current Assets Cash and Cash Equivalents $ 24,888 $ — $ 3 $ — $ 24,891 Accounts Receivable 24,252 16 47 — 24,315 Taxes Receivable — — 18 — 18 Short-Term Derivative Instruments 29,012 — — — 29,012 Inventory, Prepaid Expenses and Other 3,156 — 12 — 3,168 Total Current Assets 81,308 16 80 — 81,404 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,300,678 801 — 1,301,479 Unevaluated Oil and Gas Properties 257,697 — — — 257,697 Other Property and Equipment 40,133 895 — — 41,028 Wells and Facilities in Progress 75,269 245 — — 75,514 Pipelines 16,780 — — — 16,780 Total Property and Equipment 1,690,557 1,941 — — 1,692,498 Less: Accumulated Depreciation, Depletion and Amortization (720,100 ) (898 ) — — (720,998 ) Net Property and Equipment 970,457 1,043 — — 971,500 Other Assets 2,489 — — — 2,489 Intercompany Receivables — — 1,095,371 (1,095,371 ) — Investment in Subsidiaries – Net (2,388 ) — (127,974 ) 130,362 — Long-Term Derivative Instruments 8,460 — — — 8,460 Total Assets $ 1,060,326 $ 1,059 $ 967,477 $ (965,009 ) $ 1,063,853 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 42,818 $ — $ — $ — $ 42,818 Current Maturities of Long-Term Debt 434 — 9,500 — 9,934 Accrued Liabilities 32,709 20 11,567 44,296 Short-Term Derivative Instruments 3,758 — — — 3,758 Total Current Liabilities 79,719 20 21,067 — 100,806 Long-Term Derivative Instruments 6,908 — — — 6,908 Senior Secured Line of Credit and Other Long-Term Debt, Net of Issuance Costs — — 143,294 — 143,294 Senior Notes, Net of Issuance Costs — — 657,511 — 657,511 Premium on Senior Notes – Net — — 2,245 — 2,245 Other Deposits and Liabilities 3,140 — — — 3,140 Future Abandonment Cost 42,964 448 — — 43,412 Intercompany Payables 1,090,818 4,553 — (1,095,371 ) — Total Liabilities 1,223,549 5,021 824,117 (1,095,371 ) 957,316 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 63 — 63 Additional Paid-In Capital 177,144 — 630,301 (177,144 ) 630,301 Accumulated Earnings (Deficit) (340,367 ) (3,962 ) (487,005 ) 307,506 (523,828 ) Total Stockholders’ Equity (163,223 ) (3,962 ) 143,360 130,362 106,537 Total Liabilities and Stockholders’ Equity $ 1,060,326 $ 1,059 $ 967,477 $ (965,009 ) $ 1,063,853 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2016 ($ in Thousands) Guarantor Non-Guarantor Rex Energy Eliminations Consolidated OPERATING REVENUE Oil, Natural Gas and NGL Sales $ 30,463 $ 31 $ — $ — $ 30,494 Other Revenue 13 — — — 13 TOTAL OPERATING REVENUE 30,476 31 — — 30,507 OPERATING EXPENSES Production and Lease Operating Expense 30,121 25 — — 30,146 General and Administrative Expense 6,068 9 (14 ) — 6,063 Gain on Disposal of Asset (30 ) — — — (30 ) Impairment Expense 14,184 — — — 14,184 Exploration Expense 993 — — — 993 Depreciation, Depletion, Amortization and Accretion 19,379 29 — — 19,408 Other Operating Income 329 — — — 329 TOTAL OPERATING EXPENSES 71,044 63 (14 ) — 71,093 INCOME (LOSS) FROM OPERATIONS (40,568 ) (32 ) 14 — (40,586 ) OTHER INCOME (EXPENSE) Interest Expense (273 ) — (12,759 ) — (13,032 ) Gain on Derivatives, Net 4,049 — — — 4,049 Debt Exchange Expense — — (8,480 ) — (8,480 ) Income (Loss) From Equity in Consolidated Subsidiaries (25 ) 25 (38,151 ) 38,151 — TOTAL OTHER INCOME (EXPENSE) 3,751 25 (59,390 ) 38,151 (17,463 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (36,817 ) (7 ) (59,376 ) 38,151 (58,049 ) Income Tax Expense (1,326 ) (1 ) (765 ) — (2,092 ) NET INCOME (LOSS) (38,143 ) (8 ) (60,141 ) 38,151 (60,141 ) Preferred Stock Dividends — — 2,105 — 2,105 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (38,143 ) $ (8 ) $ (62,246 ) $ 38,151 $ (62,246 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDING MARCH 31, 2016 ($ in Thousands) Guarantor Non-Guarantor Rex Energy Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (38,143 ) $ (8 ) $ (60,141 ) $ 38,151 $ (60,141 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Non-Cash Expenses (Income) (30 ) — 527 — 497 Depreciation, Depletion, Amortization and Accretion 19,379 29 — — 19,408 Gain on Derivatives (4,049 ) — — — (4,049 ) Cash Settlements of Derivatives 12,994 — — — 12,994 Dry Hole Expense 843 — — — 843 Gain on Sale of Asset (30 ) — — — (30 ) Deferred Income Tax Expense 1,326 1 765 — 2,092 Impairment Expense 14,184 — 14,184 (14,184 ) 14,184 Changes in operating assets and liabilities Accounts Receivable 15,852 10 (20,735 ) — (4,873 ) Inventory, Prepaid Expenses and Other Assets 648 — 12 — 660 Accounts Payable and Accrued Liabilities 1,922 21 (2,251 ) — (308 ) Other Assets and Liabilities (170 ) — — — (170 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 24,726 53 (67,639 ) 23,967 (18,893 ) CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 27 (21 ) 23,961 (23,967 ) — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 71 — — — 71 Proceeds from Joint Venture for Reimbursement of Capital Costs 19,461 — — — 19,461 Acquisitions of Undeveloped Acreage (5,266 ) — — — (5,266 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (15,036 ) (32 ) — — (15,068 ) NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (743 ) (53 ) 23,961 (23,967 ) (802 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — — 46,500 — 46,500 Repayments of Loans and Other Long-Term Debt (184 ) — — — (184 ) Debt Issuance Costs — — (2,821 ) — (2,821 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (184 ) — 43,679 — 43,495 NET INCREASE IN CASH 23,799 — 1 — 23,800 CASH – BEGINNING 1,089 — 2 — 1,091 CASH – ENDING $ 24,888 $ — $ 3 $ — $ 24,891 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF DECEMBER 31, 2015 ($ in Thousands) Guarantor Non-Guarantor Rex Energy Eliminations Consolidated ASSETS Current Assets Cash and Cash Equivalents $ 1,089 $ — $ 2 $ — $ 1,091 Accounts Receivable 19,423 11 49 — 19,483 Taxes Receivable — — 18 — 18 Short-Term Derivative Instruments 34,260 — — — 34,260 Inventory, Prepaid Expenses and Other 3,804 — 25 — 3,829 Total Current Assets 58,576 11 94 — 58,681 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,245,626 774 — (6,970 ) 1,239,430 Unevaluated Oil and Gas Properties 262,992 — — — 262,992 Other Property and Equipment 39,217 895 — — 40,112 Wells and Facilities in Progress 144,587 239 — (270 ) 144,556 Pipelines 16,161 — — (2,137 ) 14,024 Total Property and Equipment 1,708,583 1,908 — (9,377 ) 1,701,114 Less: Accumulated Depreciation, Depletion and Amortization (702,537 ) (880 ) — 3,518 (699,899 ) Net Property and Equipment 1,006,046 1,028 — (5,859 ) 1,001,215 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 $ 1,074,750 $ 1,039 $ 1,313,973 $ (1,317,831 ) $ 1,071,931 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 37,874 $ — $ — $ — $ 37,874 Current Maturities of Long-Term Debt 590 — — — 590 Accrued Liabilities 32,601 — 11,725 — 44,326 Short-Term Derivative Instruments 2,486 — — — 2,486 Total Current Liabilities 73,551 — 11,725 — 85,276 Long-Term Derivative Instruments 5,556 — — — 5,556 Senior Secured Line of Credit and Other Long-Term Debt, Net of Issuance Costs 28 — 109,368 — 109,396 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 42,443 440 — — 42,883 Intercompany Payables 1,070,096 452 — (1,070,548 ) — Total Liabilities 1,194,830 892 786,526 (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) (297,223 ) 147 (92,385 ) (74,226 ) (463,687 ) Total Stockholders’ Equity (120,080 ) 147 527,447 (247,283 ) 160,231 Total Liabilities and Stockholders’ Equity $ 1,074,750 $ 1,039 $ 1,313,973 $ (1,317,831 ) $ 1,071,931 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2015 ($ in Thousands) Guarantor Non-Guarantor Rex Energy Eliminations Consolidated OPERATING REVENUE Oil, Natural Gas and NGL Sales $ 54,000 $ 111 $ — $ — $ 54,111 Other Revenue 11 — — — 11 TOTAL OPERATING REVENUE 54,011 111 — — 54,122 OPERATING EXPENSES Production and Lease Operating Expense 29,014 38 — — 29,052 General and Administrative Expense 6,659 16 2,976 — 9,651 Loss on Disposal of Asset 65 — — — 65 Impairment Expense 7,012 11 — — 7,023 Exploration Expense 518 — — — 518 Depreciation, Depletion, Amortization and Accretion 26,292 69 — (235 ) 26,126 Other Operating Expense 5,191 — — — 5,191 TOTAL OPERATING EXPENSES 74,751 134 2,976 (235 ) 77,626 INCOME (LOSS) FROM OPERATIONS (20,740 ) (23 ) (2,976 ) 235 (23,504 ) OTHER INCOME (EXPENSE) Interest Expense (58 ) — (11,959 ) — (12,017 ) Gain on Derivatives, Net 16,856 — 263 — 17,119 Other Expense 34 — — — 34 Loss From Equity Method Investments (203 ) — — — (203 ) Income (Loss) From Equity in Consolidated Subsidiaries (23 ) 23 (3,214 ) 3,214 — TOTAL OTHER INCOME (EXPENSE) 16,606 23 (14,910 ) 3,214 4,933 INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (4,134 ) — (17,886 ) 3,449 (18,571 ) Income Tax Benefit 20 — 72 — 92 INCOME (LOSS) FROM CONTINUING OPERATIONS (4,114 ) — (17,814 ) 3,449 (18,479 ) Loss From Discontinued Operations, Net of Income Tax — 2,826 — (864 ) 1,962 Net Income (Loss) (4,114 ) 2,826 (17,814 ) 2,585 (16,517 ) Net Income Attributable to Noncontrolling Interests of Discontinued Operations — 1,297 — — 1,297 NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ (4,114 ) $ 1,529 $ (17,814 ) $ 2,585 $ (17,814 ) Preferred Stock Dividends — — 2,415 — 2,415 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (4,114 ) $ 1,529 $ (20,229 ) $ 2,585 $ (20,229 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDING MARCH 31, 2015 ($ in Thousands) Guarantor Non-Guarantor Rex Energy Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (4,114 ) $ 2,826 $ (17,814 ) $ 2,585 $ (16,517 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Loss From Equity Method Investments 203 — — — 203 Non-Cash Expenses (70 ) 44 3,403 — 3,377 Depreciation, Depletion, Amortization and Accretion 26,292 1,480 — (1,607 ) 26,165 Gain on Derivatives (16,856 ) — (263 ) — (17,119 ) Cash Settlements of Derivatives 10,579 — 500 — 11,079 Dry Hole Expense (1 ) — — — (1 ) (Gain) Loss on Sale of Asset 65 (32 ) — — 33 Impairment Expense 7,012 11 — — 7,023 Changes in operating assets and liabilities Accounts Receivable 10,437 (1,087 ) 428 251 10,029 Inventory, Prepaid Expenses and Other Assets 712 (322 ) (62 ) — 328 Accounts Payable and Accrued Liabilities (12,518 ) (2,496 ) 2,336 (251 ) (12,929 ) Other Assets and Liabilities (199 ) (133 ) 27 — (305 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 21,542 291 (11,445 ) 978 11,366 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 27,192 (1,688 ) (23,681 ) (1,823 ) — Proceeds from Joint Venture Acreage Management 39 — — — 39 Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 217 455 — — 672 Proceeds from Joint Venture for Reimbursement of Capital Costs 16,611 — — — 16,611 Acquisitions of Undeveloped Acreage (17,454 ) (5 ) — — (17,459 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (60,719 ) (7,139 ) — 845 (67,013 ) NET CASH USED IN INVESTING ACTIVITIES (34,114 ) (8,377 ) (23,681 ) (978 ) (67,150 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — 18,826 54,000 — 72,826 Repayments of Long-Term Debt and Lines of Credit — (9,761 ) (16,000 ) — (25,761 ) Repayments of Loans and Other Notes Payable (392 ) (294 ) — — (686 ) Debt Issuance Costs — — (459 ) — (459 ) Dividends Paid — — (2,415 ) — (2,415 ) Distributions by the Partners of Consolidated Subsidiaries — (531 ) — — (531 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (392 ) 8,240 35,126 — 42,974 NET INCREASE IN CASH (12,964 ) 154 — — (12,810 ) CASH – BEGINNING 17,978 113 5 — 18,096 CASH – ENDING $ 5,014 $ 267 $ 5 $ — $ 5,286	25. CONDENSED CONSOLIDATING FINANCIAL INFORMATION As of December 31, 2015, we had $675.0 million of outstanding Senior Notes, as shown in Note 9, Long-Term Debt • Rex Energy I, LLC • Rex Energy Operating Corporation • Rex Energy IV, LLC • PennTex Resources Illinois, Inc. • R.E. Gas Development, LLC The non-guarantor subsidiaries include certain consolidated subsidiaries, including Water Solutions, R.E. Disposal, LLC, Rex Energy Marketing, LLC and R.E. Ventures, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of December 31, 2015, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries. The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the notes, (ii) the combined Guarantors, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of December 31, 2015 and 2014, and the condensed consolidating statements of operations and condensed consolidating statements of cash flows for each of the years in the three-year period ended December 31, 2015. REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS FOR THE YEAR ENDED DECEMBER 31, 2015 ($ in Thousands, Except Share and Per Share Data) 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 19,423 11 49 — 19,483 Taxes Receivable — — 18 — 18 Short-Term Derivative Instruments 34,260 — — — 34,260 Inventory, Prepaid Expenses and Other 3,804 — 25 — 3,829 Total Current Assets 58,576 11 94 — 58,681 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,245,626 774 — (6,970 ) 1,239,430 Unevaluated Oil and Gas Properties 262,992 — — — 262,992 Other Property and Equipment 39,217 895 — — 40,112 Wells and Facilities in Progress 144,587 239 — (270 ) 144,556 Pipelines 16,161 — — (2,137 ) 14,024 Total Property and Equipment 1,708,583 1,908 — (9,377 ) 1,701,114 Less: Accumulated Depreciation, Depletion and Amortization (702,537 ) (880 ) — 3,518 (699,899 ) Net Property and Equipment 1,006,046 1,028 — (5,859 ) 1,001,215 Deferred Financing Costs and Other Assets – Net 2,501 — 14,043 — 16,544 Equity Method Investments — — — — — Long-Term Deferred Tax Asset — — 12,532 — 12,532 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 $ 1,074,750 $ 1,039 $ 1,340,548 $ (1,317,831 ) $ 1,098,506 LIABILITIES AND EQUITY Current Liabilities Accounts Payable $ 37,874 $ — $ — $ — $ 37,874 Current Maturities of Long-Term Debt 590 — — — 590 Accrued Liabilities 32,601 — 11,725 — 44,326 Short-Term Derivative Instruments 2,486 — — — 2,486 Current Deferred Tax Liability — — 12,532 — 12,532 Total Current Liabilities 73,551 — 24,257 — 97,808 8.875% Senior Notes Due 2020 — — 350,000 — 350,000 6.25% Senior Notes Due 2022 — — 325,000 — 325,000 Premium on Senior Notes – Net — — 2,344 — 2,344 Senior Secured Line of Credit and Other Long-Term Debt 28 — 111,500 — 111,528 Long-Term Derivative Instruments 5,556 — — — 5,556 Other Deposits and Liabilities 3,156 — — — 3,156 Future Abandonment Cost 42,443 440 — — 42,883 Intercompany Payables 1,070,096 452 — (1,070,548 ) — Total Liabilities 1,194,830 892 813,101 (1,070,548 ) 938,275 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) (297,223 ) 147 (92,385 ) (74,226 ) (463,687 ) Rex Energy Stockholders’ Equity (120,080 ) 147 527,447 (247,283 ) 160,231 Noncontrolling Interests — — — — — Total Stockholders’ Equity (120,080 ) 147 527,447 (247,283 ) 160,231 Total Liabilities and Stockholders’ Equity $ 1,074,750 $ 1,039 $ 1,340,548 $ (1,317,831 ) $ 1,098,506 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Oil, Natural Gas and NGL Sales $ 171,440 $ 511 $ — $ — $ 171,951 Other Revenue 42 — — — 42 TOTAL OPERATING REVENUE 171,482 511 — — 171,993 OPERATING EXPENSES Production and Lease Operating Expense 118,825 174 — — 118,999 General and Administrative Expense 22,879 52 6,504 — 29,435 Gain on Disposal of Asset (477 ) — — — (477 ) Impairment Expense 345,892 1,396 — (1,513 ) 345,775 Exploration Expense 2,879 137 — (5 ) 3,011 Depreciation, Depletion, Amortization and Accretion 105,556 157 — (969 ) 104,744 Other Operating Expense 5,595 — — — 5,595 TOTAL OPERATING EXPENSES 601,149 1,916 6,504 (2,487 ) 607,082 INCOME (LOSS) FROM OPERATIONS (429,667 ) (1,405 ) (6,504 ) 2,487 (435,089 ) OTHER INCOME (EXPENSE) Interest Expense (271 ) — (47,535 ) — (47,806 ) Gain on Derivatives, Net 59,242 — 934 — 60,176 Other Expense (115 ) — — — (115 ) Loss From Equity Method Investments (411 ) — — — (411 ) Income (Loss) From Equity in Consolidated Subsidiaries (1,324 ) 1,324 (313,198 ) 313,198 — TOTAL OTHER INCOME (EXPENSE) 57,121 1,324 (359,799 ) 313,198 11,844 INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (372,546 ) (81 ) (366,303 ) 315,685 (423,245 ) Income Tax Benefit 21,122 81 3,024 — 24,227 NET INCOME (LOSS) FROM CONTINUING OPERATIONS (351,424 ) — (363,279 ) 315,685 (399,018 ) Income (Loss) From Discontinued Operations, Net of Income Tax — 3,908 35,269 (1,192 ) 37,985 NET INCOME (LOSS) (351,424 ) 3,908 (328,010 ) 314,493 (361,033 ) Net Income Attributable to Noncontrolling Interests of Discontinued Operations — 2,245 — — 2,245 NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ (351,424 ) $ 1,663 $ (328,010 ) $ 314,493 $ (363,278 ) Preferred Stock Dividends — — 9,660 — 9,660 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (351,424 ) $ 1,663 $ (337,670 ) $ 314,493 $ (372,938 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDING DECEMBER 31, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (351,424 ) $ 3,908 $ (328,010 ) $ 314,493 $ (361,033 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Loss on Equity Method Investments 411 — — — 411 Non-Cash Expenses (Income) (201 ) (334 ) 8,184 — 7,649 Depreciation, Depletion, Amortization and Accretion 105,555 3,230 — (3,963 ) 104,822 Gain on Derivatives (59,242 ) — (934 ) — (60,176 ) Cash Settlements of Derivatives 54,859 — 934 — 55,793 Dry Hole Expense 199 136 — (5 ) 330 Gain on Sale of Asset (477 ) (44 ) — — (521 ) Gain on Sale of Water Solutions — — (57,778 ) — (57,778 ) Impairment Expense 345,892 1,396 345,892 (347,405 ) 345,775 Changes in operating assets and liabilities Accounts Receivable 24,240 (453 ) 429 (2,537 ) 21,679 Inventory, Prepaid Expenses and Other Assets (431 ) (142 ) 5 — (568 ) Accounts Payable and Accrued Liabilities (20,008 ) (4,969 ) (515 ) 2,537 (22,955 ) Other Assets and Liabilities (2,497 ) (73 ) 27 — (2,543 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 96,876 2,655 (31,766 ) (36,880 ) 30,885 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany Loans to Subsidiaries 103,212 (3,362 ) (135,566 ) 35,716 — Proceeds from Joint Venture Acreage Management 58 — — — 58 Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 9,766 560 66,900 — 77,226 Proceeds from Joint Venture 16,611 — — — 16,611 Acquisitions of Undeveloped Acreage (27,963 ) (279 ) — — (28,242 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (214,450 ) (7,813 ) — 1,164 (221,099 ) NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (112,766 ) (10,894 ) (68,666 ) 36,880 (155,446 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — 35,814 193,500 — 229,314 Repayments of Long-Term Debt and Lines of Credit — (26,335 ) (82,000 ) — (108,335 ) Repayments of Loans and Other Notes Payable (999 ) (520 ) — — (1,519 ) Debt Issuance Costs — (3 ) (1,411 ) — (1,414 ) Distributions by the Partners of Consolidated Subsidiary — (830 ) — — (830 ) Dividends Paid on Preferred Stock — — (9,660 ) — (9,660 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (999 ) 8,126 100,429 — 107,556 NET (DECREASE) IN CASH (16,889 ) (113 ) (3 ) — (17,005 ) CASH – BEGINNING 17,978 113 5 — 18,096 CASH – ENDING $ 1,089 $ — $ 2 $ — $ 1,091 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS FOR THE YEAR ENDED DECEMBER 31, 2014 ($ in Thousands, Except Share and Per Share Data) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 17,978 $ — $ — $ — $ 17,978 Accounts Receivable 43,726 210 — — 43,936 Taxes Receivable — — 504 — 504 Short-Term Derivative Instruments 29,265 — — — 29,265 Assets Held For Sale — 36,794 — (2,537 ) 34,257 Inventory, Prepaid Expenses and Other 3,374 — 29 — 3,403 Total Current Assets 94,343 37,004 533 (2,537 ) 129,343 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,084,332 467 — (5,760 ) 1,079,039 Unevaluated Oil and Gas Properties 321,708 705 — — 322,413 Other Property and Equipment 45,466 895 — — 46,361 Wells and Facilities in Progress 127,759 456 — (560 ) 127,655 Pipelines 17,555 — — (1,898 ) 15,657 Total Property and Equipment 1,596,820 2,523 — (8,218 ) 1,591,125 Less: Accumulated Depreciation, Depletion and Amortization (367,224 ) (730 ) — 1,037 (366,917 ) Net Property and Equipment 1,229,596 1,793 — (7,181 ) 1,224,208 Deferred Financing Costs and Other Assets—Net 2,421 — 14,649 — 17,070 Equity Method Investments 17,895 — — — 17,895 Long-Term Deferred Tax Asset — — 8,301 — 8,301 Intercompany Receivables — — 951,025 (951,025 ) — Investment in Subsidiaries – Net 4,161 1,541 258,448 (264,150 ) — Long-Term Derivative Instruments 4,904 — — — 4,904 Total Assets $ 1,353,320 $ 40,338 $ 1,232,956 $ (1,224,893 ) $ 1,401,721 LIABILITIES AND EQUITY Current Liabilities Accounts Payable $ 55,877 $ — $ — $ (2,537 ) $ 53,340 Current Maturities of Long-Term Debt 1,176 — — — 1,176 Accrued Liabilities 46,783 571 12,124 — 59,478 Short-Term Derivative Instruments 421 — — — 421 Long-Term Deferred Tax Liability — — 8,301 — 8,301 Liabilities Related to Assets Held For Sale — 25,115 — — 25,115 Total Current Liabilities 104,257 25,686 20,425 (2,537 ) 147,831 8.875% Senior Notes Due 2020 — — 350,000 — 350,000 6.25% Senior Notes Due 2022 325,000 325,000 Premium (Discount) on Senior Notes – Net — — 2,725 — 2,725 Senior Secured Line of Credit and Other Long-Term Debt 251 — — — 251 Long-Term Derivative Instruments 2,377 — — — 2,377 Other Deposits and Liabilities 4,018 — — — 4,018 Future Abandonment Cost 38,097 49 — — 38,146 Intercompany Payables 947,114 3,911 — (951,025 ) — Total Liabilities 1,096,114 29,646 698,150 (953,562 ) 870,348 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 54 — 54 Additional Paid-In Capital 177,144 79,743 617,826 (256,887 ) 617,826 Accumulated Earnings (Deficit) 80,062 (69,253 ) (83,075 ) (18,483 ) (90,749 ) Rex Energy Stockholders’ Equity 257,206 10,490 534,806 (275,370 ) 527,132 Noncontrolling Interests — 202 — 4,039 4,241 Total Stockholders’ Equity 257,206 10,692 534,806 (271,331 ) 531,373 Total Liabilities and Stockholders’ Equity $ 1,353,320 $ 40,338 $ 1,232,956 $ (1,224,893 ) $ 1,401,721 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2014 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Oil, Natural Gas and NGL Sales $ 297,710 $ 159 $ — $ — $ 297,869 Other Revenue 118 — — — 118 TOTAL OPERATING REVENUE 297,828 159 — — 297,987 OPERATING EXPENSES Production and Lease Operating Expense 100,261 21 — — 100,282 General and Administrative Expense 30,317 83 5,737 — 36,137 Loss on Disposal of Asset 644 — — — 644 Impairment Expense 126,662 5,956 — — 132,618 Exploration Expense 9,165 281 — — 9,446 Depreciation, Depletion, Amortization and Accretion 94,643 513 — (689 ) 94,467 Other Operating Expense 134 — — — 134 TOTAL OPERATING EXPENSES 361,826 6,854 5,737 (689 ) 373,728 INCOME (LOSS) FROM OPERATIONS (63,998 ) (6,695 ) (5,737 ) 689 (75,741 ) OTHER INCOME (EXPENSE) Interest Expense (142 ) — (36,835 ) — (36,977 ) Gain on Derivatives, Net 37,359 — 1,517 — 38,876 Other Income (Expense) 90 — — — 90 Loss From Equity Method Investments (813 ) — — — (813 ) Income (Loss) From Equity in Consolidated Subsidiaries (4,278 ) 4,278 (20,204 ) 20,204 — TOTAL OTHER INCOME (EXPENSE) 32,216 4,278 (55,522 ) 20,204 1,176 INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (31,782 ) (2,417 ) (61,259 ) 20,893 (74,565 ) Income Tax (Expense) Benefit 9,928 2,417 14,570 — 26,915 NET INCOME (LOSS) FROM CONTINUING OPERATIONS (21,854 ) — (46,689 ) 20,893 (47,650 ) Income From Discontinued Operations, Net of Income Taxes — 9,330 — (4,330 ) 5,000 NET INCOME (LOSS) (21,854 ) 9,330 (46,689 ) 16,563 (42,650 ) Net Income Attributable to Noncontrolling Interests of Discontinued Operations — 4,039 — — 4,039 NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ (21,854 ) $ 5,291 $ (46,689 ) $ 16,563 $ (46,689 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDING DECEMBER 31, 2014 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (21,854 ) $ 9,330 $ (46,689 ) $ 16,563 $ (42,650 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Loss on Equity Method Investments 813 — — — 813 Non-Cash Expenses (Income) (273 ) 278 6,784 — 6,789 Depreciation, Depletion, Amortization and Accretion 94,643 4,217 — (689 ) 98,171 Deferred Income Tax Benefit (9,928 ) (1,649 ) (14,415 ) — (25,992 ) Gain on Derivatives (37,359 ) — (1,517 ) — (38,876 ) Cash Settlements of Derivatives 5,969 — 1,312 — 7,281 Dry Hole Expense 3,797 267 — — 4,064 (Gain) Loss on Sale of Asset 644 (55 ) — — 589 Impairment Expense 126,662 6,022 — — 132,684 Changes in operating assets and liabilities Accounts Receivable (11,450 ) (6,090 ) 4,686 (766 ) (13,620 ) Inventory, Prepaid Expenses and Other Assets (1,283 ) (74 ) (2 ) — (1,359 ) Accounts Payable and Accrued Liabilities 23,768 3,488 9,252 766 37,274 Other Assets and Liabilities (2,127 ) (335 ) — — (2,462 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 172,022 15,399 (40,589 ) 15,874 162,706 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany Loans to Subsidiaries 397,382 (5,412 ) (371,768 ) (20,202 ) — Proceeds from Joint Venture Acreage Management 263 — — — 263 Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 254 292 — — 546 Acquisitions of Undeveloped Acreage (168,713 ) (710 ) — — (169,423 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (382,889 ) (12,861 ) — 4,328 (391,422 ) NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (153,703 ) (18,691 ) (371,768 ) (15,874 ) (560,036 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — 38,895 171,000 — 209,895 Repayments of Long-Term Debt and Lines of Credit — (33,152 ) (230,000 ) — (263,152 ) Repayments of Loans and Other Notes Payable (1,727 ) (994 ) — — (2,721 ) Proceeds from Senior Notes, net of Discounts and Premiums — — 325,000 — 325,000 Debt Issuance Costs — (8 ) (6,816 ) — (6,824 ) Proceeds from Issuance of Preferred Stock, Net — — 154,988 — 154,988 Proceeds from the Exercise of Stock Options — — 515 — 515 Purchase of Non-Controlling Interests — (1,840 ) — — (1,840 ) Dividends Paid on Preferred Stock — — (2,335 ) — (2,335 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (1,727 ) 2,901 412,352 — 413,526 NET INCREASE (DECREASE) IN CASH 16,592 (391 ) (5 ) — 16,196 CASH – BEGINNING 1,386 504 10 — 1,900 CASH – ENDING $ 17,978 $ 113 $ 5 $ — $ 18,096 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2013 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Eliminations Consolidated Balance OPERATING REVENUE Oil, Natural Gas and NGL Sales $ 213,919 $ — $ — $ — $ 213,919 Other Revenue 200 — — — 200 TOTAL OPERATING REVENUE 214,119 — — — 214,119 OPERATING EXPENSES Production and Lease Operating Expense 62,138 12 — — 62,150 General and Administrative Expense 25,376 43 5,420 — 30,839 Loss on Disposal of Asset 1,601 1 — — 1,602 Impairment Expense 32,072 — — — 32,072 Exploration Expense 11,395 13 — — 11,408 Depreciation, Depletion, Amortization and Accretion 62,540 46 — (200 ) 62,386 Other Operating Expense 592 — — — 592 TOTAL OPERATING EXPENSES 195,714 115 5,420 (200 ) 201,049 INCOME (LOSS) FROM OPERATIONS 18,405 (115 ) (5,420 ) 200 13,070 OTHER INCOME (EXPENSE) Interest Expense (64 ) — (22,612 ) — (22,676 ) Gain on Derivatives, Net (2,703 ) — (205 ) — (2,908 ) Other Income (Expense) 6,739 — — — 6,739 Loss From Equity Method Investments (763 ) — — — (763 ) Income (Loss) From Equity in Consolidated Subsidiaries (33 ) 33 5,703 (5,703 ) — TOTAL OTHER INCOME (EXPENSE) 3,176 33 (17,114 ) (5,703 ) (19,608 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX 21,581 (82 ) (22,534 ) (5,503 ) (6,538 ) Income Tax (Expense) Benefit (14,409 ) (1,841 ) 20,404 — 4,154 NET INCOME (LOSS) FROM CONTINUING OPERATIONS 7,172 (1,923 ) (2,130 ) (5,503 ) (2,384 ) Income From Discontinued Operations, Net of Income Taxes — 4,385 — (2,574 ) 1,811 NET INCOME (LOSS) 7,172 2,462 (2,130 ) (8,077 ) (573 ) Net Income Attributable to Noncontrolling Interests of Discontinued Operations — 1,557 — — 1,557 NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ 7,172 $ 905 $ (2,130 ) $ (8,077 ) $ (2,130 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDING DECEMBER 31, 2013 ($ in Thousands) Guarantor Subsidiaries Non- Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ 7,172 $ 2,462 $ (2,130 ) $ (8,077 ) $ (573 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Loss on Equity Method Investments 763 — — — 763 Non-Cash Expenses (194 ) 55 6,369 — 6,230 Depreciation, Depletion, Amortization and Accretion 62,540 1,604 — (200 ) 63,944 Deferred Income Tax Expense (Benefit) 14,409 2,210 (14,340 ) — 2,279 Gain on Derivatives 2,703 — 205 — 2,908 Cash Settlements of Derivatives 7,128 — — — 7,128 Dry Hole Expense 2,993 — — — 2,993 (Gain) Loss on Sale of Asset (5,289 ) (922 ) — — (6,211 ) Impairment Expense 32,072 — — — 32,072 Changes in operating assets and liabilities Accounts Receivable (5,877 ) (6,515 ) 1,241 (1,575 ) (12,726 ) Inventory, Prepaid Expenses and Other Assets (826 ) (59 ) — — (885 ) Accounts Payable and Accrued Liabilities 8,554 874 1,481 1,982 12,891 Other Assets and Liabilities (2,272 ) (88 ) (137 ) — (2,497 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 123,876 (379 ) (7,311 ) (7,870 ) 108,316 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany Loans to Subsidiaries 186,089 1,619 (193,015 ) 5,307 — Proceeds from Joint Venture Acreage Management 458 — — — 458 Contributions to Equity Method Investments (2,493 ) — — — (2,493 ) Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 8,071 3,234 — — 11,305 Acquisitions of Undeveloped Acreage (41,782 ) (2 ) — — (41,784 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (275,697 ) (7,870 ) — 2,563 (281,004 ) NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (125,354 ) (3,019 ) (193,015 ) 7,870 (313,518 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — 7,249 65,000 — 72,249 Repayments of Long-Term Debt and Lines of Credit — (2,480 ) (6,000 ) — (8,480 ) Repayments of Loans and Other Notes Payable (1,363 ) (642 ) — — (2,005 ) Proceeds from Senior Notes, net of Discounts and Premiums — — 105,000 — 105,000 Debt Issuance Costs — (8 ) (3,126 ) — (3,134 ) Proceeds from the Exercise of Stock Options — — 533 — 533 Purchase of Non-Controlling Interests — (150 ) — — (150 ) Distributions by the Partners of Consolidated Subsidiary — (886 ) — — (886 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (1,363 ) 3,083 161,407 — 163,127 NET INCREASE (DECREASE) IN CASH (2,841 ) (315 ) (38,919 ) — (42,075 ) CASH – BEGINNING 4,227 819 38,929 — 43,975 CASH – ENDING $ 1,386 $ 504 $ 10 $ — $ 1,900

Subsequent Events

Subsequent Events	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	18. SUBSEQUENT EVENTS Debt and Preferred Stock Exchanges During April 2016, we completed two privately negotiated exchanges of shares of our common stock for outstanding 2020 Notes, 2022 Notes, New Notes and our Series A Preferred Stock. In total, we exchanged approximately $17.2 million of 2020 Notes, $9.7 million of 2022 Notes, $2.2 million of New Notes and $13.8 million in face value of the Series A Preferred Stock for approximately 7.1 million shares of our common stock. In each transaction, the holders waived all accrued and unpaid interest. The shares of our common stock were issued under Section 3(a)(9) of the Securities Act of 1933, as amended. Borrowing Base Reduction In conjunction with the Exchange, effective April 1, 2016, we amended certain terms of our Senior Credit Facility including the reduction of our borrowing base from $200.0 million to $190.0 million effective April 1, 2016. As of March 31, 2016, we had approximately $158.0 million outstanding under our Senior Credit Facility and $41.0 million of undrawn letters of credit. On April 1, 2016, we paid down borrowings under our Senior Credit Facility by $9.5 million on April 1, 2016 to be in compliance with the amendment. This amount was recorded as Current Maturities of Long-Term Debt on our Consolidated Balance Sheet as of March 31, 2016.	26. SUBSEQUENT EVENTS Exchange Offer On February 3, 2016, we announced the commencement of an exchange offer and consent solicitation related to our outstanding Senior Notes, and on March 14, 2016, we revised those terms and re-announced the exchange offer. We are offering to exchange any and all of the Senior Notes held by eligible holders for up to (i) $675.0 million in new senior secured second lien notes (“New Notes”), plus the amount of additional New Notes, not to exceed $6.0 million, resulting solely from any exchange participant’s election to receive additional New Notes in lieu of shares of common stock under the exchange offering, and (ii) 10.125 million shares of our common stock. The New Notes will bear interest at a rate of 0.0% per annum for the first three bi-annual interest payments after issuance and 8.0% per annum payable in cash thereafter, paid on a bi-annual basis; provided, however, that if greater than 85% of the Senior Notes are tendered in the exchange, the New Notes will bear interest at a rate of 1.0% per annum payable in cash for the first three interest payments after issuance and 8.0% per annum payable in cash thereafter. The New Notes will mature on October 1, 2020; provided, however, that if greater than 85% of the Senior Notes are tendered in the exchange, the New Notes will mature on October 1, 2021. In addition to the exchange offer, we are soliciting consents from the eligible holders to proposed amendments to the indentures governing the Senior Notes that would eliminate or modify certain restrictive covenants and modify certain defined terms. The aggregate principal amount of our Senior Notes as of December 31, 2015 was $675.0 million. Senior Credit Facility Amendment On February 3, 2016, we amended our Senior Credit Facility, in part to permit the aforementioned exchange offer. The amendment contemplated the following changes: • Decreases our borrowing base from $350.0 million to $200.0 million; • Amends the definition of net senior secured debt to exclude undrawn letters of credit related to firm transportation contracts and second lien exchange notes; • Amends the calculation of current ratio to exclude current assets and current liabilities related to deferred taxes; • Increases pricing from 150-250 basis points to 225-325 basis points; and • Increases the commitment fee to 50 basis points. On March 14, 2016, we entered into another amendment to our Senior Credit Facility, in part to revise the terms of the exchange offering. The amendment contemplated the following changes: • Allows for the issuance of up to $675.0 million of New Notes, plus an additional amount of New Notes, not to exceed $6.0 million, resulting solely from any exchange participant’s election to receive additional New Notes in lieu of shares of common stock under the exchange offering; • In the event that holders of at least 80% of the Company’s Senior Notes exchange such notes for New Notes, amends the calculation of the Company’s maximum 3.0x Ratio of Net Senior Secured Debt to EBITDAX to become 2.75 to 1.00; • Increases the requirement for mortgages on oil and gas properties from 90% to 95%, and for certain properties in the Moraine East and Warrior North Areas, to 100%; • Restricts cash and cash equivalents held on the balance sheet to a maximum of $15.0 million, with any excess 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; • Provides in the event that any letter of credit which secures obligations under a firm transportation contract expires without renewal or replacement, or is cancelled, terminated or otherwise ceases to remain outstanding, then the borrowing base then in effect shall be automatically reduced immediately by an amount equal to the product of 0.50 multiplied by the undrawn amount of such letter of credit; • Restricts the Company’s ability to pay cash dividends to its holders of Series A Preferred Stock until after the Company delivers its audited financial statements for the fiscal year 2016 to the Lenders as required under the Senior Credit Facility, and thereafter permits such cash payments only if certain parameters are met relating to outstanding borrowings and interest expense; and • Provides for an additional redetermination of the borrowing base under the Senior Credit Facility on July 1, 2016. After the July 1, 2016 redetermination, our Senior Credit Facility will resume its normal semi-annual redetermination schedule, with the next redetermination expected to take place in the third quarter of 2016. Joint Exploration and Development Agreement On March 1, 2016, we entered into a Joint Exploration and Development Agreement (the “Joint Development Agreement”) with OhPa Drillco (“Drillco”), an affiliate of Benefit Street Partners, L.L.C. to jointly develop 58 specifically designated wells in our Moraine East and Warrior North operated areas. Under the Joint Development Agreement, Drillco has committed to fund 15% of various drilling, completing and equipping costs (“well costs”) for the first 16 wells in Moraine East at a specified rate, 12 of which have already been drilled and completed, and 65% of the well costs of six wells in Warrior North at a specified rate, three of which have already been drilled and completed. In return for Drillco’s funding of the well costs, we will assign to Drillco a working interest of 15% in the funded wells located in Moraine East and 65% in the funded wells in Warrior North, together with the rights to real and personal property, permits, licenses, and other rights that are necessary or required to operate and produce oil, gas and other hydro carbons and all associated substances from the wellbores of such wells. Drillco will also have the option to participate in the next 36 wells within the joint development areas for a 65% working interest. In addition, Drillco will earn a 15% – 20% assignment in Moraine East and Warrior North for all acreage within each unit they participate in. Total consideration for the transaction is expected to be $175.0 million, with $37.3 million committed at closing for the first 22 wells. Once the first 15 wells within the joint development areas are flowing into sales, we will receive reimbursement of approximately $19.5 million. Commodity Derivatives We continue to be opportunistic in adding commodity derivatives as market conditions warrant. To date in 2016 we have added derivatives covering approximately 380,000 barrels of oil, 2,740,000 mcf of natural gas and 120,000 barrels of NGLs for volumes related to 2016. The oil derivatives added include collars, three-way collars and cap swap contracts. The natural gas derivatives added included swap and put spread contracts. The NGL derivatives added consisted of swap contracts.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates. Estimates made in preparing these Consolidated Financial Statements include, among other things, estimates of the proved oil, NGL and natural gas reserve volumes used in calculating Depletion, Depreciation and Amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment; fair values of financial derivative instruments; volumes and prices for revenues accrued; estimates of the fair value of equity-based compensation awards; deferred tax valuation allowance and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods. The estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates and our ability to generate future income. Cash and Cash Equivalents We consider all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents. As of December 31, 2015 and 2014, our Cash and Cash Equivalents consisted of only cash. Accounts Receivable Our trade accounts receivable, which are primarily from oil, NGLs and natural gas sales and joint interest billings, are recorded at the invoiced amount and include production receivables. The production receivable is valued at the invoiced amount and does not bear interest. Accounts receivable also include joint interest billing receivables which represent billings to the non-operators associated with the drilling and operation of wells and are based on those owners’ working interests in the wells. We have assessed the financial strength of our customers and joint owners and record an allowance for bad debts as necessary. Our allowance for bad debts as of December 31, 2015 and 2014, was negligible. To the extent actual quantities and values of oil, NGLs and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Accounts Receivable in the accompanying Consolidated Balance Sheets. At December 31, 2015, we carried approximately $12.1 million in production receivable, of which approximately $10.5 million were production receivables due from four purchasers. At December 31, 2014, we carried approximately $25.2 million in production receivables, of which approximately $21.4 million were production receivables due from four purchasers. In addition, we carried approximately $3.2 million in receivables at December 31, 2015 and $6.7 million at December 31, 2014 that was in relation to our joint operations with Sumitomo Corporation and ArcLight Capital Partners, LLC. Inventory Inventory is valued at the lower of cost or market value and consists of our ownership interest in oil and NGLs held in terminal tanks located in the field. Oil and NGL cost basis is calculated using the average cost method, with average cost defined as production and lease operating expenses net of DD&A. General and Administrative expenses are not allocated to the cost of inventory for the purpose of valuing inventory. Oil, NGL and Natural Gas Property, Depreciation and Depletion We account for oil, NGL and natural gas exploration and production activities under the successful efforts method of accounting. Proved developed natural gas and oil property acquisition costs are capitalized when incurred, including our estimate of the fair value of future abandonment costs. Unproved properties with individually significant acquisition costs are assessed periodically on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop estimated proved reserves, including the costs of all development well and related equipment used in the production of oil, NGLs and natural gas, are capitalized. We capitalize interest on capital projects, most notably during the drilling and completion of oil and natural gas wells. For the years ended December 31, 2015, 2014 and 2013, we capitalized interest costs of $7.7 million, $7.3 million and $7.5 million, respectively. Depletion is calculated using the unit-of-production method. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. We periodically review estimated proved reserve estimates and make changes as needed to depletion expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in our estimated proved reserves. The costs of unproved properties are withheld from the depletion base until such time as they are proved. When estimated proved reserves are assigned, the cost of the property is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is allocated to the associated producing properties as the undeveloped acreage is developed. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of three to 40 years. We review assets for impairment when events or circumstances indicate a possible decline in the recoverability of the carrying value of such property. When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future oil, NGL and natural gas prices, operating costs, anticipated production from estimated proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Our estimates of future oil, NGL and natural gas prices are based on forward strip prices for NYMEX oil and various natural gas markets that are relevant to our operations. For unproved oil and gas properties, we analyze activity on the acreage prior to evaluating any fair value indicators, such as current drilling activity, drilling success, future development plans and the likelihood of expiration. Unproved oil and gas properties are impaired when it becomes more likely than not that a property will expire before it can be developed or an extension can be agreed upon. When evaluating the value of our unproved oil, NGL and natural gas properties, we analyze the level and success of current development, future development plans and changes in market value. Performing the impairment evaluations requires use of judgments and estimates since the results are dependent on future events, including estimates of future proved and unproved reserves, future commodity prices, the timing of future production, capital expenditures and the intent to develop properties, among others. We recognized approximately $345.8 million, $132.6 million and $32.1 million of impairment from continuing operations on certain oil, NGL and natural gas properties for the years ending December 31, 2015, 2014 and 2013, respectively. We recorded these charges as Impairment Expense on our Consolidated Statements of Operations. For additional information, see Note 16, Impairment Expense Expenditures for repairs and maintenance to sustain production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense. Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated depletion are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain. Natural Gas and Oil Reserve Quantities Our estimate of proved reserves is based on the quantities of oil, NGLs and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. For the years ended December 31, 2015 and 2014, Netherland Sewell and Associates, Inc. (“NSAI”) prepared a consolidated reserve and economic evaluation of our proved oil and gas reserves. The preparation of our proved reserve estimates are completed in accordance with our internal control procedures, which include the verification of input data used by NSAI, as well as management review and approval. Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Estimates of our crude oil, NGL and natural gas reserves, and the projected cash flows derived from these reserve estimates, are prepared by our engineers in accordance with guidelines established by the SEC. The independent reserve engineer estimates reserves annually on December 31. This annual estimate results in a new depletion rate, which we use for the preceding fourth quarter after adjusting for fourth quarter production. Deferred Financing Costs and Other Assets—Net At December 31, 2015, we had deferred financing costs and other assets consisting of $16.5 million, which is primarily made up of bond costs and loan costs that are amortized using the effective interest method and the straight line method, respectively, over their estimated lives, which is, on average, five to eight years. We amortize any costs incurred to renew or extend the terms of existing debt over the contract term or estimated useful life, as applicable. For the years ended December 31, 2015, 2014 and 2013, we recorded amortization expense from continuing operations of $2.0 million, $1.5 million and $1.2 million, respectively. The following is a summary of our deferred financing costs at the dates indicated: December 31, 2015 (in thousands) December 31, 2014 (in thousands) Deferred Financing Costs—Gross $ 20,623 $ 19,212 Accumulated Amortization (6,580 ) (4,564 ) Deferred Financing Costs—Net $ 14,043 $ 14,648 Specific to our deferred financing costs, we have incurred gross debt issuance costs of approximately $1.4 million and $6.8 million for the years ended December 31, 2015 and 2014, respectively, which are presented net of accumulated amortization of $6.6 million and $4.6 million, respectively, and include deferred financing from our senior notes and revolving line of credit. 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 asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Accretion expense from continuing operations during the years ended December 31, 2015, 2014 and 2013 totaled approximately $3.8 million, $3.6 million and $3.0 million, respectively. These amounts are recorded as DD&A on our Consolidated Statements of Operations. As of December 31, 2015 and 2014, approximately $2.2 million and $2.0 million, respectively, of our Future Abandonment Costs were classified as short-term liabilities under the caption Accrued Liabilities on our Consolidated Balance Sheets. During 2015 and 2014, we recognized an increase of $2.4 million and $8.4 million, respectively, in the estimated present value of our asset retirement obligations, representing an increase in the estimate to plug and abandon our oil and natural gas wells. The revised estimates were primarily the result of increased abandonment cost estimates, which were driven by the trends of actual outcomes. We account for asset retirement obligations that relate to wells that are drilled jointly based on our interest in those wells. December 31, 2015 (in thousands) December 31, 2014 (in thousands) Beginning Balance $ 40,099 $ 28,525 Asset Retirement Obligation Incurred 1,135 1,480 Asset Retirement Obligation Settled (2,273 ) (1,943 ) Asset Retirement Obligation Cancelled or Sold Properties (136 ) (10 ) Asset Retirement Obligation Revision of Estimated Obligation 2,428 8,426 Asset Retirement Obligation Accretion Expense 3,821 3,621 Total Future Abandonment Costs $ 45,074 $ 40,099 Revenue Recognition Oil, NGL and natural gas revenue is recognized when the oil, NGL or natural gas is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil and NGL sales, title is transferred to the purchaser when the oil or NGLs leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. It is the measurement of the purchaser that determines the amount of oil, NGL or natural gas purchased. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for oil, NGLs and natural gas purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our oil, NGL and natural gas production is at its applicable field gathering system. We do not recognize revenue for oil and NGL production held in stock tanks before delivery to the purchaser. To the extent actual quantities and values of oil, NGLs and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Oil, Natural Gas and NGL Sales on the Statements of Operations. Derivative Instruments We use put and call options (collars), fixed rate swap contracts, swaptions, puts, deferred put spreads, cap swaps, call protected swaps, basis swaps and three-way collars to manage price risks in connection with the sale of oil, natural gas and NGLs. We have also used interest rate swap agreements to manage interest rate exposure associated with our fixed rate senior notes. We have established the fair value of all derivative instruments using estimates determined by our counterparties and other third-parties. These values are based upon, among other things, future prices, volatility, time to maturity and credit risk. The values we report in our Consolidated Financial Statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. We report our derivative instruments at fair value and include them in the Consolidated Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated for hedge accounting, for financial accounting purposes, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness are recognized immediately in earnings. During 2015, 2014 and 2013 we did not have any derivative instruments designated for hedge accounting. For derivative instruments designated as fair value hedges, changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Derivative effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. For derivatives on oil, natural gas and NGL production activity, our evaluations are not documented, and as a result, we record changes on the derivative valuations through earnings. For additional information on our derivative instruments, see Note 10, Fair Value of Financial Instruments and Derivative Instruments Contingent Liabilities A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information. Income Taxes We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed several months after the close of a calendar year, tax returns are subject to audit which can take years to complete, and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards and other deductible differences and deferred tax liabilities that relate to oil and gas properties and other taxable differences. Deferred tax assets and liabilities are computed based on the difference between the financial statement and income tax basis of assets and liabilities using the enacted tax rates. Net deferred tax assets are required to be reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the net deferred tax asset will not be realized. This process requires our management to make assessments regarding the timing and probability of the ultimate tax impact. We record valuation allowances on deferred tax assets if we determine it is more likely than not that the asset will not be realized. Actual income taxes could vary from these estimates due to future changes in income tax law, significant changes in the jurisdictions in which we operate, our inability to generate sufficient future taxable income, or unpredicted results from the final determination of each year’s liability by taxing authorities. These changes could have a significant impact on our financial position. The accounting estimate related to the tax valuation allowance requires us to make assumptions regarding the timing of future events, including the probability of expected future taxable income and available tax planning opportunities. These assumptions require significant judgment because actual performance has fluctuated in the past and may do so in the future. The impact that changes in actual performance versus these estimates could have on the realization of tax benefits as reported in our results of operations could be material. We continuously evaluate facts and circumstances representing positive and negative evidence in the determination of our ability to realize the deferred tax assets. We recognize a tax position if it is more likely than not that it will be sustained upon examination. If we determine it is more likely than not a tax position will be sustained based on its technical merits, we record the impact of the position in our Consolidated Financial Statements at the largest amount that is greater than fifty percent likely of being realized upon ultimate settlement. These estimates are updated at each reporting date based on the facts, circumstances and information available. We are also required to assess at each reporting date whether it is reasonably possible that any significant increases or decreases to the unrecognized tax benefits will occur during the next twelve months (for additional information, see Note 11, Income Taxes, Stock-based Compensation We recognize in the Consolidated Financial Statements the cost of employee and non-employee director services received in exchange for awards of equity instruments based on the grant date fair value of those awards. We use a standard option pricing model (i.e. Black-Scholes) to measure the fair value of employee stock options and stock appreciation rights and a Monte Carlo simulation technique to value restricted stock awards that are tied to market performance. The fair value of non-market based restricted stock awards is determined based on the fair market value of our common stock on the date of the grant. The benefits associated with the tax deductions in excess of recognized compensation cost are reported as a financing cash flow when realized. We recognize compensation costs related to awards with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award were, in-substance, multiple awards (for additional information, see Note 15, Employee Benefit and Equity Plans, Earnings per Common Share Earnings per common share are computed by dividing consolidated net income attributable to us by the weighted average number of common shares outstanding. Diluted earnings per common share are computed based upon the weighted average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities, including the assumed conversion of preferred stock. At December 31, 2015, we had 55,741,229 common shares outstanding, 443,672 options outstanding and 20,500 stock appreciation rights outstanding with no outstanding warrants or other potentially dilutive securities. The total common shares outstanding include 2,479,408 restricted stock awards, of which approximately 1,065,296 shares are performance-based awards. For additional information, see Note 12, Earnings per Common Share Recent Accounting Pronouncements In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40). The new guidance addresses management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The standard is effective for the annual period ending after December 15, 2016 and for annual and interim periods thereafter. Early adoption is permitted. We adopted this ASU on January 1, 2016. Adoption did not have a material impact on our Consolidated Financial Statements. In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The amendments in this ASU intend to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures. The ASU focuses on the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. In addition to reducing the number of consolidation models from four to two, the new standard places more emphasis on risk of loss when determining a controlling financial interest, reduces the frequency of the application of related-party guidance when determining a controlling financial interest in a variable interest entity and changes consolidation conclusions in several industries that typically make use of limited partnerships or variable interest entities. This ASU will be effective for periods beginning after December 15, 2015, for public companies, and early adoption is permitted, including adoption in an interim period. We are currently evaluating the potential effect of this ASU but do not believe that it will have a material impact on our Consolidated Financial Statements. In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The standard requires an entity to present debt issuance costs related to a recognized liability as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The guidance in the ASU is effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein. Early adoption is permitted. We are currently evaluating the potential effect of this ASU and the related impact on our Consolidated Financial Statements. As of December 31, 2015, we had approximately $14.0 million in net deferred financing costs that would be potentially reclassified to reduce the debt carrying balance. 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 August 2015, the FASB issued ASU 2015-15, Interest – Imputation of Interest (Subtopic 835-30), Presentation and Subsequent Measurement of Debt Issuance Costs with Line-of-Credit Arrangements. This ASU clarifies the presentation of debt issuance costs associated with line-of-credit arrangements. In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, which requires the presentation of debt issuance costs related to a recognized debt liability as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 does not address presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements. Given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to line-of-credit arrangements, the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The guidance in the ASU is effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein. Early adoption is permitted. We are currently evaluating the potential effect of this ASU and the related impact on our Consolidated Financial Statements.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	8. RELATED PARTY TRANSACTIONS Aircraft Services We have an oral month-to-month agreement with Charlie Brown Air Corp. (“Charlie Brown”), a New York corporation owned by Lance T. Shaner, our Chairman, regarding the use of one airplane owned or managed on our behalf by Charlie Brown. Under our agreement with Charlie Brown, we pay a monthly fee for the right to use the airplanes equal to our percentage (based upon the total number of hours of use of the airplanes by us) of the monthly fixed costs for the airplanes, plus a variable per hour flight rate that ranges from $700 to $1,560 per hour. For the years ended December 31, 2015 and 2014, we paid Charlie Brown $0.1 million and $0.1 million, respectively, for the use of the aircrafts, including the variable per hour cost in addition to pilot fees, maintenance, hangar rental and other miscellaneous expenses. For the year ended December 31, 2013, the amounts paid to Charlie Brown were negligible. We own a 50% membership interest in Charlie Brown Air II, LLC (“Charlie Brown II”). Shaner Hotel Group Limited Partnership, a Delaware limited partnership controlled by Mr. Lance T. Shaner (“Shaner Hotel”), in Charlie Brown II, which owns and operates an Eclipse 500 aircraft. Charlie Brown II has a loan from Graystone Bank to purchase the aircraft that was originally $1.5 million at its inception in June 2007. The loan matures on June 21, 2017 and bears interest at a rate of LIBOR plus 2.5%. The loan required payments of interest only for the first three months of the loan. Thereafter, Charlie Brown II has been required to make monthly payments of principal and interest utilizing an amortization period of 180 months. The company and Shaner Hotel each guarantee up to fifty percent, or $0.8 million, of the principal balance of the loan. The balance of this loan as of December 31, 2015 and 2014 was approximately $1.0 million and $1.1 million, respectively. For the years ended December 31, 2015, 2014 and 2013, we paid Charlie Brown II approximately $0.3 million, $0.2 million and $0.2 million, respectively, for loan interest, services rendered and retainer fees. The business affairs of Charlie Brown Air II, LLC are managed by two members, appointed by each of its two owners. We have designated Thomas C. Stabley, our President and Chief Executive Officer, as the manager representing our membership interest. Actions of the company must be approved by a majority of the interest percentages of the managers. Each manager votes in matters before the company in accordance with the membership interest percentage of the member that appointed the manager. Certain events, such as the sale by a member of its interest, the merger or consolidation of the company, the filing of bankruptcy, or the sale of the airplane owned by Charlie Brown Air II, LLC, require the written consent of both managers. The consent of managers is also required before the company may change or terminate the management agreement with Charlie Brown, incur any indebtedness, sell substantially all of the company’s assets or sell the airplane owned by the company. In the event that the members are unable to unanimously agree upon any of these matters within 10 days of the proposal of any such matter, an “impasse” may be declared, and the airplane will be sold by the company. As of December 31, 2015, there were negligible amounts due to or from us to any Shaner affiliated entities. Office Rental On June 27, 2012, we entered into an office lease agreement with Shaner Office Holdings, L.P., a limited partnership controlled by Lance T. Shaner. The office lease, which replaced our former headquarters office lease in State College, Pennsylvania, calls for monthly rental payments in the amount of $35,000 which began on April 1, 2013 and ends on December 31, 2017, with an annual Consumer Price Index (“CPI”) adjustment. The annual CPI adjustment is capped at 2.5%. The term of the lease may be extended for up to three five-year extensions or the property may be purchased outright by our exercise of a purchase option at the end of the initial five-year lease term. For the year 2015, we paid Shaner Office Holdings, L.P. approximately $0.5 million in office rental payments and utilities. We account for this lease as an operating lease, subsequently recording the rental payments as General and Administrative Expense on our Consolidated Statements of Operations. During the third quarter of 2013, we purchased a parcel of land adjacent to our headquarters office location from Shaner Office Holdings, L.P. for approximately $0.6 million. RW Gathering, LLC We own a 40% interest in RW Gathering which owns gas-gathering assets to facilitate the development of our joint operations with WPX and Sumitomo (see Note 5, Equity Method Investments Water Solutions We incurred approximately $6.1 million, $20.1 million and $10.7 million in gross water transfer and equipment rental expenses that were charged to us from Water Solutions during 2015 (through the date of sale in July 2015), 2014 and 2013, respectively. Of the amounts incurred, we eliminated approximately $4.7 million, $16.2 million and $8.8 million in consolidation for the years 2015, 2014 and 2013, respectively. As of December 31, 2015 we had no payables due to sale of our interest in Water Solutions during third quarter 2015 as compared to approximately $1.3 million as of December 31, 2014, owed to Water Solutions for work performed during the periods. As of December 31, 2015 and 2014, we classified the operations of Water Solutions as Discontinued Operations. See note 4, Discontinued Operations/Assets Held for Sale

Major Customers

Major Customers	12 Months Ended
	Dec. 31, 2015
Text Block [Abstract]
Major Customers	14. MAJOR CUSTOMERS For the year ended December 31, 2015, approximately $152.7 million, or 85.1%, of our commodity sales from continuing operations were attributable to four customers with the largest single purchaser accounting for $75.8 million, or 42.2%. For the year ended December 31, 2014, approximately $253.6 million, or 85.1% of our commodity sales from continuing operations were attributable to four customers with the largest single purchaser accounting for $96.4 million, or 32.4%. For the year ended December 31, 2013, approximately $179.5 million, or 83.9%, of our commodity sales from continuing operations were derived from four customers, with the largest customer being responsible for approximately $73.8 million, or 34.5%, of total commodity sales.

Suspended Exploratory Well Cost

Suspended Exploratory Well Costs	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Suspended Exploratory Well Costs	17. SUSPENDED EXPLORATORY WELL COSTS We capitalize the costs of exploratory wells if a well finds a sufficient quantity of reserves to justify its completion as a producing well and we are making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The following table reflects the net change in capitalized exploratory well costs, excluding those related to Assets Held for Sale on our Consolidated Balance Sheets for the years ended December 31, 2015, 2014 and 2013 ($ in thousands): 2015 2014 2013 Beginning Balance at January 1, $ 23,101 $ 5,731 $ 36,968 Additions to capitalized exploratory well costs pending the determination of estimated proved reserves 144,954 258,097 171,087 Divested wells — — — Reclassification of wells, facilities, and equipment based on the determination of estimated proved reserves (147,850 ) (240,494 ) (202,323 ) Capitalized exploratory well costs charged to expense (2,907 ) (233 ) (1 ) Ending Balance at December 31, 17,298 23,101 5,731 Less exploratory well costs that have been capitalized for a period of one year or less (12,156 ) (20,407 ) (3,597 ) Capitalized exploratory well costs for a period of greater than one year $ 5,142 $ 2,694 $ 2,134 Number of projects that have exploratory well costs capitalized for a period of more than one year 14 6 3 As of December 31, 2015 we had approximately $5.1 million in capitalized exploratory well costs that were capitalized for a period greater than one year. These costs are related to nine wells in Butler County, Pennsylvania, four wells in Lawrence County, Pennsylvania and one well in our non-operated region of the Illinois Basin. In Butler County, Pennsylvania there are eight completed wells that are awaiting infrastructure and one that has been drilled and is awaiting completion. In Lawrence County, Pennsylvania, there are three completed wells that are awaiting infrastructure and one drilled well that is awaiting completion. In Kentucky, there is one well with plans to convert to a disposal well to support other proven wells in region. The properties located in Pennsylvania are wells that we purchased through our acquisition from Shell in 2014. As we continue to develop the acquired acreage from Shell and build out the infrastructure we plan to opportunistically complete these wells and place them into sales. These costs are currently classified as Wells and Facilities in Progress on our Consolidated Balance Sheets and will be reclassified to Evaluated Oil and Gas Properties upon the discovery of proved reserves or to Exploration Expense if commercial quantities of reserves are not found.

Costs Incurred In Oil And Natur

Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities	12 Months Ended
	Dec. 31, 2015
Text Block [Abstract]
Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities	18. COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES (UNAUDITED) Costs incurred in oil and natural gas property acquisitions and development are presented below and exclude any costs incurred related to Assets Held for Sale (in thousands): 2015 2014 2013 Consolidated Entities: Acquisition of Properties Proved $ 1 $ 161 $ 2,445 Unproved 28,242 169,408 39,291 Exploration Costs(a) 158,318 316,235 231,112 Development Costs(a) 31,574 71,383 64,661 Subtotal 218,135 557,187 337,509 Asset Retirement Obligations 2,818 9,110 3,031 Total Costs Incurred $ 220,953 $ 566,297 $ 340,540 Share of Equity Method Investments: Acquisition of Properties Proved $ — $ — $ — Unproved — — — Exploration Costs — — — Development Costs(a) 824 438 1,958 Total $ 824 $ 438 $ 1,958 (a) Includes Depreciation expense for support equipment and facilities The following table provides a reconciliation of the total costs incurred for our consolidated entities to our reported capital expenditures (in thousands): 2015 2014 2013 Total Costs Incurred by Consolidated Entities $ 220,953 $ 566,297 $ 340,540 Equity Method Investments — — 2,493 DJ Basin Expenditures — — 2 Exploration Expense (3,011 ) (9,446 ) (11,408 ) Asset Retirement Obligations (2,818 ) (9,110 ) (3,031 ) Depreciation for Support Equipment and Facilities (4,905 ) (6,075 ) (5,024 ) Corporate Expenditures 231 869 3,651 Other(a) (16,522 ) 7,223 10,391 Total Capital Expenditures $ 193,928 $ 549,758 $ 337,614 (a) Represents R.E. Disposal, LLC capital, future proceeds from ArcLight and intercompany capital transactions.

Oil And Natural Gas Capitalized

Oil And Natural Gas Capitalized Costs	12 Months Ended
	Dec. 31, 2015
Text Block [Abstract]
Oil And Natural Gas Capitalized Costs	19. OIL AND NATURAL GAS CAPITALIZED COSTS (UNAUDITED) Our aggregate capitalized costs for natural gas and oil production activities with applicable accumulated depreciation, depletion and amortization are presented below and exclude any properties classified as Assets Held for Sale (in thousands): 2015 2014 Consolidated Entities: Proven Oil and Natural Gas Properties $ 1,239,430 $ 1,079,039 Pipelines and Support Equipment 17,030 24,248 Field Operation Vehicles and Other Equipment 28,064 27,030 Wells and Facilities in Progress 144,408 127,597 Unproven Properties 262,992 322,413 Total 1,691,924 1,580,327 Less Accumulated Depreciation and Depletion (696,447 ) (362,804 ) Total $ 995,477 $ 1,217,523 Share of Equity Method Investments: Pipelines and Support Equipment 19,970 19,946 Wells and Facilities in Progress — — Total 19,970 19,946 Less Accumulated Depreciation and Depletion (3,411 ) (2,611 ) Total $ 16,559 $ 17,335

Oil and Natural Gas Reserve Qua

Oil and Natural Gas Reserve Quantities	12 Months Ended
	Dec. 31, 2015
Text Block [Abstract]
Oil and Natural Gas Reserve Quantities	20. OIL AND NATURAL GAS RESERVE QUANTITIES (UNAUDITED) Our independent engineers, Netherland, Sewell, and Associates, Inc. (“NSAI”) evaluated all of our proved oil, natural gas and NGL reserves for the years ended December 31, 2015, 2014 and 2013. The technical persons responsible for preparing the estimates of our estimated proved reserves meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis. We emphasize that reserve estimates are inherently imprecise. Our oil, natural gas and NGL reserve estimates were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available. All of our estimated proved reserves are located within the United States. Proved natural gas, oil and NGL reserves are those quantities of natural gas, oil and NGL which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible –from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. Based on reserve reporting rules, the price is calculated using the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. A project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas or oil on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Developed natural gas, oil and NGL reserves are reserves of any category that can be expected to be recovered (x) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (y) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Undeveloped natural gas, oil and NGL reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty. Presented below is a summary of changes in estimated reserves of the oil and natural gas wells at December 31, 2015, 2014 and 2013: 2015 Oil NGL Natural Gas (MMcf) (MMcf) Equivalents Estimated Proved Reserves-Beginning of Period 9,684.7 73,252.5 839,185.1 1,336,808.3 Extensions, Discoveries and Additions 949.0 10,079.3 76,816.9 142,986.7 Revisions of Previous Estimates (4,176.8 ) (38,249.7 ) (448,461.3 ) (703,020.3 ) Purchases (7.7 ) (1,389.6 ) (16,471.1 ) (24,854.9 ) Production (1,132.1 ) (3,345.9 ) (44,606.8 ) (71,474.8 ) Estimated Proved Reserves-End of Period 5,317.1 40,346.6 406,462.8 680,445.0 2014 Oil NGL Natural (MMcf) (MMcf) Equivalents Estimated Proved Reserves-Beginning of Period 8,619.6 46,130.7 521,282.8 849,784.6 Extensions, Discoveries and Additions 1,723.1 31,160.3 326,464.2 523,764.6 Revisions of Previous Estimates 471.1 (2,889.1 ) 9,971.0 (4,537.0 ) Purchases 12.0 933.0 18,478.3 24,148.3 Production (1,141.1 ) (2,082.4 ) (37,011.2 ) (56,352.2 ) Estimated Proved Reserves-End of Period 9,684.7 73,252.5 839,185.1 1,336,808.3 2013 Oil NGL Natural (MMcf) (MMcf) Equivalents Estimated Proved Reserves-Beginning of Period 9,375.7 31,679.9 371,716.4 618,050.0 Extensions, Discoveries and Additions 595.6 19,956.1 189,150.9 312,461.1 Revisions of Previous Estimates (438.5 ) (4,685.6 ) (16,137.7 ) (46,882.3 ) Purchases 1.0 — — 6.0 Production (914.2 ) (819.7 ) (23,446.8 ) (33,850.2 ) Estimated Proved Reserves-End of Period 8,619.6 46,130.7 521,282.8 849,784.6 Oil NGL Natural (MMcf) (MMcf) Equivalents Proved Developed Reserves December 31, 2015 4,944.6 37,941.9 389,754.4 647,073.4 December 31, 2014 7,628.1 29,215.0 365,673.3 586,731.9 December 31, 2013 7,742.5 16,322.5 212,061.4 356,451.4 Proved Undeveloped Reserves December 31, 2015 372.5 2,404.7 16,708.4 33,371.6 December 31, 2014 2,056.6 44,037.5 473,511.8 750,076.4 December 31, 2013 877.1 29,808.2 309,221.4 493,333.2 Our estimated proved undeveloped reserves did not include any locations that generated a positive future net revenue and a negative present value discounted at 10%. We may, from time to time, have proved undeveloped locations with these characteristics based on our planned operating budget and strategy to hold acreage by production combined with our expectations of future commodity prices. Revisions. Our revisions in 2015 included a negative adjustment of approximately 741.1 Bcfe related to lower commodity prices. This negative adjustment was partially offset by positive revision of approximately 15.4 Bcfe related to positive operating expenses, 4.1 Bcfe related to changes in our ethane recovery expectations and 18.6 Bcfe related to technical revisions. The positive technical revisions included 10.3 Bcfe in our Butler County, Pennsylvania area related to positive well performance. An additional 9.8 Bcfe of positive technical revisions were related to positive well performance in our Warrior North prospect in Ohio. These additions were partially offset by approximately 2.2 Bcfe in negative technical revisions related to well performance in our other areas of operation. Our revisions in 2014 included a negative adjustment of approximately 58.5 Bcfe related to PUD locations that were not developed within five years, negative revisions of 1.6 Bcfe related to commodity pricing, positive revisions of 17.6 Bcfe related to favorable operating expenses and positive technical revisions of 38.0 Bcfe. The negative revisions were related to PUD locations that were previously booked in our Butler County, Pennsylvania region. The positive technical revisions included 51.0 Bcfe in our Butler County, Pennsylvania area related to positive well performance which was partially offset by negative revisions related to well performance in our Warrior South prospect and our non-operated Westmoreland County, Pennsylvania area of approximately 15.5 Bcfe. We had significant revisions in our oil, NGL and natural gas reserves for the year ended December 31, 2013. Our negative revisions were primarily due to adjusting downward our estimated recovery of future ethane production from 2012 to 2013. Negative revisions related to our estimated ethane recovery accounted for approximately 27.3 Bcfe of our total revisions. In addition to our ethane recovery adjustments, we recognized additional negative revisions related to well performance in our non-operated Westmoreland County, Pennsylvania region as well as in the Illinois Basin. Partially offsetting these negative revisions were positive revisions due to natural gas pricing and lower than expected operating expenses. Extensions, discoveries and other additions. We had significant extensions, discoveries and other additions for the year ended December 31, 2015, of 0.9 MMBOE of oil, 10.1 MMBOE of NGLs and 76.8 Bcfe of natural gas. We had significant extensions, discoveries and other additions for the year ended December 31, 2014, of 1.7 MMBOE of oil, 31.2 MMBOE of NGLs and 326.5 Bcf of natural gas. During 2013, we had extensions, discoveries and other additions of 0.6 MMBOE of oil, 20.0 MMBOE of NGLs and 189.1 Bcf of natural gas. Our continued success in the Appalachian Basin has been the primary contributor to the growth of our extensions, discoveries and other additions, specifically the Marcellus and Utica Shales. At December 31, 2015, approximately 102.1 Bcfe of our extensions, discoveries and other additions were related to Marcellus Shale properties while an additional 30.0 Bcfe was related to the Utica Shale.

Standardized Measure Of Discoun

Standardized Measure Of Discounted Future Net Cash Flows	12 Months Ended
	Dec. 31, 2015
Text Block [Abstract]
Standardized Measure Of Discounted Future Net Cash Flows	21. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED) FASB ASC 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proved reserves. We followed these guidelines, which are briefly discussed below. Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of oil and natural gas to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of estimated proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0% annual discount factor. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process. The following summary sets forth our future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by FASB ASC 932 at December 31, 2015, 2014 and 2013 ($ in thousands): 2015 2014 2013 Future Cash Inflows $ 1,716,131 (a) $ 5,824,231 (b) $ 3,899,878 (c) Future Costs: Production (1,144,049 ) (2,332,151 ) (1,619,629 ) Abandonment (143,459 ) (134,308 ) (95,183 ) Development (18,952 ) (686,676 ) (517,875 ) Net Future Cash Inflow Before Income Taxes 409,671 2,671,096 1,667,191 Future Income Tax Expense — (468,597 ) (359,322 ) Total Future Net Cash Flows Before 10.0% Discount 409,671 2,202,499 1,307,869 Less: Effect of 10.0% Discount Factor (154,048 ) (1,177,135 ) (778,756 ) Standardized Measure of Discounted Future Net Cash Flows $ 255,623 $ 1,025,364 $ 529,113 (a) Calculated using weighted average prices of $2.401 per Mcf, $44.45 per barrel of oil and $12.48 per barrel of NGLs (b) Calculated using weighted average prices of $3.455 per Mcf, $88.02 per barrel of oil and $28.30 per barrel of NGLs (c) Calculated using weighted average prices of $3.588 per Mcf, $94.28 per barrel of oil and $26.37 per barrel of NGLs The principal sources of change in the standardized measure of discounted future net cash flows are as follows: 2015 2014 2013 Standardized Measure – Beginning of Period $ 1,025,364 $ 529,113 $ 396,123 Revisions of Previous Estimates: Changes in Prices and Production Costs (1,296,866 ) 253,865 72,503 Revisions in Quantities (270,673 ) (5,970 ) (51,289 ) Changes in Future Development Costs 595,547 (51,794 ) 22,341 Accretion of Discount and Timing of Future Cash Flows 116,514 64,013 47,571 Net Change in Income Tax 139,776 28,756 31,433 Purchase (Sale) of Reserves in Place (37,101 ) 28,316 — Plus Extensions, Discoveries, and Other Additions 88,152 430,252 170,846 Development Costs Incurred 31,574 71,383 64,661 Sales of Product – Net of Production Costs (52,952 ) (197,587 ) (151,781 ) Changes in Timing and Other (83,712 ) (124,983 ) (73,295 ) Standardized Measure – End of Period $ 255,623 $ 1,025,364 $ 529,113

Results of Operations for Oil a

Results of Operations for Oil and Gas Producing Activities	12 Months Ended
	Dec. 31, 2015
Text Block [Abstract]
Results of Operations for Oil and Gas Producing Activities	22. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) Results of operations are equal to revenues, less (a) production costs, (b) impairment expenses, (c) exploration expenses, (d) DD&A expenses, and (e) income tax expense (benefit) (certain prior year amounts have been reclassified to conform to current presentation): 2015 2014 2013 Consolidated Entities (in thousands): Revenues Oil and Natural Gas Sales $ 171,951 $ 297,869 $ 213,919 Expenses Production and Lease Operating Expense 118,999 100,282 62,150 Impairment Expense 345,775 132,618 32,072 Exploration Expense 3,011 9,446 11,408 Depletion, Depreciation, Amortization and Accretion 104,744 94,467 62,386 Total Costs 572,529 336,813 168,016 Pre-Tax Operating Income (Loss) (400,578 ) (38,944 ) 45,903 Income Tax (Expense) Benefit(a) 22,833 14,059 (29,148 ) Results of Operations for Oil and Gas Producing Activities $ (377,745 ) $ (24,885 ) $ 16,755 Share of Equity Method Investments (in thousands): Expenses Depletion, Depreciation, Amortization and Accretion $ 812 $ 805 $ 752 Total Costs 812 805 752 Pre-Tax Operating Loss (812 ) (805 ) (752 ) Income Tax Benefit (a) 46 291 478 Results of Operations for Oil and Gas Producing Activities $ (766 ) $ (514 ) $ (274 ) Total Consolidated and Equity Method Investees Results of Operations for Oil and Gas Producing Activities $ (378,511 ) $ (25,399 ) $ 16,481 (a) Computed using the effective rate for continuing operations for each period: 5.7% in 2015; 36.1% in 2014 and; 63.5% in 2013.

Litigation

Litigation	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Litigation	23. LITIGATION Illinois Basin EPA Consent Decree In September 2006, the United States Department of Justice (“DOJ”), the United States Environmental Protection Agency (“EPA”) and the State of Illinois initiated an enforcement action against us seeking mandatory injunctive relief and potential civil penalties based on allegations that we (and various predecessor companies) were violating the Clean Air Act in connection with the release of hydrogen sulfide gas and volatile organic compounds (“VOC’s”) in the course of our oil producing operations near the towns of Bridgeport, Illinois and Petrolia, Illinois. In June 2007, we entered a consent decree to resolve the enforcement action. The consent decree required us to take certain remedial actions to reduce hydrogen sulfide and VOC emissions and monitor the same. The consent decree did not require us to pay any civil fine or penalty, although it does provide for the possible imposition of specified daily fines and penalties for any violation of the terms and conditions of the consent decree. In 2010, the EPA, DOJ and Illinois EPA approved revisions we proposed to a Directed Inspection and Maintenance Plan, which had been previously implemented by us pursuant to the terms of the consent decree. In 2014, in consultation with the EPA, DOJ and Illinois EPA, we implemented additional measures under the Directed Inspection and Maintenance Plan to reflect changes in hydrogen sulfide control monitoring and procedures. We are required under the terms of the consent decree to submit quarterly reports and to annually reassess the Directed Inspection and Maintenance Plan. There were no material changes to the Directed Inspection and Maintenance Plan in 2015 and we were compliant with all reporting requirements for the year. Litigation Related to Proposed Oil and Gas Leases in Clearfield County, Pennsylvania 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. 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.

Selected Quarterly Financial Da

Selected Quarterly Financial Data	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Data	24. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) The following tables set forth unaudited financial information on a quarterly basis for each of the last two years. REX ENERGY CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS ($ and Shares in Thousands Except per Share Data) 2015 March June September December Revenues $ 54,122 $ 45,772 $ 37,573 $ 34,526 Impairment Expense 7,023 117,842 139,812 81,098 Other Costs and Expenses 65,578 81,303 27,054 51,301 Net Loss From Continuing Operations (18,479 ) (153,373 ) (129,293 ) (97,873 ) Net Income (Loss) From Discontinued Operations, Net of Income Taxes 1,962 1,570 34,617 (164 ) Net Loss (16,517 ) (151,803 ) (94,676 ) (98,037 ) Net Income (Loss) Attributable to Noncontrolling Interests 1,297 949 (1 ) — Net Loss Attributable to Rex Energy (17,814 ) (152,752 ) (94,675 ) (98,037 ) Preferred Stock Dividends 2,415 2,415 2,415 2,415 Net Loss Attributable to Common Shareholders $ (20,229 ) $ (155,167 ) $ (97,090 ) $ (100,452 ) Income (Loss) per Common Share Attributable to Rex Energy Common Shareholders: Basic – Continuing Operations $ (0.38 ) $ (2.88 ) $ (2.44 ) $ (1.85 ) Basic – Discontinued Operations 0.01 0.01 0.64 — Basic – Net Loss $ (0.37 ) $ (2.87 ) $ (1.80 ) $ (1.85 ) Basic – Weighted Average Shares Outstanding 54,370 54,118 53,936 54,342 Diluted – Continuing Operations $ (0.38 ) $ (2.88 ) $ (2.44 ) $ (1.85 ) Diluted – Discontinued Operations 0.01 0.01 0.64 — Diluted – Net Loss $ (0.37 ) $ (2.87 ) $ (1.80 ) $ (1.85 ) Diluted – Weighted Average Shares Outstanding 54,370 54,118 53,936 54,342 2014 March June September December Revenues $ 81,343 $ 72,933 $ 73,466 $ 70,245 Impairment Expense 25 16 1 132,576 Other Costs and Expenses 72,562 65,274 67,846 7,337 Net Income (Loss) From Continuing Operations 8,756 7,643 5,619 (69,668 ) Net Income From Discontinued Operations, Net of Income Taxes 1,681 1,312 970 1,037 Net Income (Loss) 10,437 8,955 6,589 (68,631 ) Net Income Attributable to Noncontrolling Interests 1,569 877 895 698 Net Income (Loss) Attributable to Rex Energy $ 8,868 $ 8,078 $ 5,694 $ (69,329 ) Preferred Stock Dividends — — — 2,335 Net Income (Loss) Attributable to Common Shareholders $ 8,868 $ 8,078 $ 5,694 $ (71,664 ) Income (Loss) per Common Share Attributable to Rex Energy Common Shareholders: Basic – Continuing Operations $ 0.17 $ 0.14 $ 0.11 $ (1.35 ) Basic – Discontinued Operations — 0.01 — — Basic – Net Income (Loss) $ 0.17 $ 0.15 $ 0.11 $ (1.35 ) Basic – Weighted Average Shares Outstanding 52,984 53,164 53,214 53,261 Diluted – Continuing Operations $ 0.17 $ 0.14 $ 0.10 $ (1.35 ) Diluted – Discontinued Operations — 0.01 — — Diluted – Net Income (Loss) $ 0.17 $ 0.15 $ 0.10 $ (1.35 ) Diluted – Weighted Average Shares Outstanding 53,503 53,509 57,991 53,261

SUMMARY OF SIGNIFICANT ACCOUN37

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates. Estimates made in preparing these Consolidated Financial Statements include, among other things, estimates of the proved oil, NGL and natural gas reserve volumes used in calculating Depletion, Depreciation and Amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment; fair values of financial derivative instruments; volumes and prices for revenues accrued; estimates of the fair value of equity-based compensation awards; deferred tax valuation allowance and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods. The estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates and our ability to generate future income.
Cash and Cash Equivalents	Cash and Cash Equivalents We consider all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents. As of December 31, 2015 and 2014, our Cash and Cash Equivalents consisted of only cash.
Accounts Receivable	Accounts Receivable Our trade accounts receivable, which are primarily from oil, NGLs and natural gas sales and joint interest billings, are recorded at the invoiced amount and include production receivables. The production receivable is valued at the invoiced amount and does not bear interest. Accounts receivable also include joint interest billing receivables which represent billings to the non-operators associated with the drilling and operation of wells and are based on those owners’ working interests in the wells. We have assessed the financial strength of our customers and joint owners and record an allowance for bad debts as necessary. Our allowance for bad debts as of December 31, 2015 and 2014, was negligible. To the extent actual quantities and values of oil, NGLs and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Accounts Receivable in the accompanying Consolidated Balance Sheets. At December 31, 2015, we carried approximately $12.1 million in production receivable, of which approximately $10.5 million were production receivables due from four purchasers. At December 31, 2014, we carried approximately $25.2 million in production receivables, of which approximately $21.4 million were production receivables due from four purchasers. In addition, we carried approximately $3.2 million in receivables at December 31, 2015 and $6.7 million at December 31, 2014 that was in relation to our joint operations with Sumitomo Corporation and ArcLight Capital Partners, LLC.
Inventory	Inventory Inventory is valued at the lower of cost or market value and consists of our ownership interest in oil and NGLs held in terminal tanks located in the field. Oil and NGL cost basis is calculated using the average cost method, with average cost defined as production and lease operating expenses net of DD&A. General and Administrative expenses are not allocated to the cost of inventory for the purpose of valuing inventory.
Oil, NGL and Natural Gas Property, Depreciation and Depletion	Oil, NGL and Natural Gas Property, Depreciation and Depletion We account for oil, NGL and natural gas exploration and production activities under the successful efforts method of accounting. Proved developed natural gas and oil property acquisition costs are capitalized when incurred, including our estimate of the fair value of future abandonment costs. Unproved properties with individually significant acquisition costs are assessed periodically on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop estimated proved reserves, including the costs of all development well and related equipment used in the production of oil, NGLs and natural gas, are capitalized. We capitalize interest on capital projects, most notably during the drilling and completion of oil and natural gas wells. For the years ended December 31, 2015, 2014 and 2013, we capitalized interest costs of $7.7 million, $7.3 million and $7.5 million, respectively. Depletion is calculated using the unit-of-production method. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. We periodically review estimated proved reserve estimates and make changes as needed to depletion expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in our estimated proved reserves. The costs of unproved properties are withheld from the depletion base until such time as they are proved. When estimated proved reserves are assigned, the cost of the property is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is allocated to the associated producing properties as the undeveloped acreage is developed. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of three to 40 years. We review assets for impairment when events or circumstances indicate a possible decline in the recoverability of the carrying value of such property. When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future oil, NGL and natural gas prices, operating costs, anticipated production from estimated proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Our estimates of future oil, NGL and natural gas prices are based on forward strip prices for NYMEX oil and various natural gas markets that are relevant to our operations. For unproved oil and gas properties, we analyze activity on the acreage prior to evaluating any fair value indicators, such as current drilling activity, drilling success, future development plans and the likelihood of expiration. Unproved oil and gas properties are impaired when it becomes more likely than not that a property will expire before it can be developed or an extension can be agreed upon. When evaluating the value of our unproved oil, NGL and natural gas properties, we analyze the level and success of current development, future development plans and changes in market value. Performing the impairment evaluations requires use of judgments and estimates since the results are dependent on future events, including estimates of future proved and unproved reserves, future commodity prices, the timing of future production, capital expenditures and the intent to develop properties, among others. We recognized approximately $345.8 million, $132.6 million and $32.1 million of impairment from continuing operations on certain oil, NGL and natural gas properties for the years ending December 31, 2015, 2014 and 2013, respectively. We recorded these charges as Impairment Expense on our Consolidated Statements of Operations. For additional information, see Note 16, Impairment Expense Expenditures for repairs and maintenance to sustain production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense. Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated depletion are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.
Natural Gas and Oil Reserve Quantities	Natural Gas and Oil Reserve Quantities Our estimate of proved reserves is based on the quantities of oil, NGLs and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. For the years ended December 31, 2015 and 2014, Netherland Sewell and Associates, Inc. (“NSAI”) prepared a consolidated reserve and economic evaluation of our proved oil and gas reserves. The preparation of our proved reserve estimates are completed in accordance with our internal control procedures, which include the verification of input data used by NSAI, as well as management review and approval. Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Estimates of our crude oil, NGL and natural gas reserves, and the projected cash flows derived from these reserve estimates, are prepared by our engineers in accordance with guidelines established by the SEC. The independent reserve engineer estimates reserves annually on December 31. This annual estimate results in a new depletion rate, which we use for the preceding fourth quarter after adjusting for fourth quarter production.
Deferred Financing Costs and Other Assets-Net	Deferred Financing Costs and Other Assets—Net At December 31, 2015, we had deferred financing costs and other assets consisting of $16.5 million, which is primarily made up of bond costs and loan costs that are amortized using the effective interest method and the straight line method, respectively, over their estimated lives, which is, on average, five to eight years. We amortize any costs incurred to renew or extend the terms of existing debt over the contract term or estimated useful life, as applicable. For the years ended December 31, 2015, 2014 and 2013, we recorded amortization expense from continuing operations of $2.0 million, $1.5 million and $1.2 million, respectively. The following is a summary of our deferred financing costs at the dates indicated: December 31, 2015 (in thousands) December 31, 2014 (in thousands) Deferred Financing Costs—Gross $ 20,623 $ 19,212 Accumulated Amortization (6,580 ) (4,564 ) Deferred Financing Costs—Net $ 14,043 $ 14,648 Specific to our deferred financing costs, we have incurred gross debt issuance costs of approximately $1.4 million and $6.8 million for the years ended December 31, 2015 and 2014, respectively, which are presented net of accumulated amortization of $6.6 million and $4.6 million, respectively, and include deferred financing from our senior notes and revolving line of credit.
Future Abandonment Cost	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 asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Accretion expense from continuing operations during the years ended December 31, 2015, 2014 and 2013 totaled approximately $3.8 million, $3.6 million and $3.0 million, respectively. These amounts are recorded as DD&A on our Consolidated Statements of Operations. As of December 31, 2015 and 2014, approximately $2.2 million and $2.0 million, respectively, of our Future Abandonment Costs were classified as short-term liabilities under the caption Accrued Liabilities on our Consolidated Balance Sheets. During 2015 and 2014, we recognized an increase of $2.4 million and $8.4 million, respectively, in the estimated present value of our asset retirement obligations, representing an increase in the estimate to plug and abandon our oil and natural gas wells. The revised estimates were primarily the result of increased abandonment cost estimates, which were driven by the trends of actual outcomes. We account for asset retirement obligations that relate to wells that are drilled jointly based on our interest in those wells. December 31, 2015 (in thousands) December 31, 2014 (in thousands) Beginning Balance $ 40,099 $ 28,525 Asset Retirement Obligation Incurred 1,135 1,480 Asset Retirement Obligation Settled (2,273 ) (1,943 ) Asset Retirement Obligation Cancelled or Sold Properties (136 ) (10 ) Asset Retirement Obligation Revision of Estimated Obligation 2,428 8,426 Asset Retirement Obligation Accretion Expense 3,821 3,621 Total Future Abandonment Costs $ 45,074 $ 40,099
Revenue Recognition	Revenue Recognition Oil, NGL and natural gas revenue is recognized when the oil, NGL or natural gas is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil and NGL sales, title is transferred to the purchaser when the oil or NGLs leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. It is the measurement of the purchaser that determines the amount of oil, NGL or natural gas purchased. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for oil, NGLs and natural gas purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our oil, NGL and natural gas production is at its applicable field gathering system. We do not recognize revenue for oil and NGL production held in stock tanks before delivery to the purchaser. To the extent actual quantities and values of oil, NGLs and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Oil, Natural Gas and NGL Sales on the Statements of Operations.
Derivative Instruments	Derivative Instruments We use put and call options (collars), fixed rate swap contracts, swaptions, puts, deferred put spreads, cap swaps, call protected swaps, basis swaps and three-way collars to manage price risks in connection with the sale of oil, natural gas and NGLs. We have also used interest rate swap agreements to manage interest rate exposure associated with our fixed rate senior notes. We have established the fair value of all derivative instruments using estimates determined by our counterparties and other third-parties. These values are based upon, among other things, future prices, volatility, time to maturity and credit risk. The values we report in our Consolidated Financial Statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. We report our derivative instruments at fair value and include them in the Consolidated Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated for hedge accounting, for financial accounting purposes, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness are recognized immediately in earnings. During 2015, 2014 and 2013 we did not have any derivative instruments designated for hedge accounting. For derivative instruments designated as fair value hedges, changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Derivative effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. For derivatives on oil, natural gas and NGL production activity, our evaluations are not documented, and as a result, we record changes on the derivative valuations through earnings. For additional information on our derivative instruments, see Note 10, Fair Value of Financial Instruments and Derivative Instruments
Contingent Liabilities	Contingent Liabilities A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information.
Income Taxes	Income Taxes We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed several months after the close of a calendar year, tax returns are subject to audit which can take years to complete, and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards and other deductible differences and deferred tax liabilities that relate to oil and gas properties and other taxable differences. Deferred tax assets and liabilities are computed based on the difference between the financial statement and income tax basis of assets and liabilities using the enacted tax rates. Net deferred tax assets are required to be reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the net deferred tax asset will not be realized. This process requires our management to make assessments regarding the timing and probability of the ultimate tax impact. We record valuation allowances on deferred tax assets if we determine it is more likely than not that the asset will not be realized. Actual income taxes could vary from these estimates due to future changes in income tax law, significant changes in the jurisdictions in which we operate, our inability to generate sufficient future taxable income, or unpredicted results from the final determination of each year’s liability by taxing authorities. These changes could have a significant impact on our financial position. The accounting estimate related to the tax valuation allowance requires us to make assumptions regarding the timing of future events, including the probability of expected future taxable income and available tax planning opportunities. These assumptions require significant judgment because actual performance has fluctuated in the past and may do so in the future. The impact that changes in actual performance versus these estimates could have on the realization of tax benefits as reported in our results of operations could be material. We continuously evaluate facts and circumstances representing positive and negative evidence in the determination of our ability to realize the deferred tax assets. We recognize a tax position if it is more likely than not that it will be sustained upon examination. If we determine it is more likely than not a tax position will be sustained based on its technical merits, we record the impact of the position in our Consolidated Financial Statements at the largest amount that is greater than fifty percent likely of being realized upon ultimate settlement. These estimates are updated at each reporting date based on the facts, circumstances and information available. We are also required to assess at each reporting date whether it is reasonably possible that any significant increases or decreases to the unrecognized tax benefits will occur during the next twelve months (for additional information, see Note 11, Income Taxes,
Stock-based Compensation	Stock-based Compensation We recognize in the Consolidated Financial Statements the cost of employee and non-employee director services received in exchange for awards of equity instruments based on the grant date fair value of those awards. We use a standard option pricing model (i.e. Black-Scholes) to measure the fair value of employee stock options and stock appreciation rights and a Monte Carlo simulation technique to value restricted stock awards that are tied to market performance. The fair value of non-market based restricted stock awards is determined based on the fair market value of our common stock on the date of the grant. The benefits associated with the tax deductions in excess of recognized compensation cost are reported as a financing cash flow when realized. We recognize compensation costs related to awards with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award were, in-substance, multiple awards (for additional information, see Note 15, Employee Benefit and Equity Plans,
Earnings per Common Share	Earnings per Common Share Earnings per common share are computed by dividing consolidated net income attributable to us by the weighted average number of common shares outstanding. Diluted earnings per common share are computed based upon the weighted average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities, including the assumed conversion of preferred stock. At December 31, 2015, we had 55,741,229 common shares outstanding, 443,672 options outstanding and 20,500 stock appreciation rights outstanding with no outstanding warrants or other potentially dilutive securities. The total common shares outstanding include 2,479,408 restricted stock awards, of which approximately 1,065,296 shares are performance-based awards. For additional information, see Note 12, Earnings per Common Share
Recent Accounting Pronouncements	Recent Accounting Pronouncements In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40). The new guidance addresses management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The standard is effective for the annual period ending after December 15, 2016 and for annual and interim periods thereafter. Early adoption is permitted. We adopted this ASU on January 1, 2016. Adoption did not have a material impact on our Consolidated Financial Statements. In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The amendments in this ASU intend to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures. The ASU focuses on the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. In addition to reducing the number of consolidation models from four to two, the new standard places more emphasis on risk of loss when determining a controlling financial interest, reduces the frequency of the application of related-party guidance when determining a controlling financial interest in a variable interest entity and changes consolidation conclusions in several industries that typically make use of limited partnerships or variable interest entities. This ASU will be effective for periods beginning after December 15, 2015, for public companies, and early adoption is permitted, including adoption in an interim period. We are currently evaluating the potential effect of this ASU but do not believe that it will have a material impact on our Consolidated Financial Statements. In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The standard requires an entity to present debt issuance costs related to a recognized liability as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The guidance in the ASU is effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein. Early adoption is permitted. We are currently evaluating the potential effect of this ASU and the related impact on our Consolidated Financial Statements. As of December 31, 2015, we had approximately $14.0 million in net deferred financing costs that would be potentially reclassified to reduce the debt carrying balance. 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 August 2015, the FASB issued ASU 2015-15, Interest – Imputation of Interest (Subtopic 835-30), Presentation and Subsequent Measurement of Debt Issuance Costs with Line-of-Credit Arrangements. This ASU clarifies the presentation of debt issuance costs associated with line-of-credit arrangements. In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, which requires the presentation of debt issuance costs related to a recognized debt liability as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 does not address presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements. Given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to line-of-credit arrangements, the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The guidance in the ASU is effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein. Early adoption is permitted. We are currently evaluating the potential effect of this ASU and the related impact on our Consolidated Financial Statements.

Future Abandonment Cost (Tables

Future Abandonment Cost (Tables)	3 Months Ended
	Mar. 31, 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) March 31, 2016 Beginning Balance at January 1, 2016 $ 45,074 Future Abandonment Obligation Incurred 402 Future Abandonment Obligation Settled (361 ) Future Abandonment Obligation Cancelled or Sold (189 ) Future Abandonment Obligation Revision of Estimated Obligation — Future Abandonment Obligation Accretion Expense 856 Total Future Abandonment Cost 1 $ 45,782 1 Includes approximately $2.4 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

Discontinued Operations_Asset39

Discontinued Operations/Assets Held For Sale (Tables)	3 Months Ended
	Mar. 31, 2016
Water Solutions Holdings, LLC
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 March 31, ($ in Thousands) 2016 2015 Revenues: Field Services Revenue $ — $ 14,964 Total Operating Revenue — 14,964 Costs and Expenses: General and Administrative Expense — 977 Depreciation, Depletion, Amortization and Accretion — 39 Field Services Operating Expense — 11,289 Gain on Sale of Asset — (32 ) Interest Expense — 191 Other Expense — 103 Total Costs and Expenses — 12,567 Income from Discontinued Operations Before Income Taxes — 2,397 Income Tax Expense — (435 ) Income from Discontinued Operations, net of taxes $ — $ 1,962

Long-Term Debt (Tables)

Long-Term Debt (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
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 March 31, 2016 and December 31, 2015: ($ in Thousands) March 31, 2016 December 31, Senior Notes, Net of Issuance Costs (a) $ 657,511 $ 663,089 Premium on Senior Notes, Net 2,245 2,344 Senior Line of Credit, Net of Issuance Costs (b)(c) 152,794 109,396 Capital Leases and Other Obligations(c) 434 618 Total Debt 812,984 775,447 Less Current Portion of Long-Term Debt (9,934 ) (590 ) Total Long-Term Debt $ 803,050 $ 774,857 (a) Includes unamortized debt issuance costs of approximately $11.1 million and $11.9 million as of March 31, 2016 and December 31, 2015, respectively. (b) Includes unamortized debt issuance costs of approximately $5.2 million and $2.1 million as of March 31, 2016 and December 31, 2015, respectively. (c) The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. The weighted average interest rate on borrowings under our Senior Credit Facility for the three months ended March 31, 2016 and the year ended December 31, 2015, was approximately 3.2 % and 1.7%, respectively. The average interest rate on our capital leases and other obligations for the three months ended March 31, 2016 and the year ended December 31, 2015, was approximately 4.5% and 5.5%, respectively.	Long-term debt and other obligations consisted of the following at December 31, 2015 and December 31, 2014: ($ in Thousands) December 31, 2015 December 31, 2014 8.875% Senior Notes Due 2020 $ 350,000 $ 350,000 6.25% Senior Notes Due 2022 325,000 325,000 Premium on Senior Notes, Net 2,344 2,725 Senior Line of Credit(a) 111,500 — Capital Leases and Other Obligations(a) 618 1,427 Total Debt 789,462 679,152 Less Current Portion of Long-Term Debt (590 ) (1,176 ) Total Long-Term Debt $ 788,872 $ 677,976 (a) The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2015, 2014 and 2013 was approximately 1.7%, 2.2 % and 1.9%, respectively. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2015, 2014 and 2013 was approximately 5.5%, 4.0% and 5.3%, respectively.
Principal Maturity Schedule for Total Debt Outstanding	The following is the principal maturity schedule for debt outstanding as of March 31, 2016: 2016 $ 9,906 2017 28 2018 — 2019 148,500 2020 652,658 Thereafter 15,865 Total(a) $ 826,957 (a) Excludes $2.2 million net premium on Senior Notes and $16.2 million in debt issuance costs	The following is the principal maturity schedule for total debt outstanding as of December 31, 2015: ($ in thousands) Year Ended December 31, 2016 $ 590 2017 28 2018 — 2019 111,500 2020 350,000 Thereafter 325,000 Total 1 $ 787,118 1 Does not include $2.3 million net premium on Senior Notes.

Derivative Instruments And Fa41

Derivative Instruments And Fair Value Measurements (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Fair Value Disclosures [Abstract]
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 March 31, 2016 and December 31, 2015 is summarized below: ($ in Thousands) March 31, December 31, Short-Term Derivative Assets: Crude Oil – Collars $ 662 $ 1,078 Crude Oil – Deferred Put Spread 42 852 Crude Oil – Three-Way Collars 616 577 NGL – Swaps 6,579 10,250 Natural Gas – Swaps 10,576 9,010 Natural Gas – Cap Swaps 1,638 1,977 Natural Gas – Basis Swaps — 70 Natural Gas – Three-Way Collars 6,326 6,183 Natural Gas – Collars 973 1,728 Natural Gas – Swaption 792 798 Natural Gas – Put Spread 808 1,737 Total Short-Term Derivative Assets $ 29,012 $ 34,260 Long-Term Derivative Assets: NGL – Swaps $ 185 $ 344 Natural Gas – Cap Swaps 1,855 2,294 Natural Gas – Swaps 1,580 1,593 Natural Gas – Basis Swaps — 195 Natural Gas – Three-Way Collars 4,840 5,108 Total Long-Term Derivative Assets $ 8,460 $ 9,534 Total Derivative Assets $ 37,472 $ 43,794 Short-Term Derivative Liabilities: Crude Oil – Three-Way Collars (276 ) — NGL – Swaps (490 ) — Refined Product – Swaps (278 ) (376 ) Natural Gas – Three-Way Collars — (31 ) Natural Gas – Basis Swaps (2,280 ) (1,585 ) Natural Gas – Call (189 ) — Natural Gas – Swaption (46 ) (202 ) Natural Gas – Swaps (9 ) (292 ) Natural Gas – Cap Swaps (190 ) — Total Short – Term Derivative Liabilities $ (3,758 ) $ (2,486 ) Long-Term Derivative Liabilities: NGL – Swaps (400 ) — Natural Gas – Swaption (433 ) (297 ) Natural Gas – Basis Swaps (4,993 ) (4,186 ) Natural Gas – Call (892 ) (989 ) Natural Gas – Cap Swaps (190 ) — Natural Gas – Three-Way Collars — (84 ) Total Long-Term Derivative Liabilities $ (6,908 ) $ (5,556 ) Total Derivative Liabilities $ (10,666 ) $ (8,042 )	The combined fair value of our derivatives included in our Consolidated Balance Sheets as of December 31, 2015 and December 31, 2014 is summarized below. ($ in Thousands) December 31, December 31, Short-Term Derivative Assets: Crude Oil – Collars $ 1,078 $ — Crude Oil – Call Protected Swap — 1,227 Crude Oil – Deferred Put Spread 852 1,413 Crude Oil – Three-Way Collars 577 4,596 NGL – Swaps 10,250 6,181 Natural Gas – Swaps 9,010 4,522 Natural Gas – Cap Swaps 1,977 3,430 Natural Gas – Basis Swaps 70 2,815 Natural Gas – Three-Way Collars 6,183 5,081 Natural Gas – Collars 1,728 — Natural Gas – Swaption 798 — Natural Gas – Put Spread 1,737 — Total Short-Term Derivative Assets $ 34,260 $ 29,265 Long-Term Derivative Assets: NGL – Swaps $ 344 $ — Natural Gas – Cap Swaps 2,294 1,617 Natural Gas – Swaps 1,593 1,554 Natural Gas – Basis Swaps 195 — Natural Gas – Three-Way Collars 5,108 1,733 Total Long-Term Derivative Assets $ 9,534 $ 4,904 Total Derivative Assets $ 43,794 $ 34,169 Short-Term Derivative Liabilities: Refined Product – Swaps (376 ) — Natural Gas – Three-Way Collars (31 ) — Natural Gas – Basis Swaps (1,585 ) (193 ) Natural Gas – Call — (74 ) Natural Gas – Swaption (202 ) (154 ) Natural Gas – Swaps (292 ) — Total Short – Term Derivative Liabilities $ (2,486 ) $ (421 ) Long-Term Derivative Liabilities: Natural Gas – Swaption (297 ) — Natural Gas – Basis Swaps (4,186 ) (1,281 ) Natural Gas – Call (989 ) (1,096 ) Natural Gas – Three-Way Collars (84 ) — Total Long-Term Derivative Liabilities $ (5,556 ) $ (2,377 ) Total Derivative Liabilities $ (8,042 ) $ (2,798 )
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 March 31, 2016 and December 31, 2015 are included in the table below. As of March 31, 2016 Range (price per Mcf) Weighted (price per Mcf) Fair Value (in thousands) Natural Gas Basis Differential Forward Curve – Dominion South ($ 0.30) – ($1.02) $ (0.85 ) $ (6,247 ) Natural Gas Basis Differential Forward Curve – Texas Gas ($ 0.09) – ($0.13) $ (0.13 ) $ (1,026 ) As of December 31, 2015 Range (price per Mcf) Weighted (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 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 December 31, 2015 and 2014 are included in the table below. 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 ) As of December 31, 2014 Range (price per Mcf) Weighted Fair Value Natural Gas Basis Differential Forward Curve ($0.27) – ($1.39 ) $ (0.84 ) $ 1,341
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 March 31, ($ in Thousands) Total Quoted Significant Significant Commodity Derivatives $ 26,806 $ — $ 34,079 $ (7,273 ) Fair Value Measurements at December 31, ($ in Thousands) Total Quoted Significant Significant (Level 3) Commodity Derivatives $ 35,752 $ — $ 41,258 $ (5,506 )	The following table presents the fair value hierarchy table for assets and liabilities measured at fair value: Fair Value Measurements at December 31, 2015 Using: ($ in Thousands) Total Carrying Value as of December 31, 2015 Quoted in Active Markets for Identical (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ 35,752 $ — $ 41,258 $ (5,506 ) Fair Value Measurements at December 31, ($ in Thousands) Total Value as of December 31, 2014 Quoted in Active Markets for Identical (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives $ 31,371 $ — $ 30,030 $ 1,341
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 three months ended March 31, 2016 and 2015: Three Months Ended March 31, ($ in Thousands) 2016 2015 Beginning Balance of Level 3 $ (5,506 ) $ 1,341 Changes in Fair Value (2,037 ) (1,955 ) Purchases — — Settlements Received 270 409 Ending Balance of Level 3 $ (7,273 ) $ (205 )	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 years ended December 31, 2015 and 2014 (in thousands): For the Year Ended December 31, ($ in Thousands) 2015 2014 Beginning Balance of Level 3 $ 1,341 $ 4,323 Changes in Fair Value (2,548 ) (1,670 ) Purchases — — Settlements Received (4,299 ) (1,312 ) Ending Balance of Level 3 $ (5,506 ) $ 1,341
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: March 31, 2016 December 31, 2015 ($ in Thousands) Carrying Fair Value Carrying Fair Value Senior Notes, Net of Issuance Costs $ 657,511 $ 78,715 $ 663,089 $ 137,402 Secured Line of Credit 152,794 152,794 109,396 109,396 Capital Leases and Other Obligations 434 427 618 606 Total $ 810,739 $ 231,936 $ 773,103 $ 247,404	The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements: December 31, 2015 December 31, 2014 ($ in Thousands) Carrying Amount Fair Value Carrying Amount Fair Value 8.875% Senior Notes due 2020 $ 350,000 $ 77,000 $ 350,000 $ 311,955 6.25% Senior Notes due 2022 325,000 72,313 325,000 241,313 Secured Lines of Credit 111,500 111,500 — — Capital Leases and Other Obligations 618 606 1,427 1,393 Total $ 787,118 $ 261,419 $ 676,427 $ 554,661
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 years ended December 31, 2015, 2014 and 2013: For the Year Ended December 31, ($ in Thousands) 2015 2014 2013 Oil $ 7,132 $ 8,613 $ (2,798 ) Natural Gas 37,647 18,406 1,807 NGLs 14,463 10,340 (1,711 ) Interest Rate 934 1,517 (206 ) Gain (Loss) on Derivatives, Net $ 60,176 $ 38,876 $ (2,908 )
Asset or Liability Financial Commodity Derivative Instrument Positions		The fair value associated with our derivative instruments was a net asset of $35.8 million as of December 31, 2015, and a net asset of $31.4 million at December 31, 2014. Our open asset/(liability) financial commodity derivative instrument positions at December 31, 2015 consisted of the following: Period Volume Put Floor Ceiling Swap Fair Market Value ($ in Thousands) Oil 2016 – Deferred Put Spreads 120,000 Bbls $ 50.00 $ 65.00 $ — $ — $ 852 2016 – Collars 379,500 Bbls — 39.17 52.67 — 1,078 2016 – Three-Way Collars 45,000 Bbls 50.00 65.00 70.00 — 577 544,500 Bbls $ 2,507 Natural Gas 2016 – Swaps 12,900,000 Mcf $ — $ — $ — $ 3.19 $ 8,717 2016 – Swaptions 1,200,000 Mcf — — — 3.15 596 2016 – Cap Swaps 3,600,000 Mcf 3.45 — — 4.11 1,977 2016 – Three-Way Collars 18,570,000 Mcf 2.34 3.04 3.86 — 5,941 2016 – Put Spread 4,500,000 Mcf 2.93 3.59 — — 1,737 2016 – Basis Swaps – Dominion South 16,630,000 Mcf — — — (0.94 ) (1,634 ) 2016 – Collars 3,900,000 Mcf — 2.82 3.32 — 1,728 2017 – Swaps 960,000 Mcf — — — 3.60 797 2017 – Swaptions 0 Mcf — — — — (297 ) 2017 – Cap Swaps 2,100,000 Mcf 3.34 — — 4.07 1,225 2017 – Three-Way Collars 16,300,000 Mcf 2.33 3.02 3.89 — 4,319 2017 – Basis Swaps – Dominion South 4,550,000 Mcf — — — (0.83 ) (665 ) 2017 – Basis Swaps – Texas Gas 14,600,000 Mcf — — — (0.13 ) (19 ) 2017 – Calls 3,000,000 Mcf — — 3.64 — (380 ) 2018 – Swaps 960,000 Mcf — — — 3.60 797 2018 – Cap Swaps 1,800,000 Mcf 3.30 — — 4.05 1,069 2018 – Three-Way Collars 7,875,000 Mcf 2.29 2.88 3.56 — 916 2018 – Calls 5,810,000 Mcf — — 3.97 — (609 ) 2018 – Basis Swaps – Dominion South 6,400,000 Mcf — — — (0.83 ) (960 ) 2018 – Basis Swaps – Texas Gas 14,600,000 Mcf — — — (0.13 ) (19 ) 2019 – Basis Swaps – Dominion South 7,300,000 Mcf — — — (0.83 ) (1,103 ) 2020 – Basis Swaps – Dominion South 7,320,000 Mcf — — — (0.83 ) (1,106 ) 154,875,000 Mcf $ 23,027 NGLs 2016 C3 + NGL Swaps 1,131,000 Bbls $ — $ — $ — $ 32.76 $ 9,888 2016 Ethane Swaps 240,000 Bbls — — — 8.82 362 2017 C3 + NGL Swaps 180,000 Bbls — — — 21.42 344 1,551,000 Bbls $ 10,594 Refined Product (Heating Oil) 2016 – Swaps 12,000 Bbls $ — $ — $ — $ 84.00 $ (376 ) 12,000 Bbls $ (376 )

Income Taxes (Tables)

Income Taxes (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Reconciliation of Income Tax Expense (Benefit) Using Statutory Rate Compared With Actual Income Tax Expense	Income tax included in continuing operations was as follows: Three Months ($ in Thousands) 2016 2015 Income (Expense) Benefit $ (2,092 ) $ 92 Effective Tax Rate -3.6 % 0.5 %	A reconciliation of income tax expense (benefit) using the statutory U.S. income tax rate compared with actual income tax expense is as follows: ($ in Thousands) Year Ended December 31, 2015 Year Ended December 31, 2014 Year Ended December 31, 2013 Loss from continuing operations before noncontrolling interests and income taxes $ (423,245 ) $ (74,565 ) $ (6,538 ) Statutory U.S. income tax rate 35.0 % 35.0 % 35.0 % Tax expense recognized using statutory U.S. income tax rate $ (148,136 ) $ (26,098 ) $ (2,288 ) State income taxes, net of federal income tax benefit (20,446 ) (3,144 ) (805 ) Change in estimated future state rates (212 ) (1,015 ) (484 ) Permanent differences 1,609 970 83 Change in valuation allowances 143,566 2,450 (160 ) Other (608 ) (78 ) (500 ) Total income tax benefit $ (24,227 ) $ (26,915 ) $ (4,154 ) Effective income tax rate 5.7 % 36.1 % 63.5 %
Income Tax Expense (Benefit) from Continuing Operations		Our income tax expense (benefit) from continuing operations consisted of the following: For the Years Ended December 31, ($ in Thousands) 2015 2014 2013 Current: Federal $ — $ — $ (1,936 ) State — 6 (4,105 ) Deferred: Federal (20,993 ) (23,691 ) 509 State (3,234 ) (3,230 ) 1,378 Income Tax Benefit $ (24,227 ) $ (26,915 ) $ (4,154 )
Components of Deferred Tax Assets (Liabilities)		Deferred tax assets (liabilities) are comprised of the following at December 31, 2015 and 2014: For the Years Ended December 31, ($ in Thousands) 2015 2014 Tax effects of temporary differences for: Current: Assets: Asset retirement obligation $ 866 $ 772 Deferred compensation plans 2,028 695 Compensation Accruals 767 2,087 Valuation allowances (3,478 ) (71 ) Other 93 68 Total gross current deferred tax assets 276 3,551 Liabilities: Unrealized gain on derivatives (12,570 ) (11,410 ) Other (238 ) (442 ) Total gross current deferred tax liabilities (12,808 ) (11,852 ) Net total current deferred tax liability $ (12,532 ) $ (8,301 ) Long-Term: Assets: Timing differences – tax partnerships $ 4,166 $ — Tax basis of oil and gas properties in excess of book basis 8,965 — Asset retirement obligation 16,965 15,091 Deferred compensation plans 1,083 2,218 Net operating loss carryforward 123,488 73,531 Organization costs 456 525 Deferred revenue 1,098 1,209 Percentage depletion carryforward 2,673 2,155 AMT credits 292 292 Valuation allowances (144,681 ) (4,318 ) Other 280 269 Total gross long-term deferred tax assets 14,785 88,817 Liabilities: Timing differences – tax partnerships — (7,135 ) Book basis of oil and gas properties in excess of tax basis — (73,557 ) Unrealized gain on derivatives (1,574 ) (999 ) Other (679 ) $ (980 ) Total gross long-term deferred tax liabilities (2,253 ) (80,516 ) Net total long-term deferred tax asset $ 12,532 $ 8,301 (a) As a result of certain realization requirements of FASB ASC 718, the table of deferred tax assets and liabilities does not include $1.3 million at December 31, 2015 and 2014, of excess tax benefits that arose directly from tax deductions related to stock-based compensation greater than compensation recognized for financial reporting. Total stockholders’ equity will be increased by $1.3 million if and when such excess tax benefits are ultimately realized.
Expirations by Year for Federal and State Net Operating Loss Carryforwards		The following table shows expirations by year for federal and state net operating loss carryforwards (all figures presented are tax effected): Year of Expiration Net Operating Loss Carryforwards (in thousands) 2020 $ 134 2021 175 2022 — 2023 899 2024 — 2025 531 2026 405 2027 1,003 2028 3,333 2029 767 2030 751 2031 19,746 2032 253 2033 19,703 2034 18,670 2035 57,118 Total 123,488

Employee Benefit and Equity P43

Employee Benefit and Equity Plans (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of Issued and Outstanding Stock Options	A summary of the status of our issued and outstanding stock options as of March 31, 2016 is as follows: Outstanding Exercisable Exercise Price Number Outstanding At 3/31/16 Weighted-Average Number Exercisable At 3/31/16 Weighted-Average $1.69 851,422 $ 1.69 — $ — $4.05 40,000 $ 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 $11.87 3,500 $ 11.87 3,500 $ 11.87 $13.19 50,000 $ 13.19 50,000 $ 13.19 $22.34 30,000 $ 22.34 30,000 $ 22.34 1,295,094 $ 4.41 367,005 $ 10.72	A summary of the status of our issued and outstanding stock options as of December 31, 2015 is as follows: Outstanding Exercisable Exercise Price Number Outstanding At 12/31/15 Weighted-Average Exercise Price Number Exercisable At 12/31/15 Weighted-Average Exercise Price $4.05 40,000 $ 4.05 — $ — $4.90 40,000 $ 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 $11.89 3,500 $ 11.89 3,500 $ 11.89 $13.19 50,000 $ 13.19 50,000 $ 13.19 $22.34 30,000 $ 22.34 30,000 $ 22.34 443,672 $ 9.64 363,672 $ 10.77
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 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	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 Year Ended December 31, Expected Dividend Yield 0.0% 0.0% Risk-Free Interest Rate 1.0% 0.8% Expected Volatility – Rex Energy 58.6% 50.4% Expected Volatility – Peer Group 29.8%-85.0% 28.4%-65.7% Market Index 35.6% 35.3% Expected Life Three Years Three Years
Summary of Nonvested Restricted Stock Activity	A summary of the restricted stock activity for the three months ended March 31, 2016 is as follows: Number of Weighted- Restricted stock awards, as of December 31, 2015 2,479,408 $ 6.27 Awards 420,901 1.67 Forfeitures (346,876 ) 7.83 Vested (142,516 ) 12.76 Restricted stock awards, as of March 31, 2016 2,410,917 $ 4.86	A summary of the restricted stock activity for the years ended December 31, 2015, 2014 and 2013 is as follows: Number of Shares Weighted-Average Grant Date Fair Value Restricted stock awards, as of January 1, 2013 1,431,573 $ 12.45 Awards 981,544 16.03 Vested (182,994 ) 11.59 Forfeitures (57,484 ) 11.84 Restricted stock awards, as of December 31, 2013 2,172,639 $ 14.16 Awards 131,610 8.76 Vested (595,085 ) 13.09 Forfeitures (189,863 ) 14.60 Restricted stock awards, as of December 31, 2014 1,519,301 $ 14.05 Awards 2,236,839 3.35 Vested (606,359 ) 9.39 Forfeitures (670,373 ) 11.33 Restricted stock awards, as of December 31, 2015 2,479,408 $ 6.27
Summary of Stock Option Activity		A summary of the stock option activity is as follows: Number of Shares Weighted- Exercise Weighted- Remaining (in years) Aggregate Value (in Options outstanding December 31, 2012 502,253 $ 10.95 Granted — — Exercised (49,166 ) 10.85 Cancelled/Forfeited (4,000 ) 23.28 Options outstanding December 31, 2013 449,087 $ 10.85 Granted — — Exercised (46,526 ) 11.09 Cancelled/Forfeited — — Options outstanding December 31, 2014 402,561 $ 10.82 Granted 80,000 4.48 Exercised — — Cancelled/Forfeited (38,889 ) 11.23 Options Outstanding December 31, 2015 443,672 $ 9.64 2.8 $ — Options Exercisable December 31, 2015 363,672 $ 10.77 2.1 $ —
Percentage of Awards to Vest		The number of shares ultimately awarded will correspond with the final TSR rank amongst the peer group in accordance with the following schedule: TSR Rank Percentage of Awards to Vest 1-3 100 % 4-6 75 % 7-10 50 % 11-13 25 % 14-16 0 %

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Lease Commitments for Each of Next Five Years	Lease commitments by year for each of the next five years are presented in the table below: ($ in Thousands) 2016 $ 766 2017 991 2018 565 2019 563 2020 422 Thereafter — Total $ 3,307	Lease commitments by year for each of the next five years are presented in the table below. ($ in Thousands) 2016 $ 1,058 2017 991 2018 565 2019 563 2020 422 Thereafter — Total $ 3,599
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 $ 24,715 2017 49,357 2018 53,456 2019 52,904 2020 51,697 Thereafter 458,695 Total $ 690,824	Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows: ($ in Thousands) Total 2016 $ 23,836 2017 38,434 2018 39,993 2019 39,017 2020 37,744 Thereafter 395,980 Total $ 575,004
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) 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.	The fee for each unconventional natural gas well is determined using the following matrix with vertical unconventional natural gas wells being charged 20%: <$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) Pricing utilized for determining annual fees 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 year ending December 31.

Earnings Per Common Share (Tabl

Earnings Per Common Share (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
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 2016 2015 Numerator: Net Loss From Continuing Operations $ (60,141 ) $ (18,479 ) Net Income From Discontinued Operations, Less Noncontrolling Interests — 665 Less: Preferred Stock Dividends (2,105 ) (2,415 ) Net Loss Attributable to Common Shareholders $ (62,246 ) $ (20,229 ) Denominator: Weighted Average Common Shares Outstanding – Basic 56,003 54,370 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 56,003 54,370 Earnings per Common Share Attributable to Rex Energy Common Shareholders: Basic – Net Loss From Continuing Operations $ (1.11 ) $ (0.38 ) – Net Income From Discontinued Operations — 0.01 – Net Loss Attributable to Rex Energy Common Shareholders $ (1.11 ) $ (0.37 ) Diluted – Net Loss From Continuing Operations $ (1.11 ) $ (0.38 ) – Net Income From Discontinued Operations — 0.01 – Net Loss Attributable to Rex Energy Common Shareholders $ (1.11 ) $ (0.37 )	The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share data): Year Ended December 31, Year Ended December 31, Year Ended December 31, (in thousands, except per share amounts) 2015 2014 2013 Numerator: Net Loss From Continuing Operations $ (399,018 ) $ (47,650 ) $ (2,384 ) Net Income From Discontinued Operations, Less Noncontrolling Interests 35,740 961 254 Less: Preferred Stock Dividends 9,660 2,335 — Net Loss Attributable to Common Shareholders $ (372,938 ) $ (49,024 ) $ (2,130 ) Denominator: Weighted Average Common Shares Outstanding – Basic 54,392 53,150 52,572 Weighted Average Common Shares Outstanding – Diluted 54,392 53,150 52,572 Earnings per Common Share Attributable to Rex Energy Common Shareholders(a): Basic – Net Loss From Continuing Operations $ (7.51 ) $ (0.94 ) $ (0.05 ) – Net Income From Discontinued Operations 0.66 0.02 0.01 – Net Loss Attributable to Rex Energy Common Shareholders $ (6.85 ) $ (0.92 ) $ (0.04 ) Diluted – Net Loss From Continuing Operations $ (7.51 ) $ (0.94 ) $ (0.05 ) – Net Income From Discontinued Operations 0.66 0.02 0.01 – Net Loss Attributable to Rex Energy Common Shareholders $ (6.85 ) $ (0.92 ) $ (0.04 ) (a) All earnings per share amounts are attributable to Rex common shareholders.

Condensed Consolidating Finan46

Condensed Consolidating Financial Information (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Condensed Consolidating Balance Sheets	REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF MARCH 31, 2016 ($ in Thousands) Guarantor Non-Guarantor Rex Energy Eliminations Consolidated ASSETS Current Assets Cash and Cash Equivalents $ 24,888 $ — $ 3 $ — $ 24,891 Accounts Receivable 24,252 16 47 — 24,315 Taxes Receivable — — 18 — 18 Short-Term Derivative Instruments 29,012 — — — 29,012 Inventory, Prepaid Expenses and Other 3,156 — 12 — 3,168 Total Current Assets 81,308 16 80 — 81,404 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,300,678 801 — 1,301,479 Unevaluated Oil and Gas Properties 257,697 — — — 257,697 Other Property and Equipment 40,133 895 — — 41,028 Wells and Facilities in Progress 75,269 245 — — 75,514 Pipelines 16,780 — — — 16,780 Total Property and Equipment 1,690,557 1,941 — — 1,692,498 Less: Accumulated Depreciation, Depletion and Amortization (720,100 ) (898 ) — — (720,998 ) Net Property and Equipment 970,457 1,043 — — 971,500 Other Assets 2,489 — — — 2,489 Intercompany Receivables — — 1,095,371 (1,095,371 ) — Investment in Subsidiaries – Net (2,388 ) — (127,974 ) 130,362 — Long-Term Derivative Instruments 8,460 — — — 8,460 Total Assets $ 1,060,326 $ 1,059 $ 967,477 $ (965,009 ) $ 1,063,853 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 42,818 $ — $ — $ — $ 42,818 Current Maturities of Long-Term Debt 434 — 9,500 — 9,934 Accrued Liabilities 32,709 20 11,567 44,296 Short-Term Derivative Instruments 3,758 — — — 3,758 Total Current Liabilities 79,719 20 21,067 — 100,806 Long-Term Derivative Instruments 6,908 — — — 6,908 Senior Secured Line of Credit and Other Long-Term Debt, Net of Issuance Costs — — 143,294 — 143,294 Senior Notes, Net of Issuance Costs — — 657,511 — 657,511 Premium on Senior Notes – Net — — 2,245 — 2,245 Other Deposits and Liabilities 3,140 — — — 3,140 Future Abandonment Cost 42,964 448 — — 43,412 Intercompany Payables 1,090,818 4,553 — (1,095,371 ) — Total Liabilities 1,223,549 5,021 824,117 (1,095,371 ) 957,316 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 63 — 63 Additional Paid-In Capital 177,144 — 630,301 (177,144 ) 630,301 Accumulated Earnings (Deficit) (340,367 ) (3,962 ) (487,005 ) 307,506 (523,828 ) Total Stockholders’ Equity (163,223 ) (3,962 ) 143,360 130,362 106,537 Total Liabilities and Stockholders’ Equity $ 1,060,326 $ 1,059 $ 967,477 $ (965,009 ) $ 1,063,853 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF DECEMBER 31, 2015 ($ in Thousands) Guarantor Non-Guarantor Rex Energy Eliminations Consolidated ASSETS Current Assets Cash and Cash Equivalents $ 1,089 $ — $ 2 $ — $ 1,091 Accounts Receivable 19,423 11 49 — 19,483 Taxes Receivable — — 18 — 18 Short-Term Derivative Instruments 34,260 — — — 34,260 Inventory, Prepaid Expenses and Other 3,804 — 25 — 3,829 Total Current Assets 58,576 11 94 — 58,681 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,245,626 774 — (6,970 ) 1,239,430 Unevaluated Oil and Gas Properties 262,992 — — — 262,992 Other Property and Equipment 39,217 895 — — 40,112 Wells and Facilities in Progress 144,587 239 — (270 ) 144,556 Pipelines 16,161 — — (2,137 ) 14,024 Total Property and Equipment 1,708,583 1,908 — (9,377 ) 1,701,114 Less: Accumulated Depreciation, Depletion and Amortization (702,537 ) (880 ) — 3,518 (699,899 ) Net Property and Equipment 1,006,046 1,028 — (5,859 ) 1,001,215 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 $ 1,074,750 $ 1,039 $ 1,313,973 $ (1,317,831 ) $ 1,071,931 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts Payable $ 37,874 $ — $ — $ — $ 37,874 Current Maturities of Long-Term Debt 590 — — — 590 Accrued Liabilities 32,601 — 11,725 — 44,326 Short-Term Derivative Instruments 2,486 — — — 2,486 Total Current Liabilities 73,551 — 11,725 — 85,276 Long-Term Derivative Instruments 5,556 — — — 5,556 Senior Secured Line of Credit and Other Long-Term Debt, Net of Issuance Costs 28 — 109,368 — 109,396 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 42,443 440 — — 42,883 Intercompany Payables 1,070,096 452 — (1,070,548 ) — Total Liabilities 1,194,830 892 786,526 (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) (297,223 ) 147 (92,385 ) (74,226 ) (463,687 ) Total Stockholders’ Equity (120,080 ) 147 527,447 (247,283 ) 160,231 Total Liabilities and Stockholders’ Equity $ 1,074,750 $ 1,039 $ 1,313,973 $ (1,317,831 ) $ 1,071,931	REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS FOR THE YEAR ENDED DECEMBER 31, 2015 ($ in Thousands, Except Share and Per Share Data) 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 19,423 11 49 — 19,483 Taxes Receivable — — 18 — 18 Short-Term Derivative Instruments 34,260 — — — 34,260 Inventory, Prepaid Expenses and Other 3,804 — 25 — 3,829 Total Current Assets 58,576 11 94 — 58,681 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,245,626 774 — (6,970 ) 1,239,430 Unevaluated Oil and Gas Properties 262,992 — — — 262,992 Other Property and Equipment 39,217 895 — — 40,112 Wells and Facilities in Progress 144,587 239 — (270 ) 144,556 Pipelines 16,161 — — (2,137 ) 14,024 Total Property and Equipment 1,708,583 1,908 — (9,377 ) 1,701,114 Less: Accumulated Depreciation, Depletion and Amortization (702,537 ) (880 ) — 3,518 (699,899 ) Net Property and Equipment 1,006,046 1,028 — (5,859 ) 1,001,215 Deferred Financing Costs and Other Assets – Net 2,501 — 14,043 — 16,544 Equity Method Investments — — — — — Long-Term Deferred Tax Asset — — 12,532 — 12,532 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 $ 1,074,750 $ 1,039 $ 1,340,548 $ (1,317,831 ) $ 1,098,506 LIABILITIES AND EQUITY Current Liabilities Accounts Payable $ 37,874 $ — $ — $ — $ 37,874 Current Maturities of Long-Term Debt 590 — — — 590 Accrued Liabilities 32,601 — 11,725 — 44,326 Short-Term Derivative Instruments 2,486 — — — 2,486 Current Deferred Tax Liability — — 12,532 — 12,532 Total Current Liabilities 73,551 — 24,257 — 97,808 8.875% Senior Notes Due 2020 — — 350,000 — 350,000 6.25% Senior Notes Due 2022 — — 325,000 — 325,000 Premium on Senior Notes – Net — — 2,344 — 2,344 Senior Secured Line of Credit and Other Long-Term Debt 28 — 111,500 — 111,528 Long-Term Derivative Instruments 5,556 — — — 5,556 Other Deposits and Liabilities 3,156 — — — 3,156 Future Abandonment Cost 42,443 440 — — 42,883 Intercompany Payables 1,070,096 452 — (1,070,548 ) — Total Liabilities 1,194,830 892 813,101 (1,070,548 ) 938,275 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) (297,223 ) 147 (92,385 ) (74,226 ) (463,687 ) Rex Energy Stockholders’ Equity (120,080 ) 147 527,447 (247,283 ) 160,231 Noncontrolling Interests — — — — — Total Stockholders’ Equity (120,080 ) 147 527,447 (247,283 ) 160,231 Total Liabilities and Stockholders’ Equity $ 1,074,750 $ 1,039 $ 1,340,548 $ (1,317,831 ) $ 1,098,506 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS FOR THE YEAR ENDED DECEMBER 31, 2014 ($ in Thousands, Except Share and Per Share Data) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance ASSETS Current Assets Cash and Cash Equivalents $ 17,978 $ — $ — $ — $ 17,978 Accounts Receivable 43,726 210 — — 43,936 Taxes Receivable — — 504 — 504 Short-Term Derivative Instruments 29,265 — — — 29,265 Assets Held For Sale — 36,794 — (2,537 ) 34,257 Inventory, Prepaid Expenses and Other 3,374 — 29 — 3,403 Total Current Assets 94,343 37,004 533 (2,537 ) 129,343 Property and Equipment (Successful Efforts Method) Evaluated Oil and Gas Properties 1,084,332 467 — (5,760 ) 1,079,039 Unevaluated Oil and Gas Properties 321,708 705 — — 322,413 Other Property and Equipment 45,466 895 — — 46,361 Wells and Facilities in Progress 127,759 456 — (560 ) 127,655 Pipelines 17,555 — — (1,898 ) 15,657 Total Property and Equipment 1,596,820 2,523 — (8,218 ) 1,591,125 Less: Accumulated Depreciation, Depletion and Amortization (367,224 ) (730 ) — 1,037 (366,917 ) Net Property and Equipment 1,229,596 1,793 — (7,181 ) 1,224,208 Deferred Financing Costs and Other Assets—Net 2,421 — 14,649 — 17,070 Equity Method Investments 17,895 — — — 17,895 Long-Term Deferred Tax Asset — — 8,301 — 8,301 Intercompany Receivables — — 951,025 (951,025 ) — Investment in Subsidiaries – Net 4,161 1,541 258,448 (264,150 ) — Long-Term Derivative Instruments 4,904 — — — 4,904 Total Assets $ 1,353,320 $ 40,338 $ 1,232,956 $ (1,224,893 ) $ 1,401,721 LIABILITIES AND EQUITY Current Liabilities Accounts Payable $ 55,877 $ — $ — $ (2,537 ) $ 53,340 Current Maturities of Long-Term Debt 1,176 — — — 1,176 Accrued Liabilities 46,783 571 12,124 — 59,478 Short-Term Derivative Instruments 421 — — — 421 Long-Term Deferred Tax Liability — — 8,301 — 8,301 Liabilities Related to Assets Held For Sale — 25,115 — — 25,115 Total Current Liabilities 104,257 25,686 20,425 (2,537 ) 147,831 8.875% Senior Notes Due 2020 — — 350,000 — 350,000 6.25% Senior Notes Due 2022 325,000 325,000 Premium (Discount) on Senior Notes – Net — — 2,725 — 2,725 Senior Secured Line of Credit and Other Long-Term Debt 251 — — — 251 Long-Term Derivative Instruments 2,377 — — — 2,377 Other Deposits and Liabilities 4,018 — — — 4,018 Future Abandonment Cost 38,097 49 — — 38,146 Intercompany Payables 947,114 3,911 — (951,025 ) — Total Liabilities 1,096,114 29,646 698,150 (953,562 ) 870,348 Stockholders’ Equity Preferred Stock — — 1 — 1 Common Stock — — 54 — 54 Additional Paid-In Capital 177,144 79,743 617,826 (256,887 ) 617,826 Accumulated Earnings (Deficit) 80,062 (69,253 ) (83,075 ) (18,483 ) (90,749 ) Rex Energy Stockholders’ Equity 257,206 10,490 534,806 (275,370 ) 527,132 Noncontrolling Interests — 202 — 4,039 4,241 Total Stockholders’ Equity 257,206 10,692 534,806 (271,331 ) 531,373 Total Liabilities and Stockholders’ Equity $ 1,353,320 $ 40,338 $ 1,232,956 $ (1,224,893 ) $ 1,401,721
Condensed Consolidating Statements of Cash Flows	REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDING MARCH 31, 2016 ($ in Thousands) Guarantor Non-Guarantor Rex Energy Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (38,143 ) $ (8 ) $ (60,141 ) $ 38,151 $ (60,141 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Non-Cash Expenses (Income) (30 ) — 527 — 497 Depreciation, Depletion, Amortization and Accretion 19,379 29 — — 19,408 Gain on Derivatives (4,049 ) — — — (4,049 ) Cash Settlements of Derivatives 12,994 — — — 12,994 Dry Hole Expense 843 — — — 843 Gain on Sale of Asset (30 ) — — — (30 ) Deferred Income Tax Expense 1,326 1 765 — 2,092 Impairment Expense 14,184 — 14,184 (14,184 ) 14,184 Changes in operating assets and liabilities Accounts Receivable 15,852 10 (20,735 ) — (4,873 ) Inventory, Prepaid Expenses and Other Assets 648 — 12 — 660 Accounts Payable and Accrued Liabilities 1,922 21 (2,251 ) — (308 ) Other Assets and Liabilities (170 ) — — — (170 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 24,726 53 (67,639 ) 23,967 (18,893 ) CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 27 (21 ) 23,961 (23,967 ) — Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 71 — — — 71 Proceeds from Joint Venture for Reimbursement of Capital Costs 19,461 — — — 19,461 Acquisitions of Undeveloped Acreage (5,266 ) — — — (5,266 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (15,036 ) (32 ) — — (15,068 ) NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (743 ) (53 ) 23,961 (23,967 ) (802 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — — 46,500 — 46,500 Repayments of Loans and Other Long-Term Debt (184 ) — — — (184 ) Debt Issuance Costs — — (2,821 ) — (2,821 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (184 ) — 43,679 — 43,495 NET INCREASE IN CASH 23,799 — 1 — 23,800 CASH – BEGINNING 1,089 — 2 — 1,091 CASH – ENDING $ 24,888 $ — $ 3 $ — $ 24,891 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDING MARCH 31, 2015 ($ in Thousands) Guarantor Non-Guarantor Rex Energy Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (4,114 ) $ 2,826 $ (17,814 ) $ 2,585 $ (16,517 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Loss From Equity Method Investments 203 — — — 203 Non-Cash Expenses (70 ) 44 3,403 — 3,377 Depreciation, Depletion, Amortization and Accretion 26,292 1,480 — (1,607 ) 26,165 Gain on Derivatives (16,856 ) — (263 ) — (17,119 ) Cash Settlements of Derivatives 10,579 — 500 — 11,079 Dry Hole Expense (1 ) — — — (1 ) (Gain) Loss on Sale of Asset 65 (32 ) — — 33 Impairment Expense 7,012 11 — — 7,023 Changes in operating assets and liabilities Accounts Receivable 10,437 (1,087 ) 428 251 10,029 Inventory, Prepaid Expenses and Other Assets 712 (322 ) (62 ) — 328 Accounts Payable and Accrued Liabilities (12,518 ) (2,496 ) 2,336 (251 ) (12,929 ) Other Assets and Liabilities (199 ) (133 ) 27 — (305 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 21,542 291 (11,445 ) 978 11,366 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany loans to subsidiaries 27,192 (1,688 ) (23,681 ) (1,823 ) — Proceeds from Joint Venture Acreage Management 39 — — — 39 Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 217 455 — — 672 Proceeds from Joint Venture for Reimbursement of Capital Costs 16,611 — — — 16,611 Acquisitions of Undeveloped Acreage (17,454 ) (5 ) — — (17,459 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (60,719 ) (7,139 ) — 845 (67,013 ) NET CASH USED IN INVESTING ACTIVITIES (34,114 ) (8,377 ) (23,681 ) (978 ) (67,150 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — 18,826 54,000 — 72,826 Repayments of Long-Term Debt and Lines of Credit — (9,761 ) (16,000 ) — (25,761 ) Repayments of Loans and Other Notes Payable (392 ) (294 ) — — (686 ) Debt Issuance Costs — — (459 ) — (459 ) Dividends Paid — — (2,415 ) — (2,415 ) Distributions by the Partners of Consolidated Subsidiaries — (531 ) — — (531 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (392 ) 8,240 35,126 — 42,974 NET INCREASE IN CASH (12,964 ) 154 — — (12,810 ) CASH – BEGINNING 17,978 113 5 — 18,096 CASH – ENDING $ 5,014 $ 267 $ 5 $ — $ 5,286	REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDING DECEMBER 31, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (351,424 ) $ 3,908 $ (328,010 ) $ 314,493 $ (361,033 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Loss on Equity Method Investments 411 — — — 411 Non-Cash Expenses (Income) (201 ) (334 ) 8,184 — 7,649 Depreciation, Depletion, Amortization and Accretion 105,555 3,230 — (3,963 ) 104,822 Gain on Derivatives (59,242 ) — (934 ) — (60,176 ) Cash Settlements of Derivatives 54,859 — 934 — 55,793 Dry Hole Expense 199 136 — (5 ) 330 Gain on Sale of Asset (477 ) (44 ) — — (521 ) Gain on Sale of Water Solutions — — (57,778 ) — (57,778 ) Impairment Expense 345,892 1,396 345,892 (347,405 ) 345,775 Changes in operating assets and liabilities Accounts Receivable 24,240 (453 ) 429 (2,537 ) 21,679 Inventory, Prepaid Expenses and Other Assets (431 ) (142 ) 5 — (568 ) Accounts Payable and Accrued Liabilities (20,008 ) (4,969 ) (515 ) 2,537 (22,955 ) Other Assets and Liabilities (2,497 ) (73 ) 27 — (2,543 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 96,876 2,655 (31,766 ) (36,880 ) 30,885 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany Loans to Subsidiaries 103,212 (3,362 ) (135,566 ) 35,716 — Proceeds from Joint Venture Acreage Management 58 — — — 58 Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 9,766 560 66,900 — 77,226 Proceeds from Joint Venture 16,611 — — — 16,611 Acquisitions of Undeveloped Acreage (27,963 ) (279 ) — — (28,242 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (214,450 ) (7,813 ) — 1,164 (221,099 ) NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (112,766 ) (10,894 ) (68,666 ) 36,880 (155,446 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — 35,814 193,500 — 229,314 Repayments of Long-Term Debt and Lines of Credit — (26,335 ) (82,000 ) — (108,335 ) Repayments of Loans and Other Notes Payable (999 ) (520 ) — — (1,519 ) Debt Issuance Costs — (3 ) (1,411 ) — (1,414 ) Distributions by the Partners of Consolidated Subsidiary — (830 ) — — (830 ) Dividends Paid on Preferred Stock — — (9,660 ) — (9,660 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (999 ) 8,126 100,429 — 107,556 NET (DECREASE) IN CASH (16,889 ) (113 ) (3 ) — (17,005 ) CASH – BEGINNING 17,978 113 5 — 18,096 CASH – ENDING $ 1,089 $ — $ 2 $ — $ 1,091 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDING DECEMBER 31, 2014 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ (21,854 ) $ 9,330 $ (46,689 ) $ 16,563 $ (42,650 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Loss on Equity Method Investments 813 — — — 813 Non-Cash Expenses (Income) (273 ) 278 6,784 — 6,789 Depreciation, Depletion, Amortization and Accretion 94,643 4,217 — (689 ) 98,171 Deferred Income Tax Benefit (9,928 ) (1,649 ) (14,415 ) — (25,992 ) Gain on Derivatives (37,359 ) — (1,517 ) — (38,876 ) Cash Settlements of Derivatives 5,969 — 1,312 — 7,281 Dry Hole Expense 3,797 267 — — 4,064 (Gain) Loss on Sale of Asset 644 (55 ) — — 589 Impairment Expense 126,662 6,022 — — 132,684 Changes in operating assets and liabilities Accounts Receivable (11,450 ) (6,090 ) 4,686 (766 ) (13,620 ) Inventory, Prepaid Expenses and Other Assets (1,283 ) (74 ) (2 ) — (1,359 ) Accounts Payable and Accrued Liabilities 23,768 3,488 9,252 766 37,274 Other Assets and Liabilities (2,127 ) (335 ) — — (2,462 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 172,022 15,399 (40,589 ) 15,874 162,706 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany Loans to Subsidiaries 397,382 (5,412 ) (371,768 ) (20,202 ) — Proceeds from Joint Venture Acreage Management 263 — — — 263 Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 254 292 — — 546 Acquisitions of Undeveloped Acreage (168,713 ) (710 ) — — (169,423 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (382,889 ) (12,861 ) — 4,328 (391,422 ) NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (153,703 ) (18,691 ) (371,768 ) (15,874 ) (560,036 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — 38,895 171,000 — 209,895 Repayments of Long-Term Debt and Lines of Credit — (33,152 ) (230,000 ) — (263,152 ) Repayments of Loans and Other Notes Payable (1,727 ) (994 ) — — (2,721 ) Proceeds from Senior Notes, net of Discounts and Premiums — — 325,000 — 325,000 Debt Issuance Costs — (8 ) (6,816 ) — (6,824 ) Proceeds from Issuance of Preferred Stock, Net — — 154,988 — 154,988 Proceeds from the Exercise of Stock Options — — 515 — 515 Purchase of Non-Controlling Interests — (1,840 ) — — (1,840 ) Dividends Paid on Preferred Stock — — (2,335 ) — (2,335 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (1,727 ) 2,901 412,352 — 413,526 NET INCREASE (DECREASE) IN CASH 16,592 (391 ) (5 ) — 16,196 CASH – BEGINNING 1,386 504 10 — 1,900 CASH – ENDING $ 17,978 $ 113 $ 5 $ — $ 18,096 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDING DECEMBER 31, 2013 ($ in Thousands) Guarantor Subsidiaries Non- Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss) $ 7,172 $ 2,462 $ (2,130 ) $ (8,077 ) $ (573 ) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities Loss on Equity Method Investments 763 — — — 763 Non-Cash Expenses (194 ) 55 6,369 — 6,230 Depreciation, Depletion, Amortization and Accretion 62,540 1,604 — (200 ) 63,944 Deferred Income Tax Expense (Benefit) 14,409 2,210 (14,340 ) — 2,279 Gain on Derivatives 2,703 — 205 — 2,908 Cash Settlements of Derivatives 7,128 — — — 7,128 Dry Hole Expense 2,993 — — — 2,993 (Gain) Loss on Sale of Asset (5,289 ) (922 ) — — (6,211 ) Impairment Expense 32,072 — — — 32,072 Changes in operating assets and liabilities Accounts Receivable (5,877 ) (6,515 ) 1,241 (1,575 ) (12,726 ) Inventory, Prepaid Expenses and Other Assets (826 ) (59 ) — — (885 ) Accounts Payable and Accrued Liabilities 8,554 874 1,481 1,982 12,891 Other Assets and Liabilities (2,272 ) (88 ) (137 ) — (2,497 ) NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 123,876 (379 ) (7,311 ) (7,870 ) 108,316 CASH FLOWS FROM INVESTING ACTIVITIES Intercompany Loans to Subsidiaries 186,089 1,619 (193,015 ) 5,307 — Proceeds from Joint Venture Acreage Management 458 — — — 458 Contributions to Equity Method Investments (2,493 ) — — — (2,493 ) Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets 8,071 3,234 — — 11,305 Acquisitions of Undeveloped Acreage (41,782 ) (2 ) — — (41,784 ) Capital Expenditures for Development of Oil and Gas Properties and Equipment (275,697 ) (7,870 ) — 2,563 (281,004 ) NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (125,354 ) (3,019 ) (193,015 ) 7,870 (313,518 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-Term Debt and Lines of Credit — 7,249 65,000 — 72,249 Repayments of Long-Term Debt and Lines of Credit — (2,480 ) (6,000 ) — (8,480 ) Repayments of Loans and Other Notes Payable (1,363 ) (642 ) — — (2,005 ) Proceeds from Senior Notes, net of Discounts and Premiums — — 105,000 — 105,000 Debt Issuance Costs — (8 ) (3,126 ) — (3,134 ) Proceeds from the Exercise of Stock Options — — 533 — 533 Purchase of Non-Controlling Interests — (150 ) — — (150 ) Distributions by the Partners of Consolidated Subsidiary — (886 ) — — (886 ) NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (1,363 ) 3,083 161,407 — 163,127 NET INCREASE (DECREASE) IN CASH (2,841 ) (315 ) (38,919 ) — (42,075 ) CASH – BEGINNING 4,227 819 38,929 — 43,975 CASH – ENDING $ 1,386 $ 504 $ 10 $ — $ 1,900
Condensed Consolidating Statements of Operations	REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2016 ($ in Thousands) Guarantor Non-Guarantor Rex Energy Eliminations Consolidated OPERATING REVENUE Oil, Natural Gas and NGL Sales $ 30,463 $ 31 $ — $ — $ 30,494 Other Revenue 13 — — — 13 TOTAL OPERATING REVENUE 30,476 31 — — 30,507 OPERATING EXPENSES Production and Lease Operating Expense 30,121 25 — — 30,146 General and Administrative Expense 6,068 9 (14 ) — 6,063 Gain on Disposal of Asset (30 ) — — — (30 ) Impairment Expense 14,184 — — — 14,184 Exploration Expense 993 — — — 993 Depreciation, Depletion, Amortization and Accretion 19,379 29 — — 19,408 Other Operating Income 329 — — — 329 TOTAL OPERATING EXPENSES 71,044 63 (14 ) — 71,093 INCOME (LOSS) FROM OPERATIONS (40,568 ) (32 ) 14 — (40,586 ) OTHER INCOME (EXPENSE) Interest Expense (273 ) — (12,759 ) — (13,032 ) Gain on Derivatives, Net 4,049 — — — 4,049 Debt Exchange Expense — — (8,480 ) — (8,480 ) Income (Loss) From Equity in Consolidated Subsidiaries (25 ) 25 (38,151 ) 38,151 — TOTAL OTHER INCOME (EXPENSE) 3,751 25 (59,390 ) 38,151 (17,463 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (36,817 ) (7 ) (59,376 ) 38,151 (58,049 ) Income Tax Expense (1,326 ) (1 ) (765 ) — (2,092 ) NET INCOME (LOSS) (38,143 ) (8 ) (60,141 ) 38,151 (60,141 ) Preferred Stock Dividends — — 2,105 — 2,105 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (38,143 ) $ (8 ) $ (62,246 ) $ 38,151 $ (62,246 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2015 ($ in Thousands) Guarantor Non-Guarantor Rex Energy Eliminations Consolidated OPERATING REVENUE Oil, Natural Gas and NGL Sales $ 54,000 $ 111 $ — $ — $ 54,111 Other Revenue 11 — — — 11 TOTAL OPERATING REVENUE 54,011 111 — — 54,122 OPERATING EXPENSES Production and Lease Operating Expense 29,014 38 — — 29,052 General and Administrative Expense 6,659 16 2,976 — 9,651 Loss on Disposal of Asset 65 — — — 65 Impairment Expense 7,012 11 — — 7,023 Exploration Expense 518 — — — 518 Depreciation, Depletion, Amortization and Accretion 26,292 69 — (235 ) 26,126 Other Operating Expense 5,191 — — — 5,191 TOTAL OPERATING EXPENSES 74,751 134 2,976 (235 ) 77,626 INCOME (LOSS) FROM OPERATIONS (20,740 ) (23 ) (2,976 ) 235 (23,504 ) OTHER INCOME (EXPENSE) Interest Expense (58 ) — (11,959 ) — (12,017 ) Gain on Derivatives, Net 16,856 — 263 — 17,119 Other Expense 34 — — — 34 Loss From Equity Method Investments (203 ) — — — (203 ) Income (Loss) From Equity in Consolidated Subsidiaries (23 ) 23 (3,214 ) 3,214 — TOTAL OTHER INCOME (EXPENSE) 16,606 23 (14,910 ) 3,214 4,933 INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (4,134 ) — (17,886 ) 3,449 (18,571 ) Income Tax Benefit 20 — 72 — 92 INCOME (LOSS) FROM CONTINUING OPERATIONS (4,114 ) — (17,814 ) 3,449 (18,479 ) Loss From Discontinued Operations, Net of Income Tax — 2,826 — (864 ) 1,962 Net Income (Loss) (4,114 ) 2,826 (17,814 ) 2,585 (16,517 ) Net Income Attributable to Noncontrolling Interests of Discontinued Operations — 1,297 — — 1,297 NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ (4,114 ) $ 1,529 $ (17,814 ) $ 2,585 $ (17,814 ) Preferred Stock Dividends — — 2,415 — 2,415 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (4,114 ) $ 1,529 $ (20,229 ) $ 2,585 $ (20,229 )	REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2015 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Oil, Natural Gas and NGL Sales $ 171,440 $ 511 $ — $ — $ 171,951 Other Revenue 42 — — — 42 TOTAL OPERATING REVENUE 171,482 511 — — 171,993 OPERATING EXPENSES Production and Lease Operating Expense 118,825 174 — — 118,999 General and Administrative Expense 22,879 52 6,504 — 29,435 Gain on Disposal of Asset (477 ) — — — (477 ) Impairment Expense 345,892 1,396 — (1,513 ) 345,775 Exploration Expense 2,879 137 — (5 ) 3,011 Depreciation, Depletion, Amortization and Accretion 105,556 157 — (969 ) 104,744 Other Operating Expense 5,595 — — — 5,595 TOTAL OPERATING EXPENSES 601,149 1,916 6,504 (2,487 ) 607,082 INCOME (LOSS) FROM OPERATIONS (429,667 ) (1,405 ) (6,504 ) 2,487 (435,089 ) OTHER INCOME (EXPENSE) Interest Expense (271 ) — (47,535 ) — (47,806 ) Gain on Derivatives, Net 59,242 — 934 — 60,176 Other Expense (115 ) — — — (115 ) Loss From Equity Method Investments (411 ) — — — (411 ) Income (Loss) From Equity in Consolidated Subsidiaries (1,324 ) 1,324 (313,198 ) 313,198 — TOTAL OTHER INCOME (EXPENSE) 57,121 1,324 (359,799 ) 313,198 11,844 INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (372,546 ) (81 ) (366,303 ) 315,685 (423,245 ) Income Tax Benefit 21,122 81 3,024 — 24,227 NET INCOME (LOSS) FROM CONTINUING OPERATIONS (351,424 ) — (363,279 ) 315,685 (399,018 ) Income (Loss) From Discontinued Operations, Net of Income Tax — 3,908 35,269 (1,192 ) 37,985 NET INCOME (LOSS) (351,424 ) 3,908 (328,010 ) 314,493 (361,033 ) Net Income Attributable to Noncontrolling Interests of Discontinued Operations — 2,245 — — 2,245 NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ (351,424 ) $ 1,663 $ (328,010 ) $ 314,493 $ (363,278 ) Preferred Stock Dividends — — 9,660 — 9,660 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (351,424 ) $ 1,663 $ (337,670 ) $ 314,493 $ (372,938 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2014 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Issuer) Eliminations Consolidated Balance OPERATING REVENUE Oil, Natural Gas and NGL Sales $ 297,710 $ 159 $ — $ — $ 297,869 Other Revenue 118 — — — 118 TOTAL OPERATING REVENUE 297,828 159 — — 297,987 OPERATING EXPENSES Production and Lease Operating Expense 100,261 21 — — 100,282 General and Administrative Expense 30,317 83 5,737 — 36,137 Loss on Disposal of Asset 644 — — — 644 Impairment Expense 126,662 5,956 — — 132,618 Exploration Expense 9,165 281 — — 9,446 Depreciation, Depletion, Amortization and Accretion 94,643 513 — (689 ) 94,467 Other Operating Expense 134 — — — 134 TOTAL OPERATING EXPENSES 361,826 6,854 5,737 (689 ) 373,728 INCOME (LOSS) FROM OPERATIONS (63,998 ) (6,695 ) (5,737 ) 689 (75,741 ) OTHER INCOME (EXPENSE) Interest Expense (142 ) — (36,835 ) — (36,977 ) Gain on Derivatives, Net 37,359 — 1,517 — 38,876 Other Income (Expense) 90 — — — 90 Loss From Equity Method Investments (813 ) — — — (813 ) Income (Loss) From Equity in Consolidated Subsidiaries (4,278 ) 4,278 (20,204 ) 20,204 — TOTAL OTHER INCOME (EXPENSE) 32,216 4,278 (55,522 ) 20,204 1,176 INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (31,782 ) (2,417 ) (61,259 ) 20,893 (74,565 ) Income Tax (Expense) Benefit 9,928 2,417 14,570 — 26,915 NET INCOME (LOSS) FROM CONTINUING OPERATIONS (21,854 ) — (46,689 ) 20,893 (47,650 ) Income From Discontinued Operations, Net of Income Taxes — 9,330 — (4,330 ) 5,000 NET INCOME (LOSS) (21,854 ) 9,330 (46,689 ) 16,563 (42,650 ) Net Income Attributable to Noncontrolling Interests of Discontinued Operations — 4,039 — — 4,039 NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ (21,854 ) $ 5,291 $ (46,689 ) $ 16,563 $ (46,689 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2013 ($ in Thousands) Guarantor Subsidiaries Non-Guarantor Subsidiaries Rex Energy Corporation (Note Eliminations Consolidated Balance OPERATING REVENUE Oil, Natural Gas and NGL Sales $ 213,919 $ — $ — $ — $ 213,919 Other Revenue 200 — — — 200 TOTAL OPERATING REVENUE 214,119 — — — 214,119 OPERATING EXPENSES Production and Lease Operating Expense 62,138 12 — — 62,150 General and Administrative Expense 25,376 43 5,420 — 30,839 Loss on Disposal of Asset 1,601 1 — — 1,602 Impairment Expense 32,072 — — — 32,072 Exploration Expense 11,395 13 — — 11,408 Depreciation, Depletion, Amortization and Accretion 62,540 46 — (200 ) 62,386 Other Operating Expense 592 — — — 592 TOTAL OPERATING EXPENSES 195,714 115 5,420 (200 ) 201,049 INCOME (LOSS) FROM OPERATIONS 18,405 (115 ) (5,420 ) 200 13,070 OTHER INCOME (EXPENSE) Interest Expense (64 ) — (22,612 ) — (22,676 ) Gain on Derivatives, Net (2,703 ) — (205 ) — (2,908 ) Other Income (Expense) 6,739 — — — 6,739 Loss From Equity Method Investments (763 ) — — — (763 ) Income (Loss) From Equity in Consolidated Subsidiaries (33 ) 33 5,703 (5,703 ) — TOTAL OTHER INCOME (EXPENSE) 3,176 33 (17,114 ) (5,703 ) (19,608 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX 21,581 (82 ) (22,534 ) (5,503 ) (6,538 ) Income Tax (Expense) Benefit (14,409 ) (1,841 ) 20,404 — 4,154 NET INCOME (LOSS) FROM CONTINUING OPERATIONS 7,172 (1,923 ) (2,130 ) (5,503 ) (2,384 ) Income From Discontinued Operations, Net of Income Taxes — 4,385 — (2,574 ) 1,811 NET INCOME (LOSS) 7,172 2,462 (2,130 ) (8,077 ) (573 ) Net Income Attributable to Noncontrolling Interests of Discontinued Operations — 1,557 — — 1,557 NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY $ 7,172 $ 905 $ (2,130 ) $ (8,077 ) $ (2,130 )

Business and Oil and Gas Prop47

Business and Oil and Gas Property Acquisitions and Dispositions (Tables)	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Summary of Acquisition Price Allocated	The acquisition does not meet the definition of a business combination and, therefore, has been accounted for as an asset acquisition. The acquisition price was allocated as follows: ($ in Thousands) December 31, 2014 Evaluated Oil and Gas Properties $ 6,968 Unevaluated Oil and Gas Properties 88,351 Wells and Facilities in Progress 25,244 Purchase Price $ 120,563

Suspended Exploratory Well Co48

Suspended Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Net Change in Capitalized Exploratory Well Costs	The following table reflects the net change in capitalized exploratory well costs, excluding those related to Assets Held for Sale on our Consolidated Balance Sheets for the years ended December 31, 2015, 2014 and 2013 ($ in thousands): 2015 2014 2013 Beginning Balance at January 1, $ 23,101 $ 5,731 $ 36,968 Additions to capitalized exploratory well costs pending the determination of estimated proved reserves 144,954 258,097 171,087 Divested wells — — — Reclassification of wells, facilities, and equipment based on the determination of estimated proved reserves (147,850 ) (240,494 ) (202,323 ) Capitalized exploratory well costs charged to expense (2,907 ) (233 ) (1 ) Ending Balance at December 31, 17,298 23,101 5,731 Less exploratory well costs that have been capitalized for a period of one year or less (12,156 ) (20,407 ) (3,597 ) Capitalized exploratory well costs for a period of greater than one year $ 5,142 $ 2,694 $ 2,134 Number of projects that have exploratory well costs capitalized for a period of more than one year 14 6 3

Costs Incurred In Oil And Nat49

Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities (Tables)	12 Months Ended
	Dec. 31, 2015
Text Block [Abstract]
Costs Incurred in Oil and Natural Gas Property Acquisitions and Development	Costs incurred in oil and natural gas property acquisitions and development are presented below and exclude any costs incurred related to Assets Held for Sale (in thousands): 2015 2014 2013 Consolidated Entities: Acquisition of Properties Proved $ 1 $ 161 $ 2,445 Unproved 28,242 169,408 39,291 Exploration Costs(a) 158,318 316,235 231,112 Development Costs(a) 31,574 71,383 64,661 Subtotal 218,135 557,187 337,509 Asset Retirement Obligations 2,818 9,110 3,031 Total Costs Incurred $ 220,953 $ 566,297 $ 340,540 Share of Equity Method Investments: Acquisition of Properties Proved $ — $ — $ — Unproved — — — Exploration Costs — — — Development Costs(a) 824 438 1,958 Total $ 824 $ 438 $ 1,958 (a) Includes Depreciation expense for support equipment and facilities
Reconciliation of Total Costs Incurred for Consolidated Entities to Reported Capital Expenditures	The following table provides a reconciliation of the total costs incurred for our consolidated entities to our reported capital expenditures (in thousands): 2015 2014 2013 Total Costs Incurred by Consolidated Entities $ 220,953 $ 566,297 $ 340,540 Equity Method Investments — — 2,493 DJ Basin Expenditures — — 2 Exploration Expense (3,011 ) (9,446 ) (11,408 ) Asset Retirement Obligations (2,818 ) (9,110 ) (3,031 ) Depreciation for Support Equipment and Facilities (4,905 ) (6,075 ) (5,024 ) Corporate Expenditures 231 869 3,651 Other(a) (16,522 ) 7,223 10,391 Total Capital Expenditures $ 193,928 $ 549,758 $ 337,614 (a) Represents R.E. Disposal, LLC capital, future proceeds from ArcLight and intercompany capital transactions.

Oil And Natural Gas Capitaliz50

Oil And Natural Gas Capitalized Costs (Tables)	12 Months Ended
	Dec. 31, 2015
Text Block [Abstract]
Capitalized Costs for Natural Gas and Oil Production Activities	Our aggregate capitalized costs for natural gas and oil production activities with applicable accumulated depreciation, depletion and amortization are presented below and exclude any properties classified as Assets Held for Sale (in thousands): 2015 2014 Consolidated Entities: Proven Oil and Natural Gas Properties $ 1,239,430 $ 1,079,039 Pipelines and Support Equipment 17,030 24,248 Field Operation Vehicles and Other Equipment 28,064 27,030 Wells and Facilities in Progress 144,408 127,597 Unproven Properties 262,992 322,413 Total 1,691,924 1,580,327 Less Accumulated Depreciation and Depletion (696,447 ) (362,804 ) Total $ 995,477 $ 1,217,523 Share of Equity Method Investments: Pipelines and Support Equipment 19,970 19,946 Wells and Facilities in Progress — — Total 19,970 19,946 Less Accumulated Depreciation and Depletion (3,411 ) (2,611 ) Total $ 16,559 $ 17,335

Oil and Natural Gas Reserve Q51

Oil and Natural Gas Reserve Quantities (Tables)	12 Months Ended
	Dec. 31, 2015
Text Block [Abstract]
Summary of Changes in Estimated Reserves of Oil and Natural Gas Wells	Presented below is a summary of changes in estimated reserves of the oil and natural gas wells at December 31, 2015, 2014 and 2013: 2015 Oil NGL Natural Gas (MMcf) (MMcf) Equivalents Estimated Proved Reserves-Beginning of Period 9,684.7 73,252.5 839,185.1 1,336,808.3 Extensions, Discoveries and Additions 949.0 10,079.3 76,816.9 142,986.7 Revisions of Previous Estimates (4,176.8 ) (38,249.7 ) (448,461.3 ) (703,020.3 ) Purchases (7.7 ) (1,389.6 ) (16,471.1 ) (24,854.9 ) Production (1,132.1 ) (3,345.9 ) (44,606.8 ) (71,474.8 ) Estimated Proved Reserves-End of Period 5,317.1 40,346.6 406,462.8 680,445.0 2014 Oil NGL Natural (MMcf) (MMcf) Equivalents Estimated Proved Reserves-Beginning of Period 8,619.6 46,130.7 521,282.8 849,784.6 Extensions, Discoveries and Additions 1,723.1 31,160.3 326,464.2 523,764.6 Revisions of Previous Estimates 471.1 (2,889.1 ) 9,971.0 (4,537.0 ) Purchases 12.0 933.0 18,478.3 24,148.3 Production (1,141.1 ) (2,082.4 ) (37,011.2 ) (56,352.2 ) Estimated Proved Reserves-End of Period 9,684.7 73,252.5 839,185.1 1,336,808.3 2013 Oil NGL Natural (MMcf) (MMcf) Equivalents Estimated Proved Reserves-Beginning of Period 9,375.7 31,679.9 371,716.4 618,050.0 Extensions, Discoveries and Additions 595.6 19,956.1 189,150.9 312,461.1 Revisions of Previous Estimates (438.5 ) (4,685.6 ) (16,137.7 ) (46,882.3 ) Purchases 1.0 — — 6.0 Production (914.2 ) (819.7 ) (23,446.8 ) (33,850.2 ) Estimated Proved Reserves-End of Period 8,619.6 46,130.7 521,282.8 849,784.6 Oil NGL Natural (MMcf) (MMcf) Equivalents Proved Developed Reserves December 31, 2015 4,944.6 37,941.9 389,754.4 647,073.4 December 31, 2014 7,628.1 29,215.0 365,673.3 586,731.9 December 31, 2013 7,742.5 16,322.5 212,061.4 356,451.4 Proved Undeveloped Reserves December 31, 2015 372.5 2,404.7 16,708.4 33,371.6 December 31, 2014 2,056.6 44,037.5 473,511.8 750,076.4 December 31, 2013 877.1 29,808.2 309,221.4 493,333.2

Standardized Measure Of Disco52

Standardized Measure Of Discounted Future Net Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2015
Text Block [Abstract]
Summary of Future Net Cash Flows Relating to Prove Oil and Natural Gas Reserves	The following summary sets forth our future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by FASB ASC 932 at December 31, 2015, 2014 and 2013 ($ in thousands): 2015 2014 2013 Future Cash Inflows $ 1,716,131 (a) $ 5,824,231 (b) $ 3,899,878 (c) Future Costs: Production (1,144,049 ) (2,332,151 ) (1,619,629 ) Abandonment (143,459 ) (134,308 ) (95,183 ) Development (18,952 ) (686,676 ) (517,875 ) Net Future Cash Inflow Before Income Taxes 409,671 2,671,096 1,667,191 Future Income Tax Expense — (468,597 ) (359,322 ) Total Future Net Cash Flows Before 10.0% Discount 409,671 2,202,499 1,307,869 Less: Effect of 10.0% Discount Factor (154,048 ) (1,177,135 ) (778,756 ) Standardized Measure of Discounted Future Net Cash Flows $ 255,623 $ 1,025,364 $ 529,113 (a) Calculated using weighted average prices of $2.401 per Mcf, $44.45 per barrel of oil and $12.48 per barrel of NGLs (b) Calculated using weighted average prices of $3.455 per Mcf, $88.02 per barrel of oil and $28.30 per barrel of NGLs (c) Calculated using weighted average prices of $3.588 per Mcf, $94.28 per barrel of oil and $26.37 per barrel of NGLs
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flows	The principal sources of change in the standardized measure of discounted future net cash flows are as follows: 2015 2014 2013 Standardized Measure – Beginning of Period $ 1,025,364 $ 529,113 $ 396,123 Revisions of Previous Estimates: Changes in Prices and Production Costs (1,296,866 ) 253,865 72,503 Revisions in Quantities (270,673 ) (5,970 ) (51,289 ) Changes in Future Development Costs 595,547 (51,794 ) 22,341 Accretion of Discount and Timing of Future Cash Flows 116,514 64,013 47,571 Net Change in Income Tax 139,776 28,756 31,433 Purchase (Sale) of Reserves in Place (37,101 ) 28,316 — Plus Extensions, Discoveries, and Other Additions 88,152 430,252 170,846 Development Costs Incurred 31,574 71,383 64,661 Sales of Product – Net of Production Costs (52,952 ) (197,587 ) (151,781 ) Changes in Timing and Other (83,712 ) (124,983 ) (73,295 ) Standardized Measure – End of Period $ 255,623 $ 1,025,364 $ 529,113

Results of Operations for Oil53

Results of Operations for Oil and Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2015
Text Block [Abstract]
Results of Operations	Results of operations are equal to revenues, less (a) production costs, (b) impairment expenses, (c) exploration expenses, (d) DD&A expenses, and (e) income tax expense (benefit) (certain prior year amounts have been reclassified to conform to current presentation): 2015 2014 2013 Consolidated Entities (in thousands): Revenues Oil and Natural Gas Sales $ 171,951 $ 297,869 $ 213,919 Expenses Production and Lease Operating Expense 118,999 100,282 62,150 Impairment Expense 345,775 132,618 32,072 Exploration Expense 3,011 9,446 11,408 Depletion, Depreciation, Amortization and Accretion 104,744 94,467 62,386 Total Costs 572,529 336,813 168,016 Pre-Tax Operating Income (Loss) (400,578 ) (38,944 ) 45,903 Income Tax (Expense) Benefit(a) 22,833 14,059 (29,148 ) Results of Operations for Oil and Gas Producing Activities $ (377,745 ) $ (24,885 ) $ 16,755 Share of Equity Method Investments (in thousands): Expenses Depletion, Depreciation, Amortization and Accretion $ 812 $ 805 $ 752 Total Costs 812 805 752 Pre-Tax Operating Loss (812 ) (805 ) (752 ) Income Tax Benefit (a) 46 291 478 Results of Operations for Oil and Gas Producing Activities $ (766 ) $ (514 ) $ (274 ) Total Consolidated and Equity Method Investees Results of Operations for Oil and Gas Producing Activities $ (378,511 ) $ (25,399 ) $ 16,481 (a) Computed using the effective rate for continuing operations for each period: 5.7% in 2015; 36.1% in 2014 and; 63.5% in 2013.

Selected Quarterly Financial 54

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Unaudited Financial Information on Quarterly Basis	The following tables set forth unaudited financial information on a quarterly basis for each of the last two years. REX ENERGY CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS ($ and Shares in Thousands Except per Share Data) 2015 March June September December Revenues $ 54,122 $ 45,772 $ 37,573 $ 34,526 Impairment Expense 7,023 117,842 139,812 81,098 Other Costs and Expenses 65,578 81,303 27,054 51,301 Net Loss From Continuing Operations (18,479 ) (153,373 ) (129,293 ) (97,873 ) Net Income (Loss) From Discontinued Operations, Net of Income Taxes 1,962 1,570 34,617 (164 ) Net Loss (16,517 ) (151,803 ) (94,676 ) (98,037 ) Net Income (Loss) Attributable to Noncontrolling Interests 1,297 949 (1 ) — Net Loss Attributable to Rex Energy (17,814 ) (152,752 ) (94,675 ) (98,037 ) Preferred Stock Dividends 2,415 2,415 2,415 2,415 Net Loss Attributable to Common Shareholders $ (20,229 ) $ (155,167 ) $ (97,090 ) $ (100,452 ) Income (Loss) per Common Share Attributable to Rex Energy Common Shareholders: Basic – Continuing Operations $ (0.38 ) $ (2.88 ) $ (2.44 ) $ (1.85 ) Basic – Discontinued Operations 0.01 0.01 0.64 — Basic – Net Loss $ (0.37 ) $ (2.87 ) $ (1.80 ) $ (1.85 ) Basic – Weighted Average Shares Outstanding 54,370 54,118 53,936 54,342 Diluted – Continuing Operations $ (0.38 ) $ (2.88 ) $ (2.44 ) $ (1.85 ) Diluted – Discontinued Operations 0.01 0.01 0.64 — Diluted – Net Loss $ (0.37 ) $ (2.87 ) $ (1.80 ) $ (1.85 ) Diluted – Weighted Average Shares Outstanding 54,370 54,118 53,936 54,342 2014 March June September December Revenues $ 81,343 $ 72,933 $ 73,466 $ 70,245 Impairment Expense 25 16 1 132,576 Other Costs and Expenses 72,562 65,274 67,846 7,337 Net Income (Loss) From Continuing Operations 8,756 7,643 5,619 (69,668 ) Net Income From Discontinued Operations, Net of Income Taxes 1,681 1,312 970 1,037 Net Income (Loss) 10,437 8,955 6,589 (68,631 ) Net Income Attributable to Noncontrolling Interests 1,569 877 895 698 Net Income (Loss) Attributable to Rex Energy $ 8,868 $ 8,078 $ 5,694 $ (69,329 ) Preferred Stock Dividends — — — 2,335 Net Income (Loss) Attributable to Common Shareholders $ 8,868 $ 8,078 $ 5,694 $ (71,664 ) Income (Loss) per Common Share Attributable to Rex Energy Common Shareholders: Basic – Continuing Operations $ 0.17 $ 0.14 $ 0.11 $ (1.35 ) Basic – Discontinued Operations — 0.01 — — Basic – Net Income (Loss) $ 0.17 $ 0.15 $ 0.11 $ (1.35 ) Basic – Weighted Average Shares Outstanding 52,984 53,164 53,214 53,261 Diluted – Continuing Operations $ 0.17 $ 0.14 $ 0.10 $ (1.35 ) Diluted – Discontinued Operations — 0.01 — — Diluted – Net Income (Loss) $ 0.17 $ 0.15 $ 0.10 $ (1.35 ) Diluted – Weighted Average Shares Outstanding 53,503 53,509 57,991 53,261

Basis of Presentation and Pri55

Basis of Presentation and Principles of Consolidation - Additional Information (Detail) - USD ($)		Dec. 12, 2012	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jul. 17, 2014
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Senior secured line of credit and long term debt, net issuance costs			$ 143,294,000	$ 109,396,000	$ 251,000
Senior notes, net of issuance costs	[1]		$ 657,511,000	663,089,000
Long-term tax assets				12,532,000	8,301,000
Current deferred tax liability				12,532,000	8,301,000
8.875% Senior Notes
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Senior notes, net of issuance costs				$ 350,000,000	$ 350,000,000
Interest rate		8.875%	8.875%	8.875%	8.875%
Debt instrument maturity date		Dec. 1, 2020	Dec. 1, 2020	Dec. 1, 2020	Dec. 1, 2020
6.25% Senior Notes
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Senior notes, net of issuance costs				$ 325,000,000	$ 325,000,000
Interest rate			6.25%	6.25%	6.25%	6.25%
Debt instrument maturity date			Aug. 1, 2022	Dec. 1, 2022	Dec. 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
Water Solutions Holdings, LLC
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Ownership percentage by parent					60.00%
[1]	Includes unamortized debt issuance costs of approximately $11.1 million and $11.9 million as of March 31, 2016 and December 31, 2015, respectively.

Future Abandonment Cost - Addit

Future Abandonment Cost - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
Accretion expense	$ 856	$ 900	$ 3,821	$ 3,621	$ 3,000

Future Abandonment Cost (Detail

Future Abandonment Cost (Detail) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Mar. 31, 2016		Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
Beginning Balance	$ 45,074		$ 40,099	$ 40,099	$ 28,525
Future Abandonment Obligation Incurred	402			1,135	1,480
Future Abandonment Obligation Settled	(361)			(2,273)	(1,943)
Future Abandonment Obligation Cancelled or Sold	(189)			(136)	(10)
Future Abandonment Obligation Accretion Expense	856		$ 900	3,821	3,621	$ 3,000
Total Future Abandonment Cost	$ 45,782	[1]		$ 45,074	$ 40,099	$ 28,525
[1]	Includes approximately $2.4 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) (Detail) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligations [Line Items]
Accrued Liabilities	$ 44,296	$ 44,326	$ 59,478
Remediation Property for Sale, Abandonment or Disposal
Asset Retirement Obligations [Line Items]
Accrued Liabilities	$ 2,400

Discontinued Operations_ Assets

Discontinued Operations/ Assets Held for Sale - Additional Information (Detail) - USD ($) $ in Thousands	Jul. 31, 2015	Jul. 31, 2015	Mar. 31, 2015	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jun. 30, 2015
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gain on asset held for sale	$ 66,800	$ 66,800
Gain classified as other (income) expense			$ (34)			$ 115	$ (90)	$ (6,739)
D J Basin
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gain on asset held for sale				$ 1,000
Sale of the remaining DJ Basin assets					$ 3,100
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%
Capital expenditures on facilities and equipment						8,600
Capital lease obligations incurred						1,000
Water Solutions Holdings, LLC | Discontinued Operations Assets Held For Sale
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gain classified as other (income) expense	(57,800)	(57,800)	$ 103			$ (57,589)	$ 66	$ 84
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	$ 130,000							$ 130,000

Summary of Financial Informatio

Summary of Financial Information for Discontinued Operations (Detail) bbl in Thousands, $ in Thousands	Jul. 31, 2015USD ($)	Jul. 31, 2015USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)bbl
Revenues:
Oil, Natural Gas and NGL Sales			$ 30,494				$ 54,111					$ 171,951	$ 297,869	$ 213,919
TOTAL OPERATING REVENUE			30,507	$ 34,526	$ 37,573	$ 45,772	54,122	$ 70,245	$ 73,466	$ 72,933	$ 81,343	171,993	297,987	214,119
Costs and Expenses:
Production and Lease Operating Expense			30,146				29,052					118,999	100,282	62,150
General and Administrative Expense			6,063				9,651					29,435	36,137	30,839
Depreciation, Depletion, Amortization and Accretion			19,408				26,126					104,744	94,467	62,386
Exploration Expense			993				518					3,011	9,446	11,408
Impairment Expense			14,184	$ 81,098	$ 139,812	$ 117,842	7,023	$ 132,576	$ 1	$ 16	$ 25	345,775	132,618	32,072
Other Operating Income			329				5,191					5,595	134	592
(Gain) Loss on Disposal of Asset			(30)				65					(477)	644	1,602
Interest Expense			$ 13,032				12,017					47,806	36,977	22,676
Other (Income) Expense							(34)					115	(90)	(6,739)
Income (Loss) from Discontinued Operations, net of taxes							1,962					37,985	5,000	1,811
Discontinued Operations Assets Held For Sale
Revenues:
Oil, Natural Gas and NGL Sales														25
TOTAL OPERATING REVENUE														25
Costs and Expenses:
Production and Lease Operating Expense														104
General and Administrative Expense														23
Exploration Expense														97
Other Operating Income														(3)
(Gain) Loss on Disposal of Asset														(969)
Total Costs and Expenses														(748)
Income from Discontinued Operations Before Income Taxes														773
Income Tax Expense														(1,005)
Income (Loss) from Discontinued Operations, net of taxes														(232)
Discontinued Operations Assets Held For Sale | Water Solutions Holdings, LLC
Revenues:
Field Services Revenue							14,964					33,086	58,627	23,812
TOTAL OPERATING REVENUE							14,964					33,086	58,627	23,812
Costs and Expenses:
General and Administrative Expense							977					1,961	4,081	2,287
Depreciation, Depletion, Amortization and Accretion							39					78	3,703	1,559
Impairment Expense													67
Field Service Operating Expense							11,289					25,981	44,369	17,318
(Gain) Loss on Disposal of Asset							(32)					(44)	(55)	46
Interest Expense							191					487	628	106
Other (Income) Expense	$ (57,800)	$ (57,800)					103					(57,589)	66	84
Total Costs and Expenses							12,567					(29,126)	52,859	21,400
Income from Discontinued Operations Before Income Taxes							2,397					62,212	5,768	2,412
Income Tax Expense							(435)					(24,227)	(768)	(369)
Income (Loss) from Discontinued Operations, net of taxes							$ 1,962					$ 37,985	$ 5,000	$ 2,043
Discontinued Operations Assets Held For Sale | Crude Oil
Production:
Production Units | bbl														356

Business and Oil and Gas Prop61

Business and Oil and Gas Property Acquisitions and Dispositions - Additional Information (Detail) a in Thousands, $ in Thousands	Mar. 01, 2016USD ($)Well	Jul. 31, 2015USD ($)	Mar. 31, 2015USD ($)	May. 29, 2012USD ($)	Apr. 30, 2016Well	Jul. 31, 2015USD ($)	Sep. 30, 2014USD ($)a	Mar. 31, 2016USD ($)Well	Mar. 31, 2015USD ($)Well	Sep. 30, 2012USD ($)	Dec. 31, 2015USD ($)Well	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2012USD ($)	Jun. 30, 2015USD ($)
Business Acquisition And Dispositions [Line Items]
Payments for interest in wells that have been drilled or in process of being drilled								$ 15,068	$ 67,013		$ 221,099	$ 391,422	$ 281,004
Gain on asset held for sale		$ 66,800				$ 66,800
Gain classified as other (income) expense									$ 34		(115)	$ 90	6,739
Acres prospective for Marcellus, Upper Devonian/Burkett and Utica Shales
Business Acquisition And Dispositions [Line Items]
Oil and Gas property acquired, gross area | a							208
Oil and Gas property acquired, net area | a							207
Cash paid to acquire oil and gas property							$ 120,600
Keystone Midstream Services
Business Acquisition And Dispositions [Line Items]
Base consideration for sale				$ 483,200
Proceeds from sale of equity method investment				121,400						$ 120,900
Gain (loss) on equity method investments				99,400
Cash held in escrow and paid out over the next 12 months				14,300
Proceeds from escrow amount													6,900	$ 7,200
Funds by other sellers in transaction													3,800
Water Solutions Holdings, LLC
Business Acquisition And Dispositions [Line Items]
Ownership percentage by parent												60.00%
American Water Works Company, Inc.
Business Acquisition And Dispositions [Line Items]
Aggregate consideration of Water Solutions		130,000				130,000									$ 130,000
Arc Light Capital Partners Limited Liability Corporation
Business Acquisition And Dispositions [Line Items]
Percentage of estimated well costs			35.00%						35.00%
Consideration for the transaction			$ 67,000						$ 67,000
Amount received at closing of wells			$ 16,600						$ 16,600
Payments for interest in wells that have been drilled or in process of being drilled								$ 52,200			39,800
Percentage of working interest attained through return on investment and internal rate of return			50.00%						50.00%
Percentage of working interest			35.00%						35.00%
Percentage of remaining working interest			17.50%						17.50%
Number of drilled and completed wells to be placed into service | Well								4
Benefit Street Partners Limited Liability Corporation
Business Acquisition And Dispositions [Line Items]
Consideration for the transaction	$ 175,000
Amount received at closing of wells	37,100
Payments for interest in wells that have been drilled or in process of being drilled	$ 19,500
Percentage of working interest	65.00%
Number of wells in which BSP Options to Participate in development | Well								36
Number of producing wells | Well								15
Number of drilled well that is awaiting completion | Well								3
Number of wells awaiting pipeline connection | Well								4
Minimum | Benefit Street Partners Limited Liability Corporation
Business Acquisition And Dispositions [Line Items]
Percentage of working interest earned in acreage	15.00%
Maximum | Benefit Street Partners Limited Liability Corporation
Business Acquisition And Dispositions [Line Items]
Percentage of working interest earned in acreage	20.00%
Subsequent Event | Benefit Street Partners Limited Liability Corporation
Business Acquisition And Dispositions [Line Items]
Number of wells to be drilled and completed in later period | Well					4
Discontinued Operations Assets Held For Sale | Water Solutions Holdings, LLC
Business Acquisition And Dispositions [Line Items]
Gain classified as other (income) expense		$ 57,800				$ 57,800			$ (103)		$ 57,589	$ (66)	$ (84)
Butler County, Pennsylvania
Business Acquisition And Dispositions [Line Items]
Number of drilled well that is awaiting completion | Well											1
Butler County, Pennsylvania | Arc Light Capital Partners Limited Liability Corporation
Business Acquisition And Dispositions [Line Items]
Number of specifically designated wells for development | Well									32
Butler County, Pennsylvania | Benefit Street Partners Limited Liability Corporation
Business Acquisition And Dispositions [Line Items]
Percentage of estimated well costs	15.00%
Number of drilled and completed wells to be placed into service | Well								12
Number of specifically designated wells for development | Well	16
Moraine East And Warrior North | Benefit Street Partners Limited Liability Corporation
Business Acquisition And Dispositions [Line Items]
Number of specifically designated wells for development | Well	58
Warrior North Ohio [Member] | Benefit Street Partners Limited Liability Corporation
Business Acquisition And Dispositions [Line Items]
Percentage of estimated well costs	65.00%
Number of drilled and completed wells to be placed into service | Well								3
Number of specifically designated wells for development | Well	6
Transaction Cost [Member] | Keystone Midstream Services
Business Acquisition And Dispositions [Line Items]
Gain (loss) on equity method investments				$ 3,300
Post Closing Settlement Charges [Member] | Keystone Midstream Services
Business Acquisition And Dispositions [Line Items]
Gain (loss) on equity method investments										$ 500

Recently Issued Accounting Pr62

Recently Issued Accounting Pronouncements - Additional Information (Detail) - USD ($)		Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Senior secured line of credit and long term debt, net issuance costs		$ 143,294,000	$ 109,396,000	$ 251,000
Senior notes, net of issuance costs	[1]	$ 657,511,000	663,089,000
Long-term deferred tax assets			12,532,000	8,301,000
Current deferred tax liability			12,532,000	$ 8,301,000
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
Accounting Standards Update201517
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 $11.1 million and $11.9 million as of March 31, 2016 and December 31, 2015, respectively.

Concentrations of Credit Risk -

Concentrations of Credit Risk - Additional Information (Detail)	3 Months Ended	12 Months Ended
	Mar. 31, 2016USD ($)Customer	Dec. 31, 2015USD ($)EntityCustomer	Dec. 31, 2014USD ($)Customer	Dec. 31, 2013Customer
Number of major customers | Customer		4	4
Federal Deposit Insurance Corporation's limit for cash balances | $		$ 250,000	$ 250,000
Number of Counterparties | Entity		5
Accounts Receivable | $	$ 24,315,000	$ 19,483,000	$ 43,936,000
Number of major customers | Customer		4	4
Oil And Gas Production
Accounts Receivable | $		$ 12,100,000	$ 25,200,000
Oil And Gas Production | Four Purchasers [Member]
Accounts Receivable | $		$ 10,500,000	$ 21,400,000
Sales
Number of major customers | Customer		4	4	4
Sales | Purchaser | Customer Concentration Risk
Percentage of revenue from major customers	93.50%
Number of major customers | Customer	5
Sales | Largest single purchaser | Customer Concentration Risk
Percentage of revenue from major customers	46.00%	42.20%	32.40%	34.50%

Long-Term Debt - Senior Credit

Long-Term Debt - Senior Credit Facility - Additional Information (Detail) - USD ($)	Apr. 01, 2016	Mar. 14, 2016	Feb. 03, 2016	Mar. 31, 2016	Dec. 31, 2015		Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Mar. 27, 2013
Debt Instrument [Line Items]
Line of credit facility, amount outstanding				$ 158,000,000	$ 111,500,000	[1]
Cash and Cash Equivalents				24,891,000	$ 1,091,000		$ 4,964,000	$ 17,978,000	$ 1,307,000
Effective rate					0.50%
Additional percentage with LIBOR					1.00%
Minimum
Debt Instrument [Line Items]
Net senior secured debt to EBITDAX		275.00%
Margin rate			2.25%		1.50%
Liens covering the oil and gas properties, percentage		90.00%
Percentage of senior notes exchanged for new notes.		80.00%
Maximum
Debt Instrument [Line Items]
Margin rate			3.25%		2.50%
Liens covering the oil and gas properties, percentage		95.00%
Moraine East And Warrior North
Debt Instrument [Line Items]
Liens covering the oil and gas properties, percentage		100.00%
Letter Of Credit
Debt Instrument [Line Items]
Line of credit facility, remaining borrowing capacity				41,000,000	$ 41,000,000
Senior Credit Facility
Debt Instrument [Line Items]
Line of credit facility, current borrowing capacity				200,000,000	350,000,000
Line of credit facility, maximum borrowing capacity			$ 200,000,000	200,000,000	$ 350,000,000
Line of credit facility, amount outstanding				158,000,000
Line of credit facility, remaining borrowing capacity				$ 1,000,000
Line of credit facility, maturity date				Sep. 12, 2019	Sep. 12, 2019
Current ratio				60.00%	230.00%
LIBOR rate description					The applicable per annum margin, in the case of loans bearing interest at the Adjusted LIBO Rate, ranges from 225 to 325 basis points, and in the case of loans bearing interest at the Alternate Base Rate, ranges from 125 to 225 basis points, in each case, determined based upon our borrowing base utilization at such date of determination.
Percentage of reasonably anticipated projected production					85.00%
Liens covering the oil and gas properties, percentage		95.00%
Senior Credit Facility | Minimum
Debt Instrument [Line Items]
Criteria Current ratio				100.00%	100.00%
Net senior secured debt to EBITDAX				210.00%	170.00%
Percentage of purchase price of reserves for which interim borrowing base re-determinations may be requested										10.00%
Senior Credit Facility | Maximum
Debt Instrument [Line Items]
Cash and Cash Equivalents				$ 15,000,000
Criteria of net senior secured debt to EBITDAX		300.00%		275.00%	300.00%
Duration of developed producing reserve					36 months
Outstanding principal amount of debt for borrowed money, percentage					75.00%
Senior Credit Facility | Maximum | Crude Oil
Debt Instrument [Line Items]
Percentage of reasonably anticipated projected production					75.00%
Senior Credit Facility | Maximum | Natural Gas
Debt Instrument [Line Items]
Percentage of reasonably anticipated projected production					75.00%
Senior Credit Facility | Moraine East And Warrior North
Debt Instrument [Line Items]
Liens covering the oil and gas properties, percentage		100.00%
Senior Credit Facility | Interest Rate Swap | Maximum
Debt Instrument [Line Items]
Notional amounts of interest rate swap					$ 20,000,000
Senior Credit Facility | LIBOR | Minimum
Debt Instrument [Line Items]
Margin rate					2.25%
Senior Credit Facility | LIBOR | Maximum
Debt Instrument [Line Items]
Margin rate					3.25%
Senior Credit Facility | Alternate Base Rate [Member] | Minimum
Debt Instrument [Line Items]
Margin rate					1.25%
Senior Credit Facility | Alternate Base Rate [Member] | Maximum
Debt Instrument [Line Items]
Margin rate					2.25%
Senior Credit Facility | Scenario, Forecast [Member]
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 190,000,000
Line of credit facility, effective date	Apr. 1, 2016
Senior Credit Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity				$ 500,000,000	$ 500,000,000
Senior Credit Facility | Letter Of Credit
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity				60,000,000	$ 60,000,000
Line of credit facility, remaining borrowing capacity				$ 41,000,000
Senior Notes | Maximum
Debt Instrument [Line Items]
Criteria of net senior secured debt to EBITDAX				300.00%
Subsequent Event | Senior Credit Facility
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 190,000,000
[1]	The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2015, 2014 and 2013 was approximately 1.7%, 2.2 % and 1.9%, respectively. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2015, 2014 and 2013 was approximately 5.5%, 4.0% and 5.3%, respectively.

Long-Term Debt - Senior Notes -

Long-Term Debt - Senior Notes - Additional Information (Detail) - USD ($) shares in Thousands	Mar. 14, 2016	Dec. 12, 2012	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jul. 17, 2014
Debt Instrument [Line Items]
Gain recognized due to troubled debt exchanges			$ (8,480,000)
Share of common stock	10,125		10,100
Shares issued			8,400
Fair value of stock issued			$ 6,500,000
Accrued and unpaid interest			12,800,000
Third-party debt issuance costs			$ 2,821,000	$ 459,000	$ 1,414,000	$ 6,824,000	$ 3,134,000
Trailing quarters fixed charge coverage ratio					2.25%
Fixed charge coverage ratio			1.00%
Senior Notes additional borrowings			$ 68,900,000		$ 213,600,000
Premium on Senior Notes, Net			2,245,000		2,344,000	2,725,000
Amortization of net premium			100,000		$ 400,000	$ 400,000
Maximum
Debt Instrument [Line Items]
Senior notes offered for exchange	$ 675,000,000		$ 675,000,000
Interest Payments One Through Three
Debt Instrument [Line Items]
Debt Instrument, Frequency of Periodic Payment			semi-annual		Bi-annual
Interest Payments Four And Thereafter
Debt Instrument [Line Items]
Debt Instrument, Frequency of Periodic Payment					Bi-annual
New Notes
Debt Instrument [Line Items]
Gain recognized due to troubled debt exchanges			$ 0
Debt instrument maturity date			Oct. 1, 2020
Aggregate principal amount			$ 633,700,000
Additional issuance of debt			$ 500,000
Debt instrument initial interest payment date			Oct. 1, 2016
Third-party debt issuance costs			$ 8,500,000
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	0.00%		1.00%
New Notes | Interest Payments Four And Thereafter
Debt Instrument [Line Items]
Interest rate	8.00%		8.00%
8.875% Senior Notes
Debt Instrument [Line Items]
Debt instrument maturity date		Dec. 1, 2020	Dec. 1, 2020		Dec. 1, 2020	Dec. 1, 2020
Interest rate		8.875%	8.875%		8.875%	8.875%
Aggregate principal amount		$ 250,000,000
Third-party debt issuance costs		$ 6,400,000
6.25% Senior Notes
Debt Instrument [Line Items]
Debt instrument maturity date			Aug. 1, 2022		Dec. 1, 2022	Dec. 1, 2022
Interest rate			6.25%		6.25%	6.25%		6.25%
Aggregate principal amount								$ 325,000,000
2020 Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount			$ 324,000,000
Percentage of senior notes exchanged for new notes			92.60%
2022 Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount			$ 309,100,000
Percentage of senior notes exchanged for new notes			95.10%
Debt instrument redemption date					Aug. 1, 2017
Latest date for equity proceeds to be applied to optional Note redemption					Aug. 1, 2017
Percentage of notes that can be redeemed					35.00%

Components of Long-Term Debt an

Components of Long-Term Debt and Lines of Credit (Detail) - USD ($) $ in Thousands		Mar. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Debt Disclosure [Abstract]
Senior notes, net of issuance costs	[1]	$ 657,511		$ 663,089
Premium on Senior Notes, Net		2,245		2,344		$ 2,725
Senior Line of Credit, Net of Issuance Costs	[2],[3]	152,794		109,396
Capital Leases and Other Obligations		434	[3]	618	[3],[4]	1,427	[4]
Total Debt		812,984		775,447		679,152
Less Current Portion of Long-Term Debt		(9,934)		(590)		(1,176)
Total Long-Term Debt		803,050		774,857		677,976
Senior Line of Credit		$ 158,000		111,500	[4]
Scenario, Previously Reported [Member]
Debt Disclosure [Abstract]
Senior Line of Credit, Net of Issuance Costs				111,500
Total Debt				789,462
Total Long-Term Debt				788,872
8.875% Senior Notes
Debt Disclosure [Abstract]
Senior notes, net of issuance costs				350,000		350,000
6.25% Senior Notes
Debt Disclosure [Abstract]
Senior notes, net of issuance costs				$ 325,000		$ 325,000
[1]	Includes unamortized debt issuance costs of approximately $11.1 million and $11.9 million as of March 31, 2016 and December 31, 2015, respectively.
[2]	Includes unamortized debt issuance costs of approximately $5.2 million and $2.1 million as of March 31, 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 three months ended March 31, 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 three months ended March 31, 2016 and the year ended December 31, 2015, was approximately 4.5% and 5.5%, respectively.
[4]	The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2015, 2014 and 2013 was approximately 1.7%, 2.2 % and 1.9%, respectively. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2015, 2014 and 2013 was approximately 5.5%, 4.0% and 5.3%, respectively.

Components of Long-Term Debt 67

Components of Long-Term Debt and Lines of Credit (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 12, 2012	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jul. 17, 2014
Debt Instrument [Line Items]
Average interest rate			1.70%	2.20%	1.90%
Capital Leases and Other Obligations
Debt Instrument [Line Items]
Average interest rate		4.50%	5.50%	4.00%	5.30%
Senior Notes
Debt Instrument [Line Items]
Unamortized debt issuance expense		$ 11.1	$ 11.9
Senior Line of Credit
Debt Instrument [Line Items]
Unamortized debt issuance expense		$ 5.2	$ 2.1
Senior Credit Facility
Debt Instrument [Line Items]
Average interest rate		3.20%	1.70%
8.875% Senior Notes
Debt Instrument [Line Items]
Interest rate	8.875%	8.875%	8.875%	8.875%
Debt instrument maturity date	Dec. 1, 2020	Dec. 1, 2020	Dec. 1, 2020	Dec. 1, 2020
6.25% Senior Notes
Debt Instrument [Line Items]
Interest rate		6.25%	6.25%	6.25%		6.25%
Debt instrument maturity date		Aug. 1, 2022	Dec. 1, 2022	Dec. 1, 2022

Principal Maturity Schedule for

Principal Maturity Schedule for Debt Outstanding (Detail) - USD ($) $ in Thousands	Mar. 31, 2016	Jan. 31, 2016		Dec. 31, 2015	Dec. 31, 2014
Equity Method Investments And Cost Method Investments [Abstract]
2,016		$ 9,906
2,017		28		$ 28
2,018		0
2,019		148,500		111,500
2,020		652,658		350,000
Thereafter		15,865		325,000
Total	$ 810,739	$ 826,957	[1]	773,103
2,016				590
Total, Gross				$ 787,118	$ 676,427
[1]	Excludes $2.2 million net premium on Senior Notes and $16.2 million in debt issuance costs

Principal Maturity Schedule f69

Principal Maturity Schedule for Debt Outstanding (Parenthetical) (Detail) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Senior notes, net premium	$ 2.2	$ 2.3
New Notes
Debt Instrument [Line Items]
Debt issuance costs	$ 16.2

Derivative Instruments and Fa70

Derivative Instruments and Fair Value Measurements - Additional Information (Detail) - USD ($)	3 Months Ended										12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015		Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives	$ (12,994,000)					$ (11,079,000)					$ (55,793,000)		$ (7,281,000)	$ (7,128,000)
Senior Line of Credit	158,000,000	$ 111,500,000	[1]								111,500,000	[1]
Senior Notes	675,000,000	675,000,000									675,000,000
Derivative interest rate outstanding	0	0									0
Derivatives asset (liability)	26,800,000	35,800,000					$ 31,400,000				35,800,000		31,400,000
Unrealized gain (loss) on commodity derivative contracts	2,000,000					(2,000,000)					2,500,000		1,700,000
Impairment Expense	14,184,000	81,098,000		$ 139,812,000	$ 117,842,000	7,023,000	132,576,000	$ 1,000	$ 16,000	$ 25,000	345,775,000		132,618,000	32,072,000
Crude Oil
Derivatives Fair Value [Line Items]
Derivatives asset (liability)	$ 1,044,000	$ 2,507,000									$ 2,507,000
Crude Oil | Minimum
Derivatives Fair Value [Line Items]
Commodity hedged on annualized basis hedge through 2016	100.00%	45.00%									45.00%
Commodity hedged including effects of derivatives added on annualized basis hedge through 2016		70.00%									70.00%
Other Than Temporary Impairment
Derivatives Fair Value [Line Items]
Impairment Expense	$ 14,200,000										$ 345,800,000
Natural Gas
Derivatives Fair Value [Line Items]
Derivatives asset (liability)	$ 20,166,000	$ 23,027,000									$ 23,027,000
Natural Gas | Minimum
Derivatives Fair Value [Line Items]
Commodity hedged on annualized basis hedge through 2016	100.00%	100.00%									100.00%
Commodity hedged on annualized basis hedge through 2017	50.00%
Commodity hedged including effects of derivatives added on annualized basis hedge through 2016		100.00%									100.00%
Natural Gas Liquids
Derivatives Fair Value [Line Items]
Derivatives asset (liability)	$ 5,874,000	$ 10,594,000									$ 10,594,000
Natural Gas Liquids | Minimum
Derivatives Fair Value [Line Items]
Commodity hedged on annualized basis hedge through 2016	40.00%	40.00%									40.00%
Commodity hedged including effects of derivatives added on annualized basis hedge through 2016		45.00%									45.00%
Commodity derivatives
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives	$ 13,000,000					$ 10,600,000					$ 54,900,000		6,000,000	$ 7,100,000
Derivatives asset (liability)	$ 26,806,000	$ 35,752,000					$ 31,371,000				35,752,000		31,371,000
Interest Rate Swaption [Member]
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives											500,000
Interest Rate Swap
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives											$ 900,000		$ 1,300,000
[1]	The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2015, 2014 and 2013 was approximately 1.7%, 2.2 % and 1.9%, respectively. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2015, 2014 and 2013 was approximately 5.5%, 4.0% and 5.3%, respectively.

Schedule of Location and Amount

Schedule of Location and Amounts of Gains and Losses on Derivative Instruments (Detail) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	$ 4,049	$ 17,119	$ 60,176	$ 38,876	$ (2,908)
Interest Rate Swap
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net		263	934	1,517	(206)
Natural Gas
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	5,363	13,600	37,647	18,406	1,807
Natural Gas Liquids
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	(1,621)	435	14,463	10,340	(1,711)
Crude Oil
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	325	2,876	$ 7,132	$ 8,613	$ (2,798)
Refined Product (Heating Oil)
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	$ (18)	$ (55)

Asset or Liability Financial Co

Asset or Liability Financial Commodity Derivative Instrument Positions (Detail) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2016USD ($)$ / bbl$ / McfbblMcf	Dec. 31, 2015USD ($)$ / bbl$ / McfbblMcf	Dec. 31, 2014USD ($)
Derivatives Fair Value [Line Items]
Derivatives asset (liability)	$ 26,800	$ 35,800	$ 31,400
2016 | Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	2,250,000	3,900,000
Floor | $ / Mcf	2.70	2.82
Ceiling | $ / Mcf	3.10	3.32
Derivatives asset (liability)	$ 973	$ 1,728
2016 | Cap Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	60,000
Put Option | $ / bbl	30
Swap | $ / bbl	44
Derivatives asset (liability)	$ 42
2018 | Swaptions
Derivatives Fair Value [Line Items]
Volume | Mcf	0
Derivatives asset (liability)	$ (191)
Crude Oil
Derivatives Fair Value [Line Items]
Volume | bbl	730,750	544,500
Derivatives asset (liability)	$ 1,044	$ 2,507
Crude Oil | 2016 | Deferred Put Spread
Derivatives Fair Value [Line Items]
Volume | bbl		120,000
Put Option | $ / bbl		50
Floor | $ / bbl		65
Derivatives asset (liability)		$ 852
Crude Oil | 2016 | Collars
Derivatives Fair Value [Line Items]
Volume | bbl	445,750	379,500
Floor | $ / bbl	38.72	39.17
Ceiling | $ / bbl	50.28	52.67
Derivatives asset (liability)	$ 662	$ 1,078
Crude Oil | 2016 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | bbl	225,000	45,000
Put Option | $ / bbl	31.20	50
Floor | $ / bbl	41.40	65
Ceiling | $ / bbl	49.60	70
Derivatives asset (liability)	$ 340	$ 577
Refined Product (Heating Oil)
Derivatives Fair Value [Line Items]
Volume | bbl	9,000	12,000
Derivatives asset (liability)	$ (278)	$ (376)
Refined Product (Heating Oil) | 2016 | Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	9,000	12,000
Swap | $ / bbl	84	84
Derivatives asset (liability)	$ (278)	$ (376)
Natural Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	154,080,000	154,875,000
Derivatives asset (liability)	$ 20,166	$ 23,027
Natural Gas | Basis Swaps Dominion South
Derivatives Fair Value [Line Items]
Derivatives asset (liability)	(6,247)	(5,468)
Natural Gas | Basis Swaps Texas Gas
Derivatives Fair Value [Line Items]
Derivatives asset (liability)	$ (1,026)	$ (38)
Natural Gas | 2016 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	8,480,000	18,570,000
Put Option | $ / Mcf	2.31	2.34
Floor | $ / Mcf	2.95	3.04
Ceiling | $ / Mcf	3.55	3.86
Derivatives asset (liability)	$ 5,054	$ 5,941
Natural Gas | 2016 | Cap Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	4,050,000	3,600,000
Put Option | $ / Mcf	2.90	3.45
Swap | $ / Mcf	3.48	4.11
Derivatives asset (liability)	$ 1,102	$ 1,977
Natural Gas | 2016 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	14,090,000	12,900,000
Swap | $ / Mcf	2.95	3.19
Derivatives asset (liability)	$ 10,341	$ 8,717
Natural Gas | 2016 | Swaptions
Derivatives Fair Value [Line Items]
Volume | Mcf	900,000	1,200,000
Swap | $ / Mcf	3.15	3.15
Derivatives asset (liability)	$ 767	$ 596
Natural Gas | 2016 | Put Spreads
Derivatives Fair Value [Line Items]
Volume | Mcf	9,470,000	4,500,000
Put Option | $ / Mcf	2.50	2.93
Floor | $ / Mcf	3.26	3.59
Derivatives asset (liability)	$ 808	$ 1,737
Natural Gas | 2016 | Basis Swaps Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	17,665,000	16,630,000
Swap | $ / Mcf	(0.89)	(0.94)
Derivatives asset (liability)	$ (1,879)	$ (1,634)
Natural Gas | 2017 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	16,300,000	16,300,000
Put Option | $ / Mcf	2.33	2.33
Floor | $ / Mcf	3.02	3.02
Ceiling | $ / Mcf	3.89	3.89
Derivatives asset (liability)	$ 5,066	$ 4,319
Natural Gas | 2017 | Cap Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	5,700,000	2,100,000
Put Option | $ / Mcf	2.65	3.34
Swap | $ / Mcf	3.20	4.07
Derivatives asset (liability)	$ 951	$ 1,225
Natural Gas | 2017 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	960,000	960,000
Swap | $ / Mcf	3.60	3.60
Derivatives asset (liability)	$ 903	$ 797
Natural Gas | 2017 | Swaptions
Derivatives Fair Value [Line Items]
Volume | Mcf	0	0
Derivatives asset (liability)	$ (263)	$ (297)
Natural Gas | 2017 | Basis Swaps Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	4,550,000	4,550,000
Swap | $ / Mcf	(0.83)	(0.83)
Derivatives asset (liability)	$ (1,092)	$ (665)
Natural Gas | 2017 | Calls
Derivatives Fair Value [Line Items]
Volume | Mcf	3,000,000	3,000,000
Ceiling | $ / Mcf	3.64	3.64
Derivatives asset (liability)	$ (753)	$ (380)
Natural Gas | 2017 | Basis Swaps Texas Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	14,600,000	14,600,000
Swap | $ / Mcf	(0.13)	(0.13)
Derivatives asset (liability)	$ (513)	$ (19)
Natural Gas | 2018 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume | Mcf	7,875,000	7,875,000
Put Option | $ / Mcf	2.29	2.29
Floor | $ / Mcf	2.88	2.88
Ceiling | $ / Mcf	3.56	3.56
Derivatives asset (liability)	$ 1,046	$ 916
Natural Gas | 2018 | Cap Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	1,800,000	1,800,000
Put Option | $ / Mcf	3.30	3.30
Swap | $ / Mcf	4.05	4.05
Derivatives asset (liability)	$ 1,060	$ 1,069
Natural Gas | 2018 | Swaps
Derivatives Fair Value [Line Items]
Volume | Mcf	960,000	960,000
Swap | $ / Mcf	3.60	3.60
Derivatives asset (liability)	$ 903	$ 797
Natural Gas | 2018 | Basis Swaps Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	6,400,000	6,400,000
Swap | $ / Mcf	(0.83)	(0.83)
Derivatives asset (liability)	$ (1,092)	$ (960)
Natural Gas | 2018 | Calls
Derivatives Fair Value [Line Items]
Volume | Mcf	5,810,000	5,810,000
Ceiling | $ / Mcf	3.97	3.97
Derivatives asset (liability)	$ (328)	$ (609)
Natural Gas | 2018 | Basis Swaps Texas Gas
Derivatives Fair Value [Line Items]
Volume | Mcf	14,600,000	14,600,000
Swap | $ / Mcf	(0.13)	(0.13)
Derivatives asset (liability)	$ (513)	$ (19)
Natural Gas | 2019 | Basis Swaps Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	7,300,000	7,300,000
Swap | $ / Mcf	(0.83)	(0.83)
Derivatives asset (liability)	$ (1,092)	$ (1,103)
Natural Gas | 2020 | Basis Swaps Dominion South
Derivatives Fair Value [Line Items]
Volume | Mcf	7,320,000	7,320,000
Swap | $ / Mcf	(0.83)	(0.83)
Derivatives asset (liability)	$ (1,092)	$ (1,106)
Natural Gas Liquids
Derivatives Fair Value [Line Items]
Volume | bbl	1,671,000	1,551,000
Derivatives asset (liability)	$ 5,874	$ 10,594
Natural Gas Liquids | 2016 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	1,038,000	1,131,000
Swap | $ / bbl	30.66	32.76
Derivatives asset (liability)	$ 6,006	$ 9,888
Natural Gas Liquids | 2016 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	165,000	240,000
Swap | $ / bbl	8.82	8.82
Derivatives asset (liability)	$ 155	$ 362
Natural Gas Liquids | 2017 | C3+ NGL Swaps
Derivatives Fair Value [Line Items]
Volume | bbl	468,000	180,000
Swap | $ / bbl	20.16	21.42
Derivatives asset (liability)	$ (287)	$ 344

Combined Fair Value of Derivati

Combined Fair Value of Derivatives (Detail) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	$ 29,012	$ 34,260	$ 29,265
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	8,460	9,534	4,904
Total Derivative Assets	37,472	43,794	34,169
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(3,758)	(2,486)	(421)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(6,908)	(5,556)	(2,377)
Total Derivative Liabilities	(10,666)	(8,042)	(2,798)
Natural Gas Liquids | Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	6,579	10,250	6,181
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	185	344
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(490)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(400)
Natural Gas
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(6,908)	(5,556)	(2,377)
Natural Gas | Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	973	1,728
Natural Gas | Three Way Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	6,326	6,183	5,081
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	4,840	5,108	1,733
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities		(31)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities		(84)
Natural Gas | Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	10,576	9,010	4,522
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	1,580	1,593	1,554
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(9)	(292)
Natural Gas | Cap Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	1,638	1,977	3,430
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	1,855	2,294	1,617
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(190)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(190)
Natural Gas | Basis Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets		70	2,815
Long-Term Derivative Assets:
Total Long-Term Derivative Assets		195
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(2,280)	(1,585)	(193)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(4,993)	(4,186)	(1,281)
Natural Gas | Swaptions
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	792	798
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(46)	(202)	(154)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(433)	(297)
Natural Gas | Put Spreads
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	808	1,737
Natural Gas | Calls
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(189)		(74)
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	(892)	(989)	(1,096)
Crude Oil | Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	662	1,078
Crude Oil | Call Protected Swap [Member]
Short-Term Derivative Assets:
Total Short-Term Derivative Assets			1,227
Crude Oil | Deferred Put Spread
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	42	852	1,413
Crude Oil | Three Way Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	616	577	$ 4,596
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	(276)
Refined Product (Heating Oil) | Swaps
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	$ (278)	$ (376)

Significant Unobservable Inputs

Significant Unobservable Inputs Used in Fair Value Measurements of Natural Gas Basis Swaps (Detail) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2016USD ($)$ / Mcf	Dec. 31, 2015USD ($)$ / Mcf	Dec. 31, 2014USD ($)$ / Mcf
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Derivatives asset (liability) | $	$ 26,800	$ 35,800	$ 31,400
Natural Gas
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Derivatives asset (liability) | $	$ 20,166	$ 23,027
Natural Gas | Basis Swaps Dominion South
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Weighted Average (price per Mcf)	(0.85)	(0.74)
Derivatives asset (liability) | $	$ (6,247)	$ (5,468)
Natural Gas | Basis Swaps Dominion South | Minimum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)	(0.30)	(0.27)
Natural Gas | Basis Swaps Dominion South | Maximum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)	(1.02)	(1.08)
Natural Gas | Basis Swaps Texas Gas
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Weighted Average (price per Mcf)	(0.13)	(0.12)
Derivatives asset (liability) | $	$ (1,026)	$ (38)
Natural Gas | Basis Swaps Texas Gas | Minimum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)	(0.09)	(0.05)
Natural Gas | Basis Swaps Texas Gas | Maximum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)	(0.13)	(0.17)
Natural Gas | Basis Swaps
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Weighted Average (price per Mcf)			(0.84)
Derivatives asset (liability) | $			$ 1,341
Natural Gas | Basis Swaps | Minimum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)			(0.27)
Natural Gas | Basis Swaps | Maximum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)			(1.39)

Fair Value Hierarchy Table for

Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value (Detail) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	$ 26,800	$ 35,800	$ 31,400
Commodity derivatives
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	26,806	35,752	31,371
Commodity derivatives | Significant Other Observable Inputs (Level 2)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	34,079	41,258	30,030
Commodity derivatives | Significant Unobservable Inputs (Level 3)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	$ (7,273)	$ (5,506)	$ 1,341

Reconciliation of Commodity Der

Reconciliation of Commodity Derivative Contracts Measured at Fair Value on Recurring Basis Using Significant Unobservable Inputs (Level 3) (Detail) - Commodity derivatives - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014
Fair Value Net Derivative Asset Liability Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance of Level 3	$ (5,506)	$ 1,341	$ 1,341	$ 4,323
Changes in Fair Value	(2,037)	(1,955)	(2,548)	(1,670)
Settlements Received	270	409	4,299	1,312
Ending Balance of Level 3	$ (7,273)	$ (205)	$ (5,506)	$ 1,341

Financial Instruments Not Recor

Financial Instruments Not Recorded at Fair Value (Detail) - USD ($) $ in Thousands		Mar. 31, 2016		Jan. 31, 2016	[5]	Dec. 31, 2015		Dec. 31, 2014
Senior Notes	[1]	$ 657,511				$ 663,089
Secured Line of Credit	[2],[3]	152,794				109,396
Capital Leases and Other Obligations		434	[3]			618	[3],[4]	$ 1,427	[4]
Total		810,739		$ 826,957		773,103
Total, Gross						787,118		676,427
Scenario, Previously Reported [Member]
Secured Line of Credit						111,500
Fair Value
Senior Notes		78,715				137,402
Secured Line of Credit		152,794				111,500
Capital Leases and Other Obligations		427				606		1,393
Total		$ 231,936				261,419		554,661
Fair Value | Scenario, Adjustment [Member]
Secured Line of Credit						109,396
Total						247,404
8.875% Senior Notes
Senior Notes						350,000		350,000
8.875% Senior Notes | Fair Value
Senior Notes						77,000		311,955
6.25% Senior Notes
Senior Notes						325,000		325,000
6.25% Senior Notes | Fair Value
Senior Notes						$ 72,313		$ 241,313
[1]	Includes unamortized debt issuance costs of approximately $11.1 million and $11.9 million as of March 31, 2016 and December 31, 2015, respectively.
[2]	Includes unamortized debt issuance costs of approximately $5.2 million and $2.1 million as of March 31, 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 three months ended March 31, 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 three months ended March 31, 2016 and the year ended December 31, 2015, was approximately 4.5% and 5.5%, respectively.
[4]	The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2015, 2014 and 2013 was approximately 1.7%, 2.2 % and 1.9%, respectively. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2015, 2014 and 2013 was approximately 5.5%, 4.0% and 5.3%, respectively.
[5]	Excludes $2.2 million net premium on Senior Notes and $16.2 million in debt issuance costs

Schedule of Income Tax Included

Schedule of Income Tax Included in Continuing Operations (Detail) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current:
Federal					$ (1,936)
State				$ 6	(4,105)
Deferred:
Federal			$ (20,993)	(23,691)	509
State			(3,234)	(3,230)	1,378
Income tax Expense (Benefit)	$ 2,092	$ (92)	$ (24,227)	$ (26,915)	$ (4,154)
Effective Tax Rate	(3.60%)	0.50%	5.70%	36.10%	63.50%

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Additional Textual [Abstract]
Statutory rate	35.00%	35.00%	35.00%	35.00%	35.00%
Cancellation of debt income	$ 543,200
Net operating loss carryforwards alternative minimum tax payment	$ 5,500		$ 292	$ 292
Income tax refunds		$ 500
Valuation allowance for deferred tax assets			148,200	$ 4,300
Net operating loss carryforwards			264,700
Annual utilization limit on net operating losses			$ 34,800
Minimum
Income Tax Additional Textual [Abstract]
Federal net operating loss carryforwards, expiration year			2,020
Maximum
Income Tax Additional Textual [Abstract]
Federal net operating loss carryforwards, expiration year			2,035
Federal
Income Tax Additional Textual [Abstract]
Net operating loss carryforwards			$ 308,100

Capital Stock - Additional Info

Capital Stock - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	Mar. 14, 2016	Aug. 18, 2014	Feb. 29, 2016	Mar. 31, 2016	Nov. 15, 2015	Aug. 15, 2015	May. 15, 2015	Feb. 15, 2015	Dec. 31, 2015	Dec. 31, 2014	Aug. 12, 2014
Schedule Of Capitalization Equity [Line Items]
Common stock, shares authorized				100,000,000					100,000,000	100,000,000
Preferred Stock, shares authorized				100,000					100,000	100,000
Common Stock, shares issued				66,041,227					55,741,229	54,174,763
Common Stock, shares outstanding				66,041,227					55,741,229	54,174,763
Preferred Stock, par value				$ 0.001					$ 0.001	$ 0.001
Preferred Stock, shares issued				12,836					16,100	16,100
Preferred Stock, shares outstanding				12,836					16,100	16,100
Preferred stock shares converted	10,125,000			10,100,000
Proceeds from the Issuance of Preferred Stock, Net										$ 154,988
Dividends declared on Preferred Stock									$ 6,088	2,335
Common Stock
Schedule Of Capitalization Equity [Line Items]
Preferred stock convertible preferred stock				1,800,000
Preferred stock to common stock conversion ratio									555.56
6.0% convertible perpetual preferred stock, Series A
Schedule Of Capitalization Equity [Line Items]
Preferred Stock, par value		$ 0.001		$ 0.001					$ 0.001
Preferred Stock, shares issued		16,100		12,836					16,100
Preferred Stock, shares outstanding				12,836					16,100
Preferred stock shares converted				3,264
Dividend per share percentage				6.00%					6.00%
Dividend per share in amount				$ 600					$ 600
Accumulated dividends in arrears				$ 2,100
Quarterly cash dividend paid per share			$ 0		$ 150	$ 150	$ 150	$ 150
Quarterly cash dividend amount paid					$ 2,400	$ 2,400	$ 2,400	$ 2,400
Proceeds from the Issuance of Preferred Stock, Net		$ 155,000
Dividends declared on Preferred Stock									$ 9,700	$ 2,300
Initial conversion price per share of common stock									$ 18
Premium percentage over market closing sale price									25.20%
Closing sale price per share of common stock											$ 14.38
Sale of shares transaction date									Aug. 12, 2014
Depositary shares
Schedule Of Capitalization Equity [Line Items]
Preferred Stock, shares issued		1,610,000
Liquidation preference per share				$ 10,000					$ 10,000
Preferred stock to common stock conversion ratio									5.5556

Employee Benefit and Equity P81

Employee Benefit and Equity Plans - Additional Information (Detail)	3 Months Ended		12 Months Ended
	Mar. 31, 2016USD ($)EmployeesPerson$ / sharesshares	Mar. 31, 2015USD ($)Personshares	Dec. 31, 2015USD ($)EntityEmployees$ / sharesshares	Dec. 31, 2014USD ($)Entity$ / sharesshares	Dec. 31, 2013USD ($)$ / sharesshares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of option issued to purchase common stock | shares	851,422	80,000	80,000
Stock options exercised | shares	0	0		46,526	49,166
Tax benefit	$ 0	$ 0		$ 100,000	$ 200,000
Outstanding weighted average remaining term (in years)	5 years 6 months		2 years 9 months 18 days	2 years 10 months 24 days
Weighted average remaining term of options exercisable (in years)	1 year 10 months 24 days		2 years 1 month 6 days
Aggregate intrinsic value of options outstanding	$ 0
Aggregate intrinsic value of options exercisable	0
Unrecognized compensation expense	500,000		$ 100,000
Restricted Stock or Unit Expense	$ 1,500,000	$ 2,500,000
Employer contribution to the plan			$ 800,000	$ 900,000	700,000
Intrinsic value of stock options exercised				$ 300,000	400,000
Expected Dividend Yield			0.00%	0.00%
Stock Options
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of employees | Employees	29		3
Share-based compensation				$ 100,000	$ 200,000
Stock Options | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expiration period for outstanding stock options			5 years
Stock Options | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expiration period for outstanding stock options			10 years
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation expense	$ 3,600,000		$ 4,500,000
Common stock issued by compensation committee | shares	420,901	1,336,295	2,236,839	131,610	981,544
Number of employees subjected to issuance of common stock | Person	22	126
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	$ 1.67		$ 3.35	$ 8.76	$ 16.03
Share-based compensation		$ 3,000,000	$ 6,400,000	$ 5,800,000	$ 5,100,000
Vested stock | shares	142,516		606,359	595,085	182,994
Unrecognized compensation expense weighted average period, in years	1 year 6 months		1 year 8 months 12 days
Number of companies in peer group | Entity			15	13
Expected Dividend Yield			0.00%
Total fair value of stock awards vested in period			$ 2,000,000	$ 7,700,000
Restricted Stock | Certain Performance Factors Waived
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vested stock | shares	235,573	189,872
2007 Long Term Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares authorized for issuance | shares			5,979,470
Shares available for grant | shares			1,144,297	2,825,260
TSR | Restricted Stock
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	$ 10.15	$ 12.59

Summary of Issued and Outstandi

Summary of Issued and Outstanding Stock Options (Detail) - $ / shares	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Number Outstanding	1,295,094	443,672	402,561	449,087	502,253
Weighted-Average Exercise Price, Outstanding	$ 4.41	$ 9.64	$ 10.82	$ 10.85	$ 10.95
Number Exercisable	367,005	363,672
Weighted-Average Exercise Price, Exercisable	$ 10.72	$ 10.77
Exercise Price Range 4.05
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 4.05	$ 4.05
Number Outstanding	40,000	40,000
Weighted-Average Exercise Price, Outstanding	$ 4.05	$ 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	$ 4.90
Number Outstanding	40,000	40,000
Weighted-Average Exercise Price, Outstanding	$ 4.90	$ 4.90
Number Exercisable	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	$ 5.04
Number Outstanding	46,041	46,041
Weighted-Average Exercise Price, Outstanding	$ 5.04	$ 5.04
Number Exercisable	46,041	46,041
Weighted-Average Exercise Price, Exercisable	$ 5.04	$ 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	$ 9.50
Number Outstanding	75,000	75,000
Weighted-Average Exercise Price, Outstanding	$ 9.50	$ 9.50
Number Exercisable	75,000	75,000
Weighted-Average Exercise Price, Exercisable	$ 9.50	$ 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	$ 9.99
Number Outstanding	129,583	129,583
Weighted-Average Exercise Price, Outstanding	$ 9.99	$ 9.99
Number Exercisable	129,583	129,583
Weighted-Average Exercise Price, Exercisable	$ 9.99	$ 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	$ 10.42
Number Outstanding	29,548	29,548
Weighted-Average Exercise Price, Outstanding	$ 10.42	$ 10.42
Number Exercisable	29,548	29,548
Weighted-Average Exercise Price, Exercisable	$ 10.42	$ 10.42
Exercise Price Range 11.87
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 11.87	$ 11.89
Number Outstanding	3,500	3,500
Weighted-Average Exercise Price, Outstanding	$ 11.87	$ 11.89
Number Exercisable	3,500	3,500
Weighted-Average Exercise Price, Exercisable	$ 11.87	$ 11.89
Exercise Price Range 13.19
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$ 13.19	$ 13.19
Number Outstanding	50,000	50,000
Weighted-Average Exercise Price, Outstanding	$ 13.19	$ 13.19
Number Exercisable	50,000	50,000
Weighted-Average Exercise Price, Exercisable	$ 13.19	$ 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	$ 22.34
Number Outstanding	30,000	30,000
Weighted-Average Exercise Price, Outstanding	$ 22.34	$ 22.34
Number Exercisable	30,000	30,000
Weighted-Average Exercise Price, Exercisable	$ 22.34	$ 22.34
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	851,422
Weighted-Average Exercise Price, Outstanding	$ 1.69

Summary of Nonvested Stock Acti

Summary of Nonvested Stock Activity (Detail) - Restricted Stock - $ / shares	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock awards, beginning balance, Number of Shares	2,479,408	1,519,301	1,519,301	2,172,639	1,431,573
Awards, Number of Shares	420,901	1,336,295	2,236,839	131,610	981,544
Forfeitures, Number of Shares	(346,876)		(670,373)	(189,863)	(57,484)
Vested, Number of Shares	(142,516)		(606,359)	(595,085)	(182,994)
Stock awards, ending balance, Number of Shares	2,410,917		2,479,408	1,519,301	2,172,639
Stock awards, beginning balance, Weighted Average Grant Date Fair Value	$ 6.27	$ 14.05	$ 14.05	$ 14.16	$ 12.45
Awards, Weighted Average Grant Date Fair Value	1.67		3.35	8.76	16.03
Forfeitures, Weighted Average Grant Date Fair Value	7.83		11.33	14.60	11.84
Vested, Weighted Average Grant Date Fair Value	12.76		9.39	13.09	11.59
Stock awards, ending balance, Weighted Average Grant Date Fair Value	$ 4.86		$ 6.27	$ 14.05	$ 14.16

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail)	1 Months Ended		3 Months Ended		12 Months Ended
	Jan. 31, 2016USD ($)	Jan. 31, 2015USD ($)	Mar. 31, 2016USD ($)	Mar. 31, 2015USD ($)Rigs	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Sep. 30, 2015Rigs
Loss Contingencies [Line Items]
Significant probable or possible environmental contingent liabilities			$ 0		$ 0
Letters of credit			41,000,000		41,000,000	$ 6,000,000
Rent expense			300,000	$ 200,000	1,000,000	800,000	$ 600,000
Termination fees incurred				4,800,000	4,800,000
Loss on Contract Termination	$ 2,500,000	$ 2,300,000
Maximum guarantee of payment of obligations			$ 418,000,000		421,800,000
Guarantee obligations period			2,021
Transportation, processing and marketing expenses of oil natural gas and natural gas liquids			$ 21,500,000	18,900,000	79,500,000	55,400,000	26,400,000
Fees related to unutilized capacity commitments			400,000	900,000
Production and Lease Operating Expense			30,146,000	29,052,000	118,999,000	100,282,000	62,150,000
Accrued Liabilities			$ 44,296,000		$ 44,326,000	59,478,000
Capacity Reservation
Loss Contingencies [Line Items]
Estimated working interest			53.00%		52.60%
Charges incurred for unutilized processing capacity			$ 600,000	$ 200,000	$ 600,000	200,000	300,000
Capacity Reservation | 2016
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed			10,900,000		14,400,000
Capacity Reservation | 2017
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed			16,500,000		16,400,000
Capacity Reservation | 2018
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed			16,500,000		16,400,000
Capacity Reservation | 2019
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed			16,500,000		16,400,000
Capacity Reservation | 2020
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed			16,600,000		16,500,000
Capacity Reservation | Thereafter
Loss Contingencies [Line Items]
Obligation for the cryogenic gas processing plant if gas is not processed			97,900,000		97,200,000
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			1,700,000		2,300,000
Minimum gross cost to retain the completion services			4,000,000		4,000,000
Drilling Commitments | 2017
Loss Contingencies [Line Items]
Minimum cost to retain drilling rigs			2,300,000		$ 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%		20.00%
Production and Lease Operating Expense			$ 500,000	$ 600,000	$ 3,000,000	$ 4,100,000	$ 3,200,000
Accrued Liabilities			$ 3,600,000
Natural Gas Transportation Agreement
Loss Contingencies [Line Items]
Letters of credit					$ 39,800,000

Lease Commitments for Each of N

Lease Commitments for Each of Next Five Years (Detail) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
2,016	$ 766	$ 1,058
2,017	991	991
2,018	565	565
2,019	563	563
2,020	422	422
Thereafter		0
Total	$ 3,307	$ 3,599

Minimum Net Obligations under S

Minimum Net Obligations under Sales, Gathering and Transportation Agreements (Detail) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
2,016	$ 24,715
2,016		$ 23,836
2,017	49,357	38,434
2,018	53,456	39,993
2,019	52,904	39,017
2,020	51,697	37,744
Thereafter	458,695	395,980
Total	$ 690,824	$ 575,004

Fee for Unconventional Gas Well

Fee for Unconventional Gas Wells (Detail) - Pennsylvania Impact Fee - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2016	[1]	Dec. 31, 2015
Less than $2.25
Unconventional Gas Wells [Line Items]
Year One	$ 40,200		$ 40,200
Year Two	30,200		30,200
Year Three	25,200		25,200
Year 4 - 10	10,100		10,100
Year 11 - 15	5,000		5,000
$2.26 - $2.99
Unconventional Gas Wells [Line Items]
Year One	45,300		45,300
Year Two	35,200		35,200
Year Three	30,200		30,200
Year 4 - 10	15,100		15,100
Year 11 - 15	5,000		5,000
$3.00 - $4.99
Unconventional Gas Wells [Line Items]
Year One	50,300		50,300
Year Two	40,200		40,200
Year Three	30,200		30,200
Year 4 - 10	20,100		20,100
Year 11 - 15	10,100		10,100
$5.00 - $5.99
Unconventional Gas Wells [Line Items]
Year One	55,300		55,300
Year Two	45,300		45,300
Year Three	40,200		40,200
Year 4 - 10	20,100		20,100
Year 11 - 15	10,100		10,100
More than $5.99
Unconventional Gas Wells [Line Items]
Year One	60,400		60,400
Year Two	55,300		55,300
Year Three	50,300		50,300
Year 4 - 10	20,100		20,100
Year 11 - 15	$ 10,100		$ 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 (Detail) - shares shares in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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%		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	7.1		8.9	3.3
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	0.4	0.4	0.4
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	1.1	0.8	1.3

Earnings Per Share - Computatio

Earnings Per Share - Computation of Basic and Diluted Earning Per Common Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended									12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Numerator:
Net Loss From Continuing Operations	$ (60,141)	$ (97,873)	$ (129,293)	$ (153,373)	$ (18,479)	$ (69,668)	$ 5,619	$ 7,643	$ 8,756	$ (399,018)		$ (47,650)		$ (2,384)
Net Income From Discontinued Operations, Less Noncontrolling Interests		(164)	34,617	1,570	1,962	1,037	970	1,312	1,681	35,740		961		254
Less: Preferred Stock Dividends	(2,105)	(2,415)	(2,415)	(2,415)	(2,415)	(2,335)				(9,660)		(2,335)
Net Loss Attributable to Common Shareholders	$ (62,246)	$ (100,452)	$ (97,090)	$ (155,167)	$ (20,229)	$ (71,664)	$ 5,694	$ 8,078	$ 8,868	$ (372,938)		$ (49,024)		$ (2,130)
Denominator:
Weighted Average Common Shares Outstanding - Basic	56,003	54,342	53,936	54,118	54,370	53,261	53,214	53,164	52,984	54,392		53,150		52,572
Weighted Average Common Shares Outstanding - Diluted	56,003	54,342	53,936	54,118	54,370	53,261	57,991	53,509	53,503	54,392		53,150		52,572
Earnings per Common Share Attributable to Rex Energy Common Shareholders(a):
Basic - Net Loss From Continuing Operations	$ (1.11)	$ (1.85)	$ (2.44)	$ (2.88)	$ (0.38)	$ (1.35)	$ 0.11	$ 0.14	$ 0.17	$ (7.51)	[1]	$ (0.94)	[1]	$ (0.05)	[1]
- Net Income From Discontinued Operations			0.64	0.01	0.01			0.01		0.66	[1]	0.02	[1]	0.01	[1]
- Net Loss Attributable to Rex Energy Common Shareholders	(1.11)	(1.85)	(1.80)	(2.87)	(0.37)	(1.35)	0.11	0.15	0.17	(6.85)	[1]	(0.92)	[1]	(0.04)	[1]
Diluted - Net Loss From Continuing Operations	(1.11)	(1.85)	(2.44)	(2.88)	(0.38)	(1.35)	0.10	0.14	0.17	(7.51)	[1]	(0.94)	[1]	(0.05)	[1]
- Net Income From Discontinued Operations			0.64	0.01	0.01			0.01		0.66	[1]	0.02	[1]	0.01	[1]
- Net Loss Attributable to Rex Energy Common Shareholders	$ (1.11)	$ (1.85)	$ (1.80)	$ (2.87)	$ (0.37)	$ (1.35)	$ 0.10	$ 0.15	$ 0.17	$ (6.85)	[1]	$ (0.92)	[1]	$ (0.04)	[1]
Scenario, Previously Reported [Member]
Numerator:
Net Income From Discontinued Operations, Less Noncontrolling Interests					$ 665
[1]	All earnings per share amounts are attributable to Rex common shareholders.

Equity Method Investments - Add

Equity Method Investments - Additional Information (Detail) - USD ($)	3 Months Ended									12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule Of Equity Method Investments [Line Items]
Impairment Expense	$ 14,184,000	$ 81,098,000	$ 139,812,000	$ 117,842,000	$ 7,023,000	$ 132,576,000	$ 1,000	$ 16,000	$ 25,000	$ 345,775,000	$ 132,618,000	$ 32,072,000
Contributions to Equity Method Investments												2,493,000
Loss on Equity Method Investments					(203,000)					(411,000)	(813,000)	(763,000)
Equity Method Investments				0		$ 17,895,000					17,895,000
Production and Lease Operating Expense	$ 30,146,000				29,052,000					$ 118,999,000	100,282,000	62,150,000
Rw Gathering Llc
Schedule Of Equity Method Investments [Line Items]
Ownership percentage	40.00%	40.00%								40.00%
Impairment Expense				$ 17,500,000						$ 17,500,000
Contributions to Equity Method Investments	$ 0				0					0
Loss on Equity Method Investments	(500,000)				(500,000)					$ (2,000,000)	$ (2,000,000)	$ (1,900,000)
Impairment charge in percentage				100.00%						100.00%
Production and Lease Operating Expense	200,000				$ 200,000
Receivables	0	$ 0								$ 0
Payables	$ 0	$ 0								$ 0

Impairment Expense - Additional

Impairment Expense - Additional Information (Detail) - USD ($) $ in Thousands

3 Months Ended

12 Months Ended

Mar. 31, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

$ 14,184

$ 81,098

$ 139,812

$ 117,842

$ 7,023

$ 132,576

$ 1

$ 16

$ 25

$ 345,775

$ 132,618

$ 32,072

Illinois Basin

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

$ 103,900

$ 29,300

Production from oil and gas properties

100.00%

Appalachian Basin

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

3,000

205,400

$ 3,600

Undeveloped properties, cost

257,700

Appalachian Basin | Regulatory And Environmental Climate [Member]

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

5,900

Rw Gathering Llc

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

17,500

Proved Properties

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

271,300

113,400

Proved Properties | Illinois Basin

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

3,500

47,700

Proved Properties | Appalachian Basin

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

9,500

Proved Properties | Pennsylvania Impact Fee

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

$ 4,000

Unproved Property Impairments

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

74,500

Unproved Property Impairments | Illinois Basin

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

14,800

8,500

Unproved Property Impairments | Appalachian Basin

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

$ 10,700

59,700

18,900

Unproved Property Impairments | Marcellus And Utica Shale [Member]

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

$ 263,000

Unproved Property Impairments | Lease Agreements [Member] | Appalachian Basin

Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]

Impairment Expense

$ 10,400

Exploration Expense - Additiona

Exploration Expense - Additional Information (Detail) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016USD ($)Well	Mar. 31, 2015USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Exploration Expense [Line Items]
Exploration Expense	$ 993	$ 518	$ 3,011	$ 9,446	$ 11,408
Geological and Geophysical Type Expenditures
Exploration Expense [Line Items]
Exploration Expense	200
Dry Hole Expense For Non Operated Properties | Appalachian Basin
Exploration Expense [Line Items]
Exploration Expense	$ 800
Number of exploratory wells | Well	2

Condensed Consolidating Finan93

Condensed Consolidating Financial Information - Additional Information (Detail) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Senior Notes, Net of Issuance Costs	$ 675	$ 675

Condensed Consolidating Balance

Condensed Consolidating Balance Sheets (Detail) - USD ($) $ in Thousands		Mar. 31, 2016	Dec. 31, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current Assets
Cash and Cash Equivalents		$ 24,891	$ 1,091		$ 4,964	$ 17,978	$ 1,307
Accounts Receivable		24,315	19,483			43,936
Taxes Receivable		18	18			504
Short-Term Derivative Instruments		29,012	34,260			29,265
Assets Held for Sale						34,257
Inventory, Prepaid Expenses and Other		3,168	3,829			3,403
Total Current Assets		81,404	58,681			129,343
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,301,479	1,239,430			1,079,039
Unevaluated Oil and Gas Properties		257,697	262,992			322,413
Other Property and Equipment		41,028	40,112			46,361
Wells and Facilities in Progress		75,514	144,556			127,655
Pipelines		16,780	14,024			15,657
Total Property and Equipment		1,692,498	1,701,114			1,591,125
Less: Accumulated Depreciation, Depletion and Amortization		(720,998)	(699,899)			(366,917)
Net Property and Equipment		971,500	1,001,215			1,224,208
Deferred Financing Costs and Other Assets - Net			16,544			17,070
Other Assets		2,489	2,501
Equity Method Investments				$ 0		17,895
Long-Term Deferred Tax Asset			12,532			8,301
Long-Term Derivative Instruments		8,460	9,534			4,904
Total Assets		1,063,853	1,071,931			1,401,721
Current Liabilities
Accounts Payable		42,818	37,874			53,340
Current Maturities of Long-Term Debt		9,934	590			1,176
Accrued Liabilities		44,296	44,326			59,478
Short-Term Derivative Instruments		3,758	2,486			421
Current deferred tax liability			12,532			8,301
Liabilities Related to Assets Held For Sale						25,115
Total Current Liabilities		100,806	85,276			147,831
Premium (Discount) on Senior Notes - Net		2,245	2,344			2,725
Senior Secured Line of Credit and Other Long-Term Debt		143,294	109,396			251
Long-Term Derivative Instruments		6,908	5,556			2,377
6.25% Senior Notes Due 2022	[1]	657,511	663,089
Other Deposits and Liabilities		3,140	3,156			4,018
Future Abandonment Cost		43,412	42,883			38,146
Total Liabilities		957,316	911,700			870,348
Stockholders' Equity
Preferred Stock		1	1			1
Common Stock		63	54			54
Additional Paid-In Capital		630,301	623,863			617,826
Accumulated Earnings (Deficit)		(523,828)	(463,687)			(90,749)
Rex Energy Stockholders' Equity			160,231			527,132
Noncontrolling Interests						4,241
Total Stockholders' Equity		106,537	160,231			531,373	$ 416,925	$ 412,294
Total Liabilities and Stockholders' Equity		1,063,853	1,071,931			1,401,721
Scenario, Previously Reported [Member]
Property and Equipment (Successful Efforts Method)
Deferred Financing Costs and Other Assets - Net			2,501
Total Assets			1,098,506
Current Liabilities
Total Current Liabilities			97,808
Senior Secured Line of Credit and Other Long-Term Debt			111,528
Total Liabilities			938,275
Stockholders' Equity
Total Liabilities and Stockholders' Equity			1,098,506
Eliminations
Current Assets
Assets Held for Sale						(2,537)
Total Current Assets						(2,537)
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties			(6,970)			(5,760)
Wells and Facilities in Progress			(270)			(560)
Pipelines			(2,137)			(1,898)
Total Property and Equipment			(9,377)			(8,218)
Less: Accumulated Depreciation, Depletion and Amortization			3,518			1,037
Net Property and Equipment			(5,859)			(7,181)
Intercompany Receivables		(1,095,371)	(1,070,548)			(951,025)
Investment in Subsidiaries - Net		130,362	(241,424)			(264,150)
Total Assets		(965,009)				(1,224,893)
Current Liabilities
Accounts Payable						(2,537)
Total Current Liabilities						(2,537)
Intercompany Payables		(1,095,371)	(1,070,548)			(951,025)
Total Liabilities		(1,095,371)				(953,562)
Stockholders' Equity
Additional Paid-In Capital		(177,144)	(173,057)			(256,887)
Accumulated Earnings (Deficit)		307,506	(74,226)			(18,483)
Rex Energy Stockholders' Equity			(247,283)			(275,370)
Noncontrolling Interests						4,039
Total Stockholders' Equity		130,362	(247,283)			(271,331)
Total Liabilities and Stockholders' Equity		(965,009)				(1,224,893)
Eliminations | Scenario, Previously Reported [Member]
Property and Equipment (Successful Efforts Method)
Total Assets			(1,317,831)
Current Liabilities
Total Liabilities			(1,070,548)
Stockholders' Equity
Total Liabilities and Stockholders' Equity			(1,317,831)
8.875% Senior Notes
Current Liabilities
6.25% Senior Notes Due 2022			350,000			350,000
6.25% Senior Notes
Current Liabilities
6.25% Senior Notes Due 2022			325,000			325,000
Guarantor Subsidiaries
Current Assets
Cash and Cash Equivalents		24,888	1,089			17,978
Accounts Receivable		24,252	19,423			43,726
Short-Term Derivative Instruments		29,012	34,260			29,265
Inventory, Prepaid Expenses and Other		3,156	3,804			3,374
Total Current Assets		81,308	58,576			94,343
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,300,678	1,245,626			1,084,332
Unevaluated Oil and Gas Properties		257,697	262,992			321,708
Other Property and Equipment		40,133	39,217			45,466
Wells and Facilities in Progress		75,269	144,587			127,759
Pipelines		16,780	16,161			17,555
Total Property and Equipment		1,690,557	1,708,583			1,596,820
Less: Accumulated Depreciation, Depletion and Amortization		(720,100)	(702,537)			(367,224)
Net Property and Equipment		970,457	1,006,046			1,229,596
Deferred Financing Costs and Other Assets - Net			2,501			2,421
Other Assets		2,489
Equity Method Investments						17,895
Investment in Subsidiaries - Net		(2,388)	(1,907)			4,161
Long-Term Derivative Instruments		8,460	9,534			4,904
Total Assets		1,060,326				1,353,320
Current Liabilities
Accounts Payable		42,818	37,874			55,877
Current Maturities of Long-Term Debt		434	590			1,176
Accrued Liabilities		32,709	32,601			46,783
Short-Term Derivative Instruments		3,758	2,486			421
Total Current Liabilities		79,719				104,257
Senior Secured Line of Credit and Other Long-Term Debt						251
Long-Term Derivative Instruments		6,908	5,556			2,377
Other Deposits and Liabilities		3,140	3,156			4,018
Future Abandonment Cost		42,964	42,443			38,097
Intercompany Payables		1,090,818	1,070,096			947,114
Total Liabilities		1,223,549				1,096,114
Stockholders' Equity
Additional Paid-In Capital		177,144	177,143			177,144
Accumulated Earnings (Deficit)		(340,367)	(297,223)			80,062
Rex Energy Stockholders' Equity			(120,080)			257,206
Total Stockholders' Equity		(163,223)	(120,080)			257,206
Total Liabilities and Stockholders' Equity		1,060,326				1,353,320
Guarantor Subsidiaries | Scenario, Previously Reported [Member]
Property and Equipment (Successful Efforts Method)
Deferred Financing Costs and Other Assets - Net			2,501
Total Assets			1,074,750
Current Liabilities
Total Current Liabilities			73,551
Senior Secured Line of Credit and Other Long-Term Debt			28
Total Liabilities			1,194,830
Stockholders' Equity
Total Liabilities and Stockholders' Equity			1,074,750
Non-Guarantor Subsidiaries
Current Assets
Accounts Receivable		16	11			210
Assets Held for Sale						36,794
Total Current Assets		16	11			37,004
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		801	774			467
Unevaluated Oil and Gas Properties						705
Other Property and Equipment		895	895			895
Wells and Facilities in Progress		245	239			456
Total Property and Equipment		1,941	1,908			2,523
Less: Accumulated Depreciation, Depletion and Amortization		(898)	(880)			(730)
Net Property and Equipment		1,043	1,028			1,793
Investment in Subsidiaries - Net						1,541
Total Assets		1,059				40,338
Current Liabilities
Accrued Liabilities		20				571
Liabilities Related to Assets Held For Sale						25,115
Total Current Liabilities		20				25,686
Future Abandonment Cost		448	440			49
Intercompany Payables		4,553	452			3,911
Total Liabilities		5,021				29,646
Stockholders' Equity
Additional Paid-In Capital						79,743
Accumulated Earnings (Deficit)		(3,962)	147			(69,253)
Rex Energy Stockholders' Equity			147			10,490
Noncontrolling Interests						202
Total Stockholders' Equity		(3,962)	147			10,692
Total Liabilities and Stockholders' Equity		1,059				40,338
Non-Guarantor Subsidiaries | Scenario, Previously Reported [Member]
Property and Equipment (Successful Efforts Method)
Total Assets			1,039
Current Liabilities
Total Liabilities			892
Stockholders' Equity
Total Liabilities and Stockholders' Equity			1,039
Parent Company
Current Assets
Cash and Cash Equivalents		3	2
Accounts Receivable		47	49
Taxes Receivable		18	18			504
Inventory, Prepaid Expenses and Other		12	25			29
Total Current Assets		80	94			533
Property and Equipment (Successful Efforts Method)
Deferred Financing Costs and Other Assets - Net			14,043			14,649
Long-Term Deferred Tax Asset			12,532			8,301
Intercompany Receivables		1,095,371	1,070,548			951,025
Investment in Subsidiaries - Net		(127,974)	243,331			258,448
Total Assets		967,477				1,232,956
Current Liabilities
Current Maturities of Long-Term Debt		9,500
Accrued Liabilities		11,567	11,725			12,124
Current deferred tax liability			12,532			8,301
Total Current Liabilities		21,067				20,425
Premium (Discount) on Senior Notes - Net		2,245	2,344			2,725
Senior Secured Line of Credit and Other Long-Term Debt		143,294
6.25% Senior Notes Due 2022		657,511
Total Liabilities		824,117				698,150
Stockholders' Equity
Preferred Stock		1	1			1
Common Stock		63	54			54
Additional Paid-In Capital		630,301	619,777			617,826
Accumulated Earnings (Deficit)		(487,005)	(92,385)			(83,075)
Rex Energy Stockholders' Equity			527,447			534,806
Total Stockholders' Equity		143,360	527,447			534,806
Total Liabilities and Stockholders' Equity		$ 967,477				1,232,956
Parent Company | Scenario, Previously Reported [Member]
Property and Equipment (Successful Efforts Method)
Total Assets			1,340,548
Current Liabilities
Total Current Liabilities			24,257
Senior Secured Line of Credit and Other Long-Term Debt			111,500
Total Liabilities			813,101
Stockholders' Equity
Total Liabilities and Stockholders' Equity			1,340,548
Parent Company | 8.875% Senior Notes
Current Liabilities
6.25% Senior Notes Due 2022			350,000			350,000
Parent Company | 6.25% Senior Notes
Current Liabilities
6.25% Senior Notes Due 2022			$ 325,000			$ 325,000
[1]	Includes unamortized debt issuance costs of approximately $11.1 million and $11.9 million as of March 31, 2016 and December 31, 2015, respectively.

Condensed Consolidating Stateme

Condensed Consolidating Statements of Operations (Detail) - USD ($) $ in Thousands	3 Months Ended									12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$ 30,494				$ 54,111					$ 171,951	$ 297,869	$ 213,919
Other Revenue	13				11					42	118	200
TOTAL OPERATING REVENUE	30,507	$ 34,526	$ 37,573	$ 45,772	54,122	$ 70,245	$ 73,466	$ 72,933	$ 81,343	171,993	297,987	214,119
OPERATING EXPENSES
Production and Lease Operating Expense	30,146				29,052					118,999	100,282	62,150
General and Administrative Expense	6,063				9,651					29,435	36,137	30,839
Gain on Disposal of Asset	(30)				65					(477)	644	1,602
Impairment Expense	14,184	81,098	139,812	117,842	7,023	132,576	1	16	25	345,775	132,618	32,072
Exploration Expense	993				518					3,011	9,446	11,408
Depreciation, Depletion, Amortization and Accretion	19,408				26,126					104,744	94,467	62,386
Other Operating Expense	329				5,191					5,595	134	592
TOTAL OPERATING EXPENSES	71,093				77,626					607,082	373,728	201,049
INCOME (LOSS) FROM OPERATIONS	(40,586)				(23,504)					(435,089)	(75,741)	13,070
OTHER INCOME (EXPENSE)
Interest Expense	(13,032)				(12,017)					(47,806)	(36,977)	(22,676)
Gain on Derivatives, Net	4,049				17,119					60,176	38,876	(2,908)
Other Expense					34					(115)	90	6,739
Debt Exchange Expense	(8,480)
Loss From Equity Method Investments					(203)					(411)	(813)	(763)
TOTAL OTHER INCOME (EXPENSE)	(17,463)				4,933					11,844	1,176	(19,608)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(58,049)				(18,571)					(423,245)	(74,565)	(6,538)
Income Tax (Expense) Benefit	(2,092)				92					24,227	26,915	4,154
INCOME (LOSS) FROM CONTINUING OPERATIONS	(60,141)	(97,873)	(129,293)	(153,373)	(18,479)	(69,668)	5,619	7,643	8,756	(399,018)	(47,650)	(2,384)
Income (Loss) From Discontinued Operations, Net of Income Tax					1,962					37,985	5,000	1,811
NET INCOME (LOSS)	(60,141)	(98,037)	(94,676)	(151,803)	(16,517)	(68,631)	6,589	8,955	10,437	(361,033)	(42,650)	(573)
Net Income Attributable to Noncontrolling Interests of Discontinued Operations			(1)	949	1,297	698	895	877	1,569	2,245	4,039	1,557
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	(60,141)	(98,037)	(94,675)	(152,752)	(17,814)	(69,329)	5,694	8,078	8,868	(363,278)	(46,689)	(2,130)
Preferred Stock Dividends	2,105	2,415	2,415	2,415	2,415	2,335				9,660	2,335
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	(62,246)	$ (100,452)	$ (97,090)	$ (155,167)	(20,229)	$ (71,664)	$ 5,694	$ 8,078	$ 8,868	(372,938)	(49,024)	(2,130)
Eliminations
OPERATING EXPENSES
Impairment Expense										(1,513)
Exploration Expense										(5)
Depreciation, Depletion, Amortization and Accretion					(235)					(969)	(689)	(200)
TOTAL OPERATING EXPENSES					(235)					(2,487)	(689)	(200)
INCOME (LOSS) FROM OPERATIONS					235					2,487	689	200
OTHER INCOME (EXPENSE)
Income (Loss) From Equity in Consolidated Subsidiaries	38,151				3,214					313,198	20,204	(5,703)
TOTAL OTHER INCOME (EXPENSE)	38,151				3,214					313,198	20,204	(5,703)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX	38,151				3,449					315,685	20,893	(5,503)
INCOME (LOSS) FROM CONTINUING OPERATIONS					3,449					315,685	20,893	(5,503)
Income (Loss) From Discontinued Operations, Net of Income Tax					(864)					(1,192)	(4,330)	(2,574)
NET INCOME (LOSS)	38,151				2,585					314,493	16,563	(8,077)
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY					2,585					314,493	16,563	(8,077)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	38,151				2,585					314,493
Guarantor Subsidiaries
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	30,463				54,000					171,440	297,710	213,919
Other Revenue	13				11					42	118	200
TOTAL OPERATING REVENUE	30,476				54,011					171,482	297,828	214,119
OPERATING EXPENSES
Production and Lease Operating Expense	30,121				29,014					118,825	100,261	62,138
General and Administrative Expense	6,068				6,659					22,879	30,317	25,376
Gain on Disposal of Asset	(30)				65					(477)	644	1,601
Impairment Expense	14,184				7,012					345,892	126,662	32,072
Exploration Expense	993				518					2,879	9,165	11,395
Depreciation, Depletion, Amortization and Accretion	19,379				26,292					105,556	94,643	62,540
Other Operating Expense	329				5,191					5,595	134	592
TOTAL OPERATING EXPENSES	71,044				74,751					601,149	361,826	195,714
INCOME (LOSS) FROM OPERATIONS	(40,568)				(20,740)					(429,667)	(63,998)	18,405
OTHER INCOME (EXPENSE)
Interest Expense	(273)				(58)					(271)	(142)	(64)
Gain on Derivatives, Net	4,049				16,856					59,242	37,359	(2,703)
Other Expense					34					(115)	90	6,739
Loss From Equity Method Investments					(203)					(411)	(813)	(763)
Income (Loss) From Equity in Consolidated Subsidiaries	(25)				(23)					(1,324)	(4,278)	(33)
TOTAL OTHER INCOME (EXPENSE)	3,751				16,606					57,121	32,216	3,176
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(36,817)				(4,134)					(372,546)	(31,782)	21,581
Income Tax (Expense) Benefit	(1,326)				20					21,122	9,928	(14,409)
INCOME (LOSS) FROM CONTINUING OPERATIONS					(4,114)					(351,424)	(21,854)	7,172
NET INCOME (LOSS)	(38,143)				(4,114)					(351,424)	(21,854)	7,172
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY					(4,114)					(351,424)	(21,854)	7,172
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	(38,143)				(4,114)					(351,424)
Non-Guarantor Subsidiaries
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	31				111					511	159
TOTAL OPERATING REVENUE	31				111					511	159
OPERATING EXPENSES
Production and Lease Operating Expense	25				38					174	21	12
General and Administrative Expense	9				16					52	83	43
Gain on Disposal of Asset												1
Impairment Expense					11					1,396	5,956
Exploration Expense										137	281	13
Depreciation, Depletion, Amortization and Accretion	29				69					157	513	46
TOTAL OPERATING EXPENSES	63				134					1,916	6,854	115
INCOME (LOSS) FROM OPERATIONS	(32)				(23)					(1,405)	(6,695)	(115)
OTHER INCOME (EXPENSE)
Income (Loss) From Equity in Consolidated Subsidiaries	25				23					1,324	4,278	33
TOTAL OTHER INCOME (EXPENSE)	25				23					1,324	4,278	33
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(7)									(81)	(2,417)	(82)
Income Tax (Expense) Benefit	(1)									81	2,417	(1,841)
INCOME (LOSS) FROM CONTINUING OPERATIONS												(1,923)
Income (Loss) From Discontinued Operations, Net of Income Tax					2,826					3,908	9,330	4,385
NET INCOME (LOSS)	(8)				2,826					3,908	9,330	2,462
Net Income Attributable to Noncontrolling Interests of Discontinued Operations					1,297					2,245	4,039	1,557
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY					1,529					1,663	5,291	905
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	(8)				1,529					1,663
Parent Company
OPERATING EXPENSES
General and Administrative Expense	(14)				2,976					6,504	5,737	5,420
TOTAL OPERATING EXPENSES	(14)				2,976					6,504	5,737	5,420
INCOME (LOSS) FROM OPERATIONS	14				(2,976)					(6,504)	(5,737)	(5,420)
OTHER INCOME (EXPENSE)
Interest Expense	(12,759)				(11,959)					(47,535)	(36,835)	(22,612)
Gain on Derivatives, Net					263					934	1,517	(205)
Debt Exchange Expense	(8,480)
Income (Loss) From Equity in Consolidated Subsidiaries	(38,151)				(3,214)					(313,198)	(20,204)	5,703
TOTAL OTHER INCOME (EXPENSE)	(59,390)				(14,910)					(359,799)	(55,522)	(17,114)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(59,376)				(17,886)					(366,303)	(61,259)	(22,534)
Income Tax (Expense) Benefit	(765)				72					3,024	14,570	20,404
INCOME (LOSS) FROM CONTINUING OPERATIONS					(17,814)					(363,279)	(46,689)	(2,130)
Income (Loss) From Discontinued Operations, Net of Income Tax										35,269
NET INCOME (LOSS)	(60,141)				(17,814)					(328,010)	(46,689)	(2,130)
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY					(17,814)					(328,010)	$ (46,689)	$ (2,130)
Preferred Stock Dividends	2,105				2,415					9,660
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (62,246)				$ (20,229)					$ (337,670)

Condensed Consolidating State96

Condensed Consolidating Statements of Cash Flows (Detail) - USD ($) $ in Thousands	3 Months Ended									12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$ (60,141)	$ (98,037)	$ (94,676)	$ (151,803)	$ (16,517)	$ (68,631)	$ 6,589	$ 8,955	$ 10,437	$ (361,033)	$ (42,650)	$ (573)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss from Equity Method Investments					203					411	813	763
Non-Cash Expenses	497				3,377					7,649	6,789	6,230
Depreciation, Depletion, Amortization and Accretion	19,408				26,165					104,822	98,171	63,944
Deferred Income Tax Benefit	2,092										(25,992)	2,279
Gain on Derivatives	(4,049)				(17,119)					(60,176)	(38,876)	2,908
Cash Settlements of Derivatives	12,994				11,079					55,793	7,281	7,128
Dry Hole Expense										330	4,064	2,993
Dry Hole Expense	843				(1)					330	4,064	2,993
(Gain) Loss on Sale of Asset	(30)				33					(521)	589	(6,211)
Gain on Sale of Water Solutions										(57,778)
Impairment Expense	14,184				7,023					345,775	132,684	32,072
Changes in operating assets and liabilities
Accounts Receivable	(4,873)				10,029					21,679	(13,620)	(12,726)
Inventory, Prepaid Expenses and Other Assets	660				328					(568)	(1,359)	(885)
Accounts Payable and Accrued Liabilities	(308)				(12,929)					(22,955)	37,274	12,891
Other Assets and Liabilities	(170)				(305)					(2,543)	(2,462)	(2,497)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	(18,893)				11,366					30,885	162,706	108,316
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management					39					58	263	458
Contributions to Equity Method Investments												(2,493)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	71				672					77,226	546	11,305
Proceeds from Joint Venture	19,461				16,611					16,611
Acquisitions of Undeveloped Acreage	(5,266)				(17,459)					(28,242)	(169,423)	(41,784)
Capital Expenditures for Development of Oil and Gas Properties and Equipment	(15,068)				(67,013)					(221,099)	(391,422)	(281,004)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(802)				(67,150)					(155,446)	(560,036)	(313,518)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit	46,500				72,826					229,314	209,895	72,249
Repayments of Long-Term Debt and Lines of Credit					(25,761)					(108,335)	(263,152)	(8,480)
Repayments of Loans and Other Long-Term Debt	(184)				(686)					(1,519)	(2,721)	(2,005)
Proceeds from Senior Notes, net of Discounts and Premiums											325,000	105,000
Debt Issuance Costs	(2,821)				(459)					(1,414)	(6,824)	(3,134)
Proceeds from Issuance of Preferred Stock, Net											154,988
Proceeds from the Exercise of Stock Options											515	533
Purchase of Non-Controlling Interests											(1,840)	(150)
Distributions by the Partners of Consolidated Subsidiaries					(531)					(830)	(1,840)	(886)
Dividends Paid					(2,415)					(9,660)	(2,335)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	43,495				42,974					107,556	413,526	163,127
NET (DECREASE) IN CASH	23,800				(12,810)					(17,005)	16,196	(42,075)
CASH - BEGINNING	1,091			5,286	18,096				1,900	18,096	1,900	43,975
CASH - ENDING	24,891	1,091			5,286	18,096				1,091	18,096	1,900
Eliminations
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	38,151				2,585					314,493	16,563	(8,077)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Depreciation, Depletion, Amortization and Accretion					(1,607)					(3,963)	(689)	(200)
Dry Hole Expense										(5)
Impairment Expense	(14,184)									(347,405)
Changes in operating assets and liabilities
Accounts Receivable					251					(2,537)	(766)	(1,575)
Accounts Payable and Accrued Liabilities					(251)					2,537	766	1,982
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	23,967				978					(36,880)	15,874	(7,870)
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries	(23,967)				(1,823)					35,716	(20,202)	5,307
Capital Expenditures for Development of Oil and Gas Properties and Equipment					845					1,164	4,328	2,563
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(23,967)				(978)					36,880	(15,874)	7,870
Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	(38,143)				(4,114)					(351,424)	(21,854)	7,172
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss from Equity Method Investments					203					411	813	763
Non-Cash Expenses	(30)				(70)					(201)	(273)	(194)
Depreciation, Depletion, Amortization and Accretion	19,379				26,292					105,555	94,643	62,540
Deferred Income Tax Benefit	1,326										(9,928)	14,409
Gain on Derivatives	(4,049)				(16,856)					(59,242)	(37,359)	2,703
Cash Settlements of Derivatives	12,994				10,579					54,859	5,969	7,128
Dry Hole Expense										199	3,797	2,993
Dry Hole Expense	843				(1)
(Gain) Loss on Sale of Asset	(30)				65					(477)	644	(5,289)
Impairment Expense	14,184				7,012					345,892	126,662	32,072
Changes in operating assets and liabilities
Accounts Receivable	15,852				10,437					24,240	(11,450)	(5,877)
Inventory, Prepaid Expenses and Other Assets	648				712					(431)	(1,283)	(826)
Accounts Payable and Accrued Liabilities	1,922				(12,518)					(20,008)	23,768	8,554
Other Assets and Liabilities	(170)				(199)					(2,497)	(2,127)	(2,272)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	24,726				21,542					96,876	172,022	123,876
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries	27				27,192					103,212	397,382	186,089
Proceeds from Joint Venture Acreage Management					39					58	263	458
Contributions to Equity Method Investments												(2,493)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	71				217					9,766	254	8,071
Proceeds from Joint Venture	19,461				16,611					16,611
Acquisitions of Undeveloped Acreage	(5,266)				(17,454)					(27,963)	(168,713)	(41,782)
Capital Expenditures for Development of Oil and Gas Properties and Equipment	(15,036)				(60,719)					(214,450)	(382,889)	(275,697)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(743)				(34,114)					(112,766)	(153,703)	(125,354)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Loans and Other Long-Term Debt	(184)				(392)					(999)	(1,727)	(1,363)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(184)				(392)					(999)	(1,727)	(1,363)
NET (DECREASE) IN CASH	23,799				(12,964)					(16,889)	16,592	(2,841)
CASH - BEGINNING	1,089			5,014	17,978				1,386	17,978	1,386	4,227
CASH - ENDING	24,888	1,089			5,014	17,978				1,089	17,978	1,386
Non-Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	(8)				2,826					3,908	9,330	2,462
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Non-Cash Expenses					44					(334)	278	55
Depreciation, Depletion, Amortization and Accretion	29				1,480					3,230	4,217	1,604
Deferred Income Tax Benefit	1										(1,649)	2,210
Dry Hole Expense										136	267
(Gain) Loss on Sale of Asset					(32)					(44)	(55)	(922)
Impairment Expense					11					1,396	6,022
Changes in operating assets and liabilities
Accounts Receivable	10				(1,087)					(453)	(6,090)	(6,515)
Inventory, Prepaid Expenses and Other Assets					(322)					(142)	(74)	(59)
Accounts Payable and Accrued Liabilities	21				(2,496)					(4,969)	3,488	874
Other Assets and Liabilities					(133)					(73)	(335)	(88)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	53				291					2,655	15,399	(379)
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries	(21)				(1,688)					(3,362)	(5,412)	1,619
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets					455					560	292	3,234
Acquisitions of Undeveloped Acreage					(5)					(279)	(710)	(2)
Capital Expenditures for Development of Oil and Gas Properties and Equipment	(32)				(7,139)					(7,813)	(12,861)	(7,870)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(53)				(8,377)					(10,894)	(18,691)	(3,019)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit					18,826					35,814	38,895	7,249
Repayments of Long-Term Debt and Lines of Credit					(9,761)					(26,335)	(33,152)	(2,480)
Repayments of Loans and Other Long-Term Debt					(294)					(520)	(994)	(642)
Debt Issuance Costs										(3)	(8)	(8)
Purchase of Non-Controlling Interests											(1,840)	(150)
Distributions by the Partners of Consolidated Subsidiaries					(531)					(830)		(886)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES					8,240					8,126	2,901	3,083
NET (DECREASE) IN CASH					154					(113)	(391)	(315)
CASH - BEGINNING				267	113				504	113	504	819
CASH - ENDING					267	113					113	504
Parent Company
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	(60,141)				(17,814)					(328,010)	(46,689)	(2,130)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Non-Cash Expenses	527				3,403					8,184	6,784	6,369
Deferred Income Tax Benefit	765										(14,415)	(14,340)
Gain on Derivatives					(263)					(934)	(1,517)	205
Cash Settlements of Derivatives					500					934	1,312
Gain on Sale of Water Solutions										(57,778)
Impairment Expense	14,184									345,892
Changes in operating assets and liabilities
Accounts Receivable	(20,735)				428					429	4,686	1,241
Inventory, Prepaid Expenses and Other Assets	12				(62)					5	(2)
Accounts Payable and Accrued Liabilities	(2,251)				2,336					(515)	9,252	1,481
Other Assets and Liabilities					27					27		(137)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	(67,639)				(11,445)					(31,766)	(40,589)	(7,311)
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries	23,961				(23,681)					(135,566)	(371,768)	(193,015)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets										66,900
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	23,961				(23,681)					(68,666)	(371,768)	(193,015)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit	46,500				54,000					193,500	171,000	65,000
Repayments of Long-Term Debt and Lines of Credit					(16,000)					(82,000)	(230,000)	(6,000)
Proceeds from Senior Notes, net of Discounts and Premiums											325,000	105,000
Debt Issuance Costs	(2,821)				(459)					(1,411)	(6,816)	(3,126)
Proceeds from Issuance of Preferred Stock, Net											154,988
Proceeds from the Exercise of Stock Options											515	533
Dividends Paid					(2,415)					(9,660)	(2,335)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	43,679				35,126					100,429	412,352	161,407
NET (DECREASE) IN CASH	1									(3)	(5)	(38,919)
CASH - BEGINNING	2			$ 5	5				$ 10	5	10	38,929
CASH - ENDING	$ 3	$ 2			$ 5	$ 5				$ 2	$ 5	$ 10

Subsequent Events - Additional

Subsequent Events - Additional Information (Detail)	Apr. 01, 2016USD ($)	Mar. 15, 2016bblMcf	Mar. 14, 2016USD ($)shares	Mar. 01, 2016USD ($)Well	Feb. 03, 2016USD ($)	Apr. 30, 2016USD ($)Exchangeshares	Mar. 31, 2016USD ($)sharesbblMcf	Dec. 31, 2015USD ($)bblMcf
Subsequent Event [Line Items]
Line of credit facility, amount outstanding							$ 158,000,000	$ 111,500,000	[1]
Initial conversion share of common stock | shares			10,125,000				10,100,000
Rate multiplied by undrawn letter of credit amount to calculate reduction of borrowing base in effect			0.50
Letter Of Credit
Subsequent Event [Line Items]
Line of credit facility, remaining borrowing capacity							$ 41,000,000	$ 41,000,000
Natural Gas
Subsequent Event [Line Items]
Volume | Mcf							154,080,000	154,875,000
Natural Gas Liquids
Subsequent Event [Line Items]
Volume | bbl							1,671,000	1,551,000
Senior Credit Facility
Subsequent Event [Line Items]
Line of credit facility, maximum borrowing capacity					$ 200,000,000		$ 200,000,000	$ 350,000,000
Line of credit facility, amount outstanding							158,000,000
Line of credit facility, remaining borrowing capacity							1,000,000
Commitment fee					0.50%
Liens covering the oil and gas properties, percentage			95.00%
Senior Credit Facility | Letter Of Credit
Subsequent Event [Line Items]
Line of credit facility, maximum borrowing capacity							60,000,000	$ 60,000,000
Line of credit facility, remaining borrowing capacity							$ 41,000,000
Benefit Street Partners Limited Liability Corporation
Subsequent Event [Line Items]
Percentage of working interest				65.00%
Total consideration for the transaction				$ 175,000,000
Amount received at closing of wells				$ 37,100,000
Benefit Street Partners Limited Liability Corporation | Drillco
Subsequent Event [Line Items]
Number of specifically designated wells for development | Well				36
Percentage of working interest				65.00%
Percentage of estimated well costs				15.00%
Joint Development Agreement [Member]
Subsequent Event [Line Items]
Total consideration for the transaction				$ 175,000,000
Amount received at closing of wells				$ 37,300,000
Number of wells committed | Well				22
Number of wells flowing in to sales | Well				15
Received reimbursement				$ 19,500,000
Crude Oil
Subsequent Event [Line Items]
Volume | bbl							730,750	544,500
Moraine East And Warrior North
Subsequent Event [Line Items]
Liens covering the oil and gas properties, percentage			100.00%
Moraine East And Warrior North | Senior Credit Facility
Subsequent Event [Line Items]
Liens covering the oil and gas properties, percentage			100.00%
Moraine East And Warrior North | Benefit Street Partners Limited Liability Corporation
Subsequent Event [Line Items]
Number of specifically designated wells for development | Well				58
Moraine East And Warrior North | Benefit Street Partners Limited Liability Corporation | Drillco
Subsequent Event [Line Items]
Number of specifically designated wells for development | Well				58
Moraine East | Benefit Street Partners Limited Liability Corporation | Drillco
Subsequent Event [Line Items]
Number of specifically designated wells for development | Well				16
Percentage of working interest				15.00%
Number of specifically designated wells drilled | Well				12
Warrior North | Benefit Street Partners Limited Liability Corporation | Drillco
Subsequent Event [Line Items]
Number of specifically designated wells for development | Well				6
Percentage of working interest				65.00%
Number of specifically designated wells drilled | Well				3
Percentage of estimated well costs				65.00%
Maximum
Subsequent Event [Line Items]
Senior notes offered for exchange			$ 675,000,000				$ 675,000,000
Additional new notes			$ 6,000,000
Margin rate					3.25%			2.50%
Liens covering the oil and gas properties, percentage			95.00%
Maximum | Senior Notes
Subsequent Event [Line Items]
Criteria of net senior secured debt to EBITDAX							300.00%
Maximum | Senior Credit Facility
Subsequent Event [Line Items]
Criteria of net senior secured debt to EBITDAX			300.00%				275.00%	300.00%
Restricted Cash and Cash Equivalents			$ 15,000,000
Maximum | Moraine East And Warrior North | Benefit Street Partners Limited Liability Corporation | Drillco
Subsequent Event [Line Items]
Percentage of working interest attained through return on investment and internal rate of return				20.00%
Interest Payments One Through Three
Subsequent Event [Line Items]
Debt Instrument, Frequency of Periodic Payment							semi-annual	Bi-annual
Interest Payments Four And Thereafter
Subsequent Event [Line Items]
Debt Instrument, Frequency of Periodic Payment								Bi-annual
Minimum
Subsequent Event [Line Items]
Percentage of senior notes exchanged for new notes.			80.00%
Margin rate					2.25%			1.50%
Net senior secured debt to EBITDAX			275.00%
Liens covering the oil and gas properties, percentage			90.00%
Minimum | Senior Credit Facility
Subsequent Event [Line Items]
Net senior secured debt to EBITDAX							210.00%	170.00%
Minimum | Moraine East And Warrior North | Benefit Street Partners Limited Liability Corporation | Drillco
Subsequent Event [Line Items]
Percentage of working interest attained through return on investment and internal rate of return				15.00%
Commodity derivatives | 2016 | Natural Gas
Subsequent Event [Line Items]
Volume | Mcf		2,740,000
Commodity derivatives | 2016 | Natural Gas Liquids
Subsequent Event [Line Items]
Volume | bbl		120,000
Commodity derivatives | Crude Oil | 2016
Subsequent Event [Line Items]
Volume | bbl		380,000
6.0% convertible perpetual preferred stock, Series A
Subsequent Event [Line Items]
Initial conversion share of common stock | shares							3,264
2020 Senior Notes
Subsequent Event [Line Items]
Debt issued aggregate principal amount							$ 324,000,000
2022 Senior Notes
Subsequent Event [Line Items]
Debt issued aggregate principal amount							309,100,000
New Notes
Subsequent Event [Line Items]
Percentage of senior notes exchanged for new notes.			1.00%
Debt Instrument, Maturity Date Range, Start			Oct. 1, 2020
Debt Instrument, Maturity Date Range, End			Oct. 1, 2021
Debt issued aggregate principal amount							$ 633,700,000
New Notes | Senior Notes
Subsequent Event [Line Items]
Debt issued aggregate principal amount								$ 675,000,000
New Notes | Interest Payments One Through Three
Subsequent Event [Line Items]
Debt Instrument Interest Rate Stated Percentage			0.00%				1.00%
New Notes | Interest Payments Four And Thereafter
Subsequent Event [Line Items]
Debt Instrument Interest Rate Stated Percentage			8.00%				8.00%
New Notes | Minimum
Subsequent Event [Line Items]
Minimum Threshold For Increase In Stated Interest Rate, Percentage Tendered in Exchange			85.00%
Subsequent Event
Subsequent Event [Line Items]
Number of privately negotiated exchange for shares | Exchange						2
Debt converted to common stock | shares						7,100,000
Subsequent Event | Senior Credit Facility
Subsequent Event [Line Items]
Line of credit facility, maximum borrowing capacity	$ 190,000,000
Payment of down borrowings under Senior Credit Facility	$ 9,500,000
Subsequent Event | 6.0% convertible perpetual preferred stock, Series A
Subsequent Event [Line Items]
Preferred shares, amount						$ 13,800,000
Subsequent Event | 2020 Senior Notes
Subsequent Event [Line Items]
Debt amount for conversion						17,200,000
Subsequent Event | 2022 Senior Notes
Subsequent Event [Line Items]
Debt amount for conversion						9,700,000
Subsequent Event | New Notes
Subsequent Event [Line Items]
Debt amount for conversion						$ 2,200,000
[1]	The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2015, 2014 and 2013 was approximately 1.7%, 2.2 % and 1.9%, respectively. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2015, 2014 and 2013 was approximately 5.5%, 4.0% and 5.3%, respectively.

Summary of Significant Accoun98

Summary of Significant Accounting Policies - Additional Information (Detail) $ in Thousands	3 Months Ended										12 Months Ended
	Mar. 31, 2016USD ($)shares		Dec. 31, 2015USD ($)shares	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)shares	Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2015USD ($)Customershares	Dec. 31, 2014USD ($)Customershares	Dec. 31, 2013USD ($)shares	Dec. 31, 2012shares
Accounting Policies [Line Items]
Accounts Receivable	$ 24,315		$ 19,483				$ 43,936				$ 19,483	$ 43,936
Number of customers | Customer											4	4
Capitalized interest costs											$ 7,700	$ 7,300	$ 7,500
Impairment Expense	14,184		81,098	$ 139,812	$ 117,842	$ 7,023	132,576	$ 1	$ 16	$ 25	345,775	132,618	32,072
Deferred financing costs and other assets			16,500								16,500
Amortization expense											2,000	1,500	1,200
Debt issuance costs											1,400	6,800
Debt issuance costs, accumulated amortization			6,580				4,564				6,580	4,564
Accretion expense	856					$ 900					3,821	3,621	3,000
Future Abandonment Costs	$ 45,782	[1]	$ 45,074				$ 40,099				45,074	40,099	$ 28,525
Increase in estimated present value of asset retirement obligations											$ 2,428	$ 8,426
Income tax examination minimum likelihood of tax benefits being realized upon ultimate settlement											50.00%
Common Stock, shares outstanding | shares	66,041,227		55,741,229				54,174,763				55,741,229	54,174,763
Options outstanding | shares	1,295,094		443,672				402,561				443,672	402,561	449,087	502,253
Deferred financing costs, net			$ 14,043				$ 14,648				$ 14,043	$ 14,648
Stock Appreciation Rights (SARs)
Accounting Policies [Line Items]
Other than Options outstanding | shares			20,500								20,500
Restricted Stock
Accounting Policies [Line Items]
Other than Options outstanding | shares	2,410,917		2,479,408				1,519,301				2,479,408	1,519,301	2,172,639	1,431,573
Performance Based Restricted Stock Awards
Accounting Policies [Line Items]
Other than Options outstanding | shares			1,065,296								1,065,296
Warrant [Member]
Accounting Policies [Line Items]
Share based compensation, warrants outstanding | shares			0								0
Accrued Liabilities
Accounting Policies [Line Items]
Future Abandonment Costs			$ 2,200				$ 2,000				$ 2,200	$ 2,000
Minimum
Accounting Policies [Line Items]
Service properties, equipment and other assets, estimated useful lives											3 years
Payment period for oil and natural gas purchases after end of each production month											30 days
Maximum
Accounting Policies [Line Items]
Service properties, equipment and other assets, estimated useful lives											40 years
Payment period for oil and natural gas purchases after end of each production month											60 days
Deferred Financing Costs | Minimum
Accounting Policies [Line Items]
Estimated lives of intangible assets											5 years
Deferred Financing Costs | Maximum
Accounting Policies [Line Items]
Estimated lives of intangible assets											8 years
Sumitomo Corporation and ArcLight Capital Partners, LLC.
Accounting Policies [Line Items]
Receivable from related party			3,200				6,700				$ 3,200	6,700
Oil And Gas Production
Accounting Policies [Line Items]
Accounts Receivable			12,100				25,200				12,100	25,200
Oil And Gas Production | Major Customers
Accounting Policies [Line Items]
Accounts Receivable			$ 10,500				$ 21,400				$ 10,500	$ 21,400
[1]	Includes approximately $2.4 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

Summary of Deferred Financing C

Summary of Deferred Financing Costs (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Deferred Financing Costs - Gross	$ 20,623	$ 19,212
Accumulated Amortization	(6,580)	(4,564)
Deferred Financing Costs - Net	$ 14,043	$ 14,648

Asset Retirement Obligations (D

Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Mar. 31, 2016		Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
Beginning Balance	$ 45,074		$ 40,099	$ 40,099	$ 28,525
Asset Retirement Obligation Incurred	402			1,135	1,480
Asset Retirement Obligation Settled	(361)			(2,273)	(1,943)
Asset Retirement Obligation Cancelled or Sold Properties	(189)			(136)	(10)
Asset Retirement Obligation Revision of Estimated Obligation				2,428	8,426
Asset Retirement Obligation Accretion Expense	856		$ 900	3,821	3,621	$ 3,000
Total Future Abandonment Cost	$ 45,782	[1]		$ 45,074	$ 40,099	$ 28,525
[1]	Includes approximately $2.4 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

Summary of Acquisition Price Al

Summary of Acquisition Price Allocated (Detail) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Purchase Price	$ 120,563	$ 221,099	$ 391,422	$ 281,004
Evaluated Oil and Gas Properties
Business Acquisition [Line Items]
Purchase Price	6,968
Unevaluated Oil and Gas Properties
Business Acquisition [Line Items]
Purchase Price	88,351
Wells and Facilities in Progress
Business Acquisition [Line Items]
Purchase Price	$ 25,244

Summary of Carrying Value of As

Summary of Carrying Value of Assets and Liabilities (Detail) - USD ($) $ in Thousands	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Assets:
Cash and Cash Equivalents	$ 322	$ 118	$ 593
Total Current Assets		34,257
Liabilities:
Total Liabilities Related to Assets Held for Sale		25,115
Water Solutions Holdings, LLC
Assets:
Cash and Cash Equivalents		118
Accounts Receivable		13,226
Inventory, Prepaid Expenses and Other		163
Total Current Assets		13,507
Other Property and Equipment, Net		19,690
Wells and Facilities in Progress		688
Intangible Assets, Net		372
Total Long-Term Assets		20,750
Total Assets Held for Sale		34,257
Liabilities:
Accounts Payable		3,694
Current Maturities of Long-Term Debt		6,236
Accrued Liabilities		6,304
Total Current Liabilities		16,234
Senior Secured Line of Credit and Long-Term Debt		8,881
Long-Term Liabilities		8,881
Total Liabilities Related to Assets Held for Sale		25,115
Net Assets Held for Sale:		$ 9,142

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) $ / Hours in Millions	Feb. 03, 2016	Jun. 27, 2012USD ($)	Jun. 30, 2007USD ($)	Sep. 30, 2015USD ($)	Dec. 31, 2015USD ($)Aircraft$ / Hours	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Minimum
Related Party Transaction [Line Items]
Interest rate on bank loan	2.25%				1.50%
Maximum
Related Party Transaction [Line Items]
Interest rate on bank loan	3.25%				2.50%
Charlie Brown Air Corp
Related Party Transaction [Line Items]
Number of aircrafts in related party transaction | Aircraft					1,000,000
Payments for use of aircrafts					$ 100,000	$ 100,000
Charlie Brown Air Corp | Minimum
Related Party Transaction [Line Items]
Aircraft use right, variable per hour flight rate | $ / Hours					700
Charlie Brown Air Corp | Maximum
Related Party Transaction [Line Items]
Aircraft use right, variable per hour flight rate | $ / Hours					1,560
Charlie Brown Air Two LLC
Related Party Transaction [Line Items]
Number of aircrafts in related party transaction | Aircraft					1
Percentage of membership interest					50.00%
Amount of loan guaranteed			$ 800,000
Loan interest and retainer fees					$ 300,000	200,000	$ 200,000
Charlie Brown Air Two LLC | Related Party Debt
Related Party Transaction [Line Items]
Bank loan			$ 1,500,000		1,000,000	1,100,000
Charlie Brown Air Two LLC | LIBOR | Maximum | Related Party Debt
Related Party Transaction [Line Items]
Interest rate on bank loan			2.50%
Shaner Office Holdings, L.P.
Related Party Transaction [Line Items]
Due to or from related party					0
Monthly rental payments		$ 35,000
Annual CPI adjustment capped		2.50%
Lease term		5 years
Operating lease annual rent					500,000
Land acquired from related party				$ 600,000
Rw Gathering Llc
Related Party Transaction [Line Items]
Due to or from related party					0	0	0
Production and Lease Operating Expense					$ 700	700	800
Ownership interest percentage					40.00%
Water Solutions Holding
Related Party Transaction [Line Items]
Water transfer and water purification expenses					$ 6,100,000	20,100,000	10,700,000
Water transfer and water purification expenses eliminated in consolidation					$ 4,700,000	16,200,000	$ 8,800,000
Due to related party						$ 1,300,000

Long-Term Debt - Senior Notes D

Long-Term Debt - Senior Notes Due Twenty Twenty and Senior Notes Due Twenty Twenty Two - Additional Information (Detail) - USD ($) $ in Thousands	Jul. 17, 2014	Apr. 26, 2013	Dec. 12, 2012	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Proceeds from Senior Notes, net of Discounts and Premiums							$ 325,000	$ 105,000
Senior notes, issuance cost				$ 2,821	$ 459	$ 1,414	6,824	$ 3,134
Debt issuance costs						14,043	14,648
Senior Notes inclusive of net premium						677,300	677,700
Premium on Senior Notes, Net				2,245		2,344	2,725
Amortization of net premium				100		400	$ 400
Senior Notes additional borrowings				$ 68,900		$ 213,600
Trailing quarters fixed charge coverage ratio						2.25%
2020 Senior Notes
Debt Instrument [Line Items]
Debt issued aggregate principal amount		$ 100,000
Senior notes at an issue price		105.00%
Proceeds from Senior Notes, net of Discounts and Premiums		$ 102,800
Accrued interest		3,300
Debt issuance costs		$ 2,300
8.875% Senior Notes
Debt Instrument [Line Items]
Debt issued aggregate principal amount			$ 250,000
Senior notes at an issue price			99.30%
Debt instrument maturity date			Dec. 1, 2020	Dec. 1, 2020		Dec. 1, 2020	Dec. 1, 2020
Proceeds from Senior Notes, net of Discounts and Premiums			$ 242,200
Senior notes, issuance cost			$ 6,400
Interest rate			8.875%	8.875%		8.875%	8.875%
6.25% Senior Notes
Debt Instrument [Line Items]
Debt issued aggregate principal amount	$ 325,000
Debt instrument maturity date				Aug. 1, 2022		Dec. 1, 2022	Dec. 1, 2022
Proceeds from Senior Notes, net of Discounts and Premiums	$ 318,800
Interest rate	6.25%			6.25%		6.25%	6.25%
Debt issuance costs	$ 6,300
Offering price as percentage of issue price	100.00%
2022 Senior Notes
Debt Instrument [Line Items]
Debt issued aggregate principal amount				$ 309,100
Debt instrument redemption date						Aug. 1, 2017
Latest date for equity proceeds to be applied to optional Note redemption						Aug. 1, 2017
Percentage of notes that can be redeemed						35.00%

Reconciliation of Income Tax Ex

Reconciliation of Income Tax Expense (Benefit) Using Statutory Rate Compared with Actual Income Tax Expense (Detail) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Loss from continuing operations before noncontrolling interests and income taxes			$ (423,245)	$ (74,565)	$ (6,538)
Statutory U.S. income tax rate	35.00%	35.00%	35.00%	35.00%	35.00%
Tax expense recognized using statutory U.S. income tax rate			$ (148,136)	$ (26,098)	$ (2,288)
State income taxes, net of federal income tax benefit			(20,446)	(3,144)	(805)
Change in estimated future state rates			(212)	(1,015)	(484)
Permanent differences			1,609	970	83
Change in valuation allowances			143,566	2,450	(160)
Other			(608)	(78)	(500)
Total income tax benefit	$ 2,092	$ (92)	$ (24,227)	$ (26,915)	$ (4,154)
Effective income tax rate	(3.60%)	0.50%	5.70%	36.10%	63.50%

Components of Deferred Tax Asse

Components of Deferred Tax Assets (Liabilities) (Detail) - USD ($) $ in Thousands		Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Assets:
Asset retirement obligation			$ 866	$ 772
Deferred compensation plans			2,028	695
Compensation Accruals			767	2,087
Valuation allowances			(3,478)	(71)
Other			93	68
Total gross current deferred tax assets			276	3,551
Liabilities:
Unrealized gain on derivatives			(12,570)	(11,410)
Other			(238)	(442)
Total gross current deferred tax liabilities			(12,808)	(11,852)
Net total current deferred tax liability			(12,532)	(8,301)
Assets:
Timing differences - tax partnerships			4,166
Tax basis of oil and gas properties in excess of book basis			8,965
Asset retirement obligation			16,965	15,091
Deferred compensation plans			1,083	2,218
Net operating loss carryforward	[1]		123,488	73,531
Organization costs			456	525
Deferred revenue			1,098	1,209
Percentage depletion carryforward			2,673	2,155
AMT credits		$ 5,500	292	292
Valuation allowances			(144,681)	(4,318)
Other			280	269
Total gross long-term deferred tax assets			14,785	88,817
Liabilities:
Timing differences - tax partnerships				(7,135)
Book basis of oil and gas properties in excess of tax basis				(73,557)
Unrealized gain on derivatives			(1,574)	(999)
Other			(679)	(980)
Total gross long-term deferred tax liabilities			(2,253)	(80,516)
Net total long-term deferred tax asset			$ 12,532	$ 8,301
[1]	As a result of certain realization requirements of FASB ASC 718, the table of deferred tax assets and liabilities does not include $1.3 million at December 31, 2015 and 2014, of excess tax benefits that arose directly from tax deductions related to stock-based compensation greater than compensation recognized for financial reporting. Total stockholders' equity will be increased by $1.3 million if and when such excess tax benefits are ultimately realized.

Components of Deferred Tax A107

Components of Deferred Tax Assets (Liabilities) (Parenthetical) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Excess tax benefit from share-based compensation	$ 1.3	$ 1.3
Stockholders equity increased	$ 1.3

Expirations by Year for Federal

Expirations by Year for Federal and State Net Operating Loss Carryforwards (Detail) $ in Thousands	Dec. 31, 2015USD ($)
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	$ 264,700
Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	123,488
Expiration Year, 2020 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	134
Expiration Year, 2021 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	175
Expiration Year, 2023 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	899
Expiration Year, 2025 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	531
Expiration Year, 2026 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	405
Expiration Year, 2027 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	1,003
Expiration Year, 2028 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	3,333
Expiration Year, 2029 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	767
Expiration Year, 2030 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	751
Expiration Year, 2031 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	19,746
Expiration Year, 2032 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	253
Expiration Year, 2033 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	19,703
Expiration Year, 2034 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	18,670
Expiration Year, 2035 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	$ 57,118

Major Customers - Additional In

Major Customers - Additional Information (Detail) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015USD ($)Customer	Dec. 31, 2014USD ($)Customer	Dec. 31, 2013USD ($)Customer
Revenue, Major Customer [Line Items]
Number of customers | Customer		4	4
Sales
Revenue, Major Customer [Line Items]
Number of customers | Customer		4	4	4
Sales | Largest single purchaser
Revenue, Major Customer [Line Items]
Sales revenue | $		$ 75.8	$ 96.4	$ 73.8
Sales | Customer Concentration Risk | Four customers
Revenue, Major Customer [Line Items]
Sales revenue | $		$ 152.7	$ 253.6	$ 179.5
Percentage of revenue from major customers		85.10%	85.10%	83.90%
Sales | Customer Concentration Risk | Largest single purchaser
Revenue, Major Customer [Line Items]
Percentage of revenue from major customers	46.00%	42.20%	32.40%	34.50%

Summary of Stock Option Activit

Summary of Stock Option Activity (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Beginning Balance, Number of Shares	443,672	402,561	402,561	449,087	502,253
Granted, Number of Shares			80,000
Exercised, Number of Shares	0	0		(46,526)	(49,166)
Cancelled/Forfeited, Number of Shares			(38,889)		(4,000)
Ending Balance, Number of Shares	1,295,094		443,672	402,561	449,087
Beginning Balance, Weighted Average Exercise Price	$ 9.64	$ 10.82	$ 10.82	$ 10.85	$ 10.95
Options Exercisable, Number of Shares	367,005		363,672
Granted, Weighted Average Exercise Price			$ 4.48
Exercised, Weighted Average Exercise Price				11.09	10.85
Cancelled/Forfeited, Weighted Average Exercise Price			11.23		23.28
Ending Balance, Weighted Average Exercise Price	$ 4.41		9.64	$ 10.82	$ 10.85
Options Exercisable, Weighted Average Exercise Price	$ 10.72		$ 10.77
Options Outstanding December 31, Weighted Average Remaining Term (in years)	5 years 6 months		2 years 9 months 18 days	2 years 10 months 24 days
Options Exercisable December 31, Weighted Average Remaining Term (in years)	1 year 10 months 24 days		2 years 1 month 6 days
Options Outstanding December 31, 2015, Aggregate Intrinsic Value			$ 0
Options Exercisable December 31, 2015, Aggregate Intrinsic Value			$ 0

Percentage of Awards to Vest (D

Percentage of Awards to Vest (Detail) - Restricted Stock	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
TSR Rank 1-3
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of Awards to Vest	100.00%	100.00%	100.00%
TSR Rank 4 - 6
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of Awards to Vest	75.00%	75.00%	75.00%
TSR Rank 7 - 10
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of Awards to Vest	50.00%	50.00%	50.00%
TSR Rank 11 - 13
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of Awards to Vest	25.00%	25.00%	25.00%
TSR Rank 14 - 16
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of Awards to Vest	0.00%	0.00%	0.00%

Monte Carlo Simulation Model As

Monte Carlo Simulation Model Assumptions Used to Estimate Fair Value of Restricted Stock (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected Dividend Yield	0.00%	0.00%
Risk-Free Interest Rate	1.00%	0.80%
Expected Volatility	58.60%	50.40%
Market Index	35.60%	35.30%
Expected Life	3 years	3 years
Peer Group
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected Volatility Rate Minimum	29.80%	28.40%
Expected Volatility Rate Maximum	85.00%	65.70%

Net Change in Capitalized Explo

Net Change in Capitalized Exploratory Well Costs (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)Project	Dec. 31, 2014USD ($)Project	Dec. 31, 2013USD ($)Project
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Beginning Balance at January 1,	$ 23,101	$ 5,731	$ 36,968
Additions to capitalized exploratory well costs pending the determination of estimated proved reserves	144,954	258,097	171,087
Divested wells	0	0	0
Reclassification of wells, facilities, and equipment based on the determination of estimated proved reserves	(147,850)	(240,494)	(202,323)
Capitalized exploratory well costs charged to expense	(2,907)	(233)	(1)
Ending Balance at December 31,	17,298	23,101	5,731
Less exploratory well costs that have been capitalized for a period of one year or less	(12,156)	(20,407)	(3,597)
Capitalized exploratory well costs for a period of greater than one year	$ 5,142	$ 2,694	$ 2,134
Number of projects that have exploratory well costs capitalized for a period of more than one year | Project	14	6	3

Suspended Exploratory Well C114

Suspended Exploratory Well Costs - Additional Information (Detail) $ in Thousands	Dec. 31, 2015USD ($)Well	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Oil and Gas In Process Activities [Line Items]
Capitalized exploratory well costs for a period of greater than one year | $	$ 5,142	$ 2,694	$ 2,134
Illinois Basin in Butler Country, Pennsylvania
Oil and Gas In Process Activities [Line Items]
Capitalized exploratory number of wells	9
Illinois Basin in Lawrence County, Pennsylvania
Oil and Gas In Process Activities [Line Items]
Capitalized exploratory number of wells	4
Illinois Basin in Non Operated Region
Oil and Gas In Process Activities [Line Items]
Capitalized exploratory number of wells	1
Butler County, Pennsylvania
Oil and Gas In Process Activities [Line Items]
Number of completed wells that are awaiting infrastructure	8
Number of drilled well that is awaiting completion	1
Lawrence County, Pennsylvania
Oil and Gas In Process Activities [Line Items]
Number of completed wells that are awaiting infrastructure	3
Number of drilled well that is awaiting completion	1
Kentucky
Oil and Gas In Process Activities [Line Items]
Number of wells that plans to convert to disposal well to support other proven wells in region	1

Costs Incurred in Oil and Na115

Costs Incurred in Oil and Natural Gas Property Acquisitions and Development (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Acquisition of Properties
Exploration Costs		$ 3,011	$ 9,446	$ 11,408
Development Costs		231	869	3,651
Subtotal		193,928	549,758	337,614
Asset Retirement Obligations		2,818	9,110	3,031
Total Costs Incurred		220,953	566,297	340,540
Consolidated Entities
Acquisition of Properties
Proved		1	161	2,445
Unproved		28,242	169,408	39,291
Exploration Costs	[1]	158,318	316,235	231,112
Development Costs	[1]	31,574	71,383	64,661
Subtotal		218,135	557,187	337,509
Asset Retirement Obligations		2,818	9,110	3,031
Total Costs Incurred		220,953	566,297	340,540
Equity Method Investee
Acquisition of Properties
Development Costs	[1]	824	438	1,958
Subtotal		$ 824	$ 438	$ 1,958
[1]	Includes Depreciation expense for support equipment and facilities

Reconciliation of Total Costs I

Reconciliation of Total Costs Incurred for Consolidated Entities to Reported Capital Expenditures (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Total Costs Incurred		$ 220,953	$ 566,297	$ 340,540
Contributions to Equity Method Investments				2,493
DJ Basin Expenditures				2
Exploration Expense		(3,011)	(9,446)	(11,408)
Asset Retirement Obligations		(2,818)	(9,110)	(3,031)
Depreciation for Support Equipment and Facilities		(4,905)	(6,075)	(5,024)
Corporate Expenditures		231	869	3,651
Other	[1]	(16,522)	7,223	10,391
Subtotal		$ 193,928	$ 549,758	$ 337,614
[1]	Represents R.E. Disposal, LLC capital, future proceeds from ArcLight and intercompany capital transactions.

Capitalized Costs for Natural G

Capitalized Costs for Natural Gas and Oil Production Activities (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Consolidated Entities
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proven Oil and Natural Gas Properties	$ 1,239,430	$ 1,079,039
Pipelines and Support Equipment	17,030	24,248
Field Operation Vehicles and Other Equipment	28,064	27,030
Wells and Facilities in Progress	144,408	127,597
Unproven Properties	262,992	322,413
Total	1,691,924	1,580,327
Less Accumulated Depreciation and Depletion	(696,447)	(362,804)
Total	995,477	1,217,523
Equity Method Investee
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Pipelines and Support Equipment	19,970	19,946
Total	19,970	19,946
Less Accumulated Depreciation and Depletion	(3,411)	(2,611)
Total	$ 16,559	$ 17,335

Summary of Changes in Estimated

Summary of Changes in Estimated Reserves of Oil and Natural Gas Wells (Detail)	12 Months Ended
	Dec. 31, 2015MMcfebblMcf	Dec. 31, 2014MMcfebblMcf	Dec. 31, 2013MMcfebblMcf
Reserve Quantities [Line Items]
Estimated Proved Reserves-Beginning of Period | MMcfe	1,336,808,300	849,784,600	618,050,000
Extensions, Discoveries and Additions | MMcfe	142,986,700	523,764,600	312,461,100
Revisions of Previous Estimates | MMcfe	(703,020,300)	(4,537,000)	(46,882,300)
Purchases | MMcfe	(24,854,900)
Purchases | MMcfe		24,148,300	6,000
Production | MMcfe	(71,474,800)	(56,352,200)	(33,850,200)
Estimated Proved Reserves-End of Period | MMcfe	680,445,000	1,336,808,300	849,784,600
Proved Developed Reserves Energy Equivalents | MMcfe	647,073,400	586,731,900	356,451,400
Proved Undeveloped Reserves Energy Equivalents | MMcfe	33,371,600	750,076,400	493,333,200
Crude Oil
Reserve Quantities [Line Items]
Estimated Proved Reserves-Beginning of Period	9,684,700	8,619,600	9,375,700
Extensions, Discoveries and Additions	949,000	1,723,100	595,600
Revisions of Previous Estimates	(4,176,800)	471,100	(438,500)
Purchases	(7,700)
Purchases		12,000	1,000
Production	(1,132,100)	(1,141,100)	(914,200)
Estimated Proved Reserves-End of Period	5,317,100	9,684,700	8,619,600
Proved Undeveloped Reserves	372,500	2,056,600	877,100
Proved Developed Reserves	4,944,600	7,628,100	7,742,500
Natural Gas Liquids
Reserve Quantities [Line Items]
Estimated Proved Reserves-Beginning of Period	73,252,500	46,130,700	31,679,900
Extensions, Discoveries and Additions	10,079,300	31,160,300	19,956,100
Revisions of Previous Estimates	(38,249,700)	(2,889,100)	(4,685,600)
Purchases	(1,389,600)
Purchases		933,000
Production	(3,345,900)	(2,082,400)	(819,700)
Estimated Proved Reserves-End of Period	40,346,600	73,252,500	46,130,700
Proved Undeveloped Reserves	2,404,700	44,037,500	29,808,200
Proved Developed Reserves	37,941,900	29,215,000	16,322,500
Natural Gas
Reserve Quantities [Line Items]
Estimated Proved Reserves-Beginning of Period | Mcf	839,185,100	521,282,800	371,716,400
Extensions, Discoveries and Additions | Mcf	76,816,900	326,464,200	189,150,900
Revisions of Previous Estimates | Mcf	(448,461,300)	9,971,000	(16,137,700)
Purchases | Mcf	(16,471,100)
Purchases | Mcf		18,478,300
Production | Mcf	(44,606,800)	(37,011,200)	(23,446,800)
Estimated Proved Reserves-End of Period | Mcf	406,462,800	839,185,100	521,282,800
Proved Undeveloped Reserves | Mcf	16,708,400	473,511,800	309,221,400
Proved Developed Reserves | Mcf	389,754,400	365,673,300	212,061,400

Oil and Natural Gas Reserve 119

Oil and Natural Gas Reserve Quantities - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015MMcfeMMBoe	Dec. 31, 2014MMcfeMMBoe	Dec. 31, 2013MMcfeMMBoe
Reserve Quantities [Line Items]
Discount rate	10.00%
Proved Undeveloped Reserves Extensions Discoveries And Additions	27,300
Crude Oil
Reserve Quantities [Line Items]
Proved Undeveloped Reserves Extensions Discoveries And Additions | MMBoe	0.9	1.7	0.6
Natural Gas Liquids
Reserve Quantities [Line Items]
Proved Undeveloped Reserves Extensions Discoveries And Additions | MMBoe	10.1	31.2	20
Natural Gas
Reserve Quantities [Line Items]
Proved Undeveloped Reserves Extensions Discoveries And Additions	76,800	326,500	189,100
Butler
Reserve Quantities [Line Items]
Revisions	10,300
Revisions		51,000
Warrior North Prospect in Ohio
Reserve Quantities [Line Items]
Revisions	9,800
Warrior South Prospect and Westmoreland
Reserve Quantities [Line Items]
Revisions		(15,500)
Marcellus Shale
Reserve Quantities [Line Items]
Proved Undeveloped Reserves Extensions Discoveries And Additions	102,100
Utica Shale
Reserve Quantities [Line Items]
Proved Undeveloped Reserves Extensions Discoveries And Additions	30,000
Operating Expense
Reserve Quantities [Line Items]
Revisions	15,400
Revisions		17,600
Lower commodity prices
Reserve Quantities [Line Items]
Revisions	(741,100)
Ethane Recovery Expectations
Reserve Quantities [Line Items]
Revisions	4,100
Technical Revisions
Reserve Quantities [Line Items]
Revisions	18.6
Revisions		38,000
Well Performance
Reserve Quantities [Line Items]
Revisions | MMBoe	(2,200)
Proved Undeveloped with in Five Years
Reserve Quantities [Line Items]
Revisions		(58,500)
Commodity Pricing
Reserve Quantities [Line Items]
Revisions		(1,600)

Standardized Measure of Disc120

Standardized Measure of Discounted Future Net Cash Flows - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Annual discount factor	10.00%

Summary of Future Net Cash Flow

Summary of Future Net Cash Flows Relating to Prove Oil and Natural Gas Reserves (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	[1]	Dec. 31, 2014	[2]	Dec. 31, 2013	[3]	Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future Cash Inflows	$ 1,716,131		$ 5,824,231		$ 3,899,878
Production	(1,144,049)		(2,332,151)		(1,619,629)
Abandonment	(143,459)		(134,308)		(95,183)
Development	(18,952)		(686,676)		(517,875)
Net Future Cash Inflow Before Income Taxes	409,671		2,671,096		1,667,191
Future Income Tax Expense			(468,597)		(359,322)
Total Future Net Cash Flows Before 10.0% Discount	409,671		2,202,499		1,307,869
Less: Effect of 10.0% Discount Factor	(154,048)		(1,177,135)		(778,756)
Standardized Measure of Discounted Future Net Cash Flows	$ 255,623		$ 1,025,364		$ 529,113		$ 396,123
[1]	Calculated using weighted average prices of $2.401 per Mcf, $44.45 per barrel of oil and $12.48 per barrel of NGLs
[2]	Calculated using weighted average prices of $3.455 per Mcf, $88.02 per barrel of oil and $28.30 per barrel of NGLs
[3]	Calculated using weighted average prices of $3.588 per Mcf, $94.28 per barrel of oil and $26.37 per barrel of NGLs

Summary of Future Net Cash F122

Summary of Future Net Cash Flows Relating to Prove Oil and Natural Gas Reserves (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2015$ / bbl$ / Mcf	Dec. 31, 2014$ / bbl$ / Mcf	Dec. 31, 2013$ / bbl$ / Mcf
weighted average prices | $ / Mcf	2.401	3.455	3.588
Crude Oil
weighted average prices	44.450	88.020	94.280
Natural Gas Liquids
weighted average prices | $ / bbl	12.480	28.300	26.370

Principal Sources of Change in

Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Standardized Measure - Beginning of Period	$ 1,025,364	[1]	$ 529,113	[2]	$ 396,123
Changes in Prices and Production Costs	(1,296,866)		253,865		72,503
Revisions in Quantities	(270,673)		(5,970)		(51,289)
Changes in Future Development Costs	595,547		(51,794)		22,341
Accretion of Discount and Timing of Future Cash Flows	116,514		64,013		47,571
Net Change in Income Tax	139,776		28,756		31,433
Purchase (Sale) of Reserves in Place	(37,101)		28,316
Plus Extensions, Discoveries, and Other Additions	88,152		430,252		170,846
Development Costs Incurred	31,574		71,383		64,661
Sales of Product - Net of Production Costs	(52,952)		(197,587)		(151,781)
Changes in Timing and Other	(83,712)		(124,983)		(73,295)
Standardized Measure - End of Period	$ 255,623	[3]	$ 1,025,364	[1]	$ 529,113	[2]
[1]	Calculated using weighted average prices of $3.455 per Mcf, $88.02 per barrel of oil and $28.30 per barrel of NGLs
[2]	Calculated using weighted average prices of $3.588 per Mcf, $94.28 per barrel of oil and $26.37 per barrel of NGLs
[3]	Calculated using weighted average prices of $2.401 per Mcf, $44.45 per barrel of oil and $12.48 per barrel of NGLs

Results of Operations (Detail)

Results of Operations (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Expenses
Results of Operations for Oil and Gas Producing Activities		$ (378,511)	$ (25,399)	$ 16,481
Consolidated Entities
Revenues
Oil and Natural Gas Sales		171,951	297,869	213,919
Expenses
Production and Lease Operating Expense		118,999	100,282	62,150
Impairment Expense		345,775	132,618	32,072
Exploration Expense		3,011	9,446	11,408
Depletion, Depreciation, Amortization and Accretion		104,744	94,467	62,386
Total Costs		572,529	336,813	168,016
Pre-Tax Operating Income (Loss)		(400,578)	(38,944)	45,903
Income Tax (Expense) Benefit	[1]	22,833	14,059	(29,148)
Results of Operations for Oil and Gas Producing Activities		(377,745)	(24,885)	16,755
Equity Method Investee
Expenses
Depletion, Depreciation, Amortization and Accretion		812	805	752
Total Costs		812	805	752
Pre-Tax Operating Income (Loss)		(812)	(805)	(752)
Income Tax (Expense) Benefit	[1]	46	291	478
Results of Operations for Oil and Gas Producing Activities		$ (766)	$ (514)	$ (274)
[1]	Computed using the effective rate for continuing operations for each period: 5.7% in 2015; 36.1% in 2014 and; 63.5% in 2013.

Results of Operations (Parenthe

Results of Operations (Parenthetical) (Detail)	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Effective Tax Rate	(3.60%)	0.50%	5.70%	36.10%	63.50%

Litigation - Additional Informa

Litigation - Additional Information (Detail)	1 Months Ended		12 Months Ended
	Jul. 31, 2012Cases	Oct. 31, 2011Plaintiff	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Number of plaintiffs | Plaintiff		2
Case dismissed date			2012-05
Case revised decision date			2013-05
Additional lawsuits | Cases	2

Unaudited Financial Information

Unaudited Financial Information on Quarterly Basis (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended									12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 30,507	$ 34,526	$ 37,573	$ 45,772	$ 54,122	$ 70,245	$ 73,466	$ 72,933	$ 81,343	$ 171,993		$ 297,987		$ 214,119
Impairment Expense	14,184	81,098	139,812	117,842	7,023	132,576	1	16	25	345,775		132,618		32,072
Other Costs and Expenses		51,301	27,054	81,303	65,578	7,337	67,846	65,274	72,562
Net Income (Loss) From Continuing Operations	(60,141)	(97,873)	(129,293)	(153,373)	(18,479)	(69,668)	5,619	7,643	8,756	(399,018)		(47,650)		(2,384)
Net Income (Loss) From Discontinued Operations, Net of Income Taxes		(164)	34,617	1,570	1,962	1,037	970	1,312	1,681	35,740		961		254
NET INCOME (LOSS)	(60,141)	(98,037)	(94,676)	(151,803)	(16,517)	(68,631)	6,589	8,955	10,437	(361,033)		(42,650)		(573)
Net Income (Loss) Attributable to Noncontrolling Interests			(1)	949	1,297	698	895	877	1,569	2,245		4,039		1,557
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	(60,141)	(98,037)	(94,675)	(152,752)	(17,814)	(69,329)	5,694	8,078	8,868	(363,278)		(46,689)		(2,130)
Preferred Stock Dividends	2,105	2,415	2,415	2,415	2,415	2,335				9,660		2,335
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (62,246)	$ (100,452)	$ (97,090)	$ (155,167)	$ (20,229)	$ (71,664)	$ 5,694	$ 8,078	$ 8,868	$ (372,938)		$ (49,024)		$ (2,130)
Income (Loss) per Common Share Attributable to Rex Energy Common Shareholders:
Basic - Continuing Operations	$ (1.11)	$ (1.85)	$ (2.44)	$ (2.88)	$ (0.38)	$ (1.35)	$ 0.11	$ 0.14	$ 0.17	$ (7.51)	[1]	$ (0.94)	[1]	$ (0.05)	[1]
Basic - Discontinued Operations			0.64	0.01	0.01			0.01		0.66	[1]	0.02	[1]	0.01	[1]
Basic - Net Income (Loss)	$ (1.11)	$ (1.85)	$ (1.80)	$ (2.87)	$ (0.37)	$ (1.35)	$ 0.11	$ 0.15	$ 0.17	$ (6.85)	[1]	$ (0.92)	[1]	$ (0.04)	[1]
Basic - Weighted Average Shares Outstanding	56,003	54,342	53,936	54,118	54,370	53,261	53,214	53,164	52,984	54,392		53,150		52,572
Diluted - Continuing Operations	$ (1.11)	$ (1.85)	$ (2.44)	$ (2.88)	$ (0.38)	$ (1.35)	$ 0.10	$ 0.14	$ 0.17	$ (7.51)	[1]	$ (0.94)	[1]	$ (0.05)	[1]
Diluted - Discontinued Operations			0.64	0.01	0.01			0.01		0.66	[1]	0.02	[1]	0.01	[1]
Diluted - Net Income (Loss)	$ (1.11)	$ (1.85)	$ (1.80)	$ (2.87)	$ (0.37)	$ (1.35)	$ 0.10	$ 0.15	$ 0.17	$ (6.85)	[1]	$ (0.92)	[1]	$ (0.04)	[1]
Diluted - Weighted Average Shares Outstanding	56,003	54,342	53,936	54,118	54,370	53,261	57,991	53,509	53,503	54,392		53,150		52,572
[1]	All earnings per share amounts are attributable to Rex common shareholders.

Condensed Consolidating Bala128

Condensed Consolidating Balance Sheets (Parenthetical) (Detail)	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jul. 17, 2014	Dec. 12, 2012
8.875% Senior Notes
Consolidated Balance Sheet Statements Captions [Line Items]
Interest rate	8.875%	8.875%	8.875%		8.875%
6.25% Senior Notes
Consolidated Balance Sheet Statements Captions [Line Items]
Interest rate	6.25%	6.25%	6.25%	6.25%