Rex Energy 10-Q 5 Nov 14 2014 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Sep. 30, 2014	Nov. 04, 2014
Document And Entity Information [Abstract]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Sep-14	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q3	'
Trading Symbol	'REXX	'
Entity Registrant Name	'REX ENERGY CORP	'
Entity Central Index Key	'0001397516	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	54,106,551

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current Assets	'	'
Cash and Cash Equivalents	$87,622	$1,900
Accounts Receivable	53,393	38,863
Taxes Receivable	504	5,189
Short-Term Derivative Instruments	7,257	5,668
Current Deferred Tax Asset	2,837	3,451
Inventory, Prepaid Expenses and Other	3,245	2,207
Total Current Assets	154,858	57,278
Property and Equipment (Successful Efforts Method)	'	'
Evaluated Oil and Gas Properties	1,012,467	749,680
Unevaluated Oil and Gas Properties	334,461	189,385
Other Property and Equipment	83,645	70,115
Wells and Facilities in Progress	116,979	76,545
Pipelines	15,875	7,678
Total Property and Equipment	1,563,427	1,093,403
Less: Accumulated Depreciation, Depletion and Amortization	-255,471	-190,521
Net Property and Equipment	1,307,956	902,882
Deferred Financing Costs and Other Assets – Net	17,586	11,993
Equity Method Investments	18,098	18,708
Long-Term Derivative Instruments	430	535
Total Assets	1,498,928	991,396
Current Liabilities	'	'
Accounts Payable	56,569	31,103
Current Maturities of Long-Term Debt	8,248	6,743
Accrued Liabilities	70,835	54,450
Short-Term Derivative Instruments	1,321	4,663
Total Current Liabilities	136,973	96,959
Noncurrent Liabilities	'	'
Senior Notes	675,000	'
Premium on Senior Notes, Net	2,816	3,078
Senior Secured Line of Credit and Long-Term Debt	6,385	62,191
Long-Term Derivative Instruments	945	1,765
Long-Term Deferred Tax Liability	43,414	29,446
Other Deposits and Liabilities	4,303	4,992
Future Abandonment Cost	27,434	26,040
Total Liabilities	897,270	574,471
Commitments and Contingencies (See Note 13)	'	'
Stockholders’ Equity	'	'
Preferred Stock	1	'
Common Stock	54	54
Additional Paid-In Capital	616,384	456,554
Accumulated Deficit	-19,083	-41,725
Rex Energy Stockholders’ Equity	597,356	414,883
Noncontrolling Interests	4,302	2,042
Total Stockholders’ Equity	601,658	416,925
Total Liabilities and Stockholders’ Equity	1,498,928	991,396
8.875% Senior Notes	'	'
Noncurrent Liabilities	'	'
Senior Notes	350,000	350,000
Premium on Senior Notes, Net	2,800	3,078
6.25% Senior Notes	'	'
Noncurrent Liabilities	'	'
Senior Notes	$325,000	'

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Preferred Stock, par value	0.001	0.001
Preferred Stock, shares authorized	100,000	100,000
Preferred Stock, shares issued	16,100	0
Preferred Stock, shares outstanding	16,100	0
Common Stock, par value	0.001	0.001
Common stock, shares authorized	100,000,000	100,000,000
Common Stock, shares issued	54,116,652	54,186,490
Common Stock, shares outstanding	54,116,652	54,186,490
8.875% Senior Notes	'	'
Interest rate	8.88%	8.88%
Due date	'2020	'2020
6.25% Senior Notes	'	'
Interest rate	6.25%	6.25%
Due date	'2022	'2022

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
OPERATING REVENUE	'	'	'	'
Oil, Natural Gas and NGL Sales	$73,448	$58,063	$227,650	$150,447
Field Services Revenue	13,070	4,847	41,462	15,193
Other Revenue	18	64	92	164
TOTAL OPERATING REVENUE	86,536	62,974	269,204	165,804
OPERATING EXPENSES	'	'	'	'
Production and Lease Operating Expense	27,657	17,203	69,303	43,695
General and Administrative Expense	10,409	8,826	30,039	24,404
Loss on Disposal of Asset	84	140	385	1,632
Impairment Expense	1	2,244	41	2,414
Exploration Expense	1,462	3,242	4,890	7,511
Depreciation, Depletion, Amortization and Accretion	27,364	16,267	69,014	40,367
Field Service Operating Expense	9,547	3,652	30,912	10,354
Other Operating Expense (Income)	-24	19	3	910
TOTAL OPERATING EXPENSES	76,500	51,593	204,587	131,287
INCOME FROM OPERATIONS	10,036	11,381	64,617	34,517
OTHER EXPENSE	'	'	'	'
Interest Expense	-11,080	-6,181	-25,718	-16,013
Gain (Loss) on Derivatives, Net	12,316	-4,624	2,315	-1,423
Other Income (Expense)	-12	-30	-30	2,041
Loss on Equity Method Investments	-202	-207	-610	-569
TOTAL OTHER INCOME (EXPENSE)	1,022	-11,042	-24,043	-15,964
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX	11,058	339	40,574	18,553
Income Tax (Expense) Benefit	-4,469	1,493	-14,592	-5,622
NET INCOME FROM CONTINUING OPERATIONS	6,589	1,832	25,982	12,931
Income From Discontinued Operations, Net of Income Taxes	0	0	0	460
NET INCOME	6,589	1,832	25,982	13,391
Net Income Attributable to Noncontrolling Interests	895	258	3,340	912
NET INCOME ATTRIBUTABLE TO REX ENERGY	$5,694	$1,574	$22,642	$12,479
Earnings per common share:	'	'	'	'
Basic – Net Income From Continuing Operations Attributable to Rex Energy Common Shareholders	$0.11	$0.03	$0.42	$0.23
Basic – Net Income From Discontinued Operations Attributable to Rex Energy Common Shareholders	$0	$0	$0	$0.01
Basic – Net Income Attributable to Rex Energy Common Shareholders	$0.11	$0.03	$0.42	$0.24
Basic – Weighted Average Shares of Common Stock Outstanding	53,214	52,626	53,493	52,560
Diluted – Net Income From Continuing Operations Attributable to Rex Energy Common Shareholders	$0.10	$0.03	$0.41	$0.23
Diluted – Net Income From Discontinued Operations Attributable to Rex Energy Common Shareholders	$0	$0	$0	$0.01
Diluted – Net Income Attributable to Rex Energy Common Shareholders	$0.10	$0.03	$0.41	$0.24
Diluted – Weighted Average Shares of Common Stock Outstanding	57,991	53,293	55,254	53,124

Consolidated_Statements_of_Cha

Consolidated Statements of Changes in Noncontrolling Interests and Stockholders' Equity (USD $)	Total	Common Stock	Preferred Stock	Additional Paid-in Capital	Retained Earnings	Stockholders' Equity, Total	Noncontrolling Interest
In Thousands, except Share data
Balance at Dec. 31, 2013	$416,925	$54	'	$456,554	($41,725)	$414,883	$2,042
Balance (in shares) at Dec. 31, 2013	'	54,186,490	'	'	'	'	'
Non-Cash Compensation	4,398	'	'	4,398	'	4,398	'
Issuance of Restricted Stock, Net of Forfeitures	'	0	'	'	'	'	'
Issuance of Restricted Stock, Net of Forfeitures (in shares)	'	-106,000	'	'	'	'	'
Stock Option Exercise	421	'	'	421	'	421	'
Stock Option Exercise (in shares)	'	37,000	'	'	'	'	'
Issuance of Preferred Stock (in shares)	'	'	16,100	'	'	'	'
Issuance of Preferred Stock	155,012	'	1	155,011	'	155,012	'
Capital Distributions	-1,080	'	'	'	'	'	-1,080
Net Income	25,982	'	'	'	22,642	22,642	3,340
Balance at Sep. 30, 2014	$601,658	$54	$1	$616,384	($19,083)	$597,356	$4,302
Balance (in shares) at Sep. 30, 2014	'	54,116,652	16,100	'	'	'	'

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013
CASH FLOWS FROM OPERATING ACTIVITIES	'	'
Net Income	$25,982	$13,391
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities	'	'
Loss from Equity Method Investments	610	569
Non-cash Expenses	5,146	4,432
Depreciation, Depletion, Amortization and Accretion	69,014	40,367
(Gain) Loss on Derivatives	-2,315	1,423
Cash Settlements of Derivatives	-3,331	5,540
Dry Hole Expense	237	485
Deferred Income Tax Expense	14,592	10,970
Impairment Expense	41	2,414
Loss on Sale of Asset	385	663
Changes in operating assets and liabilities	'	'
Accounts Receivable	-9,854	-7,028
Inventory, Prepaid Expenses and Other Assets	-1,038	-391
Accounts Payable and Accrued Liabilities	36,060	34,750
Other Assets and Liabilities	-1,966	-1,830
NET CASH PROVIDED BY OPERATING ACTIVITIES	133,563	105,755
CASH FLOWS FROM INVESTING ACTIVITIES	'	'
Proceeds from Joint Venture Acreage Management	210	246
Contributions to Equity Method Investments	'	-2,493
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	412	3,931
Acquisitions of Undeveloped Acreage	-153,628	-31,458
Capital Expenditures for Development of Oil & Gas Properties and Equipment	-310,353	-197,264
NET CASH USED IN INVESTING ACTIVITIES	-463,359	-227,038
CASH FLOWS FROM FINANCING ACTIVITIES	'	'
Repayments of Long-Term Debt and Line of Credit	-248,146	-1,022
Proceeds from Long-Term Debt and Line of Credit	193,041	1,750
Repayments of Loans and Other Notes Payable	-1,998	-1,363
Proceeds from Senior Notes, Net of Discounts and Premiums	325,000	105,000
Debt Issuance Costs	-6,731	-3,004
Proceeds from the Issuance of Preferred Stock, Net	155,011	'
Proceeds from the Exercise of Stock Options	421	534
Distributions by the Partners of Consolidated Joint Ventures	-1,080	-646
Purchase of Noncontrolling Interests	'	-150
NET CASH PROVIDED BY FINANCING ACTIVITIES	415,518	101,099
NET INCREASE (DECREASE) IN CASH	85,722	-20,184
CASH – BEGINNING	1,900	43,975
CASH – ENDING	87,622	23,791
SUPPLEMENTAL DISCLOSURES	'	'
Interest Paid	18,123	15,313
Cash Received for Income Taxes	-4,643	-4,976
NON-CASH ACTIVITIES	'	'
Increase in Accrued Liabilities	($7,042)	($30,455)

Basis_of_Presentation_and_Prin

Basis of Presentation and Principles of Consolidation	9 Months Ended
	Sep. 30, 2014
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 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 and the implementation of enhanced oil recovery (“EOR”) 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. In addition to our drilling and exploration activities, we are also engaged in oil and gas field services, where we provide water sourcing, water disposal and water transfer capabilities for completion operations.
	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.
	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 commodity prices for 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, 2013.
	Discontinued Operations
	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, for which the final sale was completed in 2013. Pursuant to the rules for discontinued operations, the results of operations are reflected as Discontinued Operations in our Consolidated Statements of 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, to our Consolidated Financial Statements.

Business_Segment_Information

Business Segment Information	9 Months Ended
	Sep. 30, 2014
Segment Reporting [Abstract]	'
Business Segment Information	'
	2. BUSINESS SEGMENT INFORMATION
	We have two principal reportable segments, which are segregated based on the products and services that each provides: (a) exploration and production, and (b) field services. Our exploration and production segment engages in the exploration, acquisition, development and production of oil, NGLs and natural gas. We have a single, company-wide management team that oversees all properties as a whole rather than isolating operating segments; however, we do track basic operational data by area. Our financial performance is measured as a single enterprise and not by individual area. Our field services segment operates and manages water sourcing, water transfer, equipment rental, trucking and water disposal services, primarily in the Appalachian Basin. Our field services segment is comprised of operations that have economic characteristics that are distinct from those of our exploration and production segment and is managed by its own unique management team.
	We evaluate the performance of our business segments based on net income (loss) from continuing operations, before income taxes. All intercompany transactions, including those between consolidated business segments, are eliminated in consolidation. Summarized financial information concerning our segments is shown in the following table for the three and nine months ended September 30, 2014 and 2013:
	($ in Thousands)	Exploration and Production		Field Services			Intercompany Eliminations			Consolidated Total
	Three Months Ended September 30, 2014
	Revenues	$	73,466	$	15,870		$	(2,800	)	$	86,536
	Inter-Segment Revenues		—		(2,800	)		2,800			—
	Total Revenues		73,466		13,070			—			86,536
	Income (Loss) From Continuing Operations, Before Income Taxes	$	9,503	$	2,225		$	(670	)	$	11,058
	Three Months Ended September 30, 2013
	Revenues	$	58,127	$	6,543		$	(1,696	)	$	62,974
	Inter-Segment Revenues		—		(1,696	)		1,696			—
	Total Revenues		58,127		4,847			—			62,974
	Income (Loss) From Continuing Operations, Before Income Taxes	$	192	$	629		$	(482	)	$	339
	Nine Months Ended September 30, 2014
	Revenues	$	227,742	$	54,467		$	(13,005	)	$	269,204
	Inter-Segment Revenues		—		(13,005	)		13,005			—
	Total Revenues		227,742		41,462			—			269,204
	Income (Loss) From Continuing Operations, Before Income Taxes	$	35,434	$	8,306		$	(3,166	)	$	40,574
	Nine Months Ended September, 2013
	Revenues	$	150,611	$	19,668		$	(4,475	)	$	165,804
	Inter-Segment Revenues		—		(4,475	)		4,475			—
	Total Revenues		150,611		15,193			—			165,804
	Income (Loss) From Continuing Operations, Before Income Taxes	$	16,464	$	3,344		$	(1,255	)	$	18,553
	As of September 30, 2014
	Total Assets	$	1,471,683	$	35,681		$	(8,436	)	$	1,498,928
	As of December  31, 2013
	Total Assets	$	971,973	$	26,266		$	(6,843	)	$	991,396

Future_Abandonment_Cost

Future Abandonment Cost	9 Months Ended
	Sep. 30, 2014
Asset Retirement Obligation Disclosure [Abstract]	'
Future Abandonment Cost	'
	3. FUTURE ABANDONMENT COST
	Future abandonment costs are recognized as obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed. If the fair value of a recorded future abandonment cost changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost.
	Accretion expense totaled approximately $1.3 million and $2.9 million for the three and nine months ended September 30, 2014, respectively, and $1.2 million and $2.3 million for the three and nine months ended September 30, 2013, respectively. These amounts are recorded as depreciation, depletion, amortization and accretion (“DD&A”) expense on our Consolidated Statements of Operations. We account for future abandonment costs that relate to wells that are drilled jointly based on our working interest in those wells.
	($ in Thousands)	Nine Months Ended September 30, 2014
	Beginning Balance at January 1, 2014	$	28,525
	Future Abandonment Obligation Incurred		1,321
	Future Abandonment Obligation Settled		(1,798	)
	Future Abandonment Obligation Revision of Estimated Obligation		27
	Future Abandonment Obligation Accretion Expense		2,912
	Total Future Abandonment Cost1	$	30,987
	1 Includes approximately $3.6 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

Discontinued_OperationsAssets_

Discontinued Operations/Assets Held For Sale	9 Months Ended
	Sep. 30, 2014
Discontinued Operations And Disposal Groups [Abstract]	'
Discontinued Operations/Assets Held For Sale	'
	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. During 2012, we sold various parcels of acreage throughout our DJ Basin holdings at varying prices, much of which was lower than the existing carrying value of similar remaining acreage at the time of sale. 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 $1.0 million. Since that time, we have had no assets or liabilities related to the DJ Basin or continuing cash flows from this region.
	Summarized financial information for Discontinued Operations is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support.
		Three Months Ended September 30,				Nine Months Ended September 30,
	($ in Thousands)	2014		2013		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 Income Expense		—		—		—		(3	)
	Gain on Sale of Asset		—		—		—		(969	)
	Total Costs and Expenses		—		—		—		(748	)
	Income from Discontinued Operations Before Income Taxes		—		—		—		773
	Income Tax Expense		—		—		—		(313	)
	Income from Discontinued Operations, net of taxes	$	—	$	—	$	—	$	460
	Production:
	Crude Oil (Bbls)		—		—		—		356
	Total (Mcfe)		—		—		—		2,136

Business_and_Oil_and_Gas_Prope

Business and Oil and Gas Property Acquisitions and Dispositions	9 Months Ended
	Sep. 30, 2014
Business Combinations [Abstract]	'
Business and Oil and Gas Property Acquisitions and Dispositions	'
	5. BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS AND DISPOSITIONS
	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)	30-Sep-14
	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

Recently_Issued_Accounting_Pro

Recently Issued Accounting Pronouncements	9 Months Ended
	Sep. 30, 2014
Accounting Policies [Abstract]	'
Recently Issued Accounting Pronouncements	'
	6. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
	In April 2014, the FASB issued ASU 2014-08, Presentation of Financial Statements and Property, Plant, and Equipment: Reporting Discontinued Operations and Disclosures of Disposal of Components of an Entity. The amendments in this ASU change the criteria for reporting discontinued operations while enhancing the disclosures in this area. Under the new guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization’s operations and financial results. In addition, the new guidance requires expanded disclosures about discontinued operations that will provide financial statement users with more information about the assets, liabilities, income and expenses of discontinued operations. The amendments in this ASU are effective in the first quarter of 2015 for public organizations with calendar year ends. 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 May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The amendments in this ASU affects any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards. This ASU will supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services by following five steps:
	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.
	For public entities, the amendments in this ASU are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early application is not permitted. We are currently evaluating the potential impact of this ASU.
	In June 2014, the FASB issued ASU 2014-12, Compensation – Stock Compensation. The amendments in this ASU require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. A reporting entity should apply existing guidance in Topic 718 as it relates to awards with performance conditions that affect vesting to account for such awards. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. Entities may apply the amendments in this ASU either: (a) prospectively to all awards granted or modified after the effective date; or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new awards thereafter. The amendments in this ASU are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. 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.

Concentrations_of_Credit_Risk

Concentrations of Credit Risk	9 Months Ended
	Sep. 30, 2014
Risks And Uncertainties [Abstract]	'
Concentrations of Credit Risk	'
	7. CONCENTRATIONS OF CREDIT RISK
	By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparties to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties. Our counterparties are investment grade financial institutions and lenders in our Senior Credit Facility (see Note 8, Long-term Debt, to our Consolidated Financial Statements). 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 cash settlement date. For additional information, see Note 9, Fair Value of Financial and Derivative Instruments, to our Consolidated Financial Statements.
	We also depend on a relatively small number of purchasers for a substantial portion of our revenue. For the nine months ended September 30, 2014, approximately 95.5% of our commodity sales came from 5 purchasers, with the largest single purchaser accounting for 33.9% 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.

Long_Term_Debt

Long Term Debt	9 Months Ended
	Sep. 30, 2014
Debt Disclosure [Abstract]	'
Long Term Debt	'
	8. 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 September 12, 2014 (the “Senior Credit Facility”). As of September 30, 2014, the borrowing base under the Senior Credit Facility was $400.0 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 letter of credit subfacility exists for up to $60.0 million of letters of credit. The Senior Credit Facility provides that the borrowing base will be re-determined semi-annually by the lenders. As of September 30, 2014, loans made under the Senior Credit Facility were set to mature on September 12, 2019. 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 September 30, 2014, we had no outstanding borrowings, and at December 31, 2013, we had approximately $59.0 million of outstanding borrowings under the Senior Credit Facility.
	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” (each as defined below), plus, in each case, an applicable per annum margin. The “Adjusted LIBO Rate” is equal to the product of: (i) the London Interbank Offered Rate for deposits with a maturity comparable to the borrowings (the “LIBO Rate”) multiplied by (ii) the statutory reserve rate. The Alternative Base Rate is equal to the greater of: (i) RBC’s announced prime rate; (ii) the federal funds effective rate from time to time plus 0.5%; and (iii) 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 150 to 250 basis points, and the applicable per annum margin, in the case of loans bearing interest at the Alternate Base Rate, ranges from 50 to 150 basis points, in each case, determined based upon our borrowing utilization at such date of determination. Upon the occurrence and continuance of an event of default, all outstanding loans shall bear interest at a rate equal to 200 basis points per annum plus the then effective rate of interest. Interest is payable on the last day of the relevant interest period (or at least every three months), in the case of loans bearing interest at the Adjusted LIBO Rate, and quarterly, in the case of loans bearing interest at the Alternate Base Rate.
	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. 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 and 75% of the then outstanding principal amount of our debt for borrowed money which bears interest at a floating rate. As of September 30, 2014, we were in compliance with all of these metrics, and there were no existing defaults or events of default under our Senior Credit Facility.
	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 7, Concentrations of Credit Risk, and Note 9, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements). Borrowings under the Senior Credit Facility have been used to finance our working capital needs and for general corporate purposes in the ordinary course of business, including the exploration, acquisition and development of oil and gas properties. Obligations under the Senior Credit Facility are secured by mortgages on the oil and gas properties of our subsidiaries located in Pennsylvania, Ohio, Illinois and Indiana. We are required to maintain liens covering our oil and gas properties representing at least 80% of our total value of all oil and gas properties.
	The Senior Credit Facility also requires we meet, on a quarterly basis, minimum financial requirements of consolidated current ratio, EBITDAX to interest expense and total 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 September 30, 2014 was approximately 4.0 to 1.0.  Additionally, as of the last day of any fiscal quarter, our ratio of total debt to EBITDAX for the trailing twelve months must not exceed 4.25 to 1.0. Our ratio of total debt to EBITDAX as of September 30, 2014 was approximately 3.9 to 1.0.
	2020 Senior Notes and 2022 Senior Notes
	As of September 30, 2014 and December 31, 2013, we had recorded on our Consolidated Balance Sheets approximately $352.8 million and $353.1 million of 8.875% senior notes due 2020 (the “2020 Senior Notes”), which is inclusive of a net premium of $2.8 million and $3.1 million, respectively. The amortization of our net premium during the first nine months of 2014, which follows the effective interest method, was approximately $0.3 million and was recorded as a credit to Interest Expense on our Consolidated Statement of Operations.
	We may redeem, at specified prices, some or all of the 2020 Senior Notes at any time on or after December 1, 2016. We may also redeem up to 35% of the notes using the proceeds of certain equity offerings completed before December 1, 2015. If we sell certain of our assets or experience specific kinds of changes of control, we may be required to offer to purchase the 2020 Senior Notes from the holders.
	On July 14, 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 $6.3 million were recorded as Deferred Financing Costs and Other Assets – Net on our Consolidated Balance Sheet and are being amortized over the term of the notes as Interest Expense on our Consolidated Statements of Operations. Interest is payable semi-annually at a rate of 6.25% per annum on February 1 and August 1 of each year, commencing on February 1, 2015.
	We may redeem, at specified redemption prices, some or all of the 2022 Senior Notes at any time on or after August 1, 2017. We may also redeem up to 35% of the notes using the proceeds of certain equity offerings completed before August 1, 2017. If we sell certain of our assets or experience specific kinds of changes of control, we may be required to offer to purchase the 2022 Senior Notes from the holders.
	The Senior Notes due 2020 and the Senior Notes due 2022 (collectively, the “Senior Notes”) are fully and unconditionally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries. In addition, there are no significant restrictions on our ability, or the ability of any subsidiary guarantor, to receive funds from our subsidiaries through dividends, loans, advances or otherwise. For additional information on our guarantor and non-guarantor subsidiaries, see Note 19, Condensed Consolidating Financial Information, to our Consolidated Financial Statements.
	In addition to the Senior Credit Facility and the Senior Notes, we may, from time to time in the normal course of business finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and other obligations consisted of the following at September 30, 2014 and December 31, 2013:
	($ in Thousands)	September 30, 2014 (Unaudited)			31-Dec-13
	8.875% Senior Notes Due 2020	$	350,000		$	350,000
	6.25% Senior Notes Due 2022		325,000			—
	Premium on Senior Notes, Net		2,816			3,078
	Senior Line of Credit(a)		—			59,000
	Capital Leases and Other Obligations(a)		14,633			9,934
	Total Debt		692,449			422,012
	Less Current Portion of Long-Term Debt		(8,248	)		(6,743	)
	Total Long-Term Debt	$	684,201		$	415,269
	(a)	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 and nine months ended September 30, 2014 and the year ended December 31, 2013, was approximately 2.2%, 2.1% and 1.9%, respectively. The average interest rate on our capital leases and other obligations for the three and nine months ended September 30, 2014 and the year ended December 31, 2013, was approximately 4.2%, 3.8% and 5.3%, respectively.
	Water Solutions
	On October 18, 2013, Water Solutions Holdings entered into agreements with M&T Bank (“M&T”) to obtain a revolving line of credit (“Demand Note”) and an equipment line of credit (“Equipment Term Note”).
	The borrowing base for the Demand Note is the lesser of (a) $16.0 million, increased from $4.0 million at December 31, 2013, or (b) 80% of Water Solutions’ Accounts Receivable which are less than 90 days old. Borrowings under the Demand Note are to be used for working capital and general corporate purposes. At Water Solutions’ election, borrowings under the Demand Note bear interest per annum equal to an adjusted LIBOR rate or an adjusted base rate, as defined below. The adjusted LIBOR rate is equal 2.75 percentage points above the greater of (a) one-month LIBOR, adjusting daily, or (b) one-day LIBOR. The adjusted base rate is equal to 2.0 percentage points above the rate of interest announced by M&T as its prime rate. All interest that is accrued through the last day of any calendar month will be due and payable by the tenth day of the next calendar month. While there is no stated maturity date for amounts outstanding under the Demand Note, in certain circumstances, Water Solutions may be required to repay amounts outstanding on demand from M&T. As of September 30, 2014, there was approximately $4.5 million outstanding under the Demand Note.
	The Demand Note agreement does not contain any collateral requirements on behalf of Water Solutions, nor does it contain any financial covenant requirements.
	Maximum borrowings under the Equipment Term Note are equal to $6.0 million and are to be used for purposes of making equipment or vehicle acquisitions up to a maximum of 80% of the costs of such assets. Borrowings under the Equipment Term Note bear interest per annum equal to the three month LIBOR plus 3.0 percentage points. All interest is due and payable on the first day of each fiscal quarter. Maturity dates will vary with each borrowing, but will generally be three to four years from the date of borrowing. In certain circumstances, Water Solutions may be required to prepay any loans that are outstanding. As of September 30, 2014, there was approximately $3.6 million outstanding under the Equipment Term Note.
	The Equipment Term Note contains covenants that restrict Water Solutions’ ability to, among other things, materially change their business; incur indebtedness; make loans to others; incur liens; make investments; or become a guarantor. Borrowings under the Equipment Term Note are collateralized with liens covering 80% of the value of assets purchased with associated loans under the Equipment Term Note. The Equipment Term Note also requires that Water Solutions meet certain financial covenants regarding tangible net worth, fixed charge coverage ratio and a debt to EBITDA ratio (as defined in the Equipment Term Note). EBITDA is a non-GAAP financial measure used by the management of Water Solutions and by other users of Water Solutions’ financial statements, such as 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, amortization and other similar non-cash activity. The Equipment Term Note requires that tangible net worth (i) not be less than $2.5 million measured annually, and (ii) not be less than $2.5 million plus 30% of annual net income commencing with the fiscal year ended December 31, 2013 and each fiscal year thereafter. As of December 31, 2013, Water Solutions’ net worth was approximately $9.2 million. Also, Water Solutions’ fixed charge coverage ratio for four consecutive fiscal quarters ending at the end of each fiscal quarter shall not be less than 1.75 to 1.0. As of September 30, 2014, Water Solutions’ fixed charge coverage ratio was approximately 2.3 to 1.0. Water Solutions’ debt to EBITDA ratio for the trailing 12 month period ending on the last day of the measurement period shall not be greater than 2.25 to 1.0. As of September 30, 2014, Water Solutions’ debt to EBITDA ratio was approximately 1.0 to 1.0.
	The following is the principal maturity schedule for debt outstanding as of September 30, 2014:
	2014	$	5,589
	2015		2,745
	2016		2,835
	2017		2,003
	2018		796
	Thereafter		675,665
	Total(a)	$	689,633
	(a)	Excludes $2.8 million net premium on Senior Notes.

Fair_Value_Of_Financial_And_De

Fair Value Of Financial And Derivative Instruments	9 Months Ended
	Sep. 30, 2014
Fair Value Of Financial Instruments And Derivative Instruments [Abstract]	'
Fair Value Of Financial And Derivative Instruments	'
	9. FAIR VALUE OF FINANCIAL AND DERIVATIVE INSTRUMENTS
	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 September 30, 2014 and December 31, 2013, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, swaptions, deferred put spreads, cap swaps, calls, 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.
	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. 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 7, Concentrations of Credit Risk, to our Consolidated Financial Statements.
	None of our commodity derivatives are designated for hedge accounting but are, to a degree, an economic offset to our commodity price exposure. We utilize the mark-to-market accounting method to account for these contracts. We recognize all gains and losses related to these contracts in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Expense. We received net cash settlements of $3.0 million and paid net cash settlements of $4.2 million in relation to our commodity derivatives during the three and nine months ended September 30, 2014, respectively, and received net cash settlements of $0.7 million and $5.5 million in relation to our commodity derivatives for the three and nine months ended September 30, 2013, respectively.
	As of September 30, 2014, we had over 85.0% and 20.0% of our annualized 2014 oil production hedged through the remainder of 2014 and 2015, respectively, over 75.0% and 45.0% of our annualized 2014 natural gas production hedged through the remainder of 2014 and 2015, respectively, and over 60.0% of our annualized 2014 NGL production hedged through the remainder of 2014. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future 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 September 30, 2014 and December 31, 2013, we had $0.0 million and $59.0 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 a fixed interest rate. See Note 8, Long-Term Debt, to our Consolidated Financial Statements for additional information on our Senior Credit Facility and Senior Notes.
	As of December 31, 2013, we had a $25.0 million notional fixed-to-variable interest rate swap to manage our interest rate exposure related to the Senior Notes. Prior to 2013, we did not have any interest rate swap agreements. During the second quarter of 2014, we terminated our interest rate swap for net proceeds of approximately $0.6 million. We utilized the mark-to-market accounting method to account for our interest rate swap. We recognized all gains and losses related to this contract in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Expense. During 2013, there were no cash settlements related to our interest rate swap agreement. During the three and nine months ended September 30, 2014, we received cash payments of approximately $0.0 million and $0.9 million, respectively, related to our interest rate swaps. The fair value of our interest rate swap as December 31, 2013, was a liability of approximately $0.2 million.
	The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three and nine months ended September 30, 2014 and 2013:
			For the Three Months Ended September 30,								For the Nine Months Ended September 30,
	($ in Thousands)		2014				2013				2014				2013
	Oil		$	3,776			$	(4,519	)		$	125			$	(3,989	)
	Natural Gas			6,857				1,125				77				2,605
	NGLs			1,683				(1,230	)			1,030				(39	)
	Interest Rate			—				—				1,083				—
	Gain (Loss) on Derivatives, Net		$	12,316			$	(4,624	)		$	2,315			$	(1,423	)
	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 $5.4 million and a net liability of approximately $0.2 million at September 30, 2014 and December 31, 2013, respectively.
	Our open asset/(liability) financial commodity derivative instrument positions at September 30, 2014 consisted of:
	Period		Volume		Put Option				Floor				Ceiling				Swap			Long Call		Fair Market Value ($ in Thousands)
	Oil
	2014—Collar		15,000 Bbls		$	—			$	90			$	97.65			$	—		$	—	$	26
	2014—Cap Swap		90,000 Bbls			80.83				—				—				97.72			—		649
	2014—Three Way Collar		90,000 Bbls			77.92				88.98				103.39				—			—		171
	2014—Deferred Put Spread		42,000 Bbls			75				90				—				—			—		(146	)
	2015—Three Way Collar		120,000 Bbls			78.75				89.06				100.44				—			—		292
	2015—Call Protected Swap		30,000 Bbls			—				—				—				95.76			110		228
	2015—Put		930,000 Bbls			—				90.16				—				—			—		235
			1,317,000 Bbls																			$	1,455
	Natural Gas
	2014—Call		450,000 Mcf		$	—			$	—			$	5			$	—		$	—	$	(7	)
	2014—Three Way Collar		4,050,000 Mcf			3.55				4.19				4.69				—			—		556
	2014—Swap		1,110,000 Mcf			—				—				—				3.96			—		(147	)
	2014—Collar		450,000 Mcf			—				3.51				4.43				—			—		(23	)
	2014—Swaption		600,000 Mcf			—				—				—				4.45			—		(35	)
	2014—Basis Swap		1,500,000 Mcf			—				—				—				(0.37	)		—		1,889
	2014—Cap Swap		900,000 Mcf			3.3				—				—				4.09			—		(17	)
	2015—Three Way Collar		12,900,000 Mcf			3.63				4.16				4.61				—			—		707
	2015—Swap		1,200,000 Mcf			—				—				—				4.18			—		180
	2015—Cap Swap		2,400,000 Mcf			3.28				—				—				4.1			—		(28	)
	2015—Call		2,400,000 Mcf			—				—				4.4				—			—		(528	)
	2015—Swaption		0 Mcf			—				—				—				4.47			—		(505	)
	2015—Basis Swap		1,200,000 Mcf			—				—				—				(0.56	)		—		973
	2016—Three Way Collar		2,100,000 Mcf			3.6				4.08				4.52				—			—		(127	)
	2017—Three Way Collar		1,200,000 Mcf			3.6				4.1				4.57				—			—		(82	)
			32,460,000 Mcf																			$	2,806
	NGLs
	2014—Swap		261,000 Bbls		$	—			$	—			$	—			$	56.63		$	—	$	819
	2015—Swap		258,000 Bbls			—				—				—				44.6			—		341
			519,000 Bbls																			$	1,160
	The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013 is summarized below
		30-Sep				December 31,
	($ in Thousands)	2014				2013
	Short-Term Derivative Assets:
	Crude Oil—Collars	$	26			$	380
	Crude Oil—Cap Swap		649				—
	Crude Oil—Call Protected Swap		228				—
	Crude Oil—Put		235				—
	Crude Oil—Three-Way Collars		463				104
	NGL—Swaps		1,128				83
	Natural Gas—Swaps		226				106
	Natural Gas—Cap Swaps		103				5
	Natural Gas—Basis Swaps		2,778				3,984
Natural Gas—Three-Way Collars		1,343				518
Natural Gas—Swaption		78				—
Interest Rate—Swap		—				488
Total Short-Term Derivative Assets	$	7,257			$	5,668
Long-Term Derivative Assets:
NGL—Swaps	$	61			$	—
Natural Gas—Cap Swaps		26				5
Natural Gas—Swaps		45				22
Natural Gas—Basis Swaps		84				339
Natural Gas—Three-Way Collars		214				169
Total Long-Term Derivative Assets	$	430			$	535
Total Derivative Assets	$	7,687			$	6,203
Short-Term Derivative Liabilities:
Crude Oil—Collars	$	—			$	(42	)
Crude Oil—Swaps		—				(119	)
Crude Oil—Three-Way Collars		—				(29	)
Crude Oil—Deferred Put Spread		(146	)			(585	)
NGL—Swaps		(29	)			(995	)
Natural Gas—Three-Way Collars		(228	)			(125	)
Natural Gas—Collars		(23	)			(235	)
Natural Gas—Call		(403	)			(150	)
Natural Gas—Cap Swaps		(141	)			(496	)
Natural Gas—Swaption		(113	)			(717	)
Natural Gas—Swaps		(238	)			(1,170	)
Total Short - Term Derivative Liabilities	$	(1,321	)		$	(4,663	)
Long-Term Derivative Liabilities:
Natural Gas—Swaps	$	—			$	(4	)
Natural Gas—Cap Swaps		(33	)			(307	)
Natural Gas—Three-Way Collars		(275	)			—
Natural Gas—Swaption		(505	)			—
Natural Gas—Call		(132	)			(761	)
Interest Rate—Swap		—				(693	)
Total Long-Term Derivative Liabilities	$	(945	)		$	(1,765	)
Total Derivative Liabilities	$	(2,266	)		$	(6,428	)
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—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.
Level 2—Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. 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, 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—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 September 30, 2014 and December 31, 2013, 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 September 30, 2014 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 September 30, 2014 are included in the table below.
	Range		Weighted Average				Fair Value
	(price per Mcf)		(price per Mcf)				(in thousands)
Natural Gas Basis Differential Forward Curve	($1.15) – ($1.96)		$	(1.49	)		$	2,862
During the three and nine months ended September 30, 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 September 30, 2014 Using:
($ in Thousands)	Total Carrying Value as of September 30, 2014				Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	5,421			$	—			$	2,559			$	2,862
The value of our oil derivatives are comprised of collar, three-way collar, swap, cap 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 September 30, 2014 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 puts, swaps, swaptions, collars, three way collars, basis swaps, cap swaps, 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 September 30, 2014 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 September 30, 2014 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 nine months ended September 30, 2014 and 2013:
	Nine Months Ended September 30,
($ in Thousands)	2014				2013
Beginning Balance of Level 3	$	4,323			$	—
Changes in Fair Value		(4,343	)			(721	)
Purchases		—				—
Settlements Received		2,882				23
Ending Balance of Level 3	$	2,862			$	(698	)
Changes in fair value on our Level 3 commodity derivative contracts outstanding for the nine months ended September 30, 2014 and 2013, resulted in a losses of approximately $4.3 million and $0.7 million, respectively. This amount has been included in Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations.
Future Abandonment Cost
We report the fair value of future abandonment costs on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of future abandonment costs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; estimated probabilities, amounts and timing of settlements; estimated plugging costs; the credit-adjusted risk-free rate to be used; and inflation rates. The most significant inputs used in the determination of future abandonment costs are the estimated costs to plug and abandon our wells. Significant changes in the estimated cost to plug and abandon our wells can cause significant changes in the fair value measurement of our future abandonment costs due to the large number of wells that we operate. These inputs are unobservable, and thus result in a Level 3 classification. Refer to Note 3, Future Abandonment Cost, of our Consolidated Financial Statements for further information on future abandonment costs, which include a reconciliation of the beginning and ending balances.
Financial Instruments Not Recorded at Fair Value
The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements:
	30-Sep-14								31-Dec-13
($ in Thousands)	Carrying Amount				Fair Value				Carrying Amount				Fair Value
8.875% Senior Notes due 2020	$	350,000			$	379,750			$	350,000			$	385,000
6.25% Senior Notes due 2022		325,000				312,000				—				—
Secured Lines of Credit		—				—				59,000				59,000
Capital Leases and Other Obligations		14,633				14,292				9,934				9,731
Total	$	689,633			$	706,042			$	418,934			$	453,731
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.

Income_Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2014
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	10. INCOME TAXES
	We recognize deferred income taxes for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value.
	Income tax included in continuing operations was as follows:
		Three Months Ended September 30,						Nine Months Ended September 30,
	($ in Thousands)	2014			2013			2014			2013
	Income (Expense) Benefit	$	(4,469	)	$	1,493		$	(14,592	)	$	(5,622	)
	Effective Tax Rate		44	%		-1843.2	%		39.2	%		31.9	%
	For the nine months ended September 30, 2014, our overall effective tax rate on pre-tax income from continuing operations was different than the statutory rate of 35% due primarily to state taxes and permanent items, including section 162(m) limitations. For the nine months ended September 30, 2013, our overall effective tax rate on pretax losses from continuing operations was different than the statutory rate of 35% due primarily to changes in estimates of current and deferred state taxes identified when completing the state tax returns, permanent differences and changes in state tax rates.
	Income tax payments made during the three and nine months ended September 30, 2014 and 2013 were negligible.  We received tax refunds during the three and nine months ended September 30, 2014 of approximately $1.3 million and $4.7 million, respectively.

Capital_Stock

Capital Stock	9 Months Ended
	Sep. 30, 2014
Equity [Abstract]	'
Capital Stock	'
	11. 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 September 30, 2014 and December 31, 2013, shares of common stock issued and outstanding totaled 54,116,652 and 54,186,490, 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 intend to use 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.
	We will pay cumulative dividends, when and if declared, in cash, stock or a combination therof, on a quarterly basis at a rate of $600 per share, or 6.0%, per year. No dividends had been declared as of September 30, 2014.
	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_Pl

Employee Benefit and Equity Plans	9 Months Ended
	Sep. 30, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'
Employee Benefit and Equity Plans	'
	12. EMPLOYEE BENEFIT AND EQUITY PLANS
	Equity Plans
	We recognize all share-based payments to employees, including grants of employee stock options, in our Consolidated Statements of Operations based on their grant-date fair values, using prescribed option-pricing models where applicable. The fair value is expensed over the requisite service period of the individual grantees, which generally equals one vesting period. We report any benefits of income tax deductions in excess of recognized financial accounting compensation as cash flows from financing activities, rather than as cash flows from operating activities.
	2007 Long-Term Incentive Plan
	We have granted stock options, stock appreciation rights and restricted stock awards to various employees, non-employee contractors and non-employee directors under the terms of our 2007 Long-Term Incentive Plan, as amended (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 Internal Revenue Code or covered employees, are intended to satisfy the requirements of section 162(m) to permit the deduction by us of the associated expenses for federal income tax purposes.
	All awards granted under the Plan have been issued at the closing price of our common stock on the NASDAQ Global Select Market on the date of the grant. All outstanding stock options have been awarded with five or ten year expiration dates at an exercise price equal to our closing price on the NASDAQ Global Select Market on the day the award was granted. 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 common 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 three and nine months ended September 30, 2014 and 2013, we did not issue options to purchase shares of our common stock.
	Stock-based compensation expense relating to stock options outstanding for the three and nine months ended September 30, 2014 and 2013 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. The intrinsic value of stock options exercised for the nine months ended September 30, 2014 and 2013, was approximately $0.3 million and $0.4 million, respectively.  The total tax benefit was approximately $0.1 million and for $0.2 million each of the nine-month periods ended September 30, 2014 and 2013, respectively.
	A summary of the status of our issued and outstanding stock options as of September 30, 2014 is as follows:
					Outstanding						Exercisable
	Exercise Price				Number Outstanding At 9/30/14				Weighted-Average Exercise Price		Number Exercisable At 9/30/14		Weighted-Average Exercise Price
	$	5.04				46,041			$	5.04		46,041	$	5.04
	$	9.5				85,000			$	9.5		85,000	$	9.5
	$	9.99				149,333			$	9.99		149,333	$	9.99
	$	10.42				29,548			$	10.42		29,548	$	10.42
	$	11.87				3,500			$	11.87		3,500	$	11.87
	$	12.5				19,139			$	12.5		19,139	$	12.5
	$	13.19				50,000			$	13.19		—	$	-
	$	22.34				30,000			$	22.34		30,000	$	22.34
						412,561			$	10.79		362,561	$	10.45
	The weighted average remaining contractual term and the aggregate intrinsic value for options outstanding at September 30, 2014 were 3.1 years and $1.1 million, respectively. The weighted average remaining contractual term and the aggregate intrinsic value for options exercisable at September 30, 2014 were 3.3 years and $1.1 million, respectively. As of September 30, 2014, unrecognized compensation expense related to stock options was negligible.
	Restricted Stock Awards
	During the nine-month period ended September 30, 2014, the Compensation Committee approved the issuance of an aggregate of 51,178 shares of restricted common stock to 18 employees. During the nine-month period ended September 30, 2013, the Compensation Committee approved the issuance of an aggregate of 414,924 shares of restricted stock to 38 employees and four non-employees. The shares granted 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 through 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 shares of common stock are valued at the closing price of our common stock on the NASDAQ Global Select Market on the date of grant. Upon a “change in control” of us, as such term is defined in the Plan, restrictions on time vesting and performance-based vesting restricted stock will lapse to varying degrees as outlined in each award agreement. Compensation expense associated with the restricted stock awards is recognized on a straight-line basis over the vesting period.
	Certain of our outstanding restricted stock awards granted in 2014, 2013 and 2012 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 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 2013 Awards to Vest
	3-Jan			100	%
	6-Apr			75	%
	10-Jul			50	%
	13-Nov			25	%
	14-16			0	%
	TSR Rank		Percentage of 2012 Awards to Vest
	3-Jan			100	%
	5-Apr			75	%
	8-Jun			50	%
	11-Sep			25	%
	14-Dec			0	%
	The weighted average fair value of the TSR awards granted as of September 30, 2014 and December 31, 2013 were $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:
		Nine Months Ended September 30, 2014				Year Ended December 31, 2013
	Expected Dividend Yield		0	%			0	%
	Risk-Free Interest Rate		0.8	%			0.7	%
	Expected Volatility – Rex Energy		50.4	%			50.5	%
	Expected Volatility – Peer Group	28.4%-65.7%				28.4%-63.5%
	Market Index		35.3	%			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.
	Compensation expense associated with restricted stock awards totaled $1.6 million and $4.3 million for the three and nine-month periods ended September 30, 2014, respectively, and $1.2 million and $3.5 million for the three and nine-month periods ended September 30, 2013, respectively. As of September 30, 2014, total unrecognized compensation cost related to restricted common stock grants was approximately $6.5 million, which will be recognized over a weighted average period of 1.9 years.
	A summary of the restricted stock activity for the nine months ended September 30, 2014 is as follows:
		Number of Shares				Weighted-Average Grant Date Fair Value
	Restricted stock awards, as of December 31, 2013		2,172,639			$	14.16
	Awards		51,178				15
	Forfeitures		(157,542	)			14.56
	Vested		(315,680	)			12.58
	Restricted stock awards, as of September 30, 2014		1,750,595			$	14.43

Commitments_and_Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2014
Commitments And Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	13. COMMITMENTS AND CONTINGENCIES
	Legal Reserves
	We are involved in various legal proceedings that arise in the ordinary course of our business. Although we cannot predict the outcome of these proceedings with certainty, we do not currently expect these matters to have a material adverse effect on our consolidated financial position or results of operations.
	The accrual of reserves for legal matters is included in Accrued Liabilities on our Consolidated Balance Sheets. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and the subjective judgment of management. While we believe that these reserves are adequate, there are uncertainties associated with legal proceedings and we can give no assurance that our estimate of any related liability will not increase or decrease in the future. The reserved and unreserved exposures for our legal proceedings could change based upon developments in those proceedings or changes in the facts and circumstances. It is possible that we could incur losses in excess of the amounts currently accrued. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed our current accruals by an amount that would have a material adverse effect on our consolidated financial position, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.
	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, 2013.
	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 September 30, 2014, we know of no significant probable or possible environmental contingent liabilities.
	Letters of Credit
	At September 30, 2014, we had posted $5.2 million in various letters of credit to secure our drilling and related operations.
	Lease Commitments
	As of September 30, 2014, we have lease commitments for various real estate leases. Rent expense is recognized on a straight-line basis and has been recorded in General and Administrative expense on our Consolidated Statements of Operations. Rent expense for the three and nine months ended September 30, 2014 and 2013 was $0.3 million and $0.8 million in 2014, respectively, and $0.2 million and $0.5 million in 2013, respectively. Lease commitments by year for each of the next five years are presented in the table below:
	($ in Thousands)
	2014		$	257
	2015			1,034
	2016			958
	2017			932
	2018			237
	Thereafter			26
	Total		$	3,444
	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 $4.8 million in 2014, $15.0 million in 2015, $25.8 million in 2016, $31.0 million in 2017, $31.0 million in 2018 and $245.7 million thereafter, assuming our average working interest in the region of approximately 70%. Charges incurred for processing capacity with MarkWest were negligible during the three and nine-month periods ended September 30, 2014 and 2013.
	Operational Commitments
	We have contracted drilling rig services on four rigs to support our Appalachian Basin operations. The minimum cost to retain these rigs would require payments of approximately $2.6 million in 2014, $3.9 million in 2015 and $1.5 million in 2016, which is consistent with our estimated working interest in this project area. We also have agreements for contracted completion services in the Appalachian Basin. The minimum cost to retain the completion services is approximately $2.6 million in 2014 and $5.1 million in 2015, which is consistent with our estimated working interest in this project area.
	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 $418.2 million, which is larger than our estimated minimum obligations due to certain contracts which have minimum commitment volumes and other contracts which contain provisions that require payment on all volumes delivered.
	For the three months ended September 30, 2014 and 2013, we incurred expenses related to the transportation, processing and marketing of our oil, natural gas and NGLs of approximately $15.7 million and $7.6 million, respectively. For the nine months ended September 30, 2014 and 2013, we incurred expenses related to the transportation, processing and marketing of our oil, natural gas and NGLs of approximately $36.1 million and $17.6 million, respectively. Expense related to these agreements makes up a substantial portion of our Lease Operating Expense, which we expect to continue as existing agreements commence and new transportation, processing and marketing agreements are entered that will enable us to sell our product. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows:
	($ in Thousands)		Total
	2014		$	4,372
	2015			22,122
	2016			34,428
	2017			52,723
	2018			55,539
	Thereafter			752,689
	Total		$	921,873
	Drilling Commitments
	In 2012, we entered into a drill-to-earn agreement with MFC Drilling, Inc. (“MFC”). Under the terms and conditions of the agreement, we will acquire a minimum, through a drill-to-earn structure, a 62.5% working interest in approximately 4,510 acres in Belmont, Guernsey and Noble Counties, Ohio. The agreement provides that in order for us to earn the 62.5% working interest, we will bear the cost for our 62.5% working interest and 100% of the 15% working interest of MFC until such time that we have met the $14.1 million drilling carry obligation. As of September 30, 2014, the remaining drilling carry obligation balance was approximately $4.8 million. Our 2014 capital budget includes additional development in this area.
	In addition to the drilling carry obligation, we are required to meet drilling commitments. Amounts incurred toward the attainment of the drilling commitments are credited towards the drilling carry obligation. Our drilling commitments require us to commence the drilling of at least three Utica Shale wells by November 15 of each year until the carry obligation has been satisfied, with credits given to additional wells drilled beyond the annual commitment. We currently estimate the commitment for each well drilled and completed for our working interest and that of MFC to be approximately $8.0 million to $9.0 million. Should we not comply with the drilling commitments or terminate the agreement, we would be responsible for payment of any remaining drilling carry obligation at that time.
	Pennsylvania Impact Fee
	In 2012, Pennsylvania state legislators instituted a natural gas impact fee on producers of unconventional natural gas. The fee will be 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	$	40,000		$	45,000	$	50,000	$	55,000	$	60,000
	Year Two	$	30,000		$	35,000	$	40,000	$	45,000	$	55,000
	Year Three	$	25,000		$	30,000	$	30,000	$	40,000	$	50,000
	Year 4 – 10	$	10,000		$	15,000	$	20,000	$	20,000	$	20,000
	Year 11 – 15	$	5,000		$	5,000	$	10,000	$	10,000	$	10,000
	(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 will be due on April 1 of each year. For the three and nine months ended September 30, 2014 and 2013, we recorded expense of approximately $1.2 million, and $2.5 million in 2014, respectively and approximately $0.8 million, and $2.2 million in 2013. We record expenses related to the impact fees as Production and Lease Operating Expense.
	Other
	In addition to the Asset Retirement Obligation discussed in Note 3, Future Abandonment Costs, to our Consolidated Financial Statements, we have withheld from distributions to certain other working interest owners amounts to be applied towards their share of those retirement costs. These amounts totaled $0.1 million and $0.3 million at September 30, 2014 and December 31, 2013, respectively, and are included in Other Liabilities on our Consolidated Balance Sheets.

Earnings_Loss_Per_Common_Share

Earnings (Loss) Per Common Share	9 Months Ended
	Sep. 30, 2014
Earnings Per Share [Abstract]	'
Earnings (Loss) Per Common Share	'
	14. EARNINGS PER COMMON SHARE
	Basic income 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 vesting criteria, stock options and the effect of assumed conversions of preferred stock. Diluted income per common share includes the assumed exercise of stock options, assumed conversions of preferred stock and performance-based restricted stock which contain conditions that are not earnings or market based, given that the hypothetical effect is not anti-dilutive. For each of the three and nine-month periods ending September 30, 2014, stock options to purchase 0.3 million shares of common stock were outstanding but not included in the computation of diluted net income per share primarily due to the estimate of shares that would be repurchased using the treasury method. Performance-based restricted stock awards of 0.4 million shares and 0.7 million shares of common stock for the three and nine-month periods ended September 30, 2014, respectively, were outstanding but not included in the computations of diluted net income per share calculations due to performance metrics that have not yet been attained. For each of the three and nine-month periods ending September 30, 2013, stock options to purchase 0.3 million shares of common stock were outstanding but not included in the computation of diluted net income per share because the grant prices were greater than the average market price of the common shares. Performance-based restricted stock awards of 0.5 million shares of common stock for the three and nine months ended September 30, 2013, respectively, were outstanding but not included in the computations of diluted net income per share due to due to performance metrics that have not yet been attained. The following table sets forth the computation of basic and diluted earnings per common share:
	(in thousands, except per share amounts)	Three Months Ended September 30,				Nine Months Ended September 30,
	Numerator:	2014		2013		2014		2013
	Net Income From Continuing Operations, Less Noncontrolling Interests	$	5,694	$	1,574	$	22,642	$	12,019
	Net Income From Discontinued Operations		—		—		—		460
	Net Income	$	5,694	$	1,574	$	22,642	$	12,479
	Denominator:
	Weighted Average Common Shares Outstanding - Basic		53,214		52,626		53,493		52,560
	Effect of Dilutive Securities:
	Employee Stock Options		111		164		134		137
	Employee Performance-Based Restricted Stock Awards		485		503		218		427
	Effect of Assumed Conversions of Preferred Stock		4,181		—		1,409		—
	Weighted Average Common Shares Outstanding - Diluted		57,991		53,293		55,254		53,124
	Earnings per Common Share:
	Basic — Net Income From Continuing Operations	$	0.11	$	0.03	$	0.42	$	0.23
	— Net Income From Discontinued Operations		—		—		—		0.01
	— Net Income	$	0.11	$	0.03	$	0.42	$	0.24
	Diluted — Net Income From Continuing Operations	$	0.1	$	0.03	$	0.41	$	0.23
	— Net Income From Discontinued Operations		—		—		—		0.01
	— Net Income	$	0.1	$	0.03	$	0.41	$	0.24

Consolidated_Subsidiaries

Consolidated Subsidiaries	9 Months Ended
	Sep. 30, 2014
Organization Consolidation And Presentation Of Financial Statements [Abstract]	'
Consolidated Subsidiaries	'
	15. CONSOLIDATED SUBSIDIARIES
	Water Solutions Holdings
	In November 2009, we entered into a limited liability agreement with Sand Hills Management, LLC (“Sand Hills”) to form Water Solutions Holdings, LLC (“Water Solutions”) for the purpose of acquiring, managing and operating water treatment, disposal and transportation facilities that are designed to treat, dispose or transport brine and fresh waters used and produced in oil and gas well development activities. As the result of a change in membership interest that occurred on April 1, 2013, Rex Energy Corporation owns a 60% membership interest in Water Solutions and Sand Hills owns a 40% membership interest and serves as the operator of the entity. The change in ownership interests occurred in accordance with the original operating agreement which stipulated that the change would occur upon the return of our initial capital investments. The change in ownership transaction, in which we retained our controlling financial interest, was accounted for as an equity transaction, with no impact to our Consolidated Statements of Operations. Prior to the change in membership interests, the entity was owned 80% by us and 20% by Sand Hills.
	We fully consolidate the accounts of Water Solutions in our financial statements and accounted for the 40% equity interest owned by Sand Hills as a noncontrolling interest. Water Solutions is financed through cash contributions from its members and a credit facility upon which $8.1 million was drawn as of September 30, 2014. As of September 30, 2014, Water Solutions maintained capital leases of approximately $2.9 million and equipment loans of approximately $2.5 million. Capital contributions to Water Solutions during the first nine months of 2014 and 2013 were negligible. The table below sets forth the carrying amount and classifications of Water Solutions’ assets and liabilities as of September 30, 2014 and December 31, 2013, with no restrictions or obligations to use certain assets to settle associated liabilities:
	($ in Thousands)	As of September 30, 2014			As of December 31, 2013
	Assets
	Cash and Cash Equivalents	$	337		$	593
	Accounts Receivable		13,234			9,882
	Inventory, Prepaid Expenses and Other		297			89
	Other Property and Equipment		20,628			11,798
	Wells and Facilities in Progress		781			1,031
	Accumulated Depreciation, Depletion and Amortization		(4,259	)		(1,954	)
	Deferred Financing Costs and Other Assets—Net		144			206
	Total Assets	$	31,162		$	21,645
	Liabilities
	Accounts Payable	$	1,387		$	758
	Current Maturities of Long-Term Debt		7,237			5,404
	Accrued Liabilities		4,453			6,247
	Senior Secured Line of Credit and Long-Term Debt		6,255			3,053
	Total Liabilities	$	19,332		$	15,462

Equity_Method_Investments

Equity Method Investments	9 Months Ended
	Sep. 30, 2014
Equity Method Investments And Joint Ventures [Abstract]	'
Equity Method Investments	'
	16. 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. We recorded our investment in RW Gathering of approximately $18.1 million and $18.7 million as of September 30, 2014 and December 31, 2013, respectively, on our Consolidated Balance Sheets as Equity Method Investments. We did not make any capital contributions to RW Gathering during the first nine months of 2014 as compared to contributions of $2.5 million in cash to support gathering line construction during first nine months of 2013.  RW Gathering recorded net losses from continuing operations of $0.5 million and $1.5 million for each of the three and nine months ended September 30, 2014, respectively, as compared to losses of $0.5 million and $1.4 million for each of the three and nine months ended September 30, 2013, respectively. The losses incurred were due to insurance fees, bank fees, rent expenses and depreciation expense. Our share of the net loss is recorded on the Statements of Operations as Loss on Equity Method Investments.
	During the three and nine-month periods ended September 30, 2014, we incurred approximately $0.2 million and $0.5 million in compression expenses for 2014, respectively, as compared to $0.3 million and $0.6 million for 2013, respectively, 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 September 30, 2014 and December 31, 2013, there were no receivables due from RW Gathering to us.

Impairment_Expense

Impairment Expense	9 Months Ended
	Sep. 30, 2014
Goodwill And Intangible Assets Disclosure [Abstract]	'
Impairment Expense	'
	17. IMPAIRMENT EXPENSE
	For the three and nine months ended September 30, 2014, impairment expenses incurred were negligible compared to $2.2 million and $2.4 million in impairment expenses for the three and nine months ended September 30, 2013, 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 as of September 30, 2013 was primarily related to acreage in our non-operated dry gas region of Clearfield County, Pennsylvania. These leases were approaching expiration and there was no existing plan to extend the leases or develop the acreage. As of September 30, 2014, we continued to carry the costs of undeveloped properties of approximately $334.5 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.

Exploration_Expense

Exploration Expense	9 Months Ended
	Sep. 30, 2014
Extractive Industries [Abstract]	'
Exploration Expense	'
	18. EXPLORATION EXPENSE
	For the three and nine months ended September 30, 2014, we incurred approximately $1.5 million and $4.9 million in exploration expenses, respectively, as compared to $3.2 million and $7.5 million in exploration expenses for the same periods ended September 30, 2013, respectively. Approximately $3.3 million of the expense incurred in 2014 was due to geological and geophysical type expenditures. An additional $1.2 million of expense was incurred through the payment of delay rentals, predominately in the Appalachian Basin. Approximately $7.0 million of the expense incurred in 2013 was due to geological and geophysical type expenditures and delay rental payments. An additional $0.5 million of expense was related to one exploratory well in Posey County, Indiana determined to be a dry hole.

Condensed_Consolidating_Financ

Condensed Consolidating Financial Information	9 Months Ended
	Sep. 30, 2014
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]	'
Condensed Consolidating Financial Information	'
	19. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
	As of September 30, 2014, we had $675.0 million of outstanding Senior Notes, as shown in Note 8, Long-Term Debt, to our Consolidated Financial Statements. The Senior Notes are guaranteed by certain of our wholly-owned subsidiaries, or guarantor subsidiaries. Unless otherwise noted below, each of the following guarantor subsidiaries are wholly-owned by Rex Energy Corporation and have provided guarantees of the Senior Notes that are joint and several and full and unconditional as of September 30, 2014:
	—	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 September 30, 2014, 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 September 30, 2014 and December 31, 2013, the condensed consolidating statements of operations for each of the three and nine-month periods ended September 30, 2014 and 2013, and the condensed consolidating statements of cash flows for each of the nine-month periods ended September 30, 2014 and 2013.
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING BALANCE SHEETS
	AS OF SEPTEMBER 30, 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	$	87,302		$	315		$	5		$	—		$	87,622
	Accounts Receivable		41,785			13,337			—			(1,729	)		53,393
	Taxes Receivable		—			—			504			—			504
	Short-Term Derivative Instruments		7,257			—			—			—			7,257
	Current Deferred Tax Asset		—			—			2,837			—			2,837
	Inventory, Prepaid Expenses and Other		2,905			297			43			—			3,245
	Total Current Assets		139,249			13,949			3,389			(1,729	)		154,858
	Property and Equipment (Successful Efforts Method)
	Evaluated Oil and Gas Properties		1,017,608			191			—			(5,332	)		1,012,467
	Unevaluated Oil and Gas Properties		333,600			861			—			—			334,461
	Other Property and Equipment		62,110			21,535			—			—			83,645
	Wells and Facilities in Progress		110,046			7,228			—			(295	)		116,979
	Pipelines		17,773			—			—			(1,898	)		15,875
	Total Property and Equipment		1,541,137			29,815			—			(7,525	)		1,563,427
	Less: Accumulated Depreciation, Depletion and Amortization		(251,704	)		(4,584	)		—			817			(255,471	)
	Net Property and Equipment		1,289,433			25,231			—			(6,708	)		1,307,956
	Deferred Financing Costs and Other Assets—Net		2,422			144			15,020			—			17,586
	Equity Method Investments		18,098			—			—			—			18,098
	Intercompany Receivables		—			—			966,226			(966,226	)		—
	Investment in Subsidiaries – Net		4,161			3,438			355,797			(363,396	)		—
	Long-Term Derivative Instruments		430			—			—			—			430
	Total Assets	$	1,453,793		$	42,762		$	1,340,432		$	(1,338,059	)	$	1,498,928
	LIABILITIES AND STOCKHOLDERS’ EQUITY
	Current Liabilities
	Accounts Payable	$	56,909		$	1,391		$	—		$	(1,731	)	$	56,569
	Current Maturities of Long-Term Debt		1,011			7,237			—			—			8,248
	Accrued Liabilities		50,813			4,683			15,339			—			70,835
	Short-Term Derivative Instruments		1,321			—			—			—			1,321
	Total Current Liabilities		110,054			13,311			15,339			(1,731	)		136,973
	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		—			—			2,816			—			2,816
	Senior Secured Line of Credit and Other Long-Term Debt		130			6,255			—			—			6,385
	Long-Term Derivative Instruments		945			—			—			—			945
	Long-Term Deferred Tax Liability		—			—			43,414			—			43,414
	Other Deposits and Liabilities		4,303			—			—			—			4,303
	Future Abandonment Cost		27,402			32			—			—			27,434
	Intercompany Payables		962,392			3,834			—			(966,226	)		—
	Total Liabilities		1,105,226			23,432			736,569			(967,957	)		897,270
	Stockholders’ Equity
	Preferred Stock		—			—			1			—			1
	Common Stock		—			—			54			—			54
	Additional Paid-In Capital		177,144			82,780			616,384			(259,924	)		616,384
	Accumulated Earnings (Deficit)		171,423			(64,412	)		(12,576	)		(113,518	)		(19,083	)
	Rex Energy Stockholders’ Equity		348,567			18,368			603,863			(373,442	)		597,356
	Noncontrolling Interests		—			962			—			3,340			4,302
	Total Stockholders’ Equity		348,567			19,330			603,863			(370,102	)		601,658
Total Liabilities and Stockholders’ Equity	$	1,453,793		$	42,762		$	1,340,432		$	(1,338,059	)	$	1,498,928
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
($ in Thousands)
	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	73,343		$	105		$	—		$	—		$	73,448
Field Services Revenue		—			15,870			—			(2,800	)		13,070
Other Revenue		18			—			—			—			18
TOTAL OPERATING REVENUE		73,361			15,975			—			(2,800	)		86,536
OPERATING EXPENSES
Production and Lease Operating Expense		27,668			4			—			(15	)		27,657
General and Administrative Expense		7,709			1,160			1,555			(15	)		10,409
Loss on Disposal of Asset		175			(91	)		—			—			84
Impairment Expense		1			—			—			—			1
Exploration Expense		1,452			10			—			—			1,462
Depreciation, Depletion, Amortization and Accretion		26,536			1,027			—			(199	)		27,364
Field Services Operating Expense		—			11,464			—			(1,917	)		9,547
Other Operating (Income) Expense		(24	)		—			—			—			(24	)
TOTAL OPERATING EXPENSES		63,517			13,574			1,555			(2,146	)		76,500
INCOME (LOSS) FROM OPERATIONS		9,844			2,401			(1,555	)		(654	)		10,036
OTHER INCOME (EXPENSE)
Interest Expense		(56	)		(134	)		(10,890	)		—			(11,080	)
Gain (Loss) on Derivatives, Net		12,316			—			—			—			12,316
Other Expense		3			—			—			(15	)		(12	)
Loss From Equity Method Investments		(202	)		—			—			—			(202	)
Income (Loss) From Equity in Consolidated Subsidiaries		18			(18	)		12,840			(12,840	)		—
TOTAL OTHER INCOME (EXPENSE)		12,079			(152	)		1,950			(12,855	)		1,022
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		21,923			2,249			395			(13,509	)		11,058
Income Tax (Expense) Benefit		(8,853	)		(915	)		5,299			—			(4,469	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		13,070			1,334			5,694			(13,509	)		6,589
Net Income Attributable to Noncontrolling Interests		—			895			—			—			895
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	13,070		$	439		$	5,694		$	(13,509	)	$	5,694
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2014
($ in Thousands)
	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	227,547		$	103		$	—		$	—		$	227,650
Field Services Revenue		—			54,467			—			(13,005	)		41,462
Other Revenue		92			—			—			—			92
TOTAL OPERATING REVENUE		227,639			54,570			—			(13,005	)		269,204
OPERATING EXPENSES
Production and Lease Operating Expense		69,328			10			—			(35	)		69,303
General and Administrative Expense		22,811			2,982			4,296			(50	)		30,039
Loss on Disposal of Asset		469			(84	)		—			—			385
Impairment Expense		41			—			—			—			41
Exploration Expense		4,877			13			—			—			4,890
Depreciation, Depletion, Amortization and Accretion		66,812			2,671			—			(469	)		69,014
Field Services Operating Expense		—			40,246			—			(9,334	)		30,912
Other Operating Expense		3			—			—			—			3
TOTAL OPERATING EXPENSES		164,341			45,838			4,296			(9,888	)		204,587
INCOME (LOSS) FROM OPERATIONS		63,298			8,732			(4,296	)		(3,117	)		64,617
OTHER INCOME (EXPENSE)
Interest Expense		(86	)		(482	)		(25,150	)		—			(25,718	)
Gain (Loss) on Derivatives, Net		1,232			—			1,083			—			2,315
Other Income (Expense)		20			—			—			(50	)		(30	)
Loss From Equity Method Investments		(610	)		—			—			—			(610	)
Income (Loss) From Equity in Consolidated Subsidiaries		(64	)		64			39,667			(39,667	)		—
TOTAL OTHER INCOME (EXPENSE)		492			(418	)		15,600			(39,717	)		(24,043	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		63,790			8,314			11,304			(42,834	)		40,574
Income Tax (Expense) Benefit		(22,964	)		(2,967	)		11,339			—			(14,592	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		40,826			5,347			22,643			(42,834	)		25,982
Net Income Attributable to Noncontrolling Interests		—			3,340			—			—			3,340
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	40,826		$	2,007		$	22,643		$	(42,834	)	$	22,642
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2014
($ in Thousands)
	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	40,826		$	5,347		$	22,643		$	(42,834	)	$	25,982
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss From Equity Method Investments		610			—			—			—			610
Non-Cash Expenses (Income)		(203	)		233			5,116			—			5,146
Depreciation, Depletion, Amortization and Accretion		66,812			2,671			—			(469	)		69,014
Deferred Income Tax Expense (Benefit)		22,964			2,967			(11,339	)		—			14,592
(Gain) Loss on Derivatives		(1,232	)		—			(1,083	)		—			(2,315	)
Cash Settlements of Derivatives		(4,209	)		—			878			—			(3,331	)
Dry Hole Expense		237			—			—			—			237
Loss on Sale of Asset		469			(84	)		—			—			385
Impairment Expense		41			—			—			—			41
Changes in operating assets and liabilities
Accounts Receivable		(9,510	)		(3,455	)		4,685			(1,574	)		(9,854	)
Inventory, Prepaid Expenses and Other Assets		(812	)		(209	)		(17	)		—			(1,038	)
Accounts Payable and Accrued Liabilities		22,975			(1,007	)		12,518			1,574			36,060
Other Assets and Liabilities		(1,942	)		(24	)		—			—			(1,966	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		137,026			6,439			33,401			(43,303	)		133,563
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		408,192			248			(448,109	)		39,669			—
Proceeds from Joint Venture Acreage Management		210			—			—			—			210
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		248			164			—			—			412
Acquisitions of Undeveloped Acreage		(152,765	)		(863	)		—			—			(153,628	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(305,672	)		(8,315	)		—			3,634			(310,353	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(49,787	)		(8,766	)		(448,109	)		43,303			(463,359	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			22,041			171,000			—			193,041
Repayments of Long-Term Debt and Lines of Credit		—			(18,146	)		(230,000	)		—			(248,146	)
Repayments of Loans and Other Long-Term Debt		(1,323	)		(675	)		—			—			(1,998	)
Proceeds from Senior Notes, Net of Discounts and Premiums		—			—			325,000			—			325,000
Debt Issuance Costs		—			(7	)		(6,724	)		—			(6,731	)
Proceeds from the Issuance of Preferred Stock, Net		—			—			155,011			—			155,011
Proceeds from Exercise of Stock Options		—			—			421			—			421
Distributions by the Partners of Consolidated Subsidiaries		—			(1,080	)		—			—			(1,080	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(1,323	)		2,133			414,708			—			415,518
NET INCREASE (DECREASE) IN CASH		85,916			(194	)		—			—			85,722
CASH – BEGINNING		1,386			509			5			—			1,900
CASH - ENDING	$	87,302		$	315		$	5		$	—		$	87,622
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
AS OF DECEMBER 31, 2013
($ 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	$	1,386		$	509		$	5		$	—		$	1,900
Accounts Receivable		32,283			9,882			—			(3,302	)		38,863
Taxes Receivable		—			—			5,189			—			5,189
Short-Term Derivative Instruments		5,180			—			488			—			5,668
Current Deferred Tax Asset		—			—			3,451			—			3,451
Inventory, Prepaid Expenses and Other		2,092			89			26			—			2,207
Total Current Assets		40,941			10,480			9,159			(3,302	)		57,278
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		752,781			—			—			(3,101	)		749,680
Unevaluated Oil and Gas Properties		189,385			—			—			—			189,385
Other Property and Equipment		57,409			12,706			—			—			70,115
Wells and Facilities in Progress		70,759			6,576			—			(790	)		76,545
Pipelines		7,678			—			—			—			7,678
Total Property and Equipment		1,078,012			19,282			—			(3,891	)		1,093,403
Less: Accumulated Depreciation, Depletion and Amortization		(188,699	)		(2,172	)		—			350			(190,521	)
Net Property and Equipment		889,313			17,110			—			(3,541	)		902,882
Deferred Financing Costs and Other Assets—Net		2,421			206			9,366			—			11,993
Equity Method Investments		18,708			—			—			—			18,708
Intercompany Receivables		—			—			628,517			(628,517	)		—
Investment in Subsidiaries – Net		4,442			1,197			216,945			(222,584	)		—
Long-Term Derivative Instruments		535			—			—			—			535
Total Assets	$	956,360		$	28,993		$	863,987		$	(857,944	)	$	991,396
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	33,613		$	794		$	—		$	(3,304	)	$	31,103
Current Maturities of Long-Term Debt		1,339			5,404			—			—			6,743
Accrued Liabilities		45,196			6,287			2,967			—			54,450
Short-Term Derivative Instruments		4,663			—			—			—			4,663
Total Current Liabilities		84,811			12,485			2,967			(3,304	)		96,959
8.875% Senior Notes Due 2020		—			—			350,000			—			350,000
Premium (Discount) on Senior Notes – Net		—			—			3,078			—			3,078
Senior Secured Line of Credit and Other Long-Term Debt		137			3,054			59,000			—			62,191
Long-Term Derivative Instruments		1,071			—			694			—			1,765
Long-Term Deferred Tax Liability		—			—			29,446			—			29,446
Other Deposits and Liabilities		4,992			—			—			—			4,992
Future Abandonment Cost		26,027			13			—			—			26,040
Intercompany Payables		554,329			74,188			—			(628,517	)		—
Total Liabilities		671,367			89,740			445,185			(631,821	)		574,471
Stockholders’ Equity
Common Stock		—			—			54			—			54
Additional Paid-In Capital		177,144			6,488			456,554			(183,632	)		456,554
Accumulated Earnings (Deficit)		107,849			(67,720	)		(37,806	)		(44,048	)		(41,725	)
Rex Energy Stockholders’ Equity		284,993			(61,232	)		418,802			(227,680	)		414,883
Noncontrolling Interests		—			485			—			1,557			2,042
Total Stockholders’ Equity		284,993			(60,747	)		418,802			(226,123	)		416,925
Total Liabilities and Stockholders’ Equity	$	956,360		$	28,993		$	863,987		$	(857,944	)	$	991,396
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2013
($ in Thousands)
	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	58,063		$	—		$	—		$	—		$	58,063
Field Services Revenue		—			6,543			—			(1,696	)		4,847
Other Revenue		64			—			—			—			64
TOTAL OPERATING REVENUE		58,127			6,543			—			(1,696	)		62,974
OPERATING EXPENSES
Production and Lease Operating Expense		17,201			2			—			—			17,203
General and Administrative Expense		6,863			617			1,361			(15	)		8,826
Loss on Disposal of Asset		94			46			—			—			140
Impairment Expense		2,244			—			—			—			2,244
Exploration Expense		3,241			1			—			—			3,242
Depreciation, Depletion, Amortization and Accretion		15,876			435			—			(44	)		16,267
Field Services Operating Expense		—			4,821			—			(1,169	)		3,652
Other Operating Expense		19			—			—			—			19
TOTAL OPERATING EXPENSES		45,538			5,922			1,361			(1,228	)		51,593
INCOME (LOSS) FROM OPERATIONS		12,589			621			(1,361	)		(468	)		11,381
OTHER INCOME (EXPENSE)
Interest Expense		(16	)		(26	)		(6,139	)		—			(6,181	)
Gain on Derivatives, Net		(4,624	)		—			—			—			(4,624	)
Other Income (Expense)		(15	)		—			—			(15	)		(30	)
Loss From Equity Method Investments		(207	)		—			—			—			(207	)
Income (Loss) From Equity in Consolidated Subsidiaries		(22	)		22			7,653			(7,653	)		—
TOTAL OTHER INCOME (EXPENSE)		(4,884	)		(4	)		1,514			(7,668	)		(11,042	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		7,705			617			153			(8,136	)		339
Income Tax (Expense) Benefit		11			61			1,421			—			1,493
INCOME (LOSS) FROM CONTINUING OPERATIONS		7,716			678			1,574			(8,136	)		1,832
Income From Discontinued Operations, Net of Income Taxes		—			—			—			—			—
NET INCOME (LOSS)		7,716			678			1,574			(8,136	)		1,832
Net Income Attributable to Noncontrolling Interests		—			258			—			—			258
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	7,716		$	420		$	1,574		$	(8,136	)	$	1,574
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2013
($ in Thousands)
	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	150,447		$	—		$	—		$	—		$	150,447
Field Services Revenue		—			19,668			—			(4,475	)		15,193
Other Revenue		164			—			—			—			164
TOTAL OPERATING REVENUE		150,611			19,668			—			(4,475	)		165,804
OPERATING EXPENSES
Production and Lease Operating Expense		43,688			7			—			—			43,695
General and Administrative Expense		18,896			1,765			3,814			(71	)		24,404
Loss on Disposal of Asset		1,586			46			—			—			1,632
Impairment Expense		2,414			—			—			—			2,414
Exploration Expense		7,510			1			—			—			7,511
Depreciation, Depletion, Amortization and Accretion		39,434			1,038			—			(105	)		40,367
Field Services Operating Expense		—			13,468			—			(3,114	)		10,354
Other Operating Expense		910			—			—			—			910
TOTAL OPERATING EXPENSES		114,438			16,325			3,814			(3,290	)		131,287
INCOME (LOSS) FROM OPERATIONS		36,173			3,343			(3,814	)		(1,185	)		34,517
OTHER INCOME (EXPENSE)
Interest Expense		(47	)		(66	)		(15,900	)		—			(16,013	)
Gain on Derivatives, Net		(1,423	)		—			—			—			(1,423	)
Other Income (Expense)		2,112			—			—			(71	)		2,041
Loss From Equity Method Investments		(569	)		—			—			—			(569	)
Income (Loss) From Equity in Consolidated Subsidiaries		(44	)		44			25,510			(25,510	)		—
TOTAL OTHER INCOME (EXPENSE)		29			(22	)		9,610			(25,581	)		(15,964	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		36,202			3,321			5,796			(26,766	)		18,553
Income Tax (Expense) Benefit		(11,546	)		(759	)		6,683			—			(5,622	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		24,656			2,562			12,479			(26,766	)		12,931
Income From Discontinued Operations, Net of Income Taxes		—			460			—			—			460
NET INCOME (LOSS)		24,656			3,022			12,479			(26,766	)		13,391
Net Income Attributable to Noncontrolling Interests		—			912			—			—			912
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	24,656		$	2,110		$	12,479		$	(26,766	)	$	12,479
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2013
($ in Thousands)	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	24,656		$	3,022		$	12,479		$	(26,766	)	$	13,391
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss From Equity Method Investments		569			—			—			—			569
Non-Cash Expenses		(180	)		65			4,547			—			4,432
Depreciation, Depletion, Amortization and Accretion		39,434			1,038			—			(105	)		40,367
Deferred Income Tax Expense (Benefit)		12,060			1,169			(2,259	)		—			10,970
Gain on Derivatives		1,423			—			—			—			1,423
Cash Settlements of Derivatives		5,540			—			—			—			5,540
Dry Hole Expense		485			—			—			—			485
(Gain) Loss on Sale of Asset		1,586			(923	)		—			—			663
Impairment Expense		2,414			—			—			—			2,414
Changes in operating assets and liabilities
Accounts Receivable		(2,628	)		(669	)		—			(3,731	)		(7,028	)
Inventory, Prepaid Expenses and Other Assets		(316	)		(66	)		(9	)		—			(391	)
Accounts Payable and Accrued Liabilities		23,174			(1,687	)		9,241			4,022			34,750
Other Assets and Liabilities		(1,495	)		(88	)		(247	)		—			(1,830	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		106,722			1,861			23,752			(26,580	)		105,755
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		139,294			688			(165,201	)		25,219			—
Proceeds from Joint Venture Acreage Management		246			—			—			—			246
Contributions to Equity Method Investments		(2,493	)		—			—			—			(2,493	)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		697			3,234			—			—			3,931
Acquisitions of Undeveloped Acreage		(31,456	)		(2	)		—			—			(31,458	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(193,964	)		(4,661	)		—			1,361			(197,264	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(87,676	)		(741	)		(165,201	)		26,580			(227,038	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			1,750			—			—			1,750
Repayments of Long-Term Debt and Lines of Credit		—			(1,022	)		—			—			(1,022	)
Repayments of Loans and Other Notes Payable		(934	)		(429	)		—			—			(1,363	)
Proceeds from Senior Notes, net of Discounts and Premiums		—			—			105,000			—			105,000
Debt Issuance Costs		—			—			(3,004	)		—			(3,004	)
Proceeds from the Exercise of Stock Options		—			—			534			—			534
Purchase of Non-Controlling Interests		—			(150	)		—			—			(150	)
Distributions by the Partners of Consolidated Subsidiaries		—			(646	)		—			—			(646	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(934	)		(497	)		102,530			—			101,099
NET INCREASE (DECREASE) IN CASH		18,112			623			(38,919	)		—			(20,184	)
CASH – BEGINNING		4,227			824			38,924			—			43,975
CASH - ENDING	$	22,339		$	1,447		$	5		$	—		$	23,791

Recently_Issued_Accounting_Pro1

Recently Issued Accounting Pronouncements (Policies)	9 Months Ended
	Sep. 30, 2014
Accounting Policies [Abstract]	'
Recently Issued Accounting Pronouncements	'
	In April 2014, the FASB issued ASU 2014-08, Presentation of Financial Statements and Property, Plant, and Equipment: Reporting Discontinued Operations and Disclosures of Disposal of Components of an Entity. The amendments in this ASU change the criteria for reporting discontinued operations while enhancing the disclosures in this area. Under the new guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization’s operations and financial results. In addition, the new guidance requires expanded disclosures about discontinued operations that will provide financial statement users with more information about the assets, liabilities, income and expenses of discontinued operations. The amendments in this ASU are effective in the first quarter of 2015 for public organizations with calendar year ends. 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 May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The amendments in this ASU affects any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards. This ASU will supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services by following five steps:
	—	Identify the contract(s) with a customer.
	—	Identify the performance obligations in the contract.
	—	Determine the transaction price.
	—	Allocate the transaction price to the performance obligations in the contract.
	—	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.
	For public entities, the amendments in this ASU are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early application is not permitted. We are currently evaluating the potential impact of this ASU.
	In June 2014, the FASB issued ASU 2014-12, Compensation – Stock Compensation. The amendments in this ASU require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. A reporting entity should apply existing guidance in Topic 718 as it relates to awards with performance conditions that affect vesting to account for such awards. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. Entities may apply the amendments in this ASU either: (a) prospectively to all awards granted or modified after the effective date; or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new awards thereafter. The amendments in this ASU are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. 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.

Business_Segment_Information_T

Business Segment Information (Tables)	9 Months Ended
	Sep. 30, 2014
Segment Reporting [Abstract]	'
Performance of Business Segments Based on Net Income (Loss) from Continuing Operations, before Income Taxes	'
	We evaluate the performance of our business segments based on net income (loss) from continuing operations, before income taxes. All intercompany transactions, including those between consolidated business segments, are eliminated in consolidation. Summarized financial information concerning our segments is shown in the following table for the three and nine months ended September 30, 2014 and 2013:
	($ in Thousands)	Exploration and Production		Field Services			Intercompany Eliminations			Consolidated Total
	Three Months Ended September 30, 2014
	Revenues	$	73,466	$	15,870		$	(2,800	)	$	86,536
	Inter-Segment Revenues		—		(2,800	)		2,800			—
	Total Revenues		73,466		13,070			—			86,536
	Income (Loss) From Continuing Operations, Before Income Taxes	$	9,503	$	2,225		$	(670	)	$	11,058
	Three Months Ended September 30, 2013
	Revenues	$	58,127	$	6,543		$	(1,696	)	$	62,974
	Inter-Segment Revenues		—		(1,696	)		1,696			—
	Total Revenues		58,127		4,847			—			62,974
	Income (Loss) From Continuing Operations, Before Income Taxes	$	192	$	629		$	(482	)	$	339
	Nine Months Ended September 30, 2014
	Revenues	$	227,742	$	54,467		$	(13,005	)	$	269,204
	Inter-Segment Revenues		—		(13,005	)		13,005			—
	Total Revenues		227,742		41,462			—			269,204
	Income (Loss) From Continuing Operations, Before Income Taxes	$	35,434	$	8,306		$	(3,166	)	$	40,574
	Nine Months Ended September, 2013
	Revenues	$	150,611	$	19,668		$	(4,475	)	$	165,804
	Inter-Segment Revenues		—		(4,475	)		4,475			—
	Total Revenues		150,611		15,193			—			165,804
	Income (Loss) From Continuing Operations, Before Income Taxes	$	16,464	$	3,344		$	(1,255	)	$	18,553
	As of September 30, 2014
	Total Assets	$	1,471,683	$	35,681		$	(8,436	)	$	1,498,928
	As of December  31, 2013
	Total Assets	$	971,973	$	26,266		$	(6,843	)	$	991,396

Future_Abandonment_Cost_Tables

Future Abandonment Cost (Tables)	9 Months Ended
	Sep. 30, 2014
Asset Retirement Obligation Disclosure [Abstract]	'
Future Abandonment Costs	'
	($ in Thousands)	Nine Months Ended September 30, 2014
	Beginning Balance at January 1, 2014	$	28,525
	Future Abandonment Obligation Incurred		1,321
	Future Abandonment Obligation Settled		(1,798	)
	Future Abandonment Obligation Revision of Estimated Obligation		27
	Future Abandonment Obligation Accretion Expense		2,912
	Total Future Abandonment Cost1	$	30,987
	1 Includes approximately $3.6 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

Discontinued_OperationsAssets_1

Discontinued Operations/Assets Held For Sale (Tables)	9 Months Ended
	Sep. 30, 2014
Discontinued Operations And Disposal Groups [Abstract]	'
Summary of Financial Information for Discontinued Operations	'
	Summarized financial information for Discontinued Operations 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.
		Three Months Ended September 30,				Nine Months Ended September 30,
	($ in Thousands)	2014		2013		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 Income Expense		—		—		—		(3	)
	Gain on Sale of Asset		—		—		—		(969	)
	Total Costs and Expenses		—		—		—		(748	)
	Income from Discontinued Operations Before Income Taxes		—		—		—		773
	Income Tax Expense		—		—		—		(313	)
	Income from Discontinued Operations, net of taxes	$	—	$	—	$	—	$	460
	Production:
	Crude Oil (Bbls)		—		—		—		356
	Total (Mcfe)		—		—		—		2,136

Business_and_Oil_and_Gas_Prope1

Business and Oil and Gas Property Acquisitions and Dispositions (Tables)	9 Months Ended
	Sep. 30, 2014
Business Combinations [Abstract]	'
Summary of Acquisition Price Allocated	'
	The acquisition price was allocated as follows:
	($ in Thousands)	30-Sep-14
	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

Long_Term_Debt_Tables

Long Term Debt (Tables)	9 Months Ended
	Sep. 30, 2014
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 September 30, 2014 and December 31, 2013:
	($ in Thousands)	September 30, 2014 (Unaudited)			31-Dec-13
	8.875% Senior Notes Due 2020	$	350,000		$	350,000
	6.25% Senior Notes Due 2022		325,000			—
	Premium on Senior Notes, Net		2,816			3,078
	Senior Line of Credit(a)		—			59,000
	Capital Leases and Other Obligations(a)		14,633			9,934
	Total Debt		692,449			422,012
	Less Current Portion of Long-Term Debt		(8,248	)		(6,743	)
	Total Long-Term Debt	$	684,201		$	415,269
	(a)	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 and nine months ended September 30, 2014 and the year ended December 31, 2013, was approximately 2.2%, 2.1% and 1.9%, respectively. The average interest rate on our capital leases and other obligations for the three and nine months ended September 30, 2014 and the year ended December 31, 2013, was approximately 4.2%, 3.8% and 5.3%, respectively.
Principal Maturity Schedule for Debt Outstanding	'
	The following is the principal maturity schedule for debt outstanding as of September 30, 2014:
	2014	$	5,589
	2015		2,745
	2016		2,835
	2017		2,003
	2018		796
	Thereafter		675,665
	Total(a)	$	689,633
	—	Excludes $2.8 million net premium on Senior Notes.

Fair_Value_Of_Financial_And_De1

Fair Value Of Financial And Derivative Instruments (Tables)	9 Months Ended
	Sep. 30, 2014
Fair Value Of Financial Instruments And Derivative Instruments [Abstract]	'
Schedule of Location and Amounts of Gains and Losses on Derivative Instruments	'
	The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three and nine months ended September 30, 2014 and 2013:
			For the Three Months Ended September 30,								For the Nine Months Ended September 30,
	($ in Thousands)		2014				2013				2014				2013
	Oil		$	3,776			$	(4,519	)		$	125			$	(3,989	)
	Natural Gas			6,857				1,125				77				2,605
	NGLs			1,683				(1,230	)			1,030				(39	)
	Interest Rate			—				—				1,083				—
	Gain (Loss) on Derivatives, Net		$	12,316			$	(4,624	)		$	2,315			$	(1,423	)
Asset or Liability Financial Commodity Derivative Instrument Positions	'
	Our open asset/(liability) financial commodity derivative instrument positions at September 30, 2014 consisted of:
	Period		Volume		Put Option				Floor				Ceiling				Swap			Long Call		Fair Market Value ($ in Thousands)
	Oil
	2014—Collar		15,000 Bbls		$	—			$	90			$	97.65			$	—		$	—	$	26
	2014—Cap Swap		90,000 Bbls			80.83				—				—				97.72			—		649
	2014—Three Way Collar		90,000 Bbls			77.92				88.98				103.39				—			—		171
	2014—Deferred Put Spread		42,000 Bbls			75				90				—				—			—		(146	)
	2015—Three Way Collar		120,000 Bbls			78.75				89.06				100.44				—			—		292
	2015—Call Protected Swap		30,000 Bbls			—				—				—				95.76			110		228
	2015—Put		930,000 Bbls			—				90.16				—				—			—		235
			1,317,000 Bbls																			$	1,455
	Natural Gas
	2014—Call		450,000 Mcf		$	—			$	—			$	5			$	—		$	—	$	(7	)
	2014—Three Way Collar		4,050,000 Mcf			3.55				4.19				4.69				—			—		556
	2014—Swap		1,110,000 Mcf			—				—				—				3.96			—		(147	)
	2014—Collar		450,000 Mcf			—				3.51				4.43				—			—		(23	)
	2014—Swaption		600,000 Mcf			—				—				—				4.45			—		(35	)
	2014—Basis Swap		1,500,000 Mcf			—				—				—				(0.37	)		—		1,889
	2014—Cap Swap		900,000 Mcf			3.3				—				—				4.09			—		(17	)
	2015—Three Way Collar		12,900,000 Mcf			3.63				4.16				4.61				—			—		707
	2015—Swap		1,200,000 Mcf			—				—				—				4.18			—		180
	2015—Cap Swap		2,400,000 Mcf			3.28				—				—				4.1			—		(28	)
	2015—Call		2,400,000 Mcf			—				—				4.4				—			—		(528	)
	2015—Swaption		0 Mcf			—				—				—				4.47			—		(505	)
	2015—Basis Swap		1,200,000 Mcf			—				—				—				(0.56	)		—		973
	2016—Three Way Collar		2,100,000 Mcf			3.6				4.08				4.52				—			—		(127	)
	2017—Three Way Collar		1,200,000 Mcf			3.6				4.1				4.57				—			—		(82	)
			32,460,000 Mcf																			$	2,806
	NGLs
	2014—Swap		261,000 Bbls		$	—			$	—			$	—			$	56.63		$	—	$	819
	2015—Swap		258,000 Bbls			—				—				—				44.6			—		341
			519,000 Bbls																			$	1,160
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 September 30, 2014 and December 31, 2013 is summarized below
		30-Sep				December 31,
	($ in Thousands)	2014				2013
	Short-Term Derivative Assets:
	Crude Oil—Collars	$	26			$	380
	Crude Oil—Cap Swap		649				—
	Crude Oil—Call Protected Swap		228				—
	Crude Oil—Put		235				—
	Crude Oil—Three-Way Collars		463				104
	NGL—Swaps		1,128				83
	Natural Gas—Swaps		226				106
	Natural Gas—Cap Swaps		103				5
	Natural Gas—Basis Swaps		2,778				3,984
	Natural Gas—Three-Way Collars		1,343				518
	Natural Gas—Swaption		78				—
	Interest Rate—Swap		—				488
	Total Short-Term Derivative Assets	$	7,257			$	5,668
	Long-Term Derivative Assets:
	NGL—Swaps	$	61			$	—
	Natural Gas—Cap Swaps		26				5
	Natural Gas—Swaps		45				22
	Natural Gas—Basis Swaps		84				339
	Natural Gas—Three-Way Collars		214				169
	Total Long-Term Derivative Assets	$	430			$	535
	Total Derivative Assets	$	7,687			$	6,203
	Short-Term Derivative Liabilities:
	Crude Oil—Collars	$	—			$	(42	)
	Crude Oil—Swaps		—				(119	)
	Crude Oil—Three-Way Collars		—				(29	)
	Crude Oil—Deferred Put Spread		(146	)			(585	)
	NGL—Swaps		(29	)			(995	)
	Natural Gas—Three-Way Collars		(228	)			(125	)
	Natural Gas—Collars		(23	)			(235	)
	Natural Gas—Call		(403	)			(150	)
	Natural Gas—Cap Swaps		(141	)			(496	)
	Natural Gas—Swaption		(113	)			(717	)
	Natural Gas—Swaps		(238	)			(1,170	)
	Total Short - Term Derivative Liabilities	$	(1,321	)		$	(4,663	)
	Long-Term Derivative Liabilities:
	Natural Gas—Swaps	$	—			$	(4	)
	Natural Gas—Cap Swaps		(33	)			(307	)
	Natural Gas—Three-Way Collars		(275	)			—
	Natural Gas—Swaption		(505	)			—
	Natural Gas—Call		(132	)			(761	)
	Interest Rate—Swap		—				(693	)
	Total Long-Term Derivative Liabilities	$	(945	)		$	(1,765	)
	Total Derivative Liabilities	$	(2,266	)		$	(6,428	)
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 September 30, 2014 are included in the table below.
		Range		Weighted Average				Fair Value
		(price per Mcf)		(price per Mcf)				(in thousands)
	Natural Gas Basis Differential Forward Curve	($1.15) – ($1.96)		$	(1.49	)		$	2,862
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 September 30, 2014 Using:
	($ in Thousands)	Total Carrying Value as of September 30, 2014				Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
	Commodity Derivatives	$	5,421			$	—			$	2,559			$	2,862
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 nine months ended September 30, 2014 and 2013:
		Nine Months Ended September 30,
	($ in Thousands)	2014				2013
	Beginning Balance of Level 3	$	4,323			$	—
	Changes in Fair Value		(4,343	)			(721	)
	Purchases		—				—
	Settlements Received		2,882				23
	Ending Balance of Level 3	$	2,862			$	(698	)
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:
		30-Sep-14								31-Dec-13
	($ in Thousands)	Carrying Amount				Fair Value				Carrying Amount				Fair Value
	8.875% Senior Notes due 2020	$	350,000			$	379,750			$	350,000			$	385,000
	6.25% Senior Notes due 2022		325,000				312,000				—				—
	Secured Lines of Credit		—				—				59,000				59,000
	Capital Leases and Other Obligations		14,633				14,292				9,934				9,731
	Total	$	689,633			$	706,042			$	418,934			$	453,731

Income_Taxes_Tables

Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2014
Income Tax Disclosure [Abstract]	'
Schedule of Income Tax Included in Continuing Operations	'
	Income tax included in continuing operations was as follows:
		Three Months Ended September 30,						Nine Months Ended September 30,
	($ in Thousands)	2014			2013			2014			2013
	Income (Expense) Benefit	$	(4,469	)	$	1,493		$	(14,592	)	$	(5,622	)
	Effective Tax Rate		44	%		-1843.2	%		39.2	%		31.9	%

Employee_Benefit_and_Equity_Pl1

Employee Benefit and Equity Plans (Tables)	9 Months Ended
	Sep. 30, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'
Summary of Issued and Outstanding Stock Options	'
	A summary of the status of our issued and outstanding stock options as of September 30, 2014 is as follows:
					Outstanding						Exercisable
	Exercise Price				Number Outstanding At 9/30/14				Weighted-Average Exercise Price		Number Exercisable At 9/30/14		Weighted-Average Exercise Price
	$	5.04				46,041			$	5.04		46,041	$	5.04
	$	9.5				85,000			$	9.5		85,000	$	9.5
	$	9.99				149,333			$	9.99		149,333	$	9.99
	$	10.42				29,548			$	10.42		29,548	$	10.42
	$	11.87				3,500			$	11.87		3,500	$	11.87
	$	12.5				19,139			$	12.5		19,139	$	12.5
	$	13.19				50,000			$	13.19		—	$	-
	$	22.34				30,000			$	22.34		30,000	$	22.34
						412,561			$	10.79		362,561	$	10.45
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 2013 Awards to Vest
	3-Jan			100	%
	6-Apr			75	%
	10-Jul			50	%
	13-Nov			25	%
	14-16			0	%
	TSR Rank		Percentage of 2012 Awards to Vest
	3-Jan			100	%
	5-Apr			75	%
	8-Jun			50	%
	11-Sep			25	%
	14-Dec			0	%
Monte Carlo Simulation Model Assumptions Used to Estimate Fair Value of Restricted Stock	'
	The weighted average fair value of the TSR awards granted as of September 30, 2014 and December 31, 2013 were $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:
		Nine Months Ended September 30, 2014				Year Ended December 31, 2013
	Expected Dividend Yield		0	%			0	%
	Risk-Free Interest Rate		0.8	%			0.7	%
	Expected Volatility – Rex Energy		50.4	%			50.5	%
	Expected Volatility – Peer Group	28.4%-65.7%				28.4%-63.5%
	Market Index		35.3	%			35.3	%
	Expected Life	Three Years				Three Years
Summary of Nonvested Restricted Stock Activity	'
	A summary of the restricted stock activity for the nine months ended September 30, 2014 is as follows:
		Number of Shares				Weighted-Average Grant Date Fair Value
	Restricted stock awards, as of December 31, 2013		2,172,639			$	14.16
	Awards		51,178				15
	Forfeitures		(157,542	)			14.56
	Vested		(315,680	)			12.58
	Restricted stock awards, as of September 30, 2014		1,750,595			$	14.43

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2014
Commitments And Contingencies Disclosure [Abstract]	'
Lease Commitments for Each of Next Five Years	'
	As of September 30, 2014, we have lease commitments for various real estate leases. Rent expense is recognized on a straight-line basis and has been recorded in General and Administrative expense on our Consolidated Statements of Operations. Rent expense for the three and nine months ended September 30, 2014 and 2013 was $0.3 million and $0.8 million in 2014, respectively, and $0.2 million and $0.5 million in 2013, respectively. Lease commitments by year for each of the next five years are presented in the table below:
	($ in Thousands)
	2014		$	257
	2015			1,034
	2016			958
	2017			932
	2018			237
	Thereafter			26
	Total		$	3,444
Minimum Net Obligations under Sales, Gathering and Transportation Agreements	'
	For the three months ended September 30, 2014 and 2013, we incurred expenses related to the transportation, processing and marketing of our oil, natural gas and NGLs of approximately $15.7 million and $7.6 million, respectively. For the nine months ended September 30, 2014 and 2013, we incurred expenses related to the transportation, processing and marketing of our oil, natural gas and NGLs of approximately $36.1 million and $17.6 million, respectively. Expense related to these agreements makes up a substantial portion of our Lease Operating Expense, which we expect to continue as existing agreements commence and new transportation, processing and marketing agreements are entered that will enable us to sell our product. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows:
	($ in Thousands)		Total
	2014		$	4,372
	2015			22,122
	2016			34,428
	2017			52,723
	2018			55,539
	Thereafter			752,689
	Total		$	921,873
Fee for Unconventional Gas Wells	'
	In 2012, Pennsylvania state legislators instituted a natural gas impact fee on producers of unconventional natural gas. The fee will be 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	$	40,000		$	45,000	$	50,000	$	55,000	$	60,000
	Year Two	$	30,000		$	35,000	$	40,000	$	45,000	$	55,000
	Year Three	$	25,000		$	30,000	$	30,000	$	40,000	$	50,000
	Year 4 – 10	$	10,000		$	15,000	$	20,000	$	20,000	$	20,000
	Year 11 – 15	$	5,000		$	5,000	$	10,000	$	10,000	$	10,000
	(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.

Earnings_Loss_Per_Common_Share1

Earnings (Loss) Per Common Share (Tables)	9 Months Ended
	Sep. 30, 2014
Earnings Per Share [Abstract]	'
Computation of Basic and Diluted Earning (Loss) 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 September 30,				Nine Months Ended September 30,
	Numerator:	2014		2013		2014		2013
	Net Income From Continuing Operations, Less Noncontrolling Interests	$	5,694	$	1,574	$	22,642	$	12,019
	Net Income From Discontinued Operations		—		—		—		460
	Net Income	$	5,694	$	1,574	$	22,642	$	12,479
	Denominator:
	Weighted Average Common Shares Outstanding - Basic		53,214		52,626		53,493		52,560
	Effect of Dilutive Securities:
	Employee Stock Options		111		164		134		137
	Employee Performance-Based Restricted Stock Awards		485		503		218		427
	Effect of Assumed Conversions of Preferred Stock		4,181		—		1,409		—
	Weighted Average Common Shares Outstanding - Diluted		57,991		53,293		55,254		53,124
	Earnings per Common Share:
	Basic — Net Income From Continuing Operations	$	0.11	$	0.03	$	0.42	$	0.23
	— Net Income From Discontinued Operations		—		—		—		0.01
	— Net Income	$	0.11	$	0.03	$	0.42	$	0.24
	Diluted — Net Income From Continuing Operations	$	0.1	$	0.03	$	0.41	$	0.23
	— Net Income From Discontinued Operations		—		—		—		0.01
	— Net Income	$	0.1	$	0.03	$	0.41	$	0.24

Consolidated_Subsidiaries_Tabl

Consolidated Subsidiaries (Tables) (Water Solutions)	9 Months Ended
	Sep. 30, 2014
Water Solutions	'
Schedule of Carrying Amount and Classification of Assets and Liabilities as Consolidated	'
	We fully consolidate the accounts of Water Solutions in our financial statements and accounted for the 40% equity interest owned by Sand Hills as a noncontrolling interest. Water Solutions is financed through cash contributions from its members and a credit facility upon which $8.1 million was drawn as of September 30, 2014. As of September 30, 2014, Water Solutions maintained capital leases of approximately $2.9 million and equipment loans of approximately $2.5 million. Capital contributions to Water Solutions during the first nine months of 2014 and 2013 were negligible. The table below sets forth the carrying amount and classifications of Water Solutions’ assets and liabilities as of September 30, 2014 and December 31, 2013, with no restrictions or obligations to use certain assets to settle associated liabilities:
	($ in Thousands)	As of September 30, 2014			As of December 31, 2013
	Assets
	Cash and Cash Equivalents	$	337		$	593
	Accounts Receivable		13,234			9,882
	Inventory, Prepaid Expenses and Other		297			89
	Other Property and Equipment		20,628			11,798
	Wells and Facilities in Progress		781			1,031
	Accumulated Depreciation, Depletion and Amortization		(4,259	)		(1,954	)
	Deferred Financing Costs and Other Assets—Net		144			206
	Total Assets	$	31,162		$	21,645
	Liabilities
	Accounts Payable	$	1,387		$	758
	Current Maturities of Long-Term Debt		7,237			5,404
	Accrued Liabilities		4,453			6,247
	Senior Secured Line of Credit and Long-Term Debt		6,255			3,053
	Total Liabilities	$	19,332		$	15,462

Condensed_Consolidating_Financ1

Condensed Consolidating Financial Information (Tables)	9 Months Ended
	Sep. 30, 2014
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]	'
Condensed Consolidating Balance Sheets	'
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING BALANCE SHEETS
	AS OF SEPTEMBER 30, 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	$	87,302		$	315		$	5		$	—		$	87,622
	Accounts Receivable		41,785			13,337			—			(1,729	)		53,393
	Taxes Receivable		—			—			504			—			504
	Short-Term Derivative Instruments		7,257			—			—			—			7,257
	Current Deferred Tax Asset		—			—			2,837			—			2,837
	Inventory, Prepaid Expenses and Other		2,905			297			43			—			3,245
	Total Current Assets		139,249			13,949			3,389			(1,729	)		154,858
	Property and Equipment (Successful Efforts Method)
	Evaluated Oil and Gas Properties		1,017,608			191			—			(5,332	)		1,012,467
	Unevaluated Oil and Gas Properties		333,600			861			—			—			334,461
	Other Property and Equipment		62,110			21,535			—			—			83,645
	Wells and Facilities in Progress		110,046			7,228			—			(295	)		116,979
	Pipelines		17,773			—			—			(1,898	)		15,875
	Total Property and Equipment		1,541,137			29,815			—			(7,525	)		1,563,427
	Less: Accumulated Depreciation, Depletion and Amortization		(251,704	)		(4,584	)		—			817			(255,471	)
	Net Property and Equipment		1,289,433			25,231			—			(6,708	)		1,307,956
	Deferred Financing Costs and Other Assets—Net		2,422			144			15,020			—			17,586
	Equity Method Investments		18,098			—			—			—			18,098
	Intercompany Receivables		—			—			966,226			(966,226	)		—
	Investment in Subsidiaries – Net		4,161			3,438			355,797			(363,396	)		—
	Long-Term Derivative Instruments		430			—			—			—			430
	Total Assets	$	1,453,793		$	42,762		$	1,340,432		$	(1,338,059	)	$	1,498,928
	LIABILITIES AND STOCKHOLDERS’ EQUITY
	Current Liabilities
	Accounts Payable	$	56,909		$	1,391		$	—		$	(1,731	)	$	56,569
	Current Maturities of Long-Term Debt		1,011			7,237			—			—			8,248
	Accrued Liabilities		50,813			4,683			15,339			—			70,835
	Short-Term Derivative Instruments		1,321			—			—			—			1,321
	Total Current Liabilities		110,054			13,311			15,339			(1,731	)		136,973
	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		—			—			2,816			—			2,816
	Senior Secured Line of Credit and Other Long-Term Debt		130			6,255			—			—			6,385
	Long-Term Derivative Instruments		945			—			—			—			945
	Long-Term Deferred Tax Liability		—			—			43,414			—			43,414
	Other Deposits and Liabilities		4,303			—			—			—			4,303
	Future Abandonment Cost		27,402			32			—			—			27,434
	Intercompany Payables		962,392			3,834			—			(966,226	)		—
	Total Liabilities		1,105,226			23,432			736,569			(967,957	)		897,270
	Stockholders’ Equity
	Preferred Stock		—			—			1			—			1
	Common Stock		—			—			54			—			54
	Additional Paid-In Capital		177,144			82,780			616,384			(259,924	)		616,384
	Accumulated Earnings (Deficit)		171,423			(64,412	)		(12,576	)		(113,518	)		(19,083	)
	Rex Energy Stockholders’ Equity		348,567			18,368			603,863			(373,442	)		597,356
	Noncontrolling Interests		—			962			—			3,340			4,302
	Total Stockholders’ Equity		348,567			19,330			603,863			(370,102	)		601,658
	Total Liabilities and Stockholders’ Equity	$	1,453,793		$	42,762		$	1,340,432		$	(1,338,059	)	$	1,498,928
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING BALANCE SHEETS
	AS OF DECEMBER 31, 2013
	($ 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	$	1,386		$	509		$	5		$	—		$	1,900
Accounts Receivable		32,283			9,882			—			(3,302	)		38,863
Taxes Receivable		—			—			5,189			—			5,189
Short-Term Derivative Instruments		5,180			—			488			—			5,668
Current Deferred Tax Asset		—			—			3,451			—			3,451
Inventory, Prepaid Expenses and Other		2,092			89			26			—			2,207
Total Current Assets		40,941			10,480			9,159			(3,302	)		57,278
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		752,781			—			—			(3,101	)		749,680
Unevaluated Oil and Gas Properties		189,385			—			—			—			189,385
Other Property and Equipment		57,409			12,706			—			—			70,115
Wells and Facilities in Progress		70,759			6,576			—			(790	)		76,545
Pipelines		7,678			—			—			—			7,678
Total Property and Equipment		1,078,012			19,282			—			(3,891	)		1,093,403
Less: Accumulated Depreciation, Depletion and Amortization		(188,699	)		(2,172	)		—			350			(190,521	)
Net Property and Equipment		889,313			17,110			—			(3,541	)		902,882
Deferred Financing Costs and Other Assets—Net		2,421			206			9,366			—			11,993
Equity Method Investments		18,708			—			—			—			18,708
Intercompany Receivables		—			—			628,517			(628,517	)		—
Investment in Subsidiaries – Net		4,442			1,197			216,945			(222,584	)		—
Long-Term Derivative Instruments		535			—			—			—			535
Total Assets	$	956,360		$	28,993		$	863,987		$	(857,944	)	$	991,396
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	33,613		$	794		$	—		$	(3,304	)	$	31,103
Current Maturities of Long-Term Debt		1,339			5,404			—			—			6,743
Accrued Liabilities		45,196			6,287			2,967			—			54,450
Short-Term Derivative Instruments		4,663			—			—			—			4,663
Total Current Liabilities		84,811			12,485			2,967			(3,304	)		96,959
8.875% Senior Notes Due 2020		—			—			350,000			—			350,000
Premium (Discount) on Senior Notes – Net		—			—			3,078			—			3,078
Senior Secured Line of Credit and Other Long-Term Debt		137			3,054			59,000			—			62,191
Long-Term Derivative Instruments		1,071			—			694			—			1,765
Long-Term Deferred Tax Liability		—			—			29,446			—			29,446
Other Deposits and Liabilities		4,992			—			—			—			4,992
Future Abandonment Cost		26,027			13			—			—			26,040
Intercompany Payables		554,329			74,188			—			(628,517	)		—
Total Liabilities		671,367			89,740			445,185			(631,821	)		574,471
Stockholders’ Equity
Common Stock		—			—			54			—			54
Additional Paid-In Capital		177,144			6,488			456,554			(183,632	)		456,554
Accumulated Earnings (Deficit)		107,849			(67,720	)		(37,806	)		(44,048	)		(41,725	)
Rex Energy Stockholders’ Equity		284,993			(61,232	)		418,802			(227,680	)		414,883
Noncontrolling Interests		—			485			—			1,557			2,042
Total Stockholders’ Equity		284,993			(60,747	)		418,802			(226,123	)		416,925
Total Liabilities and Stockholders’ Equity	$	956,360		$	28,993		$	863,987		$	(857,944	)	$	991,396
Condensed Consolidating Statements of Operations	'
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
	FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
	($ in Thousands)
		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
	OPERATING REVENUE
	Oil, Natural Gas and NGL Sales	$	73,343		$	105		$	—		$	—		$	73,448
	Field Services Revenue		—			15,870			—			(2,800	)		13,070
	Other Revenue		18			—			—			—			18
	TOTAL OPERATING REVENUE		73,361			15,975			—			(2,800	)		86,536
	OPERATING EXPENSES
	Production and Lease Operating Expense		27,668			4			—			(15	)		27,657
	General and Administrative Expense		7,709			1,160			1,555			(15	)		10,409
	Loss on Disposal of Asset		175			(91	)		—			—			84
	Impairment Expense		1			—			—			—			1
	Exploration Expense		1,452			10			—			—			1,462
	Depreciation, Depletion, Amortization and Accretion		26,536			1,027			—			(199	)		27,364
	Field Services Operating Expense		—			11,464			—			(1,917	)		9,547
	Other Operating (Income) Expense		(24	)		—			—			—			(24	)
	TOTAL OPERATING EXPENSES		63,517			13,574			1,555			(2,146	)		76,500
	INCOME (LOSS) FROM OPERATIONS		9,844			2,401			(1,555	)		(654	)		10,036
	OTHER INCOME (EXPENSE)
	Interest Expense		(56	)		(134	)		(10,890	)		—			(11,080	)
	Gain (Loss) on Derivatives, Net		12,316			—			—			—			12,316
	Other Expense		3			—			—			(15	)		(12	)
	Loss From Equity Method Investments		(202	)		—			—			—			(202	)
	Income (Loss) From Equity in Consolidated Subsidiaries		18			(18	)		12,840			(12,840	)		—
	TOTAL OTHER INCOME (EXPENSE)		12,079			(152	)		1,950			(12,855	)		1,022
	INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		21,923			2,249			395			(13,509	)		11,058
	Income Tax (Expense) Benefit		(8,853	)		(915	)		5,299			—			(4,469	)
	INCOME (LOSS) FROM CONTINUING OPERATIONS		13,070			1,334			5,694			(13,509	)		6,589
	Net Income Attributable to Noncontrolling Interests		—			895			—			—			895
	NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	13,070		$	439		$	5,694		$	(13,509	)	$	5,694
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
	FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2014
	($ in Thousands)
		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
	OPERATING REVENUE
	Oil, Natural Gas and NGL Sales	$	227,547		$	103		$	—		$	—		$	227,650
	Field Services Revenue		—			54,467			—			(13,005	)		41,462
	Other Revenue		92			—			—			—			92
	TOTAL OPERATING REVENUE		227,639			54,570			—			(13,005	)		269,204
	OPERATING EXPENSES
	Production and Lease Operating Expense		69,328			10			—			(35	)		69,303
	General and Administrative Expense		22,811			2,982			4,296			(50	)		30,039
	Loss on Disposal of Asset		469			(84	)		—			—			385
	Impairment Expense		41			—			—			—			41
	Exploration Expense		4,877			13			—			—			4,890
	Depreciation, Depletion, Amortization and Accretion		66,812			2,671			—			(469	)		69,014
	Field Services Operating Expense		—			40,246			—			(9,334	)		30,912
	Other Operating Expense		3			—			—			—			3
	TOTAL OPERATING EXPENSES		164,341			45,838			4,296			(9,888	)		204,587
	INCOME (LOSS) FROM OPERATIONS		63,298			8,732			(4,296	)		(3,117	)		64,617
	OTHER INCOME (EXPENSE)
	Interest Expense		(86	)		(482	)		(25,150	)		—			(25,718	)
	Gain (Loss) on Derivatives, Net		1,232			—			1,083			—			2,315
	Other Income (Expense)		20			—			—			(50	)		(30	)
	Loss From Equity Method Investments		(610	)		—			—			—			(610	)
	Income (Loss) From Equity in Consolidated Subsidiaries		(64	)		64			39,667			(39,667	)		—
	TOTAL OTHER INCOME (EXPENSE)		492			(418	)		15,600			(39,717	)		(24,043	)
	INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		63,790			8,314			11,304			(42,834	)		40,574
	Income Tax (Expense) Benefit		(22,964	)		(2,967	)		11,339			—			(14,592	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		40,826			5,347			22,643			(42,834	)		25,982
Net Income Attributable to Noncontrolling Interests		—			3,340			—			—			3,340
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	40,826		$	2,007		$	22,643		$	(42,834	)	$	22,642
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2013
($ in Thousands)
	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	150,447		$	—		$	—		$	—		$	150,447
Field Services Revenue		—			19,668			—			(4,475	)		15,193
Other Revenue		164			—			—			—			164
TOTAL OPERATING REVENUE		150,611			19,668			—			(4,475	)		165,804
OPERATING EXPENSES
Production and Lease Operating Expense		43,688			7			—			—			43,695
General and Administrative Expense		18,896			1,765			3,814			(71	)		24,404
Loss on Disposal of Asset		1,586			46			—			—			1,632
Impairment Expense		2,414			—			—			—			2,414
Exploration Expense		7,510			1			—			—			7,511
Depreciation, Depletion, Amortization and Accretion		39,434			1,038			—			(105	)		40,367
Field Services Operating Expense		—			13,468			—			(3,114	)		10,354
Other Operating Expense		910			—			—			—			910
TOTAL OPERATING EXPENSES		114,438			16,325			3,814			(3,290	)		131,287
INCOME (LOSS) FROM OPERATIONS		36,173			3,343			(3,814	)		(1,185	)		34,517
OTHER INCOME (EXPENSE)
Interest Expense		(47	)		(66	)		(15,900	)		—			(16,013	)
Gain on Derivatives, Net		(1,423	)		—			—			—			(1,423	)
Other Income (Expense)		2,112			—			—			(71	)		2,041
Loss From Equity Method Investments		(569	)		—			—			—			(569	)
Income (Loss) From Equity in Consolidated Subsidiaries		(44	)		44			25,510			(25,510	)		—
TOTAL OTHER INCOME (EXPENSE)		29			(22	)		9,610			(25,581	)		(15,964	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		36,202			3,321			5,796			(26,766	)		18,553
Income Tax (Expense) Benefit		(11,546	)		(759	)		6,683			—			(5,622	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		24,656			2,562			12,479			(26,766	)		12,931
Income From Discontinued Operations, Net of Income Taxes		—			460			—			—			460
NET INCOME (LOSS)		24,656			3,022			12,479			(26,766	)		13,391
Net Income Attributable to Noncontrolling Interests		—			912			—			—			912
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	24,656		$	2,110		$	12,479		$	(26,766	)	$	12,479
Condensed Consolidating Statements of Cash Flows	'
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
	FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2014
	($ in Thousands)
		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
	CASH FLOWS FROM OPERATING ACTIVITIES
	Net Income (Loss)	$	40,826		$	5,347		$	22,643		$	(42,834	)	$	25,982
	Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
	Loss From Equity Method Investments		610			—			—			—			610
	Non-Cash Expenses (Income)		(203	)		233			5,116			—			5,146
	Depreciation, Depletion, Amortization and Accretion		66,812			2,671			—			(469	)		69,014
	Deferred Income Tax Expense (Benefit)		22,964			2,967			(11,339	)		—			14,592
	(Gain) Loss on Derivatives		(1,232	)		—			(1,083	)		—			(2,315	)
	Cash Settlements of Derivatives		(4,209	)		—			878			—			(3,331	)
	Dry Hole Expense		237			—			—			—			237
	Loss on Sale of Asset		469			(84	)		—			—			385
	Impairment Expense		41			—			—			—			41
	Changes in operating assets and liabilities
	Accounts Receivable		(9,510	)		(3,455	)		4,685			(1,574	)		(9,854	)
	Inventory, Prepaid Expenses and Other Assets		(812	)		(209	)		(17	)		—			(1,038	)
	Accounts Payable and Accrued Liabilities		22,975			(1,007	)		12,518			1,574			36,060
	Other Assets and Liabilities		(1,942	)		(24	)		—			—			(1,966	)
	NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		137,026			6,439			33,401			(43,303	)		133,563
	CASH FLOWS FROM INVESTING ACTIVITIES
	Intercompany loans to subsidiaries		408,192			248			(448,109	)		39,669			—
	Proceeds from Joint Venture Acreage Management		210			—			—			—			210
	Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		248			164			—			—			412
	Acquisitions of Undeveloped Acreage		(152,765	)		(863	)		—			—			(153,628	)
	Capital Expenditures for Development of Oil and Gas Properties and Equipment		(305,672	)		(8,315	)		—			3,634			(310,353	)
	NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(49,787	)		(8,766	)		(448,109	)		43,303			(463,359	)
	CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from Long-Term Debt and Lines of Credit		—			22,041			171,000			—			193,041
	Repayments of Long-Term Debt and Lines of Credit		—			(18,146	)		(230,000	)		—			(248,146	)
	Repayments of Loans and Other Long-Term Debt		(1,323	)		(675	)		—			—			(1,998	)
	Proceeds from Senior Notes, Net of Discounts and Premiums		—			—			325,000			—			325,000
	Debt Issuance Costs		—			(7	)		(6,724	)		—			(6,731	)
	Proceeds from the Issuance of Preferred Stock, Net		—			—			155,011			—			155,011
	Proceeds from Exercise of Stock Options		—			—			421			—			421
	Distributions by the Partners of Consolidated Subsidiaries		—			(1,080	)		—			—			(1,080	)
	NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(1,323	)		2,133			414,708			—			415,518
	NET INCREASE (DECREASE) IN CASH		85,916			(194	)		—			—			85,722
	CASH – BEGINNING		1,386			509			5			—			1,900
	CASH - ENDING	$	87,302		$	315		$	5		$	—		$	87,622
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
	FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2013
	($ in Thousands)	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
	CASH FLOWS FROM OPERATING ACTIVITIES
	Net Income (Loss)	$	24,656		$	3,022		$	12,479		$	(26,766	)	$	13,391
	Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
	Loss From Equity Method Investments		569			—			—			—			569
	Non-Cash Expenses		(180	)		65			4,547			—			4,432
	Depreciation, Depletion, Amortization and Accretion		39,434			1,038			—			(105	)		40,367
	Deferred Income Tax Expense (Benefit)		12,060			1,169			(2,259	)		—			10,970
	Gain on Derivatives		1,423			—			—			—			1,423
	Cash Settlements of Derivatives		5,540			—			—			—			5,540
	Dry Hole Expense		485			—			—			—			485
	(Gain) Loss on Sale of Asset		1,586			(923	)		—			—			663
	Impairment Expense		2,414			—			—			—			2,414
	Changes in operating assets and liabilities
	Accounts Receivable		(2,628	)		(669	)		—			(3,731	)		(7,028	)
	Inventory, Prepaid Expenses and Other Assets		(316	)		(66	)		(9	)		—			(391	)
	Accounts Payable and Accrued Liabilities		23,174			(1,687	)		9,241			4,022			34,750
Other Assets and Liabilities		(1,495	)		(88	)		(247	)		—			(1,830	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		106,722			1,861			23,752			(26,580	)		105,755
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		139,294			688			(165,201	)		25,219			—
Proceeds from Joint Venture Acreage Management		246			—			—			—			246
Contributions to Equity Method Investments		(2,493	)		—			—			—			(2,493	)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		697			3,234			—			—			3,931
Acquisitions of Undeveloped Acreage		(31,456	)		(2	)		—			—			(31,458	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(193,964	)		(4,661	)		—			1,361			(197,264	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(87,676	)		(741	)		(165,201	)		26,580			(227,038	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			1,750			—			—			1,750
Repayments of Long-Term Debt and Lines of Credit		—			(1,022	)		—			—			(1,022	)
Repayments of Loans and Other Notes Payable		(934	)		(429	)		—			—			(1,363	)
Proceeds from Senior Notes, net of Discounts and Premiums		—			—			105,000			—			105,000
Debt Issuance Costs		—			—			(3,004	)		—			(3,004	)
Proceeds from the Exercise of Stock Options		—			—			534			—			534
Purchase of Non-Controlling Interests		—			(150	)		—			—			(150	)
Distributions by the Partners of Consolidated Subsidiaries		—			(646	)		—			—			(646	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(934	)		(497	)		102,530			—			101,099
NET INCREASE (DECREASE) IN CASH		18,112			623			(38,919	)		—			(20,184	)
CASH – BEGINNING		4,227			824			38,924			—			43,975
CASH - ENDING	$	22,339		$	1,447		$	5		$	—		$	23,791

Business_Segment_Information_A

Business Segment Information - Additional Information (Details)	9 Months Ended
	Sep. 30, 2014
	Segment
Segment Reporting [Abstract]	'
Principal reportable segments	2

Performance_of_Business_Segmen

Performance of Business Segments Based on Net Income (Loss) from Continuing Operations, before Income Taxes (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	$86,536	$62,974	$269,204	$165,804	'
Income (Loss) From Continuing Operations, Before Income Taxes	11,058	339	40,574	18,553	'
Total Assets	1,498,928	'	1,498,928	'	991,396
Exploration and Production	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	73,466	58,127	227,742	150,611	'
Field Services	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	13,070	4,847	41,462	15,193	'
Operating Segments | Exploration and Production	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	73,466	58,127	227,742	150,611	'
Income (Loss) From Continuing Operations, Before Income Taxes	9,503	192	35,434	16,464	'
Total Assets	1,471,683	'	1,471,683	'	971,973
Operating Segments | Field Services	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	15,870	6,543	54,467	19,668	'
Income (Loss) From Continuing Operations, Before Income Taxes	2,225	629	8,306	3,344	'
Total Assets	35,681	'	35,681	'	26,266
Inter-Segment Revenues	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	-2,800	-1,696	-13,005	-4,475	'
Income (Loss) From Continuing Operations, Before Income Taxes	-670	-482	-3,166	-1,255	'
Total Assets	-8,436	'	-8,436	'	-6,843
Inter-Segment Revenues | Field Services	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	($2,800)	($1,696)	($13,005)	($4,475)	'

Future_Abandonment_Cost_Additi

Future Abandonment Cost - Additional Information (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Asset Retirement Obligation Disclosure [Abstract]	'	'	'	'
Accretion expense	$1.30	$1.20	$2.90	$2.30

Future_Abandonment_Cost_Detail

Future Abandonment Cost (Details) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014
Asset Retirement Obligation Disclosure [Abstract]	'
Beginning Balance at January 1, 2014	$28,525
Future Abandonment Obligation Incurred	1,321
Future Abandonment Obligation Settled	-1,798
Future Abandonment Obligation Revision of Estimated Obligation	27
Future Abandonment Obligation Accretion Expense	2,912
Total Future Abandonment Cost	$30,987

Future_Abandonment_Cost_Parent

Future Abandonment Cost (Parenthetical) (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Asset Retirement Obligations [Line Items]	'	'
Accrued Liabilities	$70,835	$54,450
Remediation Property for Sale, Abandonment or Disposal	'	'
Asset Retirement Obligations [Line Items]	'	'
Accrued Liabilities	$3,600	'

Discontinued_Operations_Assets

Discontinued Operations/ Assets Held for Sale - Additional Information (Details) (DJ Basin, USD $)	3 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2013	Mar. 31, 2013
DJ Basin	'	'
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]	'	'
Sale of the remaining DJ Basin assets	'	$3.10
Gain on asset held for sale	$1	'

Summary_of_Financial_Informati

Summary of Financial Information for Discontinued Operations (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Revenues:	'	'	'	'
Oil, Natural Gas and NGL Sales	$73,448	$58,063	$227,650	$150,447
TOTAL OPERATING REVENUE	86,536	62,974	269,204	165,804
Costs and Expenses:	'	'	'	'
Production and Lease Operating Expense	27,657	17,203	69,303	43,695
General and Administrative Expense	10,409	8,826	30,039	24,404
Exploration Expense	1,462	3,242	4,890	7,511
Other Operating Expense (Income)	-24	19	3	910
Gain on Sale of Asset	-84	-140	-385	-1,632
Income from Discontinued Operations, net of taxes	0	0	0	460
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 Expense (Income)	'	'	'	-3
Gain on Sale of Asset	'	'	'	969
Total Costs and Expenses	'	'	'	-748
Income from Discontinued Operations Before Income Taxes	'	'	'	773
Income Tax Expense	'	'	'	-313
Income from Discontinued Operations, net of taxes	'	'	'	$460
Crude Oil (Bbls) | Discontinued Operations Assets Held For Sale	'	'	'	'
Production:	'	'	'	'
Production Units	'	'	'	356
Total (Mcfe) | Discontinued Operations Assets Held For Sale	'	'	'	'
Production:	'	'	'	'
Production Units	'	'	'	2,136

Business_and_Oil_and_Gas_Prope2

Business and Oil and Gas Property Acquisitions and Dispositions - Additional Information (Details) (Acres prospective for Marcellus, Upper Devonian/Burkett and Utica Shales, USD $)	0 Months Ended
In Millions, unless otherwise specified	Sep. 09, 2014
	acre
Acres prospective for Marcellus, Upper Devonian/Burkett and Utica Shales	'
Significant Acquisitions And Disposals [Line Items]	'
Oil and Gas property acquired, gross area	208,000
Oil and Gas property acquired, net area	207,000
Cash paid to acquire oil and gas property	$120.60

Summary_of_Acquisition_Price_A

Summary of Acquisition Price Allocated (Details) (USD $)	0 Months Ended
In Thousands, unless otherwise specified	Sep. 09, 2014
Significant Acquisitions And Disposals [Line Items]	'
Purchase Price	$120,563
Evaluated Oil and Gas Properties	'
Significant Acquisitions And Disposals [Line Items]	'
Purchase Price	6,968
Unevaluated Oil and Gas Properties	'
Significant Acquisitions And Disposals [Line Items]	'
Purchase Price	88,351
Wells and Facilities in Progress	'
Significant Acquisitions And Disposals [Line Items]	'
Purchase Price	$25,244

Concentrations_of_Credit_Risk_

Concentrations of Credit Risk - Additional Information (Details) (Sales, Customer Concentration Risk)	9 Months Ended
	Sep. 30, 2014
	Customer
Five purchaser	'
Concentration Risk [Line Items]	'
Percentage of revenue from major customers	95.50%
Number of major customers	5
Largest single purchaser	'
Concentration Risk [Line Items]	'
Percentage of revenue from major customers	33.90%

Long_Term_Debt_Senior_Credit_F

Long Term Debt - Senior Credit Facility - Additional Information (Details) (USD $)

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

In Millions, unless otherwise specified

Adjusted LIBO Rate

Alternate Base Rate

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Maximum

Maximum

Crude Oil

Natural Gas

Minimum

Maximum

Maximum

Adjusted LIBO Rate

Alternate Base Rate

Letter of Credit

Revolving Credit Facility

Defaulted Loans

Interest Rate Swap

Minimum

Minimum

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility, current borrowing capacity

'

'

'

'

$400

'

'

'

'

'

'

'

'

'

'

Line of credit facility, maximum borrowing capacity

'

'

'

'

'

'

'

'

'

'

'

'

60

500

'

Line of credit facility, amount outstanding

0

59

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility, maturity date

'

'

'

'

12-Sep-19

'

'

'

'

'

'

'

'

'

'

LIBOR rate description

'

'

'

'

'The applicable per annum margin, in the case of loans bearing interest at the Adjusted LIBO Rate, ranges from 150 to 250 basis points, and the applicable per annum margin, in the case of loans bearing interest at the Alternate Base Rate, ranges from 50 to 150 basis points, in each case, determined based upon our borrowing utilization at such date of determination.

'

'

'

'

'

'

'

'

'

'

Effective rate

'

'

'

'

0.50%

'

'

'

'

'

'

'

'

'

'

Additional percentage with LIBOR

'

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

'

Margin rate

'

'

0.25%

0.15%

'

'

'

'

'

'

1.50%

0.50%

'

'

2.00%

Percentage of reasonably anticipated projected production

'

'

'

'

85.00%

75.00%

75.00%

'

'

'

'

'

'

'

'

Duration of developed producing reserve

'

'

'

'

'

'

'

'

'36 months

'

'

'

'

'

'

Notional amounts of interest rate swap

'

'

'

'

'

'

'

'

'

$20

'

'

'

'

'

Outstanding principal amount of debt for borrowed money, percentage

'

'

'

'

'

'

'

'

75.00%

'

'

'

'

'

'

Liens covering the oil and gas properties, percentage

'

'

'

'

80.00%

'

'

'

'

'

'

'

'

'

'

Criteria Current ratio

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

Current ratio

'

'

'

'

4

'

'

'

'

'

'

'

'

'

'

Criteria Total debt to EBITAX"

'

'

'

'

'

'

'

'

4.25

'

'

'

'

'

'

Total debt to EBITAX

'

'

'

'

3.9

'

'

'

'

'

'

'

'

'

'

[1]

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 and nine months ended September 30, 2014 and the year ended December 31, 2013, was approximately 2.2%, 2.1% and 1.9%, respectively. The average interest rate on our capital leases and other obligations for the three and nine months ended September 30, 2014 and the year ended December 31, 2013, was approximately 4.2%, 3.8% and 5.3%, respectively

Long_Term_Debt_Senior_Notes_Du

Long Term Debt - Senior Notes Due Twenty Twenty and Senior Notes Due Twenty Twenty Two - Additional Information (Details) (USD $)	9 Months Ended			9 Months Ended	12 Months Ended	9 Months Ended	0 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014	Jul. 14, 2014	Sep. 30, 2014	Dec. 31, 2013
				8.875% Senior Notes	8.875% Senior Notes	8.875% Senior Notes	6.25% Senior Notes	6.25% Senior Notes	6.25% Senior Notes
						Twenty Twenty Senior Notes
Debt Instrument [Line Items]	'	'	'	'	'	'	'	'	'
Senior notes	'	'	'	$352,800,000	$353,100,000	'	'	'	'
Interest rate	'	'	'	8.88%	8.88%	'	'	6.25%	6.25%
Debt instrument maturity date	'	'	'	1-Dec-20	1-Dec-20	'	1-Aug-22	1-Aug-22	1-Aug-22
Premium on Senior Notes, Net	2,816,000	'	3,078,000	2,800,000	3,078,000	'	'	'	'
Amortization of net premium	'	'	'	300,000	'	'	'	'	'
Debt instrument redemption date	1-Aug-17	'	'	'	'	1-Dec-16	'	'	'
Percentage of notes that can be redeemed	35.00%	'	'	'	'	35.00%	'	'	'
Debt issued aggregate principal amount	'	'	'	'	'	'	325,000,000	'	'
Proceeds from Senior Notes, Net of Discounts and Premiums	325,000,000	105,000,000	'	'	'	'	'	318,800,000	'
Debt issuance costs	'	'	'	'	'	'	$6,300,000	'	'
Offering price as percentage of issue price	'	'	'	'	'	'	'	100.00%	'

Components_of_LongTerm_Debt_an

Components of Long-Term Debt and Lines of Credit (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013
Debt Instrument [Line Items]	'		'
Senior Notes	$675,000,000		'
Premium on Senior Notes, Net	2,816,000		3,078,000
Senior Lines of Credit	0		59,000,000	[1]
Capital Leases and Other Obligations	14,633,000	[1]	9,934,000	[1]
Total Debt	692,449,000		422,012,000
Less Current Portion of Long-Term Debt	-8,248,000		-6,743,000
Total Long-Term Debt	684,201,000		415,269,000
8.875% Senior Notes	'		'
Debt Instrument [Line Items]	'		'
Senior Notes	350,000,000		350,000,000
Premium on Senior Notes, Net	2,800,000		3,078,000
6.25% Senior Notes	'		'
Debt Instrument [Line Items]	'		'
Senior Notes	$325,000,000		'
[1]	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 and nine months ended September 30, 2014 and the year ended December 31, 2013, was approximately 2.2%, 2.1% and 1.9%, respectively. The average interest rate on our capital leases and other obligations for the three and nine months ended September 30, 2014 and the year ended December 31, 2013, was approximately 4.2%, 3.8% and 5.3%, respectively

Components_of_LongTerm_Debt_an1

Components of Long-Term Debt and Lines of Credit (Parenthetical) (Details)	9 Months Ended	12 Months Ended	0 Months Ended	9 Months Ended	12 Months Ended	3 Months Ended	9 Months Ended	12 Months Ended	3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Jul. 14, 2014	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014	Sep. 30, 2014	Dec. 31, 2013
	8.875% Senior Notes	8.875% Senior Notes	6.25% Senior Notes	6.25% Senior Notes	6.25% Senior Notes	Senior Credit Facility	Senior Credit Facility	Senior Credit Facility	Other Loans and Notes Payable	Other Loans and Notes Payable	Other Loans and Notes Payable
Debt Instrument [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Interest rate	8.88%	8.88%	'	6.25%	6.25%	'	'	'	'	'	'
Debt instrument maturity date	1-Dec-20	1-Dec-20	1-Aug-22	1-Aug-22	1-Aug-22	'	'	'	'	'	'
Average interest rate	'	'	'	'	'	2.20%	2.10%	1.90%	4.20%	3.80%	5.30%

Long_Term_Debt_Water_Solutions

Long Term Debt - Water Solutions - Additional Information (Details) (USD $)	0 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Oct. 18, 2013	Dec. 31, 2013		Sep. 30, 2014
Debt Instrument [Line Items]	'	'		'
Line of credit facility, amount outstanding	'	$59	[1]	$0
Water Solutions Holding | Demand Notes	'	'		'
Debt Instrument [Line Items]	'	'		'
Percentage of accounts receivable	80.00%	'		'
Accounts receivable, collection period	'90 days	'		'
Line of credit facility, amount outstanding	'	'		4.5
Line of credit facility, current borrowing capacity	16	'		'
Line of credit facility, increase current borrowing capacity	'	4		'
Water Solutions Holding | Demand Notes | LIBOR	'	'		'
Debt Instrument [Line Items]	'	'		'
Margin rate	2.75%	'		'
Water Solutions Holding | Demand Notes | Base Rate	'	'		'
Debt Instrument [Line Items]	'	'		'
Margin rate	2.00%	'		'
Water Solutions Holding | Equipment Term Note	'	'		'
Debt Instrument [Line Items]	'	'		'
Line of credit facility, amount outstanding	'	'		3.6
Line of credit facility, maximum borrowing capacity	6	'		'
Percentage of asset's cost funded by line of credit	80.00%	'		'
Line of credit, minimum required tangible net worth	2.5	'		'
Line of credit, minimum required tangible net worth, percentage of annual net income added	'	30.00%		'
Net worth	'	$9.20		'
Fixed charge coverage ratio	'	'		2.3
Total debt to EBITAX	'	'		1
Water Solutions Holding | Equipment Term Note | Minimum	'	'		'
Debt Instrument [Line Items]	'	'		'
Line of credit facility, maturity period	'3 years	'		'
Criteria fixed charge coverage ratio	1.75	'		'
Water Solutions Holding | Equipment Term Note | Maximum	'	'		'
Debt Instrument [Line Items]	'	'		'
Line of credit facility, maturity period	'4 years	'		'
Criteria Total debt to EBITAX"	2.25	'		'
Water Solutions Holding | Equipment Term Note | Three Months LIBOR	'	'		'
Debt Instrument [Line Items]	'	'		'
Margin rate	3.00%	'		'
[1]	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 and nine months ended September 30, 2014 and the year ended December 31, 2013, was approximately 2.2%, 2.1% and 1.9%, respectively. The average interest rate on our capital leases and other obligations for the three and nine months ended September 30, 2014 and the year ended December 31, 2013, was approximately 4.2%, 3.8% and 5.3%, respectively

Principal_Maturity_Schedule_fo

Principal Maturity Schedule for Debt Outstanding (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Debt Disclosure [Abstract]	'		'
2014	$5,589		'
2015	2,745		'
2016	2,835		'
2017	2,003		'
2018	796		'
Thereafter	675,665		'
Total	$689,633	[1]	$418,934
[1]	Excludes $2.8 million net premium on Senior Notes.

Principal_Maturity_Schedule_fo1

Principal Maturity Schedule for Debt Outstanding (Parenthetical) (Details) (USD $)	Sep. 30, 2014
In Millions, unless otherwise specified
Debt Disclosure [Abstract]	'
Senior notes, net premium	$2.80

Recovered_Sheet1

Fair Value of Financial and Derivative Instruments - Additional Information (Details) (USD $)

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

Sep. 30, 2014

Sep. 30, 2013

Dec. 31, 2013

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Jun. 30, 2014

Sep. 30, 2014

Dec. 31, 2013

Crude Oil

Crude Oil

Natural Gas

Natural Gas

Natural Gas Liquids

Natural Gas Liquids

Commodity derivatives

Commodity derivatives

Commodity derivatives

Commodity derivatives

Interest Rate Swap

Interest Rate Swap

Interest Rate Swap

Fixed To Floating Interest Rate Swap

Minimum

Minimum

Minimum

Derivatives Fair Value [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash Settlements of Derivatives

$3,331,000

($5,540,000)

'

'

'

'

'

'

'

$3,000,000

$700,000

$4,200,000

$5,500,000

$0

'

($900,000)

'

Commodity hedged on annualized basis hedge through 2014

'

'

'

'

85.00%

'

75.00%

'

60.00%

'

'

'

'

'

'

'

'

Commodity hedged on annualized basis hedge through 2015

'

'

'

'

20.00%

'

45.00%

'

'

'

'

'

'

'

'

'

'

Senior Lines of Credit

0

'

59,000,000

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Senior Notes

675,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative, amount of hedged item

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25,000,000

Proceeds from interest rate swaps

'

'

'

'

'

'

'

'

'

'

'

'

'

'

600,000

'

'

Fair value of interest rate swap, liability

'

'

200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivatives asset (liability)

5,400,000

'

-200,000

1,455,000

'

2,806,000

'

1,160,000

'

5,421,000

'

5,421,000

'

'

'

'

'

Unrealized gain (loss) on commodity derivative contracts

($4,300,000)

($700,000)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

[1]

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 and nine months ended September 30, 2014 and the year ended December 31, 2013, was approximately 2.2%, 2.1% and 1.9%, respectively. The average interest rate on our capital leases and other obligations for the three and nine months ended September 30, 2014 and the year ended December 31, 2013, was approximately 4.2%, 3.8% and 5.3%, respectively

Schedule_of_Location_and_Amoun

Schedule of Location and Amounts of Gains and Losses on Derivative Instruments (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Derivative Instruments Gain Loss [Line Items]	'	'	'	'
Gain (loss) on derivatives, net	$12,316	($4,624)	$2,315	($1,423)
Crude Oil	'	'	'	'
Derivative Instruments Gain Loss [Line Items]	'	'	'	'
Gain (loss) on derivatives, net	3,776	-4,519	125	-3,989
Natural Gas	'	'	'	'
Derivative Instruments Gain Loss [Line Items]	'	'	'	'
Gain (loss) on derivatives, net	6,857	1,125	77	2,605
Natural Gas Liquids	'	'	'	'
Derivative Instruments Gain Loss [Line Items]	'	'	'	'
Gain (loss) on derivatives, net	1,683	-1,230	1,030	-39
Interest Rate Swap	'	'	'	'
Derivative Instruments Gain Loss [Line Items]	'	'	'	'
Gain (loss) on derivatives, net	'	'	$1,083	'

Asset_or_Liability_Financial_C

Asset or Liability Financial Commodity Derivative Instrument Positions (Details) (USD $)

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

In Thousands, unless otherwise specified

Crude Oil

Crude Oil

Crude Oil

Crude Oil

Crude Oil

Crude Oil

Crude Oil

Crude Oil

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas Liquids

Natural Gas Liquids

Natural Gas Liquids

bbl

2014

2014

2014

2014

2015

2015

2015

Mcf

2014

2014

2014

2014

2014

2014

2014

2015

2015

2015

2015

2015

2015

2016

2017

bbl

2014

2015

Collars

Cap Swap

Three Way Collars

Deferred Put Spread

Three Way Collars

Call Protected Swap

Put

Collars

Cap Swap

Three Way Collars

Call Option

Swap

Swaption

Basis Swap

Cap Swap

Three Way Collars

Call Option

Swap

Swaption

Basis Swap

Three Way Collars

Three Way Collars

Swap

Swap

bbl

bbl

bbl

bbl

bbl

bbl

bbl

Mcf

Mcf

Mcf

Mcf

Mcf

Mcf

Mcf

Mcf

Mcf

Mcf

Mcf

Mcf

Mcf

Mcf

bbl

bbl

bbl

Derivatives Fair Value [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Volume

'

'

1,317,000

15,000

90,000

90,000

42,000

120,000

30,000

930,000

32,460,000

450,000

900,000

4,050,000

450,000

1,110,000

600,000

1,500,000

2,400,000

12,900,000

2,400,000

1,200,000

0

1,200,000

2,100,000

1,200,000

519,000

261,000

258,000

Put Option

'

'

'

'

80.83

77.92

75

78.75

'

'

'

'

3.3

3.55

'

'

'

'

3.28

3.63

'

'

'

'

3.6

3.6

'

'

'

Floor

'

'

'

90

'

88.98

90

89.06

'

90.16

'

3.51

'

4.19

'

'

'

'

'

4.16

'

'

'

'

4.08

4.1

'

'

'

Ceiling

'

'

'

97.65

'

103.39

'

100.44

'

'

'

4.43

'

4.69

5

'

'

'

'

4.61

4.4

'

'

'

4.52

4.57

'

'

'

Swap

'

'

'

'

97.72

'

'

'

95.76

'

'

'

4.09

'

'

3.96

4.45

-0.37

4.1

'

'

4.18

4.47

-0.56

'

'

'

56.63

44.6

Long Call

'

'

'

'

'

'

'

'

110

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivatives asset (liability)

$5,400

($200)

$1,455

$26

$649

$171

($146)

$292

$228

$235

$2,806

($23)

($17)

$556

($7)

($147)

($35)

$1,889

($28)

$707

($528)

$180

($505)

$973

($127)

($82)

$1,160

$819

$341

Combined_Fair_Value_of_Derivat

Combined Fair Value of Derivatives (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Short-Term Derivative Assets:	'	'
Total Short -Term Derivative Assets	$7,257	$5,668
Long-Term Derivative Assets:	'	'
Total Long - Term Derivative Assets	430	535
Total Derivative Assets	7,687	6,203
Short-Term Derivative Liabilities:	'	'
Total Short - Term Derivative Liabilities	-1,321	-4,663
Long-Term Derivative Liabilities:	'	'
Total Long-Term Derivative Liabilities	-945	-1,765
Total Derivative Liabilities	-2,266	-6,428
Interest Rate Swap	'	'
Short-Term Derivative Assets:	'	'
Total Short -Term Derivative Assets	'	488
Long-Term Derivative Liabilities:	'	'
Total Long-Term Derivative Liabilities	'	-693
Crude Oil | Collars	'	'
Short-Term Derivative Assets:	'	'
Total Short -Term Derivative Assets	26	380
Short-Term Derivative Liabilities:	'	'
Total Short - Term Derivative Liabilities	'	-42
Crude Oil | Cap Swap	'	'
Short-Term Derivative Assets:	'	'
Total Short -Term Derivative Assets	649	'
Crude Oil | Call Protected Swap	'	'
Short-Term Derivative Assets:	'	'
Total Short -Term Derivative Assets	228	'
Crude Oil | Put	'	'
Short-Term Derivative Assets:	'	'
Total Short -Term Derivative Assets	235	'
Crude Oil | Three Way Collars	'	'
Short-Term Derivative Assets:	'	'
Total Short -Term Derivative Assets	463	104
Short-Term Derivative Liabilities:	'	'
Total Short - Term Derivative Liabilities	'	-29
Crude Oil | Swap	'	'
Short-Term Derivative Liabilities:	'	'
Total Short - Term Derivative Liabilities	'	-119
Crude Oil | Deferred Put Spread	'	'
Short-Term Derivative Liabilities:	'	'
Total Short - Term Derivative Liabilities	-146	-585
Natural Gas Liquids | Swap	'	'
Short-Term Derivative Assets:	'	'
Total Short -Term Derivative Assets	1,128	83
Long-Term Derivative Assets:	'	'
Total Long - Term Derivative Assets	61	'
Short-Term Derivative Liabilities:	'	'
Total Short - Term Derivative Liabilities	-29	-995
Natural Gas | Collars	'	'
Short-Term Derivative Liabilities:	'	'
Total Short - Term Derivative Liabilities	-23	-235
Natural Gas | Cap Swap	'	'
Short-Term Derivative Assets:	'	'
Total Short -Term Derivative Assets	103	5
Long-Term Derivative Assets:	'	'
Total Long - Term Derivative Assets	26	5
Short-Term Derivative Liabilities:	'	'
Total Short - Term Derivative Liabilities	-141	-496
Long-Term Derivative Liabilities:	'	'
Total Long-Term Derivative Liabilities	-33	-307
Natural Gas | Three Way Collars	'	'
Short-Term Derivative Assets:	'	'
Total Short -Term Derivative Assets	1,343	518
Long-Term Derivative Assets:	'	'
Total Long - Term Derivative Assets	214	169
Short-Term Derivative Liabilities:	'	'
Total Short - Term Derivative Liabilities	-228	-125
Long-Term Derivative Liabilities:	'	'
Total Long-Term Derivative Liabilities	-275	'
Natural Gas | Swap	'	'
Short-Term Derivative Assets:	'	'
Total Short -Term Derivative Assets	226	106
Long-Term Derivative Assets:	'	'
Total Long - Term Derivative Assets	45	22
Short-Term Derivative Liabilities:	'	'
Total Short - Term Derivative Liabilities	-238	-1,170
Long-Term Derivative Liabilities:	'	'
Total Long-Term Derivative Liabilities	'	-4
Natural Gas | Basis Swap	'	'
Short-Term Derivative Assets:	'	'
Total Short -Term Derivative Assets	2,778	3,984
Long-Term Derivative Assets:	'	'
Total Long - Term Derivative Assets	84	339
Natural Gas | Swaption	'	'
Short-Term Derivative Assets:	'	'
Total Short -Term Derivative Assets	78	'
Short-Term Derivative Liabilities:	'	'
Total Short - Term Derivative Liabilities	-113	-717
Long-Term Derivative Liabilities:	'	'
Total Long-Term Derivative Liabilities	-505	'
Natural Gas | Call Option	'	'
Short-Term Derivative Liabilities:	'	'
Total Short - Term Derivative Liabilities	-403	-150
Long-Term Derivative Liabilities:	'	'
Total Long-Term Derivative Liabilities	($132)	($761)

Significant_Unobservable_Input

Significant Unobservable Inputs Used in Fair Value Measurements of Natural Gas Basis Swaps (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014
In Thousands, unless otherwise specified			Natural Gas	Natural Gas	Natural Gas	Natural Gas
				Basis Swap	Basis Swap	Basis Swap
					Minimum	Maximum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]	'	'	'	'	'	'
Range (price per Mcf)	'	'	'	'	-1.15	-1.96
Weighted Average (price per Mcf)	'	'	'	-1.49	'	'
Derivatives asset (liability)	$5,400	($200)	$2,806	$2,862	'	'

Fair_Value_Hierarchy_Table_for

Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivatives asset (liability)	$5,400	($200)
Commodity Swaps	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivatives asset (liability)	5,421	'
Commodity Swaps | Significant Other Observable Inputs (Level 2)	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivatives asset (liability)	2,559	'
Commodity Swaps | Significant Unobservable Inputs (Level 3)	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivatives asset (liability)	$2,862	'

Reconciliation_of_Commodity_De

Reconciliation of Commodity Derivative Contracts Measured at Fair Value on Recurring Basis Using Significant Unobservable Inputs (Level 3) (Details) (Commodity derivatives, USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013
Commodity derivatives	'	'
Fair Value Net Derivative Asset Liability Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]	'	'
Beginning Balance of Level 3	$4,323	'
Changes in Fair Value	-4,343	-721
Purchases	0	0
Settlements Received	2,882	23
Ending Balance of Level 3	$2,862	($698)

Financial_Instruments_Not_Reco

Financial Instruments Not Recorded at Fair Value (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013
Derivatives Fair Value [Line Items]	'		'
Senior Notes	$675,000,000		'
Senior Lines of Credit	0		59,000,000	[1]
Capital Leases and Other Obligations	14,633,000	[1]	9,934,000	[1]
Total	689,633,000	[2]	418,934,000
8.875% Senior Notes	'		'
Derivatives Fair Value [Line Items]	'		'
Senior Notes	350,000,000		350,000,000
6.25% Senior Notes	'		'
Derivatives Fair Value [Line Items]	'		'
Senior Notes	325,000,000		'
Fair Value	'		'
Derivatives Fair Value [Line Items]	'		'
Secured Lines of Credit	'		59,000,000
Capital Leases and Other Obligations	14,292,000		9,731,000
Total	706,042,000		453,731,000
Fair Value | 8.875% Senior Notes	'		'
Derivatives Fair Value [Line Items]	'		'
Senior Notes	379,750,000		385,000,000
Fair Value | 6.25% Senior Notes	'		'
Derivatives Fair Value [Line Items]	'		'
Senior Notes	$312,000,000		'
[1]	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 and nine months ended September 30, 2014 and the year ended December 31, 2013, was approximately 2.2%, 2.1% and 1.9%, respectively. The average interest rate on our capital leases and other obligations for the three and nine months ended September 30, 2014 and the year ended December 31, 2013, was approximately 4.2%, 3.8% and 5.3%, respectively
[2]	Excludes $2.8 million net premium on Senior Notes.

Schedule_of_Income_Tax_Include

Schedule of Income Tax Included in Continuing Operations (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Income Tax Disclosure [Abstract]	'	'	'	'
Income Tax (Expense) Benefit	($4,469)	$1,493	($14,592)	($5,622)
Effective Tax Rate	44.00%	-1843.20%	39.20%	31.90%

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Details) (USD $)	3 Months Ended	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2013
Income Tax Disclosure [Abstract]	'	'	'
Statutory rate	'	35.00%	35.00%
Income tax refunds	$1.30	$4.70	'

Capital_Stock_Additional_Infor

Capital Stock - Additional Information (Details) (USD $)	9 Months Ended		0 Months Ended	9 Months Ended		9 Months Ended		9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Aug. 18, 2014	Sep. 30, 2014	Aug. 12, 2014	Sep. 30, 2014	Aug. 18, 2014	Sep. 30, 2014
			6.0% convertible perpetual preferred stock, Series A	6.0% convertible perpetual preferred stock, Series A	6.0% convertible perpetual preferred stock, Series A	Depositary shares	Depositary shares	Common Stock
Schedule Of Capitalization Equity [Line Items]	'	'	'	'	'	'	'	'
Common stock, shares authorized	100,000,000	100,000,000	'	'	'	'	'	'
Preferred Stock, shares authorized	100,000	100,000	'	'	'	'	'	'
Common Stock, shares outstanding	54,116,652	54,186,490	'	'	'	'	'	'
Common Stock, shares issued	54,116,652	54,186,490	'	'	'	'	'	'
Preferred Stock, shares issued	16,100	0	16,100	'	'	'	1,610,000	'
Preferred Stock, par value	$0.00	$0.00	$0.00	'	'	'	'	'
Proceeds from the Issuance of Preferred Stock, Net	$155,011,000	'	$155,000,000	'	'	'	'	'
Liquidation preference per share	'	'	'	'	'	$10,000	'	'
Dividend per share in amount	'	'	'	$600	'	'	'	'
Dividend per share percentage	'	'	'	6.00%	'	'	'	'
Dividend declared	'	'	'	$0	'	'	'	'
Preferred stock to common stock conversion ratio	'	'	'	'	'	5.5556	'	555.56
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	'	'	'	12-Aug-14	'	'	'	'

Employee_Benefit_and_Equity_Pl2

Employee Benefit and Equity Plans - Additional Information (Details) (USD $)	9 Months Ended		12 Months Ended	9 Months Ended		3 Months Ended		9 Months Ended			12 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Dec. 31, 2013
		Person		Stock Options	Stock Options	Restricted Stock	Restricted Stock	Restricted Stock	Restricted Stock	Restricted Stock	Restricted Stock
				Minimum	Maximum			Person	Person	TSR	TSR
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Expiration period for outstanding stock options	'	'	'	'5 years	'10 years	'	'	'	'	'	'
Intrinsic value of stock options exercised	$0.30	$0.40	'	'	'	'	'	'	'	'	'
Total tax benefit	0.1	0.2	'	'	'	'	'	'	'	'	'
Outstanding weighted average remaining term (in years)	'3 years 1 month 6 days	'	'	'	'	'	'	'	'	'	'
Aggregate intrinsic value of options outstanding	1.1	'	'	'	'	'	'	'	'	'	'
Weighted average remaining term of options exercisable (in years)	'3 years 3 months 18 days	'	'	'	'	'	'	'	'	'	'
Aggregate intrinsic value of options exercisable	1.1	'	'	'	'	'	'	'	'	'	'
Common stock issued by compensation committee	'	'	'	'	'	'	'	51,178	414,924	'	'
Number of employees subjected to issuance of common stock	'	'	'	'	'	'	'	18	38	'	'
Number of non-employees subject to issuance of common stock	'	4	'	'	'	'	'	'	'	'	'
Fair value of TSR awards of per share estimated on date of grant	'	'	'	'	'	'	'	$15	'	$10.15	$12.59
Expected dividend yield	0.00%	'	0.00%	'	'	0.00%	'	'	'	'	'
Share-based compensation	'	'	'	'	'	1.6	1.2	4.3	3.5	'	'
Unrecognized compensation expense	'	'	'	'	'	$6.50	'	$6.50	'	'	'
Unrecognized compensation expense weighted average period, in years	'	'	'	'	'	'	'	'1 year 10 months 24 days	'	'	'

Summary_of_Issued_and_Outstand

Summary of Issued and Outstanding Stock Options (Details) (USD $)	Sep. 30, 2014
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]	'
Number Outstanding	412,561
Weighted-Average Exercise Price, Outstanding	$10.79
Number Exercisable	362,561
Weighted-Average Exercise Price, Exercisable	$10.45
Exercise Price Range 5.04	'
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]	'
Exercise Price	$5.04
Number Outstanding	46,041
Weighted-Average Exercise Price, Outstanding	$5.04
Number Exercisable	46,041
Weighted-Average Exercise Price, Exercisable	$5.04
Exercise Price Range 9.50	'
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]	'
Exercise Price	$9.50
Number Outstanding	85,000
Weighted-Average Exercise Price, Outstanding	$9.50
Number Exercisable	85,000
Weighted-Average Exercise Price, Exercisable	$9.50
Exercise Price Range 9.99	'
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]	'
Exercise Price	$9.99
Number Outstanding	149,333
Weighted-Average Exercise Price, Outstanding	$9.99
Number Exercisable	149,333
Weighted-Average Exercise Price, Exercisable	$9.99
Exercise Price Range 10.42	'
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]	'
Exercise Price	$10.42
Number Outstanding	29,548
Weighted-Average Exercise Price, Outstanding	$10.42
Number Exercisable	29,548
Weighted-Average Exercise Price, Exercisable	$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
Number Outstanding	3,500
Weighted-Average Exercise Price, Outstanding	$11.87
Number Exercisable	3,500
Weighted-Average Exercise Price, Exercisable	$11.87
Exercise Price Range 12.50	'
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]	'
Exercise Price	$12.50
Number Outstanding	19,139
Weighted-Average Exercise Price, Outstanding	$12.50
Number Exercisable	19,139
Weighted-Average Exercise Price, Exercisable	$12.50
Exercise Price Range 13.19	'
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]	'
Exercise Price	$13.19
Number Outstanding	50,000
Weighted-Average Exercise Price, Outstanding	$13.19
Exercise Price Range 22.34	'
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]	'
Exercise Price	$22.34
Number Outstanding	30,000
Weighted-Average Exercise Price, Outstanding	$22.34
Number Exercisable	30,000
Weighted-Average Exercise Price, Exercisable	$22.34

Percentage_of_Awards_to_Vest_D

Percentage of Awards to Vest (Details) (Restricted Stock)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
TSR Rank 1 - 3	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Percentage of Awards to Vest	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%	'
TSR Rank 7 - 10	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Percentage of Awards to Vest	50.00%	'
TSR Rank 11 - 13	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Percentage of Awards to Vest	25.00%	'
TSR Rank 14 - 16	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Percentage of Awards to Vest	0.00%	'
TSR Rank 4 - 5	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Percentage of Awards to Vest	'	75.00%
TSR Rank 6 - 8	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Percentage of Awards to Vest	'	50.00%
TSR Rank 9 - 11	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Percentage of Awards to Vest	'	25.00%
TSR Rank 12 - 14	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Percentage of Awards to Vest	'	0.00%

Monte_Carlo_Simulation_Model_A

Monte Carlo Simulation Model Assumptions Used to Estimate Fair Value of Restricted Stock (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Expected Dividend Yield	0.00%	0.00%
Risk-Free Interest Rate	0.80%	0.70%
Expected Volatility	50.40%	50.50%
Market Index	35.30%	35.30%
Expected Life	'3 years	'3 years
Peer Group | Minimum	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Expected Volatility	28.40%	28.40%
Peer Group | Maximum	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Expected Volatility	65.70%	63.50%

Summary_of_Nonvested_Stock_Act

Summary of Nonvested Stock Activity (Details) (Restricted Stock, USD $)	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Restricted Stock	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Stock awards, beginning balance, Number of Shares	2,172,639	'
Awards, Number of Shares	51,178	414,924
Forfeitures, Number of Shares	-157,542	'
Vested, Number of Shares	-315,680	'
Stock awards, ending balance, Number of Shares	1,750,595	'
Stock awards, beginning balance, Weighted Average Grant Date Fair Value	$14.16	'
Awards, Weighted Average Grant Date Fair Value	$15	'
Forfeitures, Weighted Average Grant Date Fair Value	$14.56	'
Vested, Weighted Average Grant Date Fair Value	$12.58	'
Stock awards, ending balance, Weighted Average Grant Date Fair Value	$14.43	'

Commitments_and_Contingencies_1

Commitments and Contingencies - Additional Information (Details) (USD $)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2012	Dec. 31, 2013
					acre
Loss Contingencies [Line Items]	'	'	'	'	'	'
Letters of credit	$5,200,000	'	$5,200,000	'	'	'
Rent expense	300,000	200,000	800,000	500,000	'	'
Maximum guarantee of payment of obligations	418,200,000	'	418,200,000	'	'	'
Transportation, processing and marketing expenses of oil natural gas and natural gas liquids	15,700,000	7,600,000	36,100,000	17,600,000	'	'
Working interest through acquisition	'	'	'	'	62.50%	'
Acres through acquisition	'	'	'	'	4,510	'
Percentage of working interest in 15% of MFC	'	'	'	'	100.00%	'
Working interest of MFC	'	'	'	'	15.00%	'
Commitment period for drilling wells	'	'	'November 15 of each year	'	'	'
Production and Lease Operating Expense	27,657,000	17,203,000	69,303,000	43,695,000	'	'
Other Liabilities	4,303,000	'	4,303,000	'	'	4,992,000
Working Interest Owners	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Other Liabilities	100,000	'	100,000	'	'	300,000
Capacity Reservation	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Estimated working interest	70.00%	'	70.00%	'	'	'
Capacity Reservation | 2014	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Obligation for the cryogenic gas processing plant if gas is not processed	'	'	4,800,000	'	'	'
Capacity Reservation | 2015	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Obligation for the cryogenic gas processing plant if gas is not processed	'	'	15,000,000	'	'	'
Capacity Reservation | 2016	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Obligation for the cryogenic gas processing plant if gas is not processed	'	'	25,800,000	'	'	'
Capacity Reservation | 2017	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Obligation for the cryogenic gas processing plant if gas is not processed	'	'	31,000,000	'	'	'
Capacity Reservation | 2018	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Obligation for the cryogenic gas processing plant if gas is not processed	'	'	31,000,000	'	'	'
Capacity Reservation | Thereafter	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Obligation for the cryogenic gas processing plant if gas is not processed	'	'	245,700,000	'	'	'
Drilling Commitments	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Number of rigs to support Appalachian Basin operations	4	'	4	'	'	'
Drilling carry obligation balance	4,800,000	'	4,800,000	'	14,100,000	'
Drilling commitments	3	'	3	'	'	'
Drilling Commitments | Minimum	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Estimated commitment for each well drilled and completed	'	'	8,000,000	'	'	'
Drilling Commitments | Maximum	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Estimated commitment for each well drilled and completed	'	'	9,000,000	'	'	'
Drilling Commitments | 2014	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Minimum cost to retain drilling rigs	'	'	2,600,000	'	'	'
Minimum cost to retain the completion services	'	'	2,600,000	'	'	'
Drilling Commitments | 2015	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Minimum cost to retain drilling rigs	'	'	3,900,000	'	'	'
Minimum cost to retain the completion services	'	'	5,100,000	'	'	'
Drilling Commitments | 2016	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Minimum cost to retain drilling rigs	'	'	1,500,000	'	'	'
Pennsylvania Impact Fee	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Rate in which unconventional wells are charged	'	'	20.00%	'	'	'
Production and Lease Operating Expense	$1,200,000	$800,000	$2,500,000	$2,200,000	'	'

Lease_Commitments_for_Each_of_

Lease Commitments for Each of Next Five Years (Details) (USD $)	Sep. 30, 2014
In Thousands, unless otherwise specified
Commitments And Contingencies Disclosure [Abstract]	'
2014	$257
2015	1,034
2016	958
2017	932
2018	237
Thereafter	26
Total	$3,444

Minimum_Net_Obligations_under_

Minimum Net Obligations under Sales, Gathering and Transportation Agreements (Details) (USD $)	Sep. 30, 2014
In Thousands, unless otherwise specified
Commitments And Contingencies Disclosure [Abstract]	'
2014	$4,372
2015	22,122
2016	34,428
2017	52,723
2018	55,539
Thereafter	752,689
Total	$921,873

Fee_for_Unconventional_Gas_Wel

Fee for Unconventional Gas Wells (Details) (Pennsylvania Impact Fee, USD $)	9 Months Ended
	Sep. 30, 2014
Less than $2.25	'
Unconventional Gas Wells [Line Items]	'
Year One	$40,000	[1]
Year Two	30,000	[1]
Year Three	25,000	[1]
Year 4 – 10	10,000	[1]
Year 11 – 15	5,000	[1]
$2.26 - $2.99	'
Unconventional Gas Wells [Line Items]	'
Year One	45,000	[1]
Year Two	35,000	[1]
Year Three	30,000	[1]
Year 4 – 10	15,000	[1]
Year 11 – 15	5,000	[1]
$3.00 - $4.99	'
Unconventional Gas Wells [Line Items]	'
Year One	50,000	[1]
Year Two	40,000	[1]
Year Three	30,000	[1]
Year 4 – 10	20,000	[1]
Year 11 – 15	10,000	[1]
$5.00 - $5.99	'
Unconventional Gas Wells [Line Items]	'
Year One	55,000	[1]
Year Two	45,000	[1]
Year Three	40,000	[1]
Year 4 – 10	20,000	[1]
Year 11 – 15	10,000	[1]
More than $5.99	'
Unconventional Gas Wells [Line Items]	'
Year One	60,000	[1]
Year Two	55,000	[1]
Year Three	50,000	[1]
Year 4 – 10	20,000	[1]
Year 11 – 15	$10,000	[1]
[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_Loss_Per_Common_Share2

Earnings (Loss) Per Common Share - Additional Information (Details)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Employee Stock Option	'	'	'	'
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]	'	'	'	'
Anti-dilutive securities excluded from computation of earnings per share	0.3	0.3	0.3	0.3
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	0.4	0.5	0.7	0.5

Earnings_Loss_Per_Share_Comput

Earnings (Loss) Per Share - Computation of Basic and Diluted Earning (Loss) Per Common Share (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Numerator:	'	'	'	'
Net Income From Continuing Operations, Less Noncontrolling Interests	$5,694	$1,574	$22,642	$12,019
Net Income From Discontinued Operations	'	'	'	460
NET INCOME ATTRIBUTABLE TO REX ENERGY	$5,694	$1,574	$22,642	$12,479
Denominator:	'	'	'	'
Weighted Average Common Shares Outstanding - Basic	53,214	52,626	53,493	52,560
Effect of Dilutive Securities:	'	'	'	'
Employee Stock Options	111	164	134	137
Employee Performance-Based Restricted Stock Awards	485	503	218	427
Effect of Assumed Conversions of Preferred Stock	4,181	'	1,409	'
Weighted Average Common Shares Outstanding - Diluted	57,991	53,293	55,254	53,124
Earnings per Common Share:	'	'	'	'
Basic — Net Income From Continuing Operations	$0.11	$0.03	$0.42	$0.23
Basic— Net Loss From Discontinued Operations	'	'	'	$0.01
Basic – Net Income Attributable to Rex Energy Common Shareholders	$0.11	$0.03	$0.42	$0.24
Diluted — Net Income From Continuing Operations	$0.10	$0.03	$0.41	$0.23
Diluted— Net Loss From Discontinued Operations	'	'	'	$0.01
Diluted – Net Income Attributable to Rex Energy Common Shareholders	$0.10	$0.03	$0.41	$0.24

Consolidated_Subsidiaries_Addi

Consolidated Subsidiaries - Additional Information (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013		Sep. 30, 2014	Mar. 31, 2013
					Water Solutions Holding	Water Solutions Holding
Consolidation Less Than Wholly Owned Subsidiary Parent Ownership Interest Effects Of Changes Net [Line Items]	'		'		'	'
Date of Agreement	'		'		'2009-11	'
Ownership percentage by parent	'		'		60.00%	80.00%
Ownership percentage by subsidiary	'		'		40.00%	20.00%
Effective date of ownership percentage	'		'		1-Apr-13	'
Line of credit facility, amount outstanding	$0		$59,000,000	[1]	$8,100,000	'
Capital Leases and Other Obligations	14,633,000	[1]	9,934,000	[1]	2,900,000	'
Equipment Loans	'		'		$2,500,000	'
[1]	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 and nine months ended September 30, 2014 and the year ended December 31, 2013, was approximately 2.2%, 2.1% and 1.9%, respectively. The average interest rate on our capital leases and other obligations for the three and nine months ended September 30, 2014 and the year ended December 31, 2013, was approximately 4.2%, 3.8% and 5.3%, respectively

Schedule_of_Carrying_Amount_an

Schedule of Carrying Amount and Classification of Assets and Liabilities of Water Solutions as Consolidated (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Consolidation Less Than Wholly Owned Subsidiary Parent Ownership Interest Effects Of Changes Net [Line Items]	'	'	'	'
Cash and Cash Equivalents	$87,622	$1,900	$23,791	$43,975
Accounts Receivable	53,393	38,863	'	'
Inventory, Prepaid Expenses and Other	3,245	2,207	'	'
Other Property and Equipment	83,645	70,115	'	'
Wells and Facilities in Progress	116,979	76,545	'	'
Less: Accumulated Depreciation, Depletion and Amortization	-255,471	-190,521	'	'
Deferred Financing Costs and Other Assets – Net	17,586	11,993	'	'
Total Assets	1,498,928	991,396	'	'
Accounts Payable	56,569	31,103	'	'
Current Maturities of Long-Term Debt	8,248	6,743	'	'
Accrued Liabilities	70,835	54,450	'	'
Senior Secured Line of Credit and Long-Term Debt	6,385	62,191	'	'
Total Liabilities	897,270	574,471	'	'
Water Solutions Holding	'	'	'	'
Consolidation Less Than Wholly Owned Subsidiary Parent Ownership Interest Effects Of Changes Net [Line Items]	'	'	'	'
Cash and Cash Equivalents	337	593	'	'
Accounts Receivable	13,234	9,882	'	'
Inventory, Prepaid Expenses and Other	297	89	'	'
Other Property and Equipment	20,628	11,798	'	'
Wells and Facilities in Progress	781	1,031	'	'
Less: Accumulated Depreciation, Depletion and Amortization	-4,259	-1,954	'	'
Deferred Financing Costs and Other Assets – Net	144	206	'	'
Total Assets	31,162	21,645	'	'
Accounts Payable	1,387	758	'	'
Current Maturities of Long-Term Debt	7,237	5,404	'	'
Accrued Liabilities	4,453	6,247	'	'
Senior Secured Line of Credit and Long-Term Debt	6,255	3,053	'	'
Total Liabilities	$19,332	$15,462	'	'

Equity_Method_Investments_Addi

Equity Method Investments - Additional Information (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Schedule Of Equity Method Investments [Line Items]	'	'	'	'	'
Equity investment	$18,098,000	'	$18,098,000	'	$18,708,000
Contributions to Equity Method Investments	'	'	'	2,493,000	'
Income (Loss) on Equity Method Investments	-202,000	-207,000	-610,000	-569,000	'
Production and Lease Operating Expense	27,657,000	17,203,000	69,303,000	43,695,000	'
RW Gathering, LLC	'	'	'	'	'
Schedule Of Equity Method Investments [Line Items]	'	'	'	'	'
Ownership percentage	40.00%	'	40.00%	'	'
Contributions to Equity Method Investments	'	'	'	2,500,000	'
Income (Loss) on Equity Method Investments	500,000	500,000	1,500,000	1,400,000	'
Production and Lease Operating Expense	200,000	300,000	500,000	600,000	'
Receivables	$0	'	$0	'	$0

Impairment_Expense_Additional_

Impairment Expense - Additional Information (Details) (USD $)	3 Months Ended	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2014
Oil And Gas Property [Abstract]	'	'	'
Undeveloped properties, cost	'	'	$334.50
Impairment Expenses	$2.20	$2.40	'

Exploration_Expense_Additional

Exploration Expense - Additional Information (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Exploration Expense [Line Items]	'	'	'	'
Exploration Expense	$1,462	$3,242	$4,890	$7,511
Posey County	'	'	'	'
Exploration Expense [Line Items]	'	'	'	'
Exploration Expense	'	'	'	500
No of exploratory well	'	1	'	1
Geological and Geophysical Type Expenditures	'	'	'	'
Exploration Expense [Line Items]	'	'	'	'
Exploration Expense	'	'	3,300	7,000
Payment of Delay Rentals | Appalachian Basin	'	'	'	'
Exploration Expense [Line Items]	'	'	'	'
Exploration Expense	'	'	$1,200	'

Condensed_Consolidating_Financ2

Condensed Consolidating Financial Information - Additional Information (Details) (USD $)	Sep. 30, 2014
In Millions, unless otherwise specified
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]	'
Senior Notes	$675

Condensed_Consolidating_Balanc

Condensed Consolidating Balance Sheets (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current Assets	'	'	'	'
Cash and Cash Equivalents	$87,622	$1,900	$23,791	$43,975
Accounts Receivable	53,393	38,863	'	'
Taxes Receivable	504	5,189	'	'
Short-Term Derivative Instruments	7,257	5,668	'	'
Current Deferred Tax Asset	2,837	3,451	'	'
Inventory, Prepaid Expenses and Other	3,245	2,207	'	'
Total Current Assets	154,858	57,278	'	'
Property and Equipment (Successful Efforts Method)	'	'	'	'
Evaluated Oil and Gas Properties	1,012,467	749,680	'	'
Unevaluated Oil and Gas Properties	334,461	189,385	'	'
Other Property and Equipment	83,645	70,115	'	'
Wells and Facilities in Progress	116,979	76,545	'	'
Pipelines	15,875	7,678	'	'
Total Property and Equipment	1,563,427	1,093,403	'	'
Less: Accumulated Depreciation, Depletion and Amortization	-255,471	-190,521	'	'
Net Property and Equipment	1,307,956	902,882	'	'
Deferred Financing Costs and Other Assets – Net	17,586	11,993	'	'
Equity Method Investments	18,098	18,708	'	'
Long-Term Derivative Instruments	430	535	'	'
Total Assets	1,498,928	991,396	'	'
Current Liabilities	'	'	'	'
Accounts Payable	56,569	31,103	'	'
Current Maturities of Long-Term Debt	8,248	6,743	'	'
Accrued Liabilities	70,835	54,450	'	'
Short-Term Derivative Instruments	1,321	4,663	'	'
Total Current Liabilities	136,973	96,959	'	'
Noncurrent Liabilities	'	'	'	'
Senior Notes	675,000	'	'	'
Premium on Senior Notes, Net	2,816	3,078	'	'
Senior Secured Line of Credit and Other Long-Term Debt	6,385	62,191	'	'
Long-Term Derivative Instruments	945	1,765	'	'
Long-Term Deferred Tax Liability	43,414	29,446	'	'
Other Deposits and Liabilities	4,303	4,992	'	'
Future Abandonment Cost	27,434	26,040	'	'
Senior Secured Line of Credit and Long-Term Debt	6,385	62,191	'	'
Total Liabilities	897,270	574,471	'	'
Stockholders’ Equity	'	'	'	'
Preferred Stock	1	'	'	'
Common Stock	54	54	'	'
Additional Paid-In Capital	616,384	456,554	'	'
Accumulated Earnings (Deficit)	-19,083	-41,725	'	'
Rex Energy Stockholders’ Equity	597,356	414,883	'	'
Noncontrolling Interests	4,302	2,042	'	'
Total Stockholders’ Equity	601,658	416,925	'	'
Total Liabilities and Stockholders’ Equity	1,498,928	991,396	'	'
Eliminations	'	'	'	'
Current Assets	'	'	'	'
Accounts Receivable	-1,729	-3,302	'	'
Total Current Assets	-1,729	-3,302	'	'
Property and Equipment (Successful Efforts Method)	'	'	'	'
Evaluated Oil and Gas Properties	-5,332	-3,101	'	'
Wells and Facilities in Progress	-295	-790	'	'
Pipelines	-1,898	'	'	'
Total Property and Equipment	-7,525	-3,891	'	'
Less: Accumulated Depreciation, Depletion and Amortization	817	350	'	'
Net Property and Equipment	-6,708	-3,541	'	'
Intercompany Receivables	-966,226	-628,517	'	'
Investment in Subsidiaries – Net	-363,396	-222,584	'	'
Total Assets	-1,338,059	-857,944	'	'
Current Liabilities	'	'	'	'
Accounts Payable	-1,731	-3,304	'	'
Total Current Liabilities	-1,731	-3,304	'	'
Noncurrent Liabilities	'	'	'	'
Intercompany Payables	-966,226	-628,517	'	'
Total Liabilities	-967,957	-631,821	'	'
Stockholders’ Equity	'	'	'	'
Additional Paid-In Capital	-259,924	-183,632	'	'
Accumulated Earnings (Deficit)	-113,518	-44,048	'	'
Rex Energy Stockholders’ Equity	-373,442	-227,680	'	'
Noncontrolling Interests	3,340	1,557	'	'
Total Stockholders’ Equity	-370,102	-226,123	'	'
Total Liabilities and Stockholders’ Equity	-1,338,059	-857,944	'	'
Guarantor Subsidiaries	'	'	'	'
Current Assets	'	'	'	'
Cash and Cash Equivalents	87,302	1,386	22,339	4,227
Accounts Receivable	41,785	32,283	'	'
Short-Term Derivative Instruments	7,257	5,180	'	'
Inventory, Prepaid Expenses and Other	2,905	2,092	'	'
Total Current Assets	139,249	40,941	'	'
Property and Equipment (Successful Efforts Method)	'	'	'	'
Evaluated Oil and Gas Properties	1,017,608	752,781	'	'
Unevaluated Oil and Gas Properties	333,600	189,385	'	'
Other Property and Equipment	62,110	57,409	'	'
Wells and Facilities in Progress	110,046	70,759	'	'
Pipelines	17,773	7,678	'	'
Total Property and Equipment	1,541,137	1,078,012	'	'
Less: Accumulated Depreciation, Depletion and Amortization	-251,704	-188,699	'	'
Net Property and Equipment	1,289,433	889,313	'	'
Deferred Financing Costs and Other Assets – Net	2,422	2,421	'	'
Equity Method Investments	18,098	18,708	'	'
Investment in Subsidiaries – Net	4,161	4,442	'	'
Long-Term Derivative Instruments	430	535	'	'
Total Assets	1,453,793	956,360	'	'
Current Liabilities	'	'	'	'
Accounts Payable	56,909	33,613	'	'
Current Maturities of Long-Term Debt	1,011	1,339	'	'
Accrued Liabilities	50,813	45,196	'	'
Short-Term Derivative Instruments	1,321	4,663	'	'
Total Current Liabilities	110,054	84,811	'	'
Noncurrent Liabilities	'	'	'	'
Senior Secured Line of Credit and Other Long-Term Debt	130	137	'	'
Long-Term Derivative Instruments	945	1,071	'	'
Other Deposits and Liabilities	4,303	4,992	'	'
Future Abandonment Cost	27,402	26,027	'	'
Intercompany Payables	962,392	554,329	'	'
Senior Secured Line of Credit and Long-Term Debt	130	137	'	'
Total Liabilities	1,105,226	671,367	'	'
Stockholders’ Equity	'	'	'	'
Additional Paid-In Capital	177,144	177,144	'	'
Accumulated Earnings (Deficit)	171,423	107,849	'	'
Rex Energy Stockholders’ Equity	348,567	284,993	'	'
Total Stockholders’ Equity	348,567	284,993	'	'
Total Liabilities and Stockholders’ Equity	1,453,793	956,360	'	'
Non-Guarantor Subsidiaries	'	'	'	'
Current Assets	'	'	'	'
Cash and Cash Equivalents	315	509	1,447	824
Accounts Receivable	13,337	9,882	'	'
Inventory, Prepaid Expenses and Other	297	89	'	'
Total Current Assets	13,949	10,480	'	'
Property and Equipment (Successful Efforts Method)	'	'	'	'
Evaluated Oil and Gas Properties	191	'	'	'
Unevaluated Oil and Gas Properties	861	'	'	'
Other Property and Equipment	21,535	12,706	'	'
Wells and Facilities in Progress	7,228	6,576	'	'
Total Property and Equipment	29,815	19,282	'	'
Less: Accumulated Depreciation, Depletion and Amortization	-4,584	-2,172	'	'
Net Property and Equipment	25,231	17,110	'	'
Deferred Financing Costs and Other Assets – Net	144	206	'	'
Investment in Subsidiaries – Net	3,438	1,197	'	'
Total Assets	42,762	28,993	'	'
Current Liabilities	'	'	'	'
Accounts Payable	1,391	794	'	'
Current Maturities of Long-Term Debt	7,237	5,404	'	'
Accrued Liabilities	4,683	6,287	'	'
Total Current Liabilities	13,311	12,485	'	'
Noncurrent Liabilities	'	'	'	'
Senior Secured Line of Credit and Other Long-Term Debt	6,255	3,054	'	'
Future Abandonment Cost	32	13	'	'
Intercompany Payables	3,834	74,188	'	'
Senior Secured Line of Credit and Long-Term Debt	6,255	3,054	'	'
Total Liabilities	23,432	89,740	'	'
Stockholders’ Equity	'	'	'	'
Additional Paid-In Capital	82,780	6,488	'	'
Accumulated Earnings (Deficit)	-64,412	-67,720	'	'
Rex Energy Stockholders’ Equity	18,368	-61,232	'	'
Noncontrolling Interests	962	485	'	'
Total Stockholders’ Equity	19,330	-60,747	'	'
Total Liabilities and Stockholders’ Equity	42,762	28,993	'	'
Parent Company	'	'	'	'
Current Assets	'	'	'	'
Cash and Cash Equivalents	5	5	5	38,924
Taxes Receivable	504	5,189	'	'
Short-Term Derivative Instruments	'	488	'	'
Current Deferred Tax Asset	2,837	3,451	'	'
Inventory, Prepaid Expenses and Other	43	26	'	'
Total Current Assets	3,389	9,159	'	'
Property and Equipment (Successful Efforts Method)	'	'	'	'
Deferred Financing Costs and Other Assets – Net	15,020	9,366	'	'
Intercompany Receivables	966,226	628,517	'	'
Investment in Subsidiaries – Net	355,797	216,945	'	'
Total Assets	1,340,432	863,987	'	'
Current Liabilities	'	'	'	'
Accrued Liabilities	15,339	2,967	'	'
Total Current Liabilities	15,339	2,967	'	'
Noncurrent Liabilities	'	'	'	'
Premium on Senior Notes, Net	2,816	3,078	'	'
Senior Secured Line of Credit and Other Long-Term Debt	'	59,000	'	'
Long-Term Derivative Instruments	'	694	'	'
Long-Term Deferred Tax Liability	43,414	29,446	'	'
Senior Secured Line of Credit and Long-Term Debt	'	59,000	'	'
Total Liabilities	736,569	445,185	'	'
Stockholders’ Equity	'	'	'	'
Preferred Stock	1	'	'	'
Common Stock	54	54	'	'
Additional Paid-In Capital	616,384	456,554	'	'
Accumulated Earnings (Deficit)	-12,576	-37,806	'	'
Rex Energy Stockholders’ Equity	603,863	418,802	'	'
Total Stockholders’ Equity	603,863	418,802	'	'
Total Liabilities and Stockholders’ Equity	1,340,432	863,987	'	'
8.875% Senior Notes	'	'	'	'
Noncurrent Liabilities	'	'	'	'
Senior Notes	350,000	350,000	'	'
Premium on Senior Notes, Net	2,800	3,078	'	'
8.875% Senior Notes | Parent Company	'	'	'	'
Noncurrent Liabilities	'	'	'	'
Senior Notes	350,000	350,000	'	'
6.25% Senior Notes	'	'	'	'
Noncurrent Liabilities	'	'	'	'
Senior Notes	325,000	'	'	'
6.25% Senior Notes | Parent Company	'	'	'	'
Noncurrent Liabilities	'	'	'	'
Senior Notes	$325,000	'	'	'

Condensed_Consolidating_Balanc1

Condensed Consolidating Balance Sheets (Parenthetical) (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
8.875% Senior Notes	'	'
Condensed Balance Sheet Statements Captions [Line Items]	'	'
Interest rate	8.88%	8.88%
Due date	'2020	'2020
6.25% Senior Notes	'	'
Condensed Balance Sheet Statements Captions [Line Items]	'	'
Interest rate	6.25%	6.25%
Due date	'2022	'2022

Condensed_Consolidating_Statem

Condensed Consolidating Statements of Operations (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
OPERATING REVENUE	'	'	'	'
Oil, Natural Gas and NGL Sales	$73,448	$58,063	$227,650	$150,447
Field Services Revenue	13,070	4,847	41,462	15,193
Other Revenue	18	64	92	164
TOTAL OPERATING REVENUE	86,536	62,974	269,204	165,804
OPERATING EXPENSES	'	'	'	'
Production and Lease Operating Expense	27,657	17,203	69,303	43,695
General and Administrative Expense	10,409	8,826	30,039	24,404
Loss on Disposal of Asset	84	140	385	1,632
Impairment Expense	1	2,244	41	2,414
Exploration Expense	1,462	3,242	4,890	7,511
Depreciation, Depletion, Amortization and Accretion	27,364	16,267	69,014	40,367
Field Services Operating Expense	9,547	3,652	30,912	10,354
Other Operating Expense (Income)	-24	19	3	910
TOTAL OPERATING EXPENSES	76,500	51,593	204,587	131,287
INCOME FROM OPERATIONS	10,036	11,381	64,617	34,517
OTHER INCOME (EXPENSE)	'	'	'	'
Interest Expense	-11,080	-6,181	-25,718	-16,013
Gain (Loss) on Derivatives, Net	12,316	-4,624	2,315	-1,423
Other Income (Expense)	-12	-30	-30	2,041
Loss on Equity Method Investments	-202	-207	-610	-569
TOTAL OTHER INCOME (EXPENSE)	1,022	-11,042	-24,043	-15,964
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX	11,058	339	40,574	18,553
Income Tax (Expense) Benefit	-4,469	1,493	-14,592	-5,622
NET INCOME FROM CONTINUING OPERATIONS	6,589	1,832	25,982	12,931
Income From Discontinued Operations, Net of Income Taxes	0	0	0	460
NET INCOME	6,589	1,832	25,982	13,391
Net Income Attributable to Noncontrolling Interests	895	258	3,340	912
NET INCOME ATTRIBUTABLE TO REX ENERGY	5,694	1,574	22,642	12,479
Eliminations	'	'	'	'
OPERATING REVENUE	'	'	'	'
Field Services Revenue	-2,800	-1,696	-13,005	-4,475
TOTAL OPERATING REVENUE	-2,800	-1,696	-13,005	-4,475
OPERATING EXPENSES	'	'	'	'
Production and Lease Operating Expense	-15	'	-35	'
General and Administrative Expense	-15	-15	-50	-71
Depreciation, Depletion, Amortization and Accretion	-199	-44	-469	-105
Field Services Operating Expense	-1,917	-1,169	-9,334	-3,114
TOTAL OPERATING EXPENSES	-2,146	-1,228	-9,888	-3,290
INCOME FROM OPERATIONS	-654	-468	-3,117	-1,185
OTHER INCOME (EXPENSE)	'	'	'	'
Other Income (Expense)	-15	-15	-50	-71
Income (Loss) From Equity in Consolidated Subsidiaries	-12,840	-7,653	-39,667	-25,510
TOTAL OTHER INCOME (EXPENSE)	-12,855	-7,668	-39,717	-25,581
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX	-13,509	-8,136	-42,834	-26,766
NET INCOME FROM CONTINUING OPERATIONS	-13,509	-8,136	-42,834	-26,766
Income From Discontinued Operations, Net of Income Taxes	'	0	'	'
NET INCOME	'	-8,136	-42,834	-26,766
NET INCOME ATTRIBUTABLE TO REX ENERGY	-13,509	-8,136	-42,834	-26,766
Guarantor Subsidiaries	'	'	'	'
OPERATING REVENUE	'	'	'	'
Oil, Natural Gas and NGL Sales	73,343	58,063	227,547	150,447
Other Revenue	18	64	92	164
TOTAL OPERATING REVENUE	73,361	58,127	227,639	150,611
OPERATING EXPENSES	'	'	'	'
Production and Lease Operating Expense	27,668	17,201	69,328	43,688
General and Administrative Expense	7,709	6,863	22,811	18,896
Loss on Disposal of Asset	175	94	469	1,586
Impairment Expense	1	2,244	41	2,414
Exploration Expense	1,452	3,241	4,877	7,510
Depreciation, Depletion, Amortization and Accretion	26,536	15,876	66,812	39,434
Other Operating Expense (Income)	-24	19	3	910
TOTAL OPERATING EXPENSES	63,517	45,538	164,341	114,438
INCOME FROM OPERATIONS	9,844	12,589	63,298	36,173
OTHER INCOME (EXPENSE)	'	'	'	'
Interest Expense	-56	-16	-86	-47
Gain (Loss) on Derivatives, Net	12,316	-4,624	1,232	-1,423
Other Income (Expense)	3	-15	20	2,112
Loss on Equity Method Investments	-202	-207	-610	-569
Income (Loss) From Equity in Consolidated Subsidiaries	18	-22	-64	-44
TOTAL OTHER INCOME (EXPENSE)	12,079	-4,884	492	29
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX	21,923	7,705	63,790	36,202
Income Tax (Expense) Benefit	-8,853	11	-22,964	-11,546
NET INCOME FROM CONTINUING OPERATIONS	13,070	7,716	40,826	24,656
Income From Discontinued Operations, Net of Income Taxes	'	0	'	'
NET INCOME	'	7,716	40,826	24,656
NET INCOME ATTRIBUTABLE TO REX ENERGY	13,070	7,716	40,826	24,656
Non-Guarantor Subsidiaries	'	'	'	'
OPERATING REVENUE	'	'	'	'
Oil, Natural Gas and NGL Sales	105	'	103	'
Field Services Revenue	15,870	6,543	54,467	19,668
TOTAL OPERATING REVENUE	15,975	6,543	54,570	19,668
OPERATING EXPENSES	'	'	'	'
Production and Lease Operating Expense	4	2	10	7
General and Administrative Expense	1,160	617	2,982	1,765
Loss on Disposal of Asset	-91	46	-84	46
Exploration Expense	10	1	13	1
Depreciation, Depletion, Amortization and Accretion	1,027	435	2,671	1,038
Field Services Operating Expense	11,464	4,821	40,246	13,468
TOTAL OPERATING EXPENSES	13,574	5,922	45,838	16,325
INCOME FROM OPERATIONS	2,401	621	8,732	3,343
OTHER INCOME (EXPENSE)	'	'	'	'
Interest Expense	-134	-26	-482	-66
Income (Loss) From Equity in Consolidated Subsidiaries	-18	22	64	44
TOTAL OTHER INCOME (EXPENSE)	-152	-4	-418	-22
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX	2,249	617	8,314	3,321
Income Tax (Expense) Benefit	-915	61	-2,967	-759
NET INCOME FROM CONTINUING OPERATIONS	1,334	678	5,347	2,562
Income From Discontinued Operations, Net of Income Taxes	'	0	'	460
NET INCOME	'	678	5,347	3,022
Net Income Attributable to Noncontrolling Interests	895	258	3,340	912
NET INCOME ATTRIBUTABLE TO REX ENERGY	439	420	2,007	2,110
Parent Company	'	'	'	'
OPERATING EXPENSES	'	'	'	'
General and Administrative Expense	1,555	1,361	4,296	3,814
TOTAL OPERATING EXPENSES	1,555	1,361	4,296	3,814
INCOME FROM OPERATIONS	-1,555	-1,361	-4,296	-3,814
OTHER INCOME (EXPENSE)	'	'	'	'
Interest Expense	-10,890	-6,139	-25,150	-15,900
Gain (Loss) on Derivatives, Net	'	'	1,083	'
Income (Loss) From Equity in Consolidated Subsidiaries	12,840	7,653	39,667	25,510
TOTAL OTHER INCOME (EXPENSE)	1,950	1,514	15,600	9,610
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX	395	153	11,304	5,796
Income Tax (Expense) Benefit	5,299	1,421	11,339	6,683
NET INCOME FROM CONTINUING OPERATIONS	5,694	1,574	22,643	12,479
Income From Discontinued Operations, Net of Income Taxes	'	0	'	'
NET INCOME	'	1,574	22,643	12,479
NET INCOME ATTRIBUTABLE TO REX ENERGY	$5,694	$1,574	$22,643	$12,479

Condensed_Consolidating_Statem1

Condensed Consolidating Statements of Cash Flows (Details) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013
CASH FLOWS FROM OPERATING ACTIVITIES	'	'
Net Income	$25,982	$13,391
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities	'	'
Loss from Equity Method Investments	610	569
Non-cash Expenses	5,146	4,432
Depreciation, Depletion, Amortization and Accretion	69,014	40,367
Deferred Income Tax Expense (Benefit)	14,592	10,970
(Gain) Loss on Derivatives	-2,315	1,423
Cash Settlements of Derivatives	-3,331	5,540
Dry Hole Expense	237	485
Loss on Sale of Asset	385	663
Impairment Expense	41	2,414
Changes in operating assets and liabilities	'	'
Accounts Receivable	-9,854	-7,028
Inventory, Prepaid Expenses and Other Assets	-1,038	-391
Accounts Payable and Accrued Liabilities	36,060	34,750
Other Assets and Liabilities	-1,966	-1,830
NET CASH PROVIDED BY OPERATING ACTIVITIES	133,563	105,755
CASH FLOWS FROM INVESTING ACTIVITIES	'	'
Proceeds from Joint Venture Acreage Management	210	246
Contributions to Equity Method Investments	'	-2,493
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	412	3,931
Acquisitions of Undeveloped Acreage	-153,628	-31,458
Capital Expenditures for Development of Oil & Gas Properties and Equipment	-310,353	-197,264
NET CASH USED IN INVESTING ACTIVITIES	-463,359	-227,038
CASH FLOWS FROM FINANCING ACTIVITIES	'	'
Proceeds from Long-Term Debt and Line of Credit	193,041	1,750
Repayments of Long-Term Debt and Line of Credit	-248,146	-1,022
Repayments of Loans and Other Notes Payable	-1,998	-1,363
Proceeds from Senior Notes, Net of Discounts and Premiums	325,000	105,000
Debt Issuance Costs	-6,731	-3,004
Proceeds from the Issuance of Preferred Stock, Net	155,011	'
Proceeds from the Exercise of Stock Options	421	534
Purchase of Noncontrolling Interests	'	-150
Distributions by the Partners of Consolidated Joint Ventures	-1,080	-646
NET CASH PROVIDED BY FINANCING ACTIVITIES	415,518	101,099
NET INCREASE (DECREASE) IN CASH	85,722	-20,184
CASH – BEGINNING	1,900	43,975
CASH – ENDING	87,622	23,791
Eliminations	'	'
CASH FLOWS FROM OPERATING ACTIVITIES	'	'
Net Income	-42,834	-26,766
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities	'	'
Depreciation, Depletion, Amortization and Accretion	-469	-105
Changes in operating assets and liabilities	'	'
Accounts Receivable	-1,574	-3,731
Accounts Payable and Accrued Liabilities	1,574	4,022
NET CASH PROVIDED BY OPERATING ACTIVITIES	-43,303	-26,580
CASH FLOWS FROM INVESTING ACTIVITIES	'	'
Intercompany loans to subsidiaries	39,669	25,219
Capital Expenditures for Development of Oil & Gas Properties and Equipment	3,634	1,361
NET CASH USED IN INVESTING ACTIVITIES	43,303	26,580
Guarantor Subsidiaries	'	'
CASH FLOWS FROM OPERATING ACTIVITIES	'	'
Net Income	40,826	24,656
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities	'	'
Loss from Equity Method Investments	610	569
Non-cash Expenses	-203	-180
Depreciation, Depletion, Amortization and Accretion	66,812	39,434
Deferred Income Tax Expense (Benefit)	22,964	12,060
(Gain) Loss on Derivatives	-1,232	1,423
Cash Settlements of Derivatives	-4,209	5,540
Dry Hole Expense	237	485
Loss on Sale of Asset	469	1,586
Impairment Expense	41	2,414
Changes in operating assets and liabilities	'	'
Accounts Receivable	-9,510	-2,628
Inventory, Prepaid Expenses and Other Assets	-812	-316
Accounts Payable and Accrued Liabilities	22,975	23,174
Other Assets and Liabilities	-1,942	-1,495
NET CASH PROVIDED BY OPERATING ACTIVITIES	137,026	106,722
CASH FLOWS FROM INVESTING ACTIVITIES	'	'
Intercompany loans to subsidiaries	408,192	139,294
Proceeds from Joint Venture Acreage Management	210	246
Contributions to Equity Method Investments	'	-2,493
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	248	697
Acquisitions of Undeveloped Acreage	-152,765	-31,456
Capital Expenditures for Development of Oil & Gas Properties and Equipment	-305,672	-193,964
NET CASH USED IN INVESTING ACTIVITIES	-49,787	-87,676
CASH FLOWS FROM FINANCING ACTIVITIES	'	'
Repayments of Loans and Other Notes Payable	-1,323	-934
NET CASH PROVIDED BY FINANCING ACTIVITIES	-1,323	-934
NET INCREASE (DECREASE) IN CASH	85,916	18,112
CASH – BEGINNING	1,386	4,227
CASH – ENDING	87,302	22,339
Non-Guarantor Subsidiaries	'	'
CASH FLOWS FROM OPERATING ACTIVITIES	'	'
Net Income	5,347	3,022
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities	'	'
Non-cash Expenses	233	65
Depreciation, Depletion, Amortization and Accretion	2,671	1,038
Deferred Income Tax Expense (Benefit)	2,967	1,169
Loss on Sale of Asset	-84	-923
Changes in operating assets and liabilities	'	'
Accounts Receivable	-3,455	-669
Inventory, Prepaid Expenses and Other Assets	-209	-66
Accounts Payable and Accrued Liabilities	-1,007	-1,687
Other Assets and Liabilities	-24	-88
NET CASH PROVIDED BY OPERATING ACTIVITIES	6,439	1,861
CASH FLOWS FROM INVESTING ACTIVITIES	'	'
Intercompany loans to subsidiaries	248	688
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	164	3,234
Acquisitions of Undeveloped Acreage	-863	-2
Capital Expenditures for Development of Oil & Gas Properties and Equipment	-8,315	-4,661
NET CASH USED IN INVESTING ACTIVITIES	-8,766	-741
CASH FLOWS FROM FINANCING ACTIVITIES	'	'
Proceeds from Long-Term Debt and Line of Credit	22,041	1,750
Repayments of Long-Term Debt and Line of Credit	-18,146	-1,022
Repayments of Loans and Other Notes Payable	-675	-429
Debt Issuance Costs	-7	'
Purchase of Noncontrolling Interests	'	-150
Distributions by the Partners of Consolidated Joint Ventures	-1,080	-646
NET CASH PROVIDED BY FINANCING ACTIVITIES	2,133	-497
NET INCREASE (DECREASE) IN CASH	-194	623
CASH – BEGINNING	509	824
CASH – ENDING	315	1,447
Parent Company	'	'
CASH FLOWS FROM OPERATING ACTIVITIES	'	'
Net Income	22,643	12,479
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities	'	'
Non-cash Expenses	5,116	4,547
Deferred Income Tax Expense (Benefit)	-11,339	-2,259
(Gain) Loss on Derivatives	-1,083	'
Cash Settlements of Derivatives	878	'
Changes in operating assets and liabilities	'	'
Accounts Receivable	4,685	'
Inventory, Prepaid Expenses and Other Assets	-17	-9
Accounts Payable and Accrued Liabilities	12,518	9,241
Other Assets and Liabilities	'	-247
NET CASH PROVIDED BY OPERATING ACTIVITIES	33,401	23,752
CASH FLOWS FROM INVESTING ACTIVITIES	'	'
Intercompany loans to subsidiaries	-448,109	-165,201
NET CASH USED IN INVESTING ACTIVITIES	-448,109	-165,201
CASH FLOWS FROM FINANCING ACTIVITIES	'	'
Proceeds from Long-Term Debt and Line of Credit	171,000	'
Repayments of Long-Term Debt and Line of Credit	-230,000	'
Proceeds from Senior Notes, Net of Discounts and Premiums	325,000	105,000
Debt Issuance Costs	-6,724	-3,004
Proceeds from the Issuance of Preferred Stock, Net	155,011	'
Proceeds from the Exercise of Stock Options	421	534
NET CASH PROVIDED BY FINANCING ACTIVITIES	414,708	102,530
NET INCREASE (DECREASE) IN CASH	'	-38,919
CASH – BEGINNING	5	38,924
CASH – ENDING	$5	$5