Rex Energy 10-K 2 Mar 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 26, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	REXX
Entity Registrant Name	REX ENERGY CORP
Entity Central Index Key	1397516
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		55,266,321
Entity Public Float			$853,065,924

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current Assets
Cash and Cash Equivalents	$17,978	$1,307
Accounts Receivable	43,936	32,284
Taxes Receivable	504	5,189
Short-Term Derivative Instruments	29,265	5,668
Current Deferred Tax Asset		3,451
Inventory, Prepaid Expenses and Other	3,403	2,118
Assets Held for Sale	34,257	18,343
Total Current Assets	129,343	68,360
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties	1,079,039	749,680
Unevaluated Oil and Gas Properties	322,413	189,385
Other Property and Equipment	46,361	58,317
Wells and Facilities in Progress	127,655	75,514
Pipelines	15,657	7,678
Total Property and Equipment	1,591,125	1,080,574
Less: Accumulated Depreciation, Depletion and Amortization	-366,917	-188,568
Net Property and Equipment	1,224,208	892,006
Deferred Financing Costs and Other Assets – Net	17,070	11,787
Equity Method Investments	17,895	18,708
Long-Term Derivative Instruments	4,904	535
Long-Term Deferred Tax Asset	8,301
Total Assets	1,401,721	991,396
Current Liabilities
Accounts Payable	53,340	30,345
Current Maturities of Long-Term Debt	1,176	1,340
Accrued Liabilities	59,478	48,204
Short-Term Derivative Instruments	421	4,663
Current Deferred Tax Liability	8,301
Liabilities Related to Assets Held for Sale	25,115	15,461
Total Current Liabilities	147,831	100,013
Noncurrent Liabilities
Senior Notes	675,000
Premium on Senior Notes, Net	2,725	3,078
Senior Secured Line of Credit and Long-Term Debt	251	59,137
Long-Term Derivative Instruments	2,377	1,765
Long-Term Deferred Tax Liability		29,446
Other Deposits and Liabilities	4,018	4,992
Future Abandonment Cost	38,146	26,040
Total Liabilities	870,348	574,471
Commitments and Contingencies (See Note 13)
Stockholders’ Equity
Preferred Stock	1
Common Stock	54	54
Additional Paid-In Capital	617,826	456,554
Accumulated Deficit	-90,749	-41,725
Rex Energy Stockholders’ Equity	527,132	414,883
Noncontrolling Interests of Discontinued Operations	4,241	2,042
Total Stockholders’ Equity	531,373	416,925
Total Liabilities and Stockholders’ Equity	1,401,721	991,396
8.875% Senior Notes
Noncurrent Liabilities
Senior Notes	350,000	350,000
6.25% Senior Notes
Noncurrent Liabilities
Senior Notes	$325,000

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 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	54,174,763	54,186,490
Common Stock, shares outstanding	54,174,763	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										12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
OPERATING REVENUE
Oil, Natural Gas and NGL Sales											$297,869		$213,919		$134,574
Other Revenue											118		200		218
TOTAL OPERATING REVENUE	70,245		73,466	72,933	81,343	63,508		58,127	51,520	40,964	297,987		214,119		134,792
OPERATING EXPENSES
Production and Lease Operating Expense											100,282		62,150		47,638
General and Administrative Expense											36,137		30,839		22,458
Loss on Disposal of Asset											644		1,602		50
Impairment Expense	132,600					29,700					132,618		32,072		20,571
Exploration Expense											9,446		11,408		4,782
Depreciation, Depletion, Amortization and Accretion											94,467		62,386		44,955
Other Operating Expense											134		592		1,136
TOTAL OPERATING EXPENSES	139,913	[1]	67,847	65,290	72,587	77,265	[1]	56,469	38,280	44,488	373,728		201,049		141,590
INCOME (LOSS) FROM OPERATIONS											-75,741		13,070		-6,798
OTHER EXPENSE
Interest Expense											-36,977		-22,676		-6,418
Gain (Loss) on Derivatives, Net											38,876		-2,908		10,687
Other Income											90		6,739		98,653
Loss on Equity Method Investments											-813		-763		-3,921
TOTAL OTHER INCOME (EXPENSE)											1,176		-19,608		99,001
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX											-74,565		-6,538		92,203
Income Tax (Expense) Benefit											26,915		4,154		-37,282
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	-69,668		5,619	7,643	8,756	-13,757		1,658	13,240	-3,524	-47,650		-2,384		54,921
Income (Loss) From Discontinued Operations, Net of Income Taxes											5,000		1,811		-8,623
NET INCOME (LOSS)	-68,631		6,589	8,955	10,437	-13,965		1,832	13,961	-2,401	-42,650		-573		46,298
Net Income Attributable to Noncontrolling Interests	698		895	877	1,569	645		258	221	433	4,039		1,557		819
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	-69,329		5,694	8,078	8,868	-14,610		1,574	13,740	-2,834	-46,689		-2,130		45,479
Preferred Stock Dividends	2,335										2,335
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	($71,664)		$5,694	$8,078	$8,868						($49,024)		($2,130)		$45,479
Earnings per common share:
Basic – Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders	($1.35)		$0.11	$0.14	$0.17	($0.26)		$0.03	$0.25	($0.06)	($0.94)	[2]	($0.05)	[2]	$1.06	[2]
Basic – Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders				$0.01		($0.02)			$0.01	$0.01	$0.02	[2]	$0.01	[2]	($0.18)	[2]
Basic – Net Income (Loss) Attributable to Rex Energy Common Shareholders	($1.35)		$0.11	$0.15	$0.17	($0.28)		$0.03	$0.26	($0.05)	($0.92)	[2]	($0.04)	[2]	$0.88	[2]
Basic – Weighted Average Shares of Common Stock Outstanding	53,261		53,214	53,164	52,984	52,705		52,626	52,555	52,367	53,150		52,572		51,543
Diluted – Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders	($1.35)		$0.10	$0.14	$0.17	($0.26)		$0.03	$0.25	($0.06)	($0.94)	[2]	($0.05)	[2]	$1.06	[2]
Diluted – Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders				$0.01		($0.02)			$0.01	$0.01	$0.02	[2]	$0.01	[2]	($0.18)	[2]
Diluted – Net Income (Loss) Attributable to Rex Energy Common Shareholders	($1.35)		$0.10	$0.15	$0.17	($0.28)		$0.03	$0.26	($0.05)	($0.92)	[2]	($0.04)	[2]	$0.88	[2]
Diluted – Weighted Average Shares of Common Stock Outstanding	53,261		57,991	53,509	53,503	52,705		53,293	52,911	52,367	53,150		52,572		52,025
[1]	For the three-month periods ended December 31, 2014 and 2013, we incurred impairment expense of approximately $132.6 million and $29.7 million, respectively.
[2]	All earnings per share amounts are attributable to Rex common shareholders.

Consolidated_Statements_of_Cha

Consolidated Statements of Changes in Noncontrolling Interests and Stockholders' Equity (USD $)	Total	Common Stock	Preferred Stock	Additional Paid-in Capital	Accumulated Deficit	Rex Energy Stockholders' Equity	Noncontrolling Interest
In Thousands, except Share data
Balance at Dec. 31, 2011	$292,274	$44		$376,843	($84,888)	$291,999	$275
Balance (in shares) at Dec. 31, 2011		44,859,000
Non-Cash Compensation	2,893			3,079	-186	2,893
Capital Distributions	-319						-319
Issuance of Restricted Stock, Net of Forfeitures (in shares)		252,000
Stock Option Exercise	565			565		565
Stock Option Exercise (in shares)	52,287	52,000
Issuance of stock, net of issuance costs	70,583	8		70,575		70,583
Issuance of stock, net of issuance costs (in shares)		8,050,000
Net Income (Loss)	46,298				45,479	45,479	819
Balance at Dec. 31, 2012	412,294	52		451,062	-39,595	411,519	775
Balance (in shares) at Dec. 31, 2012		53,213,000
Non-Cash Compensation	5,418			5,418		5,418
Capital Distributions	-886						-886
Issuance of Restricted Stock, Net of Forfeitures (in shares)		924,000
Stock Option Exercise	536	2		534		536
Stock Option Exercise (in shares)	49,166	49,000
Net Income (Loss)	-573				-2,130	-2,130	1,557
Change in Ownership of Noncontrolling Interests	136			-460		-460	596
Balance at Dec. 31, 2013	416,925	54		456,554	-41,725	414,883	2,042
Balance (in shares) at Dec. 31, 2013		54,186,000
Non-Cash Compensation	5,769			5,769		5,769
Dividends Declared on Preferred Stock ($145.00 per preferred share)	-2,335				-2,335	-2,335
Capital Distributions	-1,840						-1,840
Issuance of Restricted Stock, Net of Forfeitures (in shares)		-58,000
Stock Option Exercise	515			515		515
Stock Option Exercise (in shares)	46,526	47,000
Issuance of stock, net of issuance costs	154,989		1	154,988		154,989
Issuance of stock, net of issuance costs (in shares)			16,000
Net Income (Loss)	-42,650				-46,689	-46,689	4,039
Balance at Dec. 31, 2014	$531,373	$54	$1	$617,826	($90,749)	$527,132	$4,241
Balance (in shares) at Dec. 31, 2014		54,175,000	16,000

Consolidated_Statements_of_Cha1

Consolidated Statements of Changes in Noncontrolling Interests and Stockholders' Equity (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2014
Statement Of Stockholders Equity [Abstract]
Dividend declared, per preferred share	$145

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	($42,650)	($573)	$46,298
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss on Equity Method Investments	813	763	3,921
Non-Cash Expenses (Income)	6,789	6,230	3,191
Depreciation, Depletion, Amortization and Accretion	98,171	63,944	46,441
(Gain) Loss on Derivatives	-38,876	2,908	-10,687
Cash Settlements of Derivatives	7,281	7,128	16,219
Dry Hole Expense	4,064	2,993	656
Deferred Income Tax Expense (Benefit)	-25,992	2,279	23,665
Impairment Expense	132,684	32,072	40,355
(Gain) Loss on Sale of Assets and Equity Method Investments	589	-6,211	-100,551
Changes in operating assets and liabilities
Accounts Receivable	-13,620	-12,726	-13,698
Inventory, Prepaid Expenses and Other Assets	-1,359	-885	-92
Accounts Payable and Accrued Liabilities	37,274	12,891	-8,832
Other Assets and Liabilities	-2,462	-2,497	-1,181
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	162,706	108,316	45,705
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management	263	458	260
Contributions to Equity Method Investments		-2,493	-4,087
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	546	11,305	133,425
Acquisitions of Undeveloped Acreage	-169,423	-41,784	-51,802
Acquisitions of Oil and Gas Properties and Equipment	-391,422	-281,004	-178,538
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	-560,036	-313,518	-100,742
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds of Long-Term Debt and Lines of Credit	209,895	72,249	126,730
Repayments from Long-Term Debt and Lines of Credit	-263,152	-8,480	-351,000
Repayments of Loans and Other Notes Payable	-2,721	-2,005	-962
Proceeds from Senior Notes, Net of Discounts and Premiums	325,000	105,000	248,250
Debt Issuance Costs	-6,824	-3,134	-6,397
Settlement of Tax Withholdings Related to Share-Based Compensation Awards			-234
Proceeds from the Issuance of Common Stock, Net			70,583
Proceeds from the Issuance of Preferred Stock, Net	154,988
Proceeds from the Exercise of Stock Options	515	533	565
Purchase of Noncontrolling Interests		-150
Distributions by the Partners of Consolidated Subsidiary	-1,840	-886	-319
Dividends Paid on Preferred Stock	-2,335
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	413,526	163,127	87,216
NET INCREASE (DECREASE) IN CASH	16,196	-42,075	32,179
CASH AND CASH EQUIVALENTS – BEGINNING	1,900	43,975	11,796
CASH AND CASH EQUIVALENTS – ENDING	18,096	1,900	43,975
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO CONTINUING OPERATIONS	17,978	1,307	43,234
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO ASSETS HELD FOR SALE	118	593	741
SUPPLEMENTAL DISCLOSURES
Interest Paid, net of capitalized interest	26,874	23,605	4,551
Cash Paid (Received) for Income Taxes	-4,643	-6,390	12,824
NON-CASH ACTIVITIES
Increase in Accrued Liabilities for Capital Expenditures	$3,477	$22,138	$4,430

Basis_of_Presentation_and_Prin

Basis of Presentation and Principles of Consolidation	12 Months Ended
	Dec. 31, 2014
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Basis of Presentation and Principles of Consolidation
	1	BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION
	We are an independent oil, natural gas liquid (“NGL”) and natural gas company with operations currently focused in the Appalachian and Illinois Basins. In the Appalachian Basin, we are focused on our Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and exploration activities. In the Illinois Basin, we are focused on our developmental oil drilling and the implementation of enhanced oil recovery on our properties. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties.
	The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of all of our wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries together. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies.
	Discontinued Operations
	Unless otherwise noted, all disclosures and tables reflect the results of continuing operations and exclude any assets, liabilities or results from our discontinued operations. For additional information see Note 5, Discontinued Operations/Assets Held for Sale, to our Consolidated Financial Statements.
	During December 2011, our board of directors approved a formal plan to sell our DJ Basin assets located in the states of Wyoming and Colorado. Pursuant to the rules for discontinued operations, the results of operations are reflected as Discontinued Operations in our Consolidated Statements of Operations as of December 31, 2013 and 2012.
	During December 2014, our board of directors approved and committed to a plan to sell Water Solutions Holdings, LLC and its related subsidiaries (“Water Solutions”), of which we own a 60% interest. As a result, the assets and liabilities of Water Solutions have been classified as held for sale in the accompanying Consolidated Balance Sheets as of December 31, 2014 and 2013 and the results of operations have been classified as discontinued operations in the accompanying Consolidated Statements of Operations as of December 31, 2014, 2013 and 2012. We have not yet adopted ASU 2014-08 and are, therefore, following previous guidance set forth for presentation and disclosure. For additional information regarding ASU 2014-08, see Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements.

Summary_Of_Significant_Account

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	2	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.
	Significant estimates made in preparing these Consolidated Financial Statements include, among other things, estimates of the proved oil, NGL and natural gas reserve volumes used in calculating Depletion, Depreciation and Amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment; fair values of financial derivative instruments; volumes and prices for revenues accrued; estimates of the fair value of equity-based compensation awards; deferred tax valuation allowance and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods. The significant estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates and our ability to generate future income.
	Cash and Cash Equivalents
	We consider all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents. As of December 31, 2014 and 2013, our Cash and Cash Equivalents consisted of only cash.
	Accounts Receivable
	Our trade accounts receivable, which are primarily from oil, NGLs and natural gas sales and joint interest billings, are recorded at the invoiced amount and include production receivables. The production receivable is valued at the invoiced amount and does not bear interest. Accounts receivable also include joint interest billing receivables which represent billings to the non-operators associated with the drilling and operation of wells and are based on those owners’ working interests in the wells. We have assessed the financial strength of our customers and joint owners and record an allowance for bad debts as necessary. Our allowance for bad debts as of December 31, 2014 and 2013, was negligible.
	To the extent actual quantities and values of oil, NGLs and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Accounts Receivable in the accompanying Consolidated Balance Sheets.
	At December 31, 2014, we carried approximately $25.2 million in production receivable, of which approximately $21.4 million were production receivables due from four purchasers. At December 31, 2013, we carried approximately $26.3 million in production receivables, of which approximately $22.7 million were production receivables due from four purchasers. In addition, we carried approximately $6.7 million in receivables from Sumitomo Corporation at December 31, 2014 and $4.4 million at December 31, 2013 that was in relation to our joint operations.
	Inventory
	Inventory is valued at the lower of cost or market value and consists of our ownership interest in oil and NGLs held in terminal tanks located in the field. Oil and NGL cost basis is calculated using the average cost method, with average cost defined as production and lease operating expenses net of DD&A. General and Administrative expenses are not allocated to the cost of inventory for the purpose of valuing inventory.
	Oil, NGL and Natural Gas Property, Depreciation and Depletion
	We account for oil, NGL and natural gas exploration and production activities under the successful efforts method of accounting. Proved developed natural gas and oil property acquisition costs are capitalized when incurred, including our estimate of the fair value of future abandonment costs. Unproved properties with individually significant acquisition costs are assessed periodically on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop estimated proved reserves, including the costs of all development well and related equipment used in the production of oil, NGLs and natural gas, are capitalized. We capitalize interest on capital projects, most notably during the drilling and completion of oil and natural gas wells. For the years ended December 31, 2014, 2013 and 2012, we capitalized interest costs of $7.3 million, $7.5 million and $3.0 million, respectively.
	Depletion is calculated using the unit-of-production method. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. We periodically review estimated proved reserve estimates and make changes as needed to depletion expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in our estimated proved reserves. The costs of unproved properties are withheld from the depletion base until such time as they are proved. When estimated proved reserves are assigned, the cost of the property is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is allocated to the associated producing properties as the undeveloped acreage is developed. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of three to 40 years.
	We review assets for impairment when events or circumstances indicate a possible decline in the recoverability of the carrying value of such property. When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future oil, NGL and natural gas prices, operating costs, anticipated production from estimated proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Our estimates of future oil, NGL and natural gas prices are based on forward strip prices for NYMEX oil and Henry Hub natural gas. For unproved oil and gas properties, we analyze activity on the acreage prior to evaluating any fair value indicators, such as current drilling activity, drilling success, future development plans and the likelihood of expiration. Unproved oil and gas properties are impaired when it becomes more likely than not that a property will expire before it can be developed or an extension can be agreed upon. When evaluating the value of our unproved oil, NGL and natural gas properties, we analyze the level and success of current development, future development plans and changes in market value. Performing the impairment evaluations requires use of judgments and estimates since the results are dependent on future events, including estimates of future proved and unproved reserves, future commodity prices, the timing of future production, capital expenditures and the intent to develop properties, among others.
	We recognized approximately $132.6 million, $32.1 million and $20.6 million of impairment from continuing operations on certain oil, NGL and natural gas properties for the years ending December 31, 2014, 2013 and 2012, respectively. We recorded these charges as Impairment Expense on our Consolidated Statements of Operations. For additional information, see Note 18, Impairment Expense, to our Consolidated Financial Statements.
	Expenditures for repairs and maintenance to sustain production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense.
	Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reservoirs are capitalized.
	Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated DD&A are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.
	Natural Gas and Oil Reserve Quantities
	Our estimate of proved reserves is based on the quantities of oil, NGLs and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. For the years ended December 31, 2014 and 2013, Netherland Sewell and Associates, Inc. (“NSAI”) prepared a consolidated reserve and economic evaluation of our proved oil and gas reserves. The preparation of our proved reserve estimates are completed in accordance with our internal control procedures, which include the verification of input data used by NSAI, as well as management review and approval.
	Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Estimates of our crude oil, NGL and natural gas reserves, and the projected cash flows derived from these reserve estimates, are prepared by our engineers in accordance with guidelines established by the SEC. The independent reserve engineer estimates reserves annually on December 31. This annual estimate results in a new depletion rate, which we use for the preceding fourth quarter after adjusting for fourth quarter production.
	Deferred Financing Costs and Other Assets—Net
	At December 31, 2014, we had deferred financing costs and other assets consisting of $17.1 million, which is primarily made up of bond costs and loan costs that are amortized using the effective interest method and the straight line method, respectively, over their estimated lives, which is, on average, five to eight years. We amortize any costs incurred to renew or extend the terms of existing debt over the contract term or estimated useful life, as applicable. For the years ended December 31, 2014, 2013 and 2012, we recorded amortization expense from continuing operations of $1.5 million, $1.2 million and $1.0 million, respectively.
	The following is a summary of our deferred financing costs at the dates indicated:
			December 31,			December 31,
			2014			2013
			(in thousands)			(in thousands)
	Deferred Financing Costs - Gross		$	19,212		$	12,396
	Accumulated Amortization			(4,564	)		(3,030	)
	Deferred Financing Costs - Net		$	14,648		$	9,366
	Specific to our deferred financing costs, we have incurred gross debt issuance costs of approximately $6.8 million and $3.1 million for the years ended December 31, 2014 and 2013, respectively, which are presented net of accumulated amortization of $4.6 million and $3.0 million, respectively, and include deferred financing from our senior notes.
	Future Abandonment Cost
	Future abandonment costs are recognized as obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost.
	Accretion expense from continuing operations during the years ended December 31, 2014, 2013 and 2012 totaled approximately $3.6 million, $3.0 million and $2.1 million, respectively. These amounts are recorded as DD&A on our Consolidated Statements of Operations. As of December 31, 2014 and 2013, approximately $2.0 million and $2.5 million, respectively, of our Future Abandonment Costs were classified as short-term liabilities under the caption Accrued Expenses on our Consolidated Balance Sheets. During 2014 and 2013, we recognized an increase of $8.4 million and $1.3 million, respectively, in the estimated present value of our asset retirement obligations, representing an increase in the estimate to plug and abandon our oil and natural gas wells. The revised estimates were primarily the result of increased abandonment cost estimates, which were driven by the trends of actual outcomes. We account for asset retirement obligations that relate to wells that are drilled jointly based on our interest in those wells.
			December 31,			December 31,
			2014			2013
			(in thousands)			(in thousands)
	Beginning Balance		$	28,525		$	24,822
	Asset Retirement Obligation Incurred			1,480			1,750
	Asset Retirement Obligation Settled			(1,943	)		(2,452	)
	Asset Retirement Obligation Cancelled or Sold Properties			(10	)		—
	Asset Retirement Obligation Revision of Estimated Obligation			8,426			1,311
	Asset Retirement Obligation Accretion Expense			3,621			3,094
	Total Future Abandonment Costs		$	40,099		$	28,525
	Revenue Recognition
	Oil, NGL and natural gas revenue is recognized when the oil, NGL or natural gas is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil and NGL sales, title is transferred to the purchaser when the oil or NGLs leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. It is the measurement of the purchaser that determines the amount of oil, NGL or natural gas purchased. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for oil, NGLs and natural gas purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our oil, NGL and natural gas production is at its applicable field gathering system. We do not recognize revenue for oil and NGL production held in stock tanks before delivery to the purchaser.
	To the extent actual quantities and values of oil, NGLs and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Oil, Natural Gas and NGL Sales on the Statements of Operations.
	For Water Solutions, our services are generally sold based upon purchase orders, contracts or other agreements with customers that include fixed or determinable prices. We recognize revenue when services are performed and collection of the relevant receivables is probable. We contract for services either on a day rate or other contracted rate. In certain situations, revenue is generated from transactions that may include multiple products and services under one contract or agreement and which may be delivered to the customer over an extended period of time. Revenue from these arrangements is recognized in accordance with the above criteria and as each item or service is delivered.
	Derivative Instruments
	We use put and call options (collars), fixed rate swap contracts, swaptions, puts, deferred put spreads, cap swaps, call protected swaps, basis swaps and three-way collars to manage price risks in connection with the sale of oil, natural gas and NGLs. We have also used interest rate swap agreements to manage interest rate exposure associated with our fixed rate senior notes. We have established the fair value of all derivative instruments using estimates determined by our counterparties and other third-parties. These values are based upon, among other things, future prices, volatility, time to maturity and credit risk. The values we report in our Consolidated Financial Statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.
	We report our derivative instruments at fair value and include them in the Consolidated Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated for hedge accounting, for financial accounting purposes, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness are recognized immediately in earnings. During 2014, 2013 and 2012 we did not have any derivative instruments designated for hedge accounting.
	For derivative instruments designated as fair value hedges, changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Derivative effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. For derivatives on oil, natural gas and NGL production activity, our evaluations are not documented, and as a result, we record changes on the derivative valuations through earnings. For additional information on our derivative instruments, see Note 12, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements.
	Contingent Liabilities
	A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information.
	Income Taxes
	We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed several months after the close of a calendar year, tax returns are subject to audit which can take years to complete, and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards and other deductible differences and deferred tax liabilities that relate to oil and gas properties and other taxable differences.
	Deferred tax assets and liabilities are computed based on the difference between the financial statement and income tax bases of assets and liabilities using the enacted tax rate. Net deferred tax assets are required to be reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the net deferred tax asset will not be realized.
	This process requires our management to make assessments regarding the timing and probability of the ultimate tax impact. We record valuation allowances on deferred tax assets if we determine it is more likely than not that the asset will not be realized. Actual income taxes could vary from these estimates due to future changes in income tax law, significant changes in the jurisdictions in which we operate, our inability to generate sufficient future taxable income, or unpredicted results from the final determination of each year’s liability by taxing authorities. These changes could have a significant impact on our financial position.
	The accounting estimate related to the tax valuation allowance requires us to make assumptions regarding the timing of future events, including the probability of expected future taxable income and available tax planning opportunities. These assumptions require significant judgment because actual performance has fluctuated in the past and may do so in the future. The impact that changes in actual performance versus these estimates could have on the realization of tax benefits as reported in our results of operations could be material. We continuously evaluate facts and circumstances representing positive and negative evidence in the determination of our ability to realize the deferred tax assets.
	We recognize a tax position if it is more likely than not that it will be sustained upon examination. If we determine it is more likely than not a tax position will be sustained based on its technical merits, we record the impact of the position in our Consolidated Financial Statements at the largest amount that is greater than fifty percent likely of being realized upon ultimate settlement. These estimates are updated at each reporting date based on the facts, circumstances and information available. We are also required to assess at each reporting date whether it is reasonably possible that any significant increases or decreases to the unrecognized tax benefits will occur during the next twelve months (for additional information, see Note 13, Income Taxes, to our Consolidated Financial Statements). Our policy is to recognize interest and penalties on any unrecognized tax benefits in interest expense and general and administrative expense, respectively.
	Stock-based Compensation
	We recognize in the Consolidated Financial Statements the cost of employee and non-employee director services received in exchange for awards of equity instruments based on the grant date fair value of those awards. We use a standard option pricing model (i.e. Black-Scholes) to measure the fair value of employee stock options and stock appreciation rights and a Monte Carlo simulation technique to value restricted stock awards that are tied to market performance. The fair value of non-market based restricted stock awards is determined based on the fair market value of our common stock on the date of the grant.
The benefits associated with the tax deductions in excess of recognized compensation cost are reported as a financing cash flow when realized. We recognize compensation costs related to awards with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award were, in-substance, multiple awards (for additional information, see Note 17, Employee Benefit and Equity Plans, to our Consolidated Financial Statements). Stock appreciation rights are classified as a liability and are re-measured at fair value each reporting period.
Earnings per Common Share
Earnings per common share are computed by dividing consolidated net income attributable to us by the weighted average number of common shares outstanding. Diluted earnings per common share are computed based upon the weighted average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities, including the assumed conversion of preferred stock. At December 31, 2014, we had 54,174,763 common shares outstanding, 402,561 options outstanding and 20,500 stock appreciation rights outstanding with no outstanding warrants or other potentially dilutive securities. The total common shares outstanding include 1,519,301 restricted stock awards, of which approximately 848,447 shares are performance-based awards. For additional information, see Note 14, Earnings per Common Share, to our Consolidated Financial Statements.
Recent 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.

Business_Segment_Information

Business Segment Information	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Business Segment Information	3	BUSINESS SEGMENT INFORMATION
	We have historically divided our operations into two principal business segments, exploration and production and field services. During the fourth quarter of 2014, our board of directors approved and committed to a plan to sell Water Solutions, which accounted for the majority of our field services segment. As a result, the assets and liabilities of Water Solutions have been classified as held for sale in the Consolidated Balance Sheets as of December 31, 2014 and 2013 and the results of operations have been classified as discontinued operations in the Consolidated Statements of Operations as of December 31, 2014, 2013 and 2012. For additional information on Water Solutions, see Note 5, Discontinued Operations/Assets Held for Sale, to our Consolidated Financial Statements.

Business_and_Oil_and_Gas_Prope

Business and Oil and Gas Property Acquisitions and Dispositions	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Business and Oil and Gas Property Acquisitions and Dispositions	4	BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS AND DISPOSITIONS
	Acquisitions
	On September 9, 2014, we completed the acquisition of approximately 208,000 gross (207,000 net) acres prospective for the Marcellus, Upper Devonian/Burkett and Utica Shales from SWEPI, LP, an affiliate of Royal Dutch Shell, plc (“Shell”), for approximately $120.6 million in cash, after customary closing adjustments. Included in the acquisition were several producing wells and properties in various stages of development. The assets acquired are located in Armstrong, Beaver, Butler, Lawrence, Mercer and Venango counties in Pennsylvania and Columbiana and Mahoning counties in Ohio. The acquisition does not meet the definition of a business combination and, therefore, has been accounted for as an asset acquisition. The acquisition price was allocated as follows:
	($ in Thousands)		December 31,
			2014
	Evaluated Oil and Gas Properties		$	6,968
	Unevaluated Oil and Gas Properties			88,351
	Wells and Facilities in Progress			25,244
	Purchase Price		$	120,563
	Dispositions
	Keystone Midstream Services, LLC
	On May 29, 2012, we closed the sale of our ownership in Keystone Midstream Services, LLC (“Keystone Midstream”), which we had accounted for as an equity method investment. The base consideration for the sale was $483.2 million after adjustments for closing cash, working capital and outstanding debt. Our net proceeds at closing totaled $121.4 million, net of $3.3 million for our share of transactional costs which we recorded as Gain (Loss) on Equity Method Investments on our Consolidated Statement of Operations. During the third quarter of 2012, we recorded $0.5 million of post-closing settlement charges, effectively decreasing our net proceeds to approximately $120.9 million. We have used the proceeds to pay down amounts outstanding under our Senior Credit Facility and for working capital. The amount received at closing excluded approximately $14.3 million held in escrow to be paid out over the course of the 12 months following closing. During 2012, we received approximately $7.2 million of the outstanding escrow amount and during 2013 we received final distributions from the escrow of approximately $6.9 million, with the remaining amounts funding claims made by the purchaser. Also included in the proceeds at closing was approximately $3.8 million funded by other sellers in the transaction as consideration for our entry into an amendment to one of our gas gathering, compression and processing agreements. This consideration is recorded as Other Deposits and Liabilities on our Consolidated Balance Sheet and will be recognized in earnings over the term of the gas gathering, compression and processing agreement. We recognized a gain on the sale of our investment of Keystone Midstream, including the post-closing adjustment of $0.5 million and the receipt of the escrow funds of $7.2 million, of $99.4 million, in 2012 and a gain of approximately $6.9 million in 2013, all of which were recorded as Other Income (Expense) in our Consolidated Statement of Operations. See Note 7, Equity Method Investments, to our Consolidated Financial Statements for additional information on Keystone Midstream.
	DJ Basin Assets
	See Note 5, Discontinued Operations/Assets Held For Sale, to our Consolidated Financial Statements.

Discontinued_OperationsAssets_

Discontinued Operations/Assets Held For Sale	12 Months Ended
	Dec. 31, 2014
Discontinued Operations And Disposal Groups [Abstract]
Discontinued Operations/Assets Held For Sale	5	DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE
	DJ Basin
	During December 2011, our board of directors approved a formal plan to sell our DJ Basin assets located in the states of Wyoming and Colorado. During 2012, we sold various parcels of acreage throughout our DJ Basin 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 $1.0 million. As of December 31, 2014, we had no assets or liabilities related to the DJ Basin or continuing cash flows from this region.
	Summarized financial information for Discontinued Operations related to our DJ Basin assets is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support.
			December 31,
	($ in Thousands)		2014			2013			2012
	Revenues:
	Oil, Natural Gas and NGL Sales		$	—		$	25		$	97
	Total Operating Revenue			—			25			97
	Costs and Expenses:
	Production and Lease Operating Expense			—			104			353
	General and Administrative Expense			—			23			660
	Exploration Expense			—			97			867
	Impairment Expense			—			—			19,770
	Other Operating Expense (Income)			—			(3	)		8
	Gain on Disposal of Asset			—			(969	)		(2,126	)
	Other Income			—			—			(3	)
	Total Costs and Expenses (Income)			—			(748	)		19,529
	Income (Loss) from Discontinued Operations Before Income Taxes			—			773			(19,432	)
	Income Tax (Expense) Benefit			—			(1,005	)		8,489
	Income (Loss) from Discontinued Operations, net of taxes		$	—		$	(232	)	$	(10,943	)
	Production:
	Crude Oil (Bbls)			—			356			1,272
	Water Solutions Holdings, LLC
	In December 2014, our board of directors approved a formal plan to sell Water Solutions, of which we own a 60% interest. The sale of Water Solutions is being actively marketed and we believe the sale will take place within the next 12 months. Water Solutions operates and manages water sourcing, water transfer, equipment rental, trucking and water disposal services, primarily in the Appalachia Basin.
	The carrying value of the assets and liabilities of Water Solutions Holdings, LLC that are classified as held for sale in the accompanying Consolidated Balance Sheets at December 31, 2014 and December 31, 2013 are as follows:
			December 31,
	($ in Thousands)		2014			2013
	Assets:
	Cash and Cash Equivalents		$	118		$	593
	Accounts Receivable			13,226			6,579
	Inventory, Prepaid Expenses and Other			163			89
	Total Current Assets			13,507			7,261
	Other Property and Equipment, Net			19,690			9,845
	Wells and Facilities in Progress			688			1,031
	Intangible Assets, Net			372			206
	Total Long-Term Assets			20,750			11,082
	Total Assets Held for Sale		$	34,257		$	18,343
	Liabilities:
	Accounts Payable			3,694			758
	Current Maturities of Long-Term Debt			6,236			5,403
	Accrued Liabilities			6,304			6,246
	Total Current Liabilities			16,234			12,407
	Senior Secured Line of Credit and Long-Term Debt			8,881			3,054
	Long-Term Liabilities			8,881			3,054
	Total Liabilities Related to Assets Held for Sale		$	25,115		$	15,461
	Net Assets Held for Sale:		$	9,142		$	2,882
	Summarized financial information for Discontinued Operations related to Water Solutions is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support.
			December 31,
	($ in Thousands)		2014			2013			2012
	Revenues:
	Field Services Revenue		$	58,627		$	23,812		$	13,403
	Other Revenue (Expense)			—			—			(56	)
	Total Operating Revenue			58,627			23,812			13,347
	Costs and Expenses:
	General and Administrative Expense			4,081			2,287			887
	Depreciation, Depletion, Amortization and Accretion			3,703			1,559			482
	Impairment Expense			67			—			14
	Field Service Operating Expense			44,369			17,318			8,240
	(Gain) Loss on Disposal of Asset			(55	)		46			8
	Interest Expense			628			106			26
	Other Expense			66			84			103
	Total Costs and Expenses			52,859			21,400			9,760
	Income from Discontinued Operations Before Income Taxes			5,768			2,412			3,587
Income Tax Expense			(768	)		(369	)		(1,267	)
Income from Discontinued Operations, net of taxes		$	5,000		$	2,043		$	2,320
During 2014, Water Solutions spent approximately $11.7 million in capital expenditures on facilities and equipment to support its business growth. In addition to its cash capital expenditures, Water Solutions incurred approximately $1.6 million in non-cash vehicle acquisitions primarily related to its capital lease program.

Consolidated_Subsidiaries

Consolidated Subsidiaries	12 Months Ended
	Dec. 31, 2014
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Consolidated Subsidiaries	6	CONSOLIDATED SUBSIDIARIES
	Water Solutions
	As of December 31, 2014, Water Solutions were classified as Discontinued Operations. For more information on our Discontinued Operations, see Note 5, Discontinued Operations/Assets Held for Sale, of our Consolidated Financial Statements.

Equity_Method_Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2014
Equity Method Investments And Joint Ventures [Abstract]
Equity Method Investments	7	EQUITY METHOD INVESTMENTS
	RW Gathering
	RW Gathering, LLC (“RW Gathering”) is a Delaware limited liability company that we jointly own with WPX Energy Inc. (“WPX”) and Sumitomo, with our ownership equaling 40%. RW Gathering owns gas-gathering and other midstream assets that service jointly owned properties in Westmoreland and Clearfield Counties, Pennsylvania.
	We recorded our investment in RW Gathering of approximately $17.9 million and $18.7 million as of December 31, 2014 and 2013, respectively, on our Consolidated Balance Sheets as Equity Method Investments. During 2014, we contributed no cash to RW Gathering, compared to approximately $2.5 million to support current pipeline and gathering line construction during the same period in 2013. RW Gathering recorded net losses from continuing operations of $2.0 million, $1.9 million and $1.7 million for the years ended December 31, 2014, 2013 and 2012, respectively. The losses incurred were due to insurance fees, bank fees, rent expenses and DD&A expense. Our share of the net loss from continuing operations incurred by RW Gathering is recorded on the Statements of Operations as Loss on Equity Method Investments.
	When evaluating our Equity Method Investments for impairment we review our ability to recover the carrying amount of such investments or the entity’s ability to sustain earnings that justify its carrying amount. In the case of RW Gathering, the nature of its assets is such that under normal circumstances an entity would capitalize and evaluate the assets as a part of its producing well properties. Therefore, our ability to recover the carrying amount of our investment lies in the value of our producing well assets that utilize these gathering systems. As of December 31, 2014, we determined that we had the ability to recover the carrying amount of our investment in RW Gathering.

Concentrations_of_Credit_Risk

Concentrations of Credit Risk	12 Months Ended
	Dec. 31, 2014
Risks And Uncertainties [Abstract]
Concentrations of Credit Risk	8	CONCENTRATIONS OF CREDIT RISK
	At times during the years ended December 31, 2014 and 2013, our cash balance may have exceeded the Federal Deposit Insurance Corporation’s limit of $250,000. There were no losses incurred due to such concentrations.
	By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with five high-quality counterparties. Our counterparties are investment grade financial institutions, and lenders in our Senior Credit Facility. We have a master netting agreement in place with our counterparties that provides for the offsetting of payables against receivables from separate derivative contracts. None of our derivative contracts have a collateral provision that would require funding prior to the scheduled settlement date. For additional information, see Note 2, Summary of Significant Accounting Policies, and Note 12, Fair Value of Financial Instruments 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. At December 31, 2014, we carried approximately $25.2 million in production receivables, of which approximately $21.4 million were production receivables due from four purchasers. At December 31, 2013, we carried approximately $26.3 million in production receivables, of which approximately $22.7 million were production receivables due from four purchasers. We believe the growth in our Appalachian estimated proved reserves will help us to minimize our future risks by diversifying our ratio of oil and gas sales as well as the quantity of purchasers.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	9	COMMITMENTS AND CONTINGENCIES
	Legal Reserves
	We are involved in various legal proceedings that arise in the ordinary course of our business. Although we cannot predict the outcome of these proceedings with certainty, we do not currently expect these matters to have a material adverse effect on our consolidated financial position or results of operations.
	As of December 31, 2014 and 2013, we did not have any reserves established for future legal obligations. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and the subjective judgment of management. While we currently believe that no reserve is needed, there are uncertainties associated with legal proceedings and we can give no assurance that our estimate of any related liability will not increase or decrease in the future. The unreserved exposures for our legal proceedings could change based upon developments in those proceedings or changes in the facts and circumstances. It is possible that we could incur future losses that are not currently accrued. Based on currently available information, we believe that it is remote that future costs, if any, would have a material adverse effect on our consolidated financial position, although cash flow could be significantly impacted in the reporting periods in which such costs might be incurred.
	Environmental
	Due to the nature of the natural gas and oil business, we are exposed to possible environmental risks. We have implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. We conduct periodic reviews to identify changes our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate salaries and wages cost of employees who are expected to devote a significant amount of time directly to any remediation effort.
	We manage our exposure to environmental liabilities on properties to be acquired by conducting evaluations (both internal and using consultants) to identify existing problems and assessing the potential liability. Except for contingent liabilities associated with the consent decree with the U.S. EPA relating to alleged H 2S emissions in the Lawrence Field, we know of no significant probable or possible environmental contingent liabilities.
	Letters of Credit
	As of December 31, 2014 and 2013, we had posted $6.0 million and $1.4 million, respectively, in various letters of credit to secure our drilling and related operations.
	Lease Commitments
	At December 31, 2014 we have lease commitments for various real estate leases. Rent expense from continuing operations has been recorded in General and Administrative expense as $0.8 million, $0.6 million and $0.3 million for the years ended December 31, 2014, 2013 and 2012, respectively. Lease commitments by year for each of the next five years are presented in the table below.
	($ in Thousands)
	2015		$	1,075
	2016			1,129
	2017			1,143
	2018			721
	2019			721
	Thereafter			180
	Total		$	4,969
	Capacity Reservation
	During the second quarter of 2012, we entered into a capacity reservation arrangement with a subsidiary of MarkWest Energy Partners, L.P. (“MarkWest”) to ensure sufficient capacity at the cryogenic gas processing plants owned by MarkWest to process our produced natural gas. In the event that we do not process any gas through the cryogenic gas processing plants, we may be obligated to pay approximately $15.0 million in 2015, $25.8 million in 2016, $31.0 million in 2017, $31.0 million in 2018, $31.0 million in 2019 and $214.7 million thereafter, assuming our working interest in the region of approximately 70.0%. For the years ended December 31, 2014, 2013 and 2012, we incurred capacity reservation charges of $0.2 million, $0.3 million and $0.5 million, respectively. Charges for the capacity reservation are recorded as Production and Lease Operating Expense on our Consolidated Statements of Operations.
	Operational Commitments
	We have contracted drilling rig services on three rigs to support our Appalachian Basin operations. The minimum cost to retain these rigs would require gross payments of approximately $7.6 million in 2015 and $4.6 million in 2016. In addition, we have agreements for contracted completion services in the Appalachian Basin. The minimum gross cost to retain the completion services is approximately $11.0 million in 2015.
	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 $416.1 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 years ended December 31, 2014, 2013 and 2012, we incurred expenses related to the transportation, processing and marketing our oil, natural gas and natural gas liquids of approximately $55.4 million, $26.4 million and $14.1 million, respectively.
	Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows:
	($ in Thousands)		Total
	2015		$	21,951
	2016			34,199
	2017			52,296
	2018			55,113
	2019			53,963
	Thereafter			692,320
	Total		$	909,842
	Pennsylvania Impact Fee
	In 2012, Pennsylvania instituted a natural gas impact fee on producers of unconventional natural gas. The fee will be imposed on every producer of unconventional natural gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. Unconventional gas wells that were spud prior to 2012 are considered to be spud in 2011 for purposes of determining the fee, which is considered year one for those wells. The fee for each unconventional natural gas well is determined using the following matrix, with vertical unconventional natural gas wells being charged 20% 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 fees is based on the arithmetic mean of the NYMEX settled price for the near-month contract as reported by the Wall Street Journal for the last trading day of each month of a calendar year for the year ending December 31.
	For the years ended December 31, 2014 and 2013, we incurred approximately $4.1 million and $3.2 million, respectively, in fees related to the natural gas impact fee. For the year ended December 31, 2012, we incurred approximately $5.4 million in fees related to the natural gas impact fee, of which approximately $2.8 million was related to the first year fees for unconventional gas wells drilled prior to 2012. We have recorded these fees as Production and Lease Operating Expense on our Consolidated Statement of Operations.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions	10	RELATED PARTY TRANSACTIONS
	Aircraft Services
	We have an oral month-to-month agreement with Charlie Brown Air Corp. (“Charlie Brown”), a New York corporation owned by Lance T. Shaner, our Chairman, regarding the use of two airplanes owned or managed on our behalf by Charlie Brown. Under our agreement with Charlie Brown, we pay a monthly fee for the right to use the airplanes equal to our percentage (based upon the total number of hours of use of the airplanes by us) of the monthly fixed costs for the airplanes, plus a variable per hour flight rate that ranges from $400 to $800 per hour. In September 2010, we purchased an undivided 50% interest in one of these airplanes, a Cessna model 550, from Charlie Brown for approximately $0.6 million. In April 2011, we purchased the remaining 50% interest in this aircraft for approximately $0.6 million. The purchase of the aircraft has been recorded as Other Property and Equipment on our Consolidated Balance Sheets. For the year ended December 31, 2014, we paid Charlie Brown $0.1 million for the use of the aircrafts, including the variable per hour cost in addition to pilot fees, maintenance, hangar rental and other miscellaneous expenses. For the years ended December 31, 2013 and 2012, the amounts paid to Charlie Brown were negligible.
	We own a 25% membership interest in Charlie Brown Air II, LLC (“Charlie Brown II”). Shaner Hotel Group Limited Partnership, a Delaware limited partnership controlled by Mr. Lance T. Shaner (“Shaner Hotel”), and an unrelated third party each own 25% and 50%, respectively, in Charlie Brown II, which owns and operates an Eclipse 500 aircraft.
	Charlie Brown II has a loan from Graystone Bank to purchase the aircraft that was originally $1.5 million at its inception in June 2007. The loan matures on June 21, 2017 and bears interest at a rate of LIBOR plus 2.5%. The loan required payments of interest only for the first three months of the loan. Thereafter, Charlie Brown II has been required to make monthly payments of principal and interest utilizing an amortization period of 180 months. The company and Shaner Hotel each guarantee up to twenty five percent, or $0.4 million, of the principal balance of the loan. The balance of this loan as of December 31, 2014 and 2013 was approximately $1.1 million and $1.2 million, respectively. For the years ended December 31, 2014, 2013 and 2012, we paid Charlie Brown II approximately $0.2 million each year, respectively, for loan interest, services rendered and retainer fees.
	The business affairs of Charlie Brown Air II, LLC are managed by three members, appointed by each of its three owners. We have designated Thomas C. Stabley, our Chief Executive Officer, as the manager representing our membership interest. Actions of the company must be approved by a majority of the interest percentages of the managers. Each manager votes in matters before the company in accordance with the membership interest percentage of the member that appointed the manager. Certain events, such as the sale by a member of its interest, the merger or consolidation of the company, the filing of bankruptcy, or the sale of the airplane owned by Charlie Brown Air II, LLC, require the written consent of all managers. The consent of managers is also required before the company may change or terminate the management agreement with Charlie Brown, incur any indebtedness, sell substantially all of the company’s assets or sell the airplane owned by the company. In the event that the members are unable to unanimously agree upon any of these matters within 10 days of the proposal of any such matter, an “impasse” may be declared, and the airplane will be sold by the company.
	As of December 31, 2014, there were negligible amounts due to or from us to any Shaner affiliated entities.
	Office Rental
	On June 27, 2012, we entered into an office lease agreement with Shaner Office Holdings, L.P., a limited partnership controlled by Lance T. Shaner. The office lease, which replaced our former headquarters office lease in State College, Pennsylvania, calls for monthly rental payments in the amount of $35,000 which began on April 1, 2013 and ends on December 31, 2017, with an annual Consumer Price Index (“CPI”) adjustment. The annual CPI adjustment is capped at 2.5%. The term of the lease may be extended for up to three five-year extensions or the property may be purchased outright by our exercise of a purchase option at the end of the initial five-year lease term. For the year 2014, we paid Shaner Office Holdings, L.P. approximately $0.5 million in office rental payments and utilities. We account for this lease as an operating lease, subsequently recording the rental payments as General and Administrative Expense on our Consolidated Statements of Operations. During the third quarter of 2013, we purchased a parcel of land adjacent to our headquarters office location from Shaner Office Holdings, L.P. for approximately $0.6 million.
	RW Gathering, LLC
	We own a 40% interest in RW Gathering which owns gas-gathering assets to facilitate the development of our joint operations with WPX and Sumitomo (see Note 7, Equity Method Investments, to our Consolidated Financial Statements). We incurred approximately $0.7 million, $0.8 million and $0.8 million for the years ended December 31, 2014, 2013 and 2012, respectively, in compression expenses that were charged to us from Williams Appalachia, LLC. These costs are in relation to compression costs incurred by RW Gathering and are recorded as Production and Lease Operating Expense on our Consolidated Statement of Operations. As of December 31, 2014, 2014 and 2013, there were no receivables or payables in relation to RW Gathering due to or from us.
	Keystone Midstream
	We incurred approximately $2.4 million in transportation and processing expenses that were charged to us from Keystone Midstream during 2012, which were recorded as Production and Lease Operating Expense on our Consolidated Statements of Operations (see Note 7, Equity Method Investments, to our Consolidated Financial Statements). We sold our ownership interest in Keystone Midstream during the second quarter of 2012.
	Water Solutions
	We incurred approximately $20.1 million, $10.7 million and $3.2 million in gross water transfer and equipment rental expenses that were charged to us from Water Solutions during 2014, 2013 and 2012, respectively. Of the amounts incurred, we have eliminated approximately $16.2 million, $8.8 million and $2.2 million in consolidation for the years 2014, 2013 and 2012, respectively. As of December 31, 2014 and 2013, we had payables of approximately $1.3 million and $1.5 million, respectively, due to Water Solutions for work performed during the periods. As of December 31, 2014, we have classified the operations of Water Solutions as Discontinued Operations. See note 5, Discontinued Operations/Assets Held for Sale, of our Consolidated Financial Statements for additional information.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-Term Debt	11	LONG-TERM DEBT
	Senior Credit Facility
	We maintain a revolving credit facility evidenced by the Credit Agreement, dated March 27, 2013, with Royal Bank of Canada, as Administrative Agent and lenders from time to time parties thereto (as amended from time to time, the “Senior Credit Facility”). Borrowings under the Senior Credit Facility are limited by a borrowing base that is determined in regard to our oil and gas properties. The borrowing base under the Senior Credit Facility is currently $400.0 million; however, the revolving credit facility may be increased to up to $500.0 million upon re-determinations of the borrowing base, consent of the lenders and other conditions prescribed in the agreement. The maximum commitments of the lenders is $400.0 million. Within the Senior Credit Facility, a letter of credit subfacility exists of 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, in good faith, based on, among other things, reports regarding our oil and gas reserves attributable to our oil and gas properties, together with a projection of related production and future net income, taxes, operating expenses and capital expenditures. We may, or the Administrative Agent at the direction of a majority of the lenders may, each elect once per calendar year to cause the borrowing base to be re-determined between the scheduled re-determinations. In addition, we may request interim borrowing base re-determinations upon our proposed acquisition of proved developed producing oil and gas reserves with a purchase price for such reserves greater than 10% of the then borrowing base. Our most recent re-determination occurred during September 2014, resulting in no significant changes to the current Senior Credit Facility. As of December 31, 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 December 31, 2014, we had no balance outstanding and as of December 31, 2013 we had approximately $59.0 million outstanding on 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) Royal Bank of Canada’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.
	Under the Senior Credit Facility, we may enter into commodity swap agreements with counterparties approved by the lenders, provided that the notional volumes for such agreements, when aggregated with other commodity swap agreements then in effect (other than basis differential swaps on volumes already hedged pursuant to other swap agreements), do not exceed, as of the date the swap agreement is executed, 85% of the reasonably anticipated projected production from our proved developed producing reserves for the 36 months following the date such agreement is entered into, and 75% thereafter, for each of crude oil and natural gas, calculated separately. As of December 31, 2014, we were in compliance with these swap agreement restrictions. We may also enter into interest rate swap agreements with counterparties approved by the lenders that convert interest rates from floating to fixed provided that the notional amounts of those agreements, when aggregated with all other similar interest rate swap agreements then in effect, do not exceed the greater of $20 million or 75% of the then outstanding principal amount of our debt for borrowed money which bears interest at a floating rate.
	The Senior Credit Facility contains covenants that restrict our ability to, among other things, materially change our business; approve and distribute dividends; enter into transactions with affiliates; create or acquire additional subsidiaries; incur indebtedness; sell assets; make loans to others; make investments; enter into mergers; incur liens; and enter into agreements regarding swap and other derivative transactions (for further information, see Note 2, Summary of Significant Accounting Policies, Note 8, Concentrations of Credit Risk, and Note 12, 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 the states of 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 requires we meet, on a quarterly basis, minimum financial requirements of consolidated current ratio and net senior secured debt to EBITDAX. EBITDAX is a non-GAAP financial measure used by our management team and by other users of our financial statements, such as our commercial bank lenders, which adds to or subtracts from net income the following expenses or income for a given period to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, depletion, amortization, unrealized gains and losses from derivatives, exploration expense and other similar non-cash activity. The Senior Credit Facility requires that as of the last day of any fiscal quarter, our ratio of consolidated current assets, which includes the unused portion of our borrowing base, as of such day to consolidated current liabilities as of such day, known as our current ratio, must not be less than 1.0 to 1.0. Our current ratio as of December 31, 2014 was approximately 3.3 to 1.0. Additionally, as of the last day of any fiscal quarter, our ratio of total net senior secured debt to EBITDAX for the trailing twelve months must not exceed 1.75 to 1.0. Our ratio of total debt to EBITDAX as of December 31, 2014 was approximately 0.0 to 1.0.
	2020 Senior Notes and 2022 Senior Notes
	On December 12, 2012, we issued a $250.0 million aggregate principal amount of 8.875% senior notes in a private offering at an issue price of 99.3% due to mature on December 1, 2020 (the “2020 Senior Notes”). The net proceeds of the 2020 Senior Notes, after discounts and expenses, were approximately $242.2 million. Debt issuance costs of $6.4 million were recorded as Deferred Financing Costs and Other Assets – Net on our Consolidated Balance Sheet and are being amortized over the term of the 2020 Senior Notes as Interest Expense on our Consolidated Statements of Operations using the effective interest method. Interest is payable semi-annually at a rate of 8.875% per annum on June 1 and December 1 of each year, with the first interest payment made on June 1, 2013.
	On April 26, 2013, we issued an additional $100.0 million in aggregate principal amount of the 2020 Senior Notes in a private offering at an issue price to the initial purchasers of 105% of par plus accrued interest from December 12, 2012. Net proceeds after discounts and offering expenses were approximately $102.8 million plus accrued interest of approximately $3.3 million. Debt issuance costs of $2.3 million were recorded as Deferred Financing Costs and Other Assets – Net on our Consolidated Balance Sheet and are being amortized over the term of the 2020 Senior Notes as Interest Expense on our Consolidated Statements of Operations using the effective interest method.
	We may redeem, at specified redemption prices, some or all of the 2020 Senior Notes at any time on or after December 1, 2016. We may also redeem up to 35% of the Senior 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 in control, we may be required to offer to purchase the 2020 Senior Notes from the holders.
	On October 31, 2013, substantially all of the outstanding 2020 Senior Notes were exchanged for an equal principal amount of registered 8.875% senior notes due 2020 pursuant to an effective registration statement on Form S-4 filed on September 3, 2013 under the Securities Act (the “Exchange Notes”). The Exchange Notes are identical to the Senior Notes except that the Exchange Notes are registered under the Securities Act and do not have restrictions on transfer, registration rights or provisions for additional interest.
	On July 17, 2014, we issued a $325.0 million aggregate principal amount of 6.25% senior notes (the “2022 Senior Notes”) in a private offering at an issue price of 100.0% due to mature on August 1, 2022. The net proceeds of the 2022 Senior Notes, after discounts and expenses, were approximately $318.8 million. Debt issuance costs of $6.3 million were recorded as Deferred Financing Costs and Other Assets – Net on our Consolidated Balance Sheet and are being amortized over the term of the notes as Interest Expense on our Consolidated Statements of Operations. Interest is payable semi-annually at a rate of 6.25% per annum on February 1 and August 1 of each year, 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 27, Condensed Consolidating Financial Information, to our Consolidated Financial Statements.
	As of December 31, 2014 and 2013, we had recorded on our Consolidated Balance Sheets approximately $677.7 million and $353.1 million of Senior Notes, which is inclusive of a net premium of $2.7 million and $3.1 million, respectively. The amortization of our net premium in 2014 and 2013, which follows the effective interest method, was approximately $0.4 million and $0.2 million, respectively, and was recorded as a credit to Interest Expense on our Consolidated Statement of Operations.
	In addition to the Senior Credit Facility and the Senior Notes, we may, from time to time in the normal course of business finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and other obligations consisted of the following at December 31, 2014 and December 31, 2013:
	($ in Thousands)		December 31,			December 31,
			2014			2013
	8.875% Senior Notes Due 2020		$	350,000		$	350,000
	6.25% Senior Notes Due 2022			325,000			—
	Premium on Senior Notes, Net			2,725			3,078
	Senior Line of Credit(a)			—			59,000
	Capital Leases and Other Obligations(a)			1,427			1,477
	Total Debt			679,152			413,555
	Less Current Portion of Long-Term Debt			(1,176	)		(1,340	)
	Total Long-Term Debt		$	677,976		$	412,215
	(a)	The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2014 and 2013 was approximately 2.2 % and 1.9%, respectively. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2014 and 2013 was approximately 4.0% and 5.3%, respectively.
	The following is the principal maturity schedule for total debt outstanding as of December 31, 2014:
	($ in thousands)		Year Ended
			December 31,
	2015		$	1,176
	2016			251
	2017			—
	2018			—
	2019			—
	Thereafter			675,000
	Total1		$	676,427
	1	Does not include $2.7 million net premium on Senior Notes.

Fair_Value_Of_Financial_Instru

Fair Value Of Financial Instruments And Derivative Instruments	12 Months Ended
	Dec. 31, 2014
Fair Value Of Financial Instruments And Derivative Instruments [Abstract]
Fair Value Of Financial Instruments And Derivative Instruments	12	FAIR VALUE OF FINANCIAL INSTRUMENTS AND DERIVATIVE INSTRUMENTS
	Natural Gas, Oil and NGL Derivatives
	We enter derivative financial instruments with the primary objective of managing our exposure to commodity price fluctuations and providing more predictable cash flows. Our results of operations and operating cash flows are impacted by changes in market prices for oil, natural gas and NGLs. To mitigate a portion of the exposure to adverse market changes, we enter into oil, natural gas and NGL commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels that are less than our average price floor, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling, we make payments to our counterparties. We do not enter into these arrangements for speculative trading purposes. As of December 31, 2014, 2013 and 2012, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, swaptions, deferred put spreads, cap swaps, call protected swaps, basis swaps and three-way collars. We did not designate these instruments as cash flow hedges for accounting purposes. Accordingly, associated unrealized gains and losses are recorded directly as Gain (Loss) on Derivatives, Net. For additional information, see Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements.
	Swap contracts provide a fixed price for a notional amount of sales volumes. Collars contain a fixed floor price (“put”) and ceiling price (“call”). The put options are purchased from the counterparty by our payment of a cash premium. If the put strike price is greater than the market price for a settlement period, then the counterparty pays us an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty, for which we receive a cash premium. If the market price is greater than the call strike price for a settlement period, then we pay the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price. A three-way collar is a combination of options, a sold call, a purchased put and a sold put. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the settlement price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price we will receive for the volumes under contract. Deferred put spread contracts are similar to three-way collars except that there is no maximum price ceiling established.
	Swaption agreements provide options to counterparties to extend swaps into subsequent years. Similar to a deferred put spread and a three-way collar, a cap swap provides a sold put in combination with a swap. Should prices fall below the sold put, we would receive the settlement price plus the differential between the sold put and the swap. Basis swaps are arrangements that guarantee a price differential from a specified delivery point. Currently, our basis swaps provide basis protection between Henry Hub and Dominion Appalachia pricing.
	We enter into the majority of our derivative arrangements with five counterparties and have a netting agreement in place with these counterparties, however the fair value of our derivative contracts are reported on a gross basis. We do not obtain collateral to support the agreements, but we believe our credit risk is currently minimal on these transactions. For additional information on the credit risk regarding our counterparties, see Note 8, 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 Income (Expense). We received net cash settlements of $6.0 million, $7.1 million and $16.2 in relation to our commodity derivatives for the years ended December 31, 2014, 2013 and 2012 respectively.
	As of December 31, 2014, we had over 75.0% of our 2014 oil production volumes hedged through 2015, over 75.0% and 25.0% of our 2014 natural gas production volumes hedged through 2015 and 2016, respectively, and over 15.0% of our 2014 NGL production volumes hedged through 2015. 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 December 31, 2014, we did not have any borrowings outstanding under our Senior Credit Facility, which is subject to variable rates of interest, and had $675.0 million of Senior Notes outstanding subject to a fixed interest rate. See Note 11, 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 were party to $25.0 million notional fixed-to-variable interest rate swap to manage our interest rate exposure related to our Senior Notes. We did enter into fixed-to-variable interest rate swaps during 2014, however there were no arrangements in place as of December 31, 2014. The fair value of our interest rate swap as of December 31, 2013, was a liability of approximately $0.2 million. We utilize the mark-to-market accounting method to account for our interest rate swaps. We recognize all gains and losses related to these contract in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Income (Expense). During the year ended December 31, 2014, we received cash payments of approximately $1.3 million related to our interest rate swaps.
	The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the years ended December 31, 2014, 2013 and 2012:
			For the Year Ended December 31,
	($ in Thousands)		2014				2013				2012
	Oil		$	8,613			$	(2,798	)		$	1,579
	Natural Gas			18,406				1,807				8,162
	NGLs			10,340				(1,711	)			946
	Interest Rate			1,517				(206	)			—
	Gain (Loss) on Derivatives, Net		$	38,876			$	(2,908	)		$	10,687
	We account for our derivatives in accordance with ASC 815, which requires that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at its fair value. The fair value associated with our derivative instruments was a net asset of $31.4 million as of December 31, 2014, and a net liability of $0.2 million at December 31, 2013. Our open asset/(liability) financial commodity derivative instrument positions at December 31, 2014 consisted of the following:
	Period		Volume		Put Option				Floor				Ceiling				Swap			Long Call		Fair Market
																						Value ($ in
																						Thousands)
	Oil
	2015 - Deferred Put Spreads		180,000 Bbls		$	73.08			$	83.33			$	—			$	—		$	—	$	1,413
	2015 - Call Protected Swaps		30,000 Bbls			—				—				—				95.76			110		1,227
	2015 - Three-Way Collars		675,000 Bbls			53.44				67.89				75.67				—			—		4,596
			885,000 Bbls																			$	7,236
	Natural Gas
	2015 - Swaps		6,300,000 Mcf		$	—			$	—			$	—			$	3.96		$	—	$	4,522
	2015 - Swaptions		0 Mcf			—				—				—				—			—		(154	)
	2015 - Cap Swaps		8,400,000 Mcf			3.43				—				—				4.13			—		3,430
	2015 - Three-Way Collars		13,500,000 Mcf			3.59				4.12				4.52				—			—		5,081
	2015 - Calls		2,400,000 Mcf			—				—				4.4				—			—		(74	)
	2015 - Basis Swaps		10,380,000 Mcf			—				—				—				(0.77	)		—		2,622
	2016 - Swaps		1,500,000 Mcf			—				—				—				4.05			—		194
	2016 - Cap Swaps		3,600,000 Mcf			3.45				—				—				4.11			—		884
	2016 - Three-Way Collars		4,500,000 Mcf			3.56				4.09				4.43				—			—		1,277
	2016 - Calls		7,320,000 Mcf			—				—				4.35				—			—		(1,096	)
	2016 - Basis Swaps		7,320,000 Mcf			—				—				—				(0.83	)		—		(257	)
	2017 - Swaps		1,500,000 Mcf			—				—				—				4.05			—		194
	2017 - Cap Swaps		2,100,000 Mcf			3.34				—				—				4.07			—		412
	2017 - Three-Way Collars		1,800,000 Mcf			3.58				4.1				4.5				—			—		456
	2017 - Basis Swaps		7,300,000 Mcf			—				—				—				(0.83	)		—		(256	)
	2018 - Swaps		2,100,000 Mcf			—				—				—				4.05			—		272
	2018 - Cap Swaps		1,800,000 Mcf			3.3				—				—				4.05			—		321
	2018 - Basis Swaps		7,300,000 Mcf			—				—				—				(0.83	)		—		(256	)
	2019 - Swaps		2,100,000 Mcf			—				—				—				4.05			—		272
	2019 - Basis Swaps		7,300,000 Mcf			—				—				—				(0.83	)		—		(256	)
	2020 - Swaps		2,400,000 Mcf			—				—				—				4.05			—		311
	2020 - Basis Swaps		7,320,000 Mcf			—				—				—				(0.83	)		—		(256	)
	2021 - Swaps		2,400,000 Mcf			—				—				—				4.05			—		311
			110,640,000 Mcf																			$	17,954
	NGLs
	2015 - Propane Swaps		258,000 Bbls		$	—			$	—			$	—			$	44.52		$	—	$	5,897
	2015 - Ethane Swaps		109,500 Bbls			—				—				—				10.08			—		284
			367,500 Bbls																			$	6,181
	The combined fair value of our derivatives included in our Consolidated Balance Sheets as of December 31, 2014 and December 31, 2013 is summarized below.
			December 31,				December 31,
	($ in Thousands)		2014				2013
	Short-Term Derivative Assets:
	Crude Oil—Collars		$	—			$	380
	Crude Oil—Call Protected Swap			1,227				—
	Crude Oil—Deferred Put Spread			1,413				—
Crude Oil—Three-Way Collars			4,596				104
NGL—Swaps			6,181				83
Natural Gas—Swaps			4,522				106
Natural Gas—Cap Swaps			3,430				5
Natural Gas—Basis Swaps			2,815				3,984
Natural Gas—Three-Way Collars			5,081				518
Interest Rate—Swap			—				488
Total Short-Term Derivative Assets		$	29,265			$	5,668
Long-Term Derivative Assets:
Natural Gas—Cap Swaps		$	1,617			$	5
Natural Gas—Swaps			1,554				22
Natural Gas—Basis Swaps			—				339
Natural Gas—Three-Way Collars			1,733				169
Total Long-Term Derivative Assets		$	4,904			$	535
Total Derivative Assets		$	34,169			$	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			—				(585	)
NGL—Swaps			—				(995	)
Natural Gas—Three-Way Collars			—				(125	)
Natural Gas—Collars			—				(235	)
Natural Gas—Basis Swaps			(193	)			—
Natural Gas—Call			(74	)			(150	)
Natural Gas—Cap Swaps			—				(496	)
Natural Gas—Swaption			(154	)			(717	)
Natural Gas—Swaps			—				(1,170	)
Total Short - Term Derivative Liabilities		$	(421	)		$	(4,663	)
Long-Term Derivative Liabilities:
Natural Gas—Swaps		$	—			$	(4	)
Natural Gas—Cap Swaps			—				(307	)
Natural Gas—Basis Swaps			(1,281	)			—
Natural Gas—Call			(1,096	)			(761	)
Interest Rate—Swap			—				(693	)
Total Long-Term Derivative Liabilities		$	(2,377	)		$	(1,765	)
Total Derivative Liabilities		$	(2,798	)		$	(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—Observable inputs, such as quoted prices in active markets for identical assets or liabilities as of the reporting date.
Level 2—Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars and other like derivative contracts, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
Level 3—Unobservable inputs that are supported by little or no market activity. Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.
Our Level 2 fair value measurements are comprised of our derivative contracts, excluding our basis swap derivatives, and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, interest rates and discount rates, or can be confirmed from other active markets. The fair values recorded as of December 31, 2014 and 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 December 31, 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 December 31, 2014 are included in the table below.
		As of December 31, 2014
		Range		Weighted				Fair Value
		(price per Mcf)		Average				(in thousands)
				(price per Mcf)
Natural Gas Basis Differential Forward Curve		($0.27) - ($1.39)		$	(0.84	)		$	1,341
		As of December 31, 2013
		Range		Weighted				Fair Value
		(price per Mcf)		Average				(in thousands)
				(price per Mcf)
Natural Gas Basis Differential Forward Curve		($0.78) - ($1.08)		$	(0.91	)		$	4,323
The fair value of our derivative instruments may be different from the settlement value based on company-specific inputs, such as credit ratings, futures markets and forward curves, and readily available buyers and sellers for such assets and liabilities. During the years ended December 31, 2014 and 2013, there were no transfers into or out of Level 1 or Level 2 measurements. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value:
						Fair Value Measurements at December 31, 2014 Using:
($ in Thousands)		Total Carrying				Quoted Prices				Significant				Significant
		Value as of				in Active				Other				Unobservable
		December 31,				Markets for				Observable				Inputs
		2014				Identical Assets				Inputs				(Level 3)
						(Level 1)				(Level 2)
Commodity Derivatives		$	31,371			$	—			$	30,030			$	1,341
						Fair Value Measurements at December 31, 2013 Using:
($ in Thousands)		Total Carrying				Quoted Prices				Significant				Significant
		Value as of				in Active				Other				Unobservable
		December 31,				Markets for				Observable				Inputs
		2013				Identical Assets				Inputs				(Level 3)
						(Level 1)				(Level 2)
Commodity Derivatives		$	(20	)		$	—			$	(4,343	)		$	(4,323	)
Interest Rate Swap		$	(205	)		$	—			$	(205	)		$	—
Net derivative asset values are determined primarily by quoted futures and options prices and utilization of the counterparties’ credit default risk and net derivative liabilities are determined primarily by quoted futures and options prices and utilization of our credit default risk. The credit default risk of our counterparties and us are based on metrics such as interest coverage, operating cash flow and leverage ratios that calculate the likelihood that a firm will be unable to repay its lenders or fulfill payment obligations.
The value of our oil derivatives are comprised of three-way collar, call protected swap and deferred put spread contracts for notional barrels of oil at interval New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) oil prices. The fair value of our oil derivatives as of December 31, 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 swap, swaption, three way collar, basis swap, cap swap, call and deferred put spreads contracts for notional volumes of gas contracted at NYMEX Henry Hub (“HH”). The fair values attributable to our gas derivative contracts as of December 31, 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 December 31, 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 years ended December 31, 2014 and 2013 (in thousands):
		For the Year Ended December 31,
($ in Thousands)		2014				2013
Beginning Balance of Level 3		$	4,323			$	—
Changes in Fair Value			(1,670	)			4,328
Purchases			—				—
Settlements Received			(1,312	)			(5	)
Ending Balance of Level 3		$	1,341			$	4,323
Changes in fair value on our Level 3 commodity derivative contracts outstanding for the years ended December 31, 2014 and 2013, resulted in a gain of approximately $1.7 million and a gain of approximately $4.3 million, respectively. These amounts have been included in Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations.
Asset Retirement Obligations
We report the fair value of asset retirement obligations on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation;  amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements for further information on asset retirement obligations, which includes a reconciliation of the beginning and ending balances.
Financial Instruments Not Recorded at Fair Value
The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements:
		31-Dec-14								31-Dec-13
($ in Thousands)		Carrying				Fair Value				Carrying				Fair Value
		Amount								Amount
8.875% Senior Notes due 2020		$	350,000			$	311,955			$	350,000			$	385,000
6.25% Senior Notes due 2022			325,000				241,313				—				—
Secured Lines of Credit			—				—				59,000				59,000
Capital Leases and Other Obligations			1,427				1,393				1,477				1,449
Total		$	676,427			$	554,661			$	410,477			$	445,449
The fair value of the secured lines of credit approximates carrying value based on borrowing rates available to us for bank loans with similar terms and maturities and would be classified as Level 2 in the fair value hierarchy.
The fair value of the Senior Notes uses pricing that is readily available in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 2 in the fair value hierarchy. The fair value of our capital leases and other obligations are determined using a discounted cash flow approach based on the interest rate and payment terms of the obligations and assumed discount rate. The fair values of the obligations could be significantly influenced by the discount rate assumptions, which is unobservable. Accordingly, the fair value of the capital leases and other obligations would be classified as Level 3 in the fair value hierarchy.
The carrying values of all classes of cash and cash equivalents, accounts receivables and accounts payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.
Other Fair Value Measurements
We recorded an other than temporary impairment of $132.6 million related to proved properties, unproved properties and other non-revenue producing equipment. We utilize quoted futures prices and other observable market data in determining the fair value. The inputs used in determining fair value as a part of the impairment calculation are considered to be Level 2 within the fair value hierarchy. For additional information on our impairment, see Note 18, Impairment Expense, to our Consolidated Financial Statements.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	13	INCOME TAXES
	We recognize deferred tax liabilities and assets for the expected future tax consequences of events that may be recognized in our financial statements or tax returns. Using this method, deferred tax liabilities and assets are determined based on the difference between the financial carrying amounts and tax bases of assets and liabilities using enacted tax rates. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
	Our income tax expense (benefit) from continuing operations consisted of the following:
			For the Years Ended December 31,
	($ in Thousands)		2014			2013			2012
	Current:
	Federal		$	—		$	(1,936	)	$	2,350
	State			6			(4,105	)		5,608
	Deferred:
	Federal			-23,691			509			27,312
	State			-3,230			1,378			2,012
	Income Expense (Benefit)		$	-26,915		$	(4,154	)	$	37,282
	A reconciliation of income tax expense (benefit) using the statutory U.S. income tax rate compared with actual income tax expense is as follows:
	($ in Thousands)		Year Ended			Year Ended			Year Ended
			December 31,			December 31,			December 31,
			2014			2013			2012
	Income (loss) from continuing operations before		$	(74,565	)	$	(6,538	)	$	92,203
	noncontrolling interests and income taxes
	Statutory U.S. income tax rate			35	%		35	%		35	%
	Tax expense recognized using statutory U.S. income tax rate		$	(26,098	)	$	(2,288	)	$	32,271
	Change in estimated future state rates			(1,015	)		(484	)		(7	)
	Permanent differences			363			83			52
	Change in valuation allowances			2,450			(160	)		(131	)
	Other			608			(500	)		(493	)
	Adjusted federal income tax expense (benefit)		$	(23,692	)	$	(3,349	)	$	31,692
	State income tax expense  (benefit)			(3,223	)		(805	)		5,590
	Total income tax expense (benefit)		$	(26,915	)	$	(4,154	)	$	37,282
	Effective income tax rate			36.1	%		63.5	%		40.4	%
	Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. Deferred tax assets (liabilities) are comprised of the following at December 31, 2014 and 2013:
			For the Years Ended
			December 31,
	($ in Thousands)		2014			2013
	Tax effects of temporary differences for:
	Current:
	Assets:
	Asset retirement obligation		$	772		$	997
	Deferred compensation plans			695			2,593
	Compensation accruals			2,087			—
	Valuation allowances			(71	)		—
	Other			68			370
	Total gross current deferred tax assets			3,551			3,960
	Liabilities:
	Unrealized gain on derivatives			(11,410	)		(404	)
	Other			(442	)		(105	)
	Total gross current deferred tax liabilities			(11,852	)		(509	)
	Net total current deferred tax asset (liability)		$	(8,301	)	$	3,451
	Long-Term:
	Assets:
	Asset retirement obligation		$	15,091		$	10,445
	Deferred compensation plans			2,218			1,513
	Net operating loss carryforward(a)			73,531			48,703
	Organization costs			525			602
	Deferred revenue			1,209			1,338
	AMT credits			292			292
	Unrealized gain on derivatives			—			493
	Valuation allowances			(4,318	)		(1,965	)
	Other			269			232
	Total gross long-term deferred tax assets			88,817			61,653
	Liabilities:
	Timing differences - tax partnerships			(7,135	)		(7,474	)
	Book basis of oil and gas properties in excess of			(71,402	)		(83,594	)
	tax basis
	Unrealized gain on derivatives			(999	)		—
	Other			(980	)	$	(31	)
Total gross long-term deferred tax liabilities			(80,516	)		(91,099	)
Net total long-term deferred tax asset (liability)		$	8,301		$	(29,446	)
(a)	As a result of certain realization requirements of FASB ASC 718, the table of deferred tax assets and liabilities does not include $1.3 million and $0.4 million at December 31, 2014 and 2013, respectively, of excess tax benefits that arose directly from tax deductions related to stock-based compensation greater than compensation recognized for financial reporting. Total stockholders’ equity will be increased by $1.3 million if and when such excess tax benefits are ultimately realized.
Management continuously evaluates the facts and circumstances representing positive and negative evidence in the determination of our ability to realize the deferred tax assets. These deferred tax assets consist primarily of net operating losses and deductible temporary differences. For the year ended December 31, 2014, management determined, based on positive and negative evidence, including our three-year cumulative loss position, examined and anticipated future taxable income, that it was necessary to provide a valuation allowance of approximately $4.3 million for net operating loss carryforwards that may expire prior to being utilized, statutory depletion carryforwards and charitable contributions. For the year ended December 31, 2013, management determined, based on positive and negative evidence examined and anticipated future taxable income, that it was necessary to provide a valuation allowance of approximately $2.0 million for statutory depletion carryforwards and charitable contributions. Based on the expected patterns of reversal of all existing temporary differences, we have concluded that it is more likely than not that the remaining deferred tax assets will be realized. Our management will continue, in future periods, to assess the likely realization of the deferred tax assets. The valuation allowance may change based on future changes in circumstances.
At December 31, 2014, we had available unused gross federal net operating loss carryforwards of $186.4 million and gross state net operating loss carryforwards of $144.5 million that may be applied against future taxable income that expire from 2020 through 2034. The following table shows expirations by year for federal and state net operating loss carryforwards (all figures presented are tax effected):
Year of Expiration		Net Operating
		Loss Carryforwards
		(in thousands)
2020		$	134
2021			175
2022			—
2023			899
2024			—
2025			531
2026			600
2027			—
2028			3,333
2029			767
2030			751
2031			19,746
2032			253
2033			19,703
2034			26,639
Total			73,531
Due to a change of ownership, as defined under the provisions of the Tax Reform Act of 1986, which occurred during 2014, a portion of our domestic net operating loss and tax credit carryforwards may be limited in future periods. Further, a portion of the carryforwards may expire before being applied to reduce future income tax liabilities.
FASB ASC 740-10 sets forth a two-step process for evaluating tax positions. The first step is financial statement recognition of the tax position based on whether it is more likely than not that the position will be sustained upon examination by taxing authorities and resolution through related appeals or litigation, based on the technical merits of the case. FASB ASC 740-10 mandates certain assumptions in applying the more likely than not judgment, including the presupposition of an examination where the taxing authorities are fully informed of all relevant information for evaluation of the tax position. In other words, FASB ASC 740-10 precludes factoring the likelihood of a tax examination into the evaluation of the outcome so that the evaluation is to focus solely on the technical merits of the position.
Our management has concluded that, as of December 31, 2014, we have not taken any tax positions that would require disclosure as “unrecognized positions” and that no liability balance is required to offset any unsustainable positions. We did not have any accrued interest or penalties as of December 31, 2014 and 2013.
We file a consolidated federal income tax return and separate or consolidated state income tax returns in the United States federal jurisdiction and in many state jurisdictions. We are subject to U.S. federal income tax examinations and to various state tax examinations for periods after August 1, 2007.

Earnings_Per_Common_Share

Earnings Per Common Share	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Earnings Per Common Share	14	EARNINGS PER COMMON SHARE
	Basic income (loss) per common share is calculated based on the weighted average number of common shares outstanding at the end of the period, excluding restricted stock with performance-based and market-based vesting criteria. Diluted income per common share includes the speculative exercise of stock options and performance-based restricted stock which contain conditions that are not earnings or market-based, given that the hypothetical effect is not anti-dilutive. For the years ended December 31, 2014 and 2013, we excluded stock options to purchase 0.4 million shares of our common stock due to our Net Loss from Continuing Operations. For the year ended December 31, 2012, we excluded stock options to purchase 0.4 million shares from the computation of earnings per share because the grant prices were greater than the average market price of the common shares, which has an anti-dilutive effect on the computation. For the years ended December 31, 2014 and 2013, we excluded performance-based restricted stock of 0.8 million shares and 1.3 million shares due to our Net Loss from Continuing Operations. For the year ended December 31, 2012, we excluded 1.0 million shares from the earnings per share calculations due to performance metrics that have not yet been attained (for additional information on our non-cash compensation plans, see Note 17, Employee Benefit and Equity Plans, to our Consolidated Financial Statements). We utilize the if-converted method for calculating the impact of our 6.0% Convertible Perpetual Preferred Stock on diluted earnings per share. Under the if-converted method, convertible preferred stock is assumed as converted to common shares for the weighted average period outstanding. For the year ended December 31, 2014, we excluded the assumed conversion of preferred stock equating to approximately 3.3 million shares due to our Net Loss from Continuing Operations. The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share data):
			Year Ended			Year Ended			Year Ended
			December 31,			December 31,			December 31,
	(in thousands, except per share amounts)		2014			2013			2012
	Numerator:
	Net Income (Loss) From Continuing Operations		$	(47,650	)	$	(2,384	)	$	54,921
	Net Income (Loss) From Discontinued Operations, Less Noncontrolling Interests			961			254			(9,442	)
	Less: Preferred Stock Dividends			2,335			—
	Net Income (Loss) Attributable to Common Shareholders		$	(49,024	)	$	(2,130	)	$	45,479
	Denominator:
	Weighted Average Common Shares Outstanding - Basic			53,150			52,572			51,543
	Effect of Dilutive Securities:
	Employee Stock Options			—			—			69
	Employee Performance-Based Restricted Stock Awards			—			—			413
	Effect of Assumed Conversions of Preferred Stock			—			—			—
	Weighted Average Common Shares Outstanding - Diluted			53,150			52,572			52,025
	Earnings per Common Share Attributable to Rex Energy Common Shareholders (a):
	Basic — Net Income (Loss) From Continuing Operations		$	(0.94	)	$	(0.05	)	$	1.06
	— Net Income (Loss) From Discontinued Operations			0.02			0.01			(0.18	)
	— Net Income (Loss) Attributable to Rex Energy Common Shareholders		$	(0.92	)	$	(0.04	)	$	0.88
	Diluted — Net Income (Loss) From Continuing Operations		$	(0.94	)	$	(0.05	)	$	1.06
	— Net Income (Loss) From Discontinued Operations			0.02			0.01			(0.18	)
	— Net Income (Loss) Attributable to Rex Energy Common Shareholders		$	(0.92	)	$	(0.04	)	$	0.88
	(a)	All earnings per share amounts are attributable to Rex common shareholders.

Capital_Stock

Capital Stock	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Capital Stock	15	CAPITAL STOCK
	Common Stock
	Currently, our common stock is traded on the NASDAQ Global Select Market under the trading symbol “REXX”. We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of December 31, 2014 and 2013, we had 54,174,763 and 54,186,490 shares of common stock outstanding, respectively.
	Preferred Stock
	On August 18, 2014, we completed a registered offering of 16,100 shares of 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (the “Series A Preferred Stock”) that are represented by 1,610,000 depositary shares. The net proceeds of the offering were approximately $155.0 million, after deducting underwriting discounts, commissions and other offering expenses. We utilized a portion of the net proceeds to fund the acquisition of assets from Shell and 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 thereof, on a quarterly basis at a rate of $600 per share, or 6.0%, per year. In October 2014, we declared a quarterly cash dividend of $145.00 per share for the period from the original issue date of August 18, 2014 through November 15 totaling approximately $2.3 million.
	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.

Major_Customers

Major Customers	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Major Customers	16	MAJOR CUSTOMERS
	For the year ended December 31, 2014, approximately $253.6 million, or 85.1%, of our commodity sales from continuing operations were attributable to four customers with the largest single purchaser accounting for $96.4 million, or 32.4%. For the year ended December 31, 2013, approximately $179.5 million, or 83.9% of our commodity sales from continuing operations were attributable to four customers with the largest single purchaser accounting for $73.8 million, or 34.5%. For the year ended December 31, 2012, approximately $128.3 million, or 95.3%, of our commodity sales from continuing operations were derived from five customers, with the largest customer being responsible for approximately $64.7 million, or 48.1%, of total commodity sales.

Employee_Benefit_and_Equity_Pl

Employee Benefit and Equity Plans	12 Months Ended
	Dec. 31, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Employee Benefit and Equity Plans	17	EMPLOYEE BENEFIT AND EQUITY PLANS
	401(k) Plan
	We sponsor a 401(k) Plan for eligible employees who have satisfied age and service requirements. Employees can make contributions to the plan up to allowable limits. Our contributions to the plan are discretionary. Our contributions to the plan attributable to continuing operations were approximately $0.9 million, $0.7 million and $0.5 million for the years ended December 31, 2014, 2013 and 2012, respectively.
	Equity Plans
	We recognize all share-based payments to employees, including grants of employee stock options, in our Consolidated Statements of Operations based on their grant-date fair values, using prescribed option-pricing models where applicable. The fair value is expensed over the requisite service period of the individual grantees, which generally equals the vesting period. We report any benefits of income tax deductions in excess of recognized financial accounting compensation as a financing cash flow, rather than as an operating cash flow.
	2007 Long-Term Incentive Plan
	We have granted stock options, stock appreciation rights and restricted stock awards to various employees, non-employee directors and non-employee contractors under the terms of our Amended and Restated 2007 Long-Term Incentive Plan (the “Plan”). The Plan is administered by the Compensation Committee of our board of directors (the “Compensation Committee”). Among the Compensation Committee’s responsibilities are selecting participants to receive awards, determining the form, amount and other terms and conditions of awards, interpreting the provisions of the Plan or any award agreement and adopting such rules, forms, instruments and guidelines for administering the Plan as it deems necessary or proper. All actions, interpretations and determinations by the Compensation Committee are final and binding. The composition of the Compensation Committee is intended to permit the awards under the Plan to qualify for exemption under Rule 16b-3 of the Exchange Act. In addition, awards under the Plan, including annual incentive awards paid to executive officers subject to section 162(m) of the Code or covered employees may be designed, at the Compensation Committee’s discretion, to satisfy the requirements of section 162(m) to permit the deduction by us of the associated expenses for federal income tax purposes. The Compensation Committee has authorized the issuance of 5,979,470 shares under the Plan, with 2,825,260 and 2,785,836 still available as of December 31, 2014 and 2013, respectively.
	All awards granted under the Plan have been issued at the prevailing market price at the time of the grant. All outstanding stock options have been awarded with five or ten year expiration at an exercise price equal to our closing price on the NASDAQ Global Select Market on the day of the award. A forfeiture rate based on a blended average of individual participant terminations and number of awards cancelled is used to estimate forfeitures prospectively.
	Stock Options
	Stock options represent the right to purchase shares of stock in the future at the fair market value of the stock on the date of grant. In the event that any outstanding award expires, is forfeited, cancelled or otherwise terminated without the issuance of shares of our common stock or is otherwise settled in cash, shares of our common stock allocable to such award, including the unexercised portion of such award, shall again be available for the purposes of the Plan. If any award is exercised by tendering shares of our common stock to us, either as full or partial payment, in connection with the exercise of such award under the Plan or to satisfy our withholding obligation with respect to an award, only the number of shares of our common stock issued net of such shares tendered will be deemed delivered for purposes of determining the maximum number of shares of our common stock then available for delivery under the Plan. During the years ended December 31, 2014 and 2013, we did not issue options to purchase shares of our common stock.
	A summary of the stock option activity is as follows:
			Number of				Weighted-Average				Weighted-Average				Aggregate Intrinsic
			Shares				Exercise Price				Remaining Term				Value
											(in years)				(in thousands)
	Options outstanding December 31, 2011			698,327			$	12.94
	Granted			—				—
	Exercised			(52,287	)			10.8
	Cancelled/Forfeited			(143,787	)			20.71
	Options outstanding December 31, 2012			502,253			$	10.95
	Granted			—				—
	Exercised			(49,166	)			10.85
	Cancelled/Forfeited			(4,000	)			23.28
	Options outstanding December 31, 2013			449,087			$	10.85
	Granted			—				—
	Exercised			(46,526	)			11.09
	Cancelled/Forfeited			—				—
	Options Outstanding December 31, 2014			402,561			$	10.82				2.9			$	2.8
	Options Exercisable December 31, 2014			402,561			$	10.82				2.9			$	2.8
	Stock-based compensation expense from continuing operations relating to stock options for the years ended December 31, 2014, 2013 and 2012 totaled $0.1 million, $0.2 million and $0.2 million, respectively. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative expense. The intrinsic value of stock options exercised for the years ended December 31, 2014, 2013 and 2012 was $0.3 million, $0.4 million and $0.1 million, respectively. The total tax benefit for the years ended December 31, 2014 and 2013 was approximately $0.1 million and $0.2 million, respectively, and negligible in 2012.
	A summary of the status of our issued and outstanding stock options as of December 31, 2014 is as follows:
					Outstanding								Exercisable
	Exercise Price				Number				Weighted-Average				Number				Weighted-Average
					Outstanding				Exercise Price				Exercisable				Exercise Price
					At 12/31/14								At 12/31/14
	$	5.04				46,041			$	5.04				46,041			$	5.04
	$	9.5				75,000			$	9.5				75,000			$	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				50,000			$	13.19
	$	22.34				30,000			$	22.34				30,000			$	22.34
						402,561			$	10.82				402,561			$	10.82
	The weighted average remaining contractual term for options exercisable at December 31, 2014 was 2.9 years and the aggregate intrinsic value was negligible. The weighted average remaining contractual term and the aggregate intrinsic value for options outstanding at December 31, 2013 were 3.9 years and $4.1 million, respectively. As of December 31, 2014, all outstanding options are exercisable and there is no unrecognized compensation expense related to stock options.
	Restricted Stock Awards
	During the year ended December 31, 2014, the Compensation Committee issued 131,610 shares of restricted common stock to selected employees, non-employee directors and non-employee contractors. During the year ended December 31, 2013, the Compensation Committee issued 981,544 shares of restricted common stock to selected employees, non-employee directors and non-employee contractors. The shares granted in 2014 and 2013 are subject to time vesting and, in some cases, performance-based vesting. The shares will vest on the date on which the Compensation Committee certifies that the performance goals have been satisfied, provided that the recipient has been in continuous employment with us from the grant date until the date upon which the shares are released. Restrictions on the transfer associated with vesting schedules were determined by the Compensation Committee on an individual award basis. The restricted common stock is valued at the closing price of our common stock on the NASDAQ Global Select Market on the date of the grant. Upon a “change in control” of us, as such term is defined in the Plan, all restrictions will immediately lapse for performance-based awards to varying degrees based on performance metrics at the time of the change in control. For awards that do not contain a performance-based condition, all restrictions immediately lapse upon a change in control. Compensation expense associated with the restricted stock award is recognized on a straight-line basis over the vesting period.
	Certain of the restricted common stock awards in 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 of 13 to 15  companies over a three-year period. The number of shares ultimately awarded will correspond with the final TSR rank amongst the peer group in accordance with the following schedule:
	TSR Rank		Percentage of
			2013 and 2014
			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 as of December 31, 2014, 2013 and 2012 were $10.15, $12.59 and $7.80 per share, respectively. Average fair values were estimated on the date of each grant using a Monte Carlo Simulation model that estimates the most likely outcome based on the terms of the award and used the following assumptions:
		Year Ended				Year Ended
		December 31,				31-Dec-13
		2014
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.
We recorded compensation expense related to restricted common stock awards of $5.8 million, $5.1 million and $2.9 million for the years ended December 31, 2014, 2013 and 2012, respectively. As of December 31, 2014, total unrecognized compensation cost related to the restricted common stock grants was approximately $5.8 million to be recognized over a weighted average of 1.7 years. The total fair value of restricted common stock awards that vested in 2014 was approximately $7.7 million as compared to $3.0 million for restricted common stock awards that vested in 2013.
A summary of the restricted stock activity for the years ended December 31, 2014, 2013 and 2012 is as follows:
		Number of				Weighted-Average
		Shares				Grant Date
						Fair Value
Restricted stock awards, as of January 1, 2012			1,229,826			$	12.11
Awards			425,209				11.59
Vested			(70,750	)			2.05
Forfeitures			(152,712	)			12.13
Restricted stock awards, as of December 31, 2012			1,431,573			$	12.45
Awards			981,544				16.03
Vested			(182,994	)			11.59
Forfeitures			(57,484	)			11.84
Restricted stock awards, as of December 31, 2013			2,172,639			$	14.16
Awards			131,610				8.76
Vested			(595,085	)			13.09
Forfeitures			(189,863	)			14.6
Restricted stock awards, as of December 31, 2014			1,519,301			$	14.05

Impairment_Expense

Impairment Expense	12 Months Ended
	Dec. 31, 2014
Goodwill And Intangible Assets Disclosure [Abstract]
Impairment Expense	18	IMPAIRMENT EXPENSE
	For the years ended December 31, 2014, 2013 and 2012, we incurred impairment expense from continuing operations of approximately $132.6 million, $32.1 million and $20.6 million, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment (for additional information see Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements). Approximately $113.4 million of the impairment incurred during 2014 was attributable to proved properties and other fixed assets, of which approximately $103.9 million was attributable to the Illinois Basin and $9.5 million was attributable to the Appalachian Basin. In the Illinois Basin, which is 100% oil producing, the estimated future decline in oil prices as of December 31, 2014, caused the estimated future cash flows of certain properties to decrease below a level at which the carrying value that is expected to be recovered. In the Appalachian Basin, approximately $5.9 million of impairment was incurred for our salt water disposal well in Ohio due to the regulatory and environmental climate and the uncertainty of future viability of the disposal well. We also incurred approximately $3.6 million of impairment related to shallow conventional gas properties in the Appalachian Basin, which is attributable to the estimated future decrease in natural gas pricing as of December 31, 2014. In addition to our proved property and fixed asset impairments, we also incurred approximately $18.9 million in unproved property impairments. In the Appalachian Basin, we incurred approximately $10.4 million in unproved property impairments related to expiring leases that will not be developed. In the Illinois Basin, we incurred approximately $8.5 million of unproved property impairment primarily due to the estimated future economics of the properties at the depressed commodity price environment at December 31, 2014.
	During 2013, we incurred approximately $29.3 million of expense related to the impairment of conventional oil properties in the Illinois Basin. The impairment in Illinois was focused in two areas where extensive development activity occurred during 2013. In addition to the development activity, future estimated prices for the sale of crude oil as of December 31, 2013 decreased to a level which did not support the recovery of the full carrying value of the properties.
	During 2012, we incurred approximately $13.7 million of expense related to the impairment of proved unconventional natural gas wells in the Appalachian Basin, which in part was driven by the continued low natural gas pricing environment. All of the proved unconventional natural gas wells that were impaired in 2012, produce dry natural gas and are located in both our operated and non-operated areas in the Appalachian Basin. In addition to the impairment related to our natural gas properties, we incurred approximately $5.8 million in impairment expense related to the expected future expiration or surrender of undeveloped acreage in our non-operated dry gas area of Clearfield County, Pennsylvania. The remaining impairment was due to three non-operated properties in the Illinois Basin.

Suspended_Exploratory_Well_Cos

Suspended Exploratory Well Costs	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Suspended Exploratory Well Costs	19	SUSPENDED EXPLORATORY WELL COSTS
	We capitalize the costs of exploratory wells if a well finds a sufficient quantity of reserves to justify its completion as a producing well and we are making sufficient progress towards assessing the reserves and the economic and operating viability of the project.
	The following table reflects the net change in capitalized exploratory well costs, excluding those related to Assets Held for Sale on our Consolidated Balance Sheets for the years ended December 31, 2014, 2013 and 2012 ($ in thousands):
			2014			2013			2012
	Beginning Balance at January 1,		$	5,731		$	36,968		$	11,756
	Additions to capitalized exploratory well costs			258,097			171,087			95,980
	pending the determination of estimated
	proved reserves
	Divested wells			—			—			—
	Reclassification of wells, facilities, and equipment			(240,494	)		(202,323	)		(70,518	)
	based on the determination of estimated
	proved reserves
	Capitalized exploratory well costs charged to expense			(233	)		(1	)		(250	)
	Ending Balance at December 31,			23,101			5,731			36,968
	Less exploratory well costs that have been capitalized			(20,407	)		(3,597	)		(36,630	)
	for a period of one year or less
	Capitalized exploratory well costs for a period of greater		$	2,694		$	2,134		$	338
	than one year
	Number of projects that have exploratory well costs			6			3			2
	capitalized for a period of more than one year
	As of December 31, 2014 we had approximately $2.7 million in capitalized exploratory well costs that were capitalized for a period greater than one year. These costs are related to three units in Butler County, Pennsylvania and three units in our non-operated region in Clearfield County, Pennsylvania in the Appalachian Basin. These costs represent preliminary permitting and engineering expenses that we typically incur in advance of the commencement of drilling operations and pad construction to hold leases prior to expiration. No drilling has yet taken place on these locations, however the leases on which the proposed wells are located have extended terms providing the operator flexibility in ultimate development to maximize the rate of return. These costs are currently classified as Wells and Facilities in Progress on our Consolidated Balance Sheets and will be reclassified to Evaluated Oil and Gas Properties upon the discovery of proved reserves or to Exploration Expense if commercial quantities of reserves are not found.

Costs_Incurred_In_Oil_And_Natu

Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities	20	COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES (UNAUDITED)
	Costs incurred in oil and natural gas property acquisitions and development are presented below and exclude any costs incurred related to Assets Held for Sale (in thousands):
			2014			2013			2012
	Consolidated Entities:
	Acquisition of Properties
	Proved		$	161		$	2,445		$	1,474
	Unproved			169,408			39,291			49,331
	Exploration Costs(a)			316,235			231,112			128,748
	Development Costs(a)			71,383			64,661			57,149
	Subtotal			557,187			337,509			236,702
	Asset Retirement Obligations			9,110			3,031			4,480
	Total Costs Incurred		$	566,297		$	340,540		$	241,182
	Share of Equity Method Investments:
	Acquisition of Properties
	Proved		$	—		$	—		$	—
	Unproved			—			—			—
	Exploration Costs			—			—			—
	Development Costs(a)			438			1,958			4,316
	Total		$	438		$	1,958		$	4,316
	(a)	Includes Depreciation expense for support equipment and facilities
	The following table provides a reconciliation of the total costs incurred for our consolidated entities to our reported capital expenditures (in thousands):
			2014			2013			2012
	Total Costs Incurred by Consolidated Entities		$	566,297		$	340,540		$	241,182
	Equity Method Investments			—			2,493			4,087
	DJ Basin Expenditures			—			2			3,146
	Exploration Expense			(9,446	)		(11,408	)		(4,782	)
	Asset Retirement Obligations			(9,110	)		(3,031	)		(4,480	)
	Depreciation for Support Equipment and Facilities			(6,075	)		(5,024	)		(4,187	)
	Corporate Expenditures			869			3,651			1,156
	Other (a)			7,223			10,391			2,732
	Total Capital Expenditures		$	549,758		$	337,614		$	238,854
	(a)	Represents R.E. Disposal, LLC capital and intercompany capital transactions.

Oil_And_Natural_Gas_Capitalize

Oil And Natural Gas Capitalized Costs	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Oil And Natural Gas Capitalized Costs	21	OIL AND NATURAL GAS CAPITALIZED COSTS (UNAUDITED)
	Our aggregate capitalized costs for natural gas and oil production activities with applicable accumulated depreciation, depletion and amortization are presented below and exclude any properties classified as Assets Held for Sale (in thousands):
			2014			2013
	Consolidated Entities:
	Proven Oil and Natural Gas Properties		$	1,079,039		$	749,680
	Pipelines and Support Equipment			24,248			33,119
	Field Operation Vehicles and Other Equipment			27,030			21,608
	Wells and Facilities in Progress			127,597			69,886
	Unproven Properties			322,413			189,385
	Total			1,580,327			1,063,678
	Less Accumulated Depreciation and Depletion			(362,804	)		(184,836	)
	Total		$	1,217,523		$	878,842
	Share of Equity Method Investments:
	Pipelines and Support Equipment			19,946			19,270
	Wells and Facilities in Progress			—			238
	Total			19,946			19,508
	Less Accumulated Depreciation and Depletion			(2,611	)		(1,818	)
	Total		$	17,335		$	17,690

Oil_and_Natural_Gas_Reserve_Qu

Oil and Natural Gas Reserve Quantities	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Oil and Natural Gas Reserve Quantities	22	OIL AND NATURAL GAS RESERVE QUANTITIES (UNAUDITED)
	Our independent engineers, Netherland, Sewell, and Associates, Inc. (“NSAI”) evaluated all of our proved oil, natural gas and NGL reserves for the years ended December 31, 2014, 2013 and 2012. The technical persons responsible for preparing the estimates of our estimated proved reserves meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis. We emphasize that reserve estimates are inherently imprecise. Our oil, natural gas and NGL reserve estimates were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available. All of our estimated proved reserves are located within the United States.
	Proved natural gas, oil and NGL reserves are those quantities of natural gas, oil and NGL which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. Based on reserve reporting rules, the price is calculated using the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. A project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas or oil on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Developed natural gas, oil and NGL reserves are reserves of any category that can be expected to be recovered (x) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (y) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
	Undeveloped natural gas, oil and NGL reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.
	Presented below is a summary of changes in estimated reserves of the oil and natural gas wells at December 31, 2014, 2013 and 2012:
			2014
			Oil (MBbls)			NGL (MBbls)			Natural Gas			(MMcf)
									(MMcf)			Equivalents
	Estimated Proved Reserves-Beginning of Period			8,619.60			46,130.70			521,282.80			849,784.60
	Extensions, Discoveries and Additions			1,723.10			31,160.30			326,464.20			523,764.60
	Revisions of Previous Estimates			471.1			(2,889.1	)		9,971.00			(4,537.0	)
	Purchases			12			933			18,478.30			24,148.30
	Production			(1,141.1	)		(2,082.4	)		(37,011.2	)		(56,352.2	)
	Estimated Proved Reserves-End of Period			9,684.70			73,252.50			839,185.10			1,336,808.30
			2013
			Oil (MBbls)			NGL (MBbls)			Natural Gas			(MMcf)
									(MMcf)			Equivalents
	Estimated Proved Reserves-Beginning of Period			9,375.70			31,679.90			371,716.40			618,050.00
	Extensions, Discoveries and Additions			595.6			19,956.10			189,150.90			312,461.10
	Revisions of Previous Estimates			(438.5	)		(4,685.6	)		(16,137.7	)		(46,882.3	)
	Purchases			1			—			—			6
	Production			(914.2	)		(819.7	)		(23,446.8	)		(33,850.2	)
	Estimated Proved Reserves-End of Period			8,619.60			46,130.70			521,282.80			849,784.60
			2012
			Oil (MBbls)			NGL (MBbls)			Natural Gas			(MMcf)
									(MMcf)			Equivalents
	Estimated Proved Reserves-Beginning of Period			8,181.20			7,134.80			274,292.30			366,188.30
	Extensions, Discoveries and Additions			474.6			12,813.60			116,854.40			196,583.60
	Revisions of Previous Estimates			650.5			12,089.50			(1,413.6	)		75,026.40
	Improved Recovery			758.3			—			—			4,549.80
	Purchases			43.2			—			—			259.2
	Production			(732.1	)		(358.0	)		(18,016.7	)		(24,557.3	)
	Estimated Proved Reserves-End of Period			9,375.70			31,679.90			371,716.40			618,050.00
			Oil (MBbls)			NGL (MBbls)			Natural Gas			(MMcf)
									(MMcf)			Equivalents
	Proved Developed Reserves
	31-Dec-14			7,628.10			29,215.00			365,673.30			586,731.90
	31-Dec-13			7,742.50			16,322.50			212,061.40			356,451.40
	31-Dec-12			9,216.10			10,143.70			141,754.60			257,913.40
	Proved Undeveloped Reserves
	31-Dec-14			2,056.60			44,037.50			473,511.80			750,076.40
	31-Dec-13			877.1			29,808.20			309,221.40			493,333.20
	31-Dec-12			159.6			21,536.20			229,961.80			360,136.60
	Our estimated proved undeveloped reserves included five gross (five net) locations that generated positive future net revenue but negative present value discounted at 10%. Net reserve volumes associated with these locations were 2.1 Bcfe (approximately 0.2% of total estimated proved reserves). Given our planned operating budget, strategy to hold the acreage by production, and expectations of future commodity prices, we plan to develop these locations over the next five years and therefore have included these locations in our PUD reserves.
	Revisions. Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from developmental drilling and production history or resulting from a change in economic factors, such as commodity prices and operating costs.
	Our revisions in 2014 included a negative adjustment of approximately 58.5 Bcfe related to PUD locations that were not developed within five years, negative revisions of 1.6 Bcfe related to commodity pricing, positive revisions of 17.6 Bcfe related to favorable operating expenses and positive technical revisions of 38.0 Bcfe. The negative revisions were related to PUD locations that were previously booked in our Butler County, Pennsylvania region. The positive technical revisions included 51.0 Bcfe in our Butler County, Pennsylvania area related to positive well performance which was partially offset by negative revisions related to well performance in our Warrior South prospect and our non-operated Westmoreland County, Pennsylvania area of approximately 15.5 Bcfe.
	We had significant revisions in our oil, NGL and natural gas reserves for the year ended December 31, 2013. Our negative revisions were primarily due to adjusting downward our estimated recovery of future ethane production from 2012 to 2013. Negative revisions related to our estimated ethane recovery accounted for approximately 27.3 Bcfe of our total revisions. In addition to our ethane recovery adjustments, we recognized additional negative revisions related to well performance in our non-operated Westmoreland County, Pennsylvania region as well as in the Illinois Basin. Partially offsetting these negative revisions were positive revisions due to natural gas pricing and lower than expected operating expenses.
	We had significant revisions in our oil, NGL and natural gas reserves for the year ended December 31, 2012. Revisions due to price in our natural gas operations resulted in a significant loss of reserves. Prices used for natural gas reserves decreased from $4.55 in 2011 to $2.94 in 2012. Partially offsetting the decrease due to pricing were increased reserves due to additional field production data demonstrating better well performance than as of year-end 2011. We believe this increased performance is the result of improved completion techniques. During 2012, we executed an agreement to sell ethane as a separate product in our NGL stream, which was being utilized as plant fuel. As such, we booked for the first time ethane barrels as part of our NGL reserves. The ethane reserves contained within revisions to previous estimates are barrels associated to those wells which were considered to be proved locations as of December 31, 2011. We also had revisions in our non-operated properties. In our Westmoreland Marcellus, we saw reserve increases as a result of field production data demonstrating better well performance than last year’s estimates. For our Clearfield County Marcellus proved undeveloped acreage, we saw a reduction in proved reserves primarily due to offset well performance. In our Illinois Basin asset, we saw positive revisions, with a significant portion being the result of our re-frac program of stacked pay intervals instituted during the middle of 2012.
	Extensions, discoveries and other additions. These are additions to estimated proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with estimated proved reserves or of new reservoirs of estimated proved reserves in old fields.
	We had significant extensions, discoveries and other additions for the year ended December 31, 2014, of 1.7 MMBOE of oil, 31.2 MMBOE of NGLs and 326.5 Bcf of natural gas. During 2013, we had extensions, discoveries and other additions of 0.6 MMBOE of oil, 20.0 MMBOE of NGLs and 189.1 Bcf of natural gas. During 2012, we had extensions, discoveries and other additions of 0.5 MMBOE of oil, 12.8 MMBOE of NGLs and 116.9 Bcf of natural gas. Our continued success in the Appalachian Basin has been the primary contributor to the growth of our extensions, discoveries and other additions, specifically the Marcellus Shale. At December 31, 2012, we had 100.0 gross (58.1 net) PUD locations in the Appalachian Basin, including 97.0 gross (56.4 net) related to the Marcellus Shale. At December 31, 2013, we had 136.0 gross (85.5 net) PUD locations in the Appalachian Basin, including 120.0 gross (73.5 net) related to the Marcellus Shale. At December 31, 2014, we had 177.0 gross (117.0 net) PUD locations in the Appalachian Basin, including 162.0 gross (105.4 net) related to the Marcellus Shale.

Standardized_Measure_Of_Discou

Standardized Measure Of Discounted Future Net Cash Flows	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Standardized Measure Of Discounted Future Net Cash Flows	23	STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)
	FASB ASC 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proved reserves. We followed these guidelines, which are briefly discussed below.
	Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of oil and natural gas to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of estimated proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0% annual discount factor.
	The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.
	The following summary sets forth our future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by FASB ASC 932 at December 31, 2014, 2013 and 2012 ($ in thousands):
			2014				2013				2012
	Future Cash Inflows		$	5,824,231		(a)	$	3,899,878		(b)	$	2,988,231		(c)
	Future Costs:
	Production			(2,332,151	)			(1,619,629	)			(1,387,653	)
	Abandonment			(134,308	)			(95,183	)			(85,859	)
	Development			(686,676	)			(517,875	)			(324,873	)
	Net Future Cash Inflow Before Income Taxes			2,671,096				1,667,191				1,189,846
	Future Income Tax Expense			(468,597	)			(359,322	)			(245,078	)
	Total Future Net Cash Flows Before 10.0% Discount			2,202,499				1,307,869				944,768
	Less: Effect of 10.0% Discount Factor			(1,177,135	)			(778,756	)			(548,645	)
	Standardized Measure of Discounted Future Net Cash Flows		$	1,025,364			$	529,113			$	396,123
	(a)	Calculated using weighted average prices of $3.455 per Mcf, $88.02 per barrel of oil and $28.30 per barrel of NGLs
	(b)	Calculated using weighted average prices of $3.588 per Mcf, $94.28 per barrel of oil and $26.37 per barrel of NGLs
	(c)	Calculated using weighted average prices of $2.94 per Mcf, $90.92 per barrel of oil and $32.91 per barrel of NGLs
	The principal sources of change in the standardized measure of discounted future net cash flows are as follows:
			2014				2013				2012
	Standardized Measure – Beginning of Period		$	529,113			$	396,123			$	413,935
	Revisions of Previous Estimates:
	Changes in Prices and Production Costs			253,865				72,503				(198,433	)
	Revisions in Quantities			(5,970	)			(51,289	)			91,462
	Changes in Future Development Costs			(51,794	)			22,341				(3,885	)
	Accretion of Discount and Timing of Future Cash Flows			64,013				47,571				52,093
	Net Change in Income Tax			28,756				31,433				27,405
	Purchase of Reserves in Place			28,316				—				1,188
	Plus Extensions, Discoveries, and Other Additions			430,252				170,846				88,749
	Development Costs Incurred			71,383				64,661				57,149
	Sales of Product – Net of Production Costs			(197,587	)			(151,781	)			(86,936	)
	Changes in Timing and Other			(124,983	)			(73,295	)			(46,604	)
	Standardized Measure – End of Period		$	1,025,364			$	529,113			$	396,123

Results_Of_Operations_For_Oil_

Results Of Operations For Oil And Gas Producing Activities	12 Months Ended
	Dec. 31, 2014
Income Statement [Abstract]
Results of Operations for Oil and Gas Producing Activities	24	RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
	Results of operations are equal to revenues, less (a) production costs, (b) impairment expenses, (c) exploration expenses, (d) DD&A expenses, and (e) income tax expense (benefit) (certain prior year amounts have been reclassified to conform to current presentation):
			2014			2013			2012
	Consolidated Entities (in thousands):
	Revenues
	Oil and Natural Gas Sales		$	297,869		$	213,919		$	134,574
	Expenses
	Production and Lease Operating Expense			100,282			62,150			47,638
	Impairment Expense			132,618			32,072			20,505
	Exploration Expense			9,446			11,408			4,782
	Depletion, Depreciation, Amortization and Accretion			94,467			62,386			44,955
	Total Costs			336,813			168,016			117,880
	Pre-Tax Operating Income (Loss)			(38,944	)		45,903			16,694
	Income Tax (Expense) Benefit  (a)			14,059			(29,148	)		(6,750	)
	Results of Operations for Oil and Gas Producing Activities		$	(24,885	)	$	16,755		$	9,944
	Share of Equity Method Investments (in thousands):
	Expenses
	Depletion, Depreciation, Amortization and Accretion		$	805		$	752		$	1,082
	Total Costs			805			752			1,082
	Pre-Tax Operating Income (Loss)			(805	)		(752	)		(1,082	)
	Income Tax Benefit  (a)			291			478			438
	Results of Operations for Oil and Gas Producing Activities		$	(514	)	$	(274	)	$	(644	)
	Total Consolidated and Equity Method Investees Results of		$	(25,399	)	$	16,481		$	9,300
	Operations for Oil and Gas Producing Activities
	(a)	Computed using the effective rate for continuing operations for each period: 36.1% in 2014; 63.5% in 2013 and; 40.4% in 2012.

Litigation

Litigation	12 Months Ended
	Dec. 31, 2014
Commitments And Contingencies Disclosure [Abstract]
Litigation	25	LITIGATION
	Illinois Basin EPA Consent Decree
	In September 2006, the United States Department of Justice (“DOJ”), the United States Environmental Protection Agency (“EPA”) and the State of Illinois initiated an enforcement action against us seeking mandatory injunctive relief and potential civil penalties based on allegations that we (and various predecessor companies) were violating the Clean Air Act in connection with the release of hydrogen sulfide gas and volatile organic compounds (“VOC’s”) in the course of our oil producing operations near the towns of Bridgeport, Illinois and Petrolia, Illinois. In June 2007, we entered a consent decree to resolve the enforcement action. The consent decree required us to take certain remedial actions to reduce hydrogen sulfide and VOC emissions and monitor the same. The consent decree did not require us to pay any civil fine or penalty, although it does provide for the possible imposition of specified daily fines and penalties for any violation of the terms and conditions of the consent decree.
	In 2010, the EPA, DOJ and Illinois EPA approved revisions we proposed to a Directed Inspection and Maintenance Plan, which had been previously implemented by us pursuant to the terms of the consent decree. In 2014, in consultation with the EPA, DOJ and Illinois EPA, we implemented additional measures under the Directed Inspection and Maintenance Plan to reflect changes in hydrogen sulfide control monitoring and procedures. We are required under the terms of the consent decree to submit quarterly reports and to annually reassess the Directed Inspection and Maintenance Plan.
	Litigation Related to Proposed Oil and Gas Leases in Clearfield County, Pennsylvania
	In October 2011, we were named as defendants in a proposed class action lawsuit filed in the Court of Common Pleas of Clearfield County, Pennsylvania (the “Cardinale case”). The named plaintiffs are two individuals who have sued on behalf of themselves and all persons who are alleged to be similarly situated. The complaint in the Cardinale case generally asserts that a binding contract to lease oil and gas interests was formed between the Company and each proposed class member when representatives of Western Land Services, Inc. (“Western”), a leasing agent that we engaged, presented a form of proposed oil and gas lease and an order for payment to each person in 2008, and each person signed the proposed oil and gas lease form and order for payment and delivered the documents to representatives of Western. We rejected these leases and never signed them. The plaintiffs seek a judgment declaring the rights of the parties with respect to those proposed leases, as well as damages and other relief as may be established by plaintiffs at trial, together with interest, costs, expenses and attorneys’ fees. We filed affirmative defenses and preliminary objections to the plaintiff’s claims, and the parties each made various responsive filings throughout the first quarter of 2012. In May 2012, the trial court dismissed the Cardinale case with prejudice on the grounds that there was no contract formed between us and the plaintiffs. The plaintiffs appealed the dismissal during the second half of 2012. On May 3, 2013, the Superior Court reversed the decision of the Common Pleas Court and remanded the case for further proceedings.
	In July 2012, while the Cardinale case was in the midst of the appeals process, counsel for the plaintiffs in the Cardinale case filed two additional lawsuits against us in the Court of Common Pleas of Clearfield County, Pennsylvania: one a proposed class action lawsuit with a different named plaintiff (the “Billotte case”) and another on behalf of a group of individually named plaintiffs (the “Meeker case”). The complaint for the Billotte case contains the same claims as those set forth in the Cardinale case. We have not yet been served with a complaint in the Meeker case, but we believe the claims will also mirror those made in the Cardinale and Billotte cases. It is our understanding that these two additional lawsuits were filed for procedural reasons in light of the dismissal of the Cardinale case and the pendency of the appeal. Proceedings in both the Billotte and Meeker cases were stayed pending the outcome of the appeal in the Cardinale case. As the Cardinale case is proceeding, we are consolidating the Billotte and Cardinale cases. We expect to make a determination as to the consolidation of the Meeker case as the Cardinale case proceeds.
	We are vigorously defending against each of these claims. We are currently in the process of conducting class discovery for the Cardinale case, and we expect to progress to class certification proceedings during the second or third quarter of 2015. At this time we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses.

Selected_Quarterly_Financial_D

Selected Quarterly Financial Data	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Data	26	SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
	The following tables set forth unaudited financial information on a quarterly basis for each of the last two years.
	REX ENERGY CORPORATION
	CONSOLIDATED STATEMENTS OF OPERATIONS
	($ and Shares in Thousands Except per Share Data)
			2014
			March			June		September		December
	Revenues		$	81,343		$	72,933	$	73,466	$	70,245
	Costs and Expenses			72,587			65,290		67,847		139,913(a)
	Net Income (Loss) From Continuing Operations			8,756			7,643		5,619		-69,668
	Net Income From Discontinued Operations, Net of Income Taxes			1,681			1,312		970		1,037
	Net Income (Loss)			10,437			8,955		6,589		-68,631
	Net Income Attributable to Noncontrolling Interests			1,569			877		895		698
	Net Income (Loss) Attributable to Rex Energy			8,868			8,078		5,694		-69,329
	Preferred Stock Dividends			—			—		—		2,335
	Net Income (Loss) Attributable to Common Shareholders		$	8,868		$	8,078	$	5,694	$	-71,664
	Income (Loss) per Common Share Attributable to Rex Energy
	Common Shareholders:
	Basic — Continuing Operations		$	0.17		$	0.14	$	0.11	$	-1.35
	Basic — Discontinued Operations			—			0.01		—		—
	Basic — Net Income (Loss)		$	0.17		$	0.15	$	0.11	$	-1.35
	Basic — Weighted Average Shares Outstanding			52,984			53,164		53,214		53,261
	Diluted — Continuing Operations		$	0.17		$	0.14	$	0.1	$	-1.35
	Diluted — Discontinued Operations			—			0.01		—		—
	Diluted — Net Income (Loss)		$	0.17		$	0.15	$	0.1	$	-1.35
	Diluted — Weighted Average Shares Outstanding			53,503			53,509		57,991		53,261
			2013
			March			June		September		December
	Revenues		$	40,964		$	51,520	$	58,127	$	63,508
	Costs and Expenses			44,488			38,280		56,469		77,265(a)
	Net Income (Loss) From Continuing Operations			(3,524	)		13,240		1,658		(13,757	)
	Net Income (Loss) From Discontinued Operations, Net of Income Taxes			1,123			721		174		(208	)
	Net Income (Loss)			(2,401	)		13,961		1,832		(13,965	)
	Net Income Attributable to Noncontrolling Interests			433			221		258		645
	Net Income (Loss) Attributable to Rex Energy		$	(2,834	)	$	13,740	$	1,574	$	(14,610	)
	Income (Loss) per Common Share Attributable to Rex Energy
	Common Shareholders:
	Basic — Continuing Operations		$	(0.06	)	$	0.25	$	0.03	$	(0.26	)
	Basic — Discontinued Operations			0.01			0.01		—		(0.02	)
	Basic — Net Income (Loss)		$	(0.05	)	$	0.26	$	0.03	$	(0.28	)
	Basic — Weighted Average Shares Outstanding			52,367			52,555		52,626		52,705
	Diluted — Continuing Operations		$	(0.06	)	$	0.25	$	0.03	$	(0.26	)
	Diluted — Discontinued Operations			0.01			0.01		—		(0.02	)
	Diluted — Net Income (Loss)		$	(0.05	)	$	0.26	$	0.03	$	(0.28	)
	Diluted — Weighted Average Shares Outstanding			52,367			52,911		53,293		52,705
	(a)	For the three-month periods ended December 31, 2014 and 2013, we incurred impairment expense of approximately $132.6 million and $29.7 million, respectively.

Condensed_Consolidating_Financ

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Financial Information	27	CONDENSED CONSOLIDATING FINANCIAL INFORMATION
	As of December 31, 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 December 31, 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, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of December 31, 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 December 31, 2014 and 2013, and the condensed consolidating statements of operations and condensed consolidating statements of cash flows for each of the years in the three-year period ended December 31, 2014.
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING BALANCE SHEETS
	FOR THE YEAR ENDED DECEMBER 31, 2014
	($ in Thousands, Except Share and Per Share Data)
			Guarantor			Non-Guarantor			Rex Energy			Eliminations			Consolidated
			Subsidiaries			Subsidiaries			Corporation						Balance
									(Note Issuer)
	ASSETS
	Current Assets
	Cash and Cash Equivalents		$	17,978		$	—		$	—		$	—		$	17,978
	Accounts Receivable			43,726			210			—			—			43,936
	Taxes Receivable			—			—			504			—			504
	Short-Term Derivative Instruments			29,265			—			—			—			29,265
	Assets Held For Sale			—			36,794			—			(2,537	)		34,257
	Inventory, Prepaid Expenses and Other			3,374			—			29			—			3,403
	Total Current Assets			94,343			37,004			533			(2,537	)		129,343
	Property and Equipment (Successful Efforts Method)
	Evaluated Oil and Gas Properties			1,084,332			467			—			(5,760	)		1,079,039
	Unevaluated Oil and Gas Properties			321,708			705			—			—			322,413
	Other Property and Equipment			45,466			895			—			—			46,361
	Wells and Facilities in Progress			127,759			456			—			(560	)		127,655
	Pipelines			17,555			—			—			(1,898	)		15,657
	Total Property and Equipment			1,596,820			2,523			—			(8,218	)		1,591,125
	Less: Accumulated Depreciation, Depletion and Amortization			(367,224	)		(730	)		—			1,037			(366,917	)
	Net Property and Equipment			1,229,596			1,793			—			(7,181	)		1,224,208
	Deferred Financing Costs and Other Assets—Net			2,421			—			14,649			—			17,070
	Equity Method Investments			17,895			—			—			—			17,895
	Long-Term Deferred Tax Asset			—			—			8,301			—			8,301
	Intercompany Receivables			—			—			951,025			(951,025	)		—
	Investment in Subsidiaries – Net			4,161			1,541			258,448			(264,150	)		—
	Long-Term Derivative Instruments			4,904			—			—			—			4,904
	Total Assets		$	1,353,320		$	40,338		$	1,232,956		$	(1,224,893	)	$	1,401,721
	LIABILITIES AND EQUITY
	Current Liabilities
	Accounts Payable		$	55,877		$	—		$	—		$	(2,537	)	$	53,340
	Current Maturities of Long-Term Debt			1,176			—			—			—			1,176
	Accrued Liabilities			46,783			571			12,124			—			59,478
	Short-Term Derivative Instruments			421			—			—			—			421
	Current Deferred Tax Liability			—			—			8,301			—			8,301
	Liabilities Related to Assets Held For Sale			—			25,115			—			—			25,115
	Total Current Liabilities			104,257			25,686			20,425			(2,537	)		147,831
	8.875% Senior Notes Due 2020			—			—			350,000			—			350,000
	6.25% Senior Notes Due 2022			—			—			325,000			—			325,000
	Premium on Senior Notes – Net			—			—			2,725			—			2,725
	Senior Secured Line of Credit and Other Long-Term Debt			251			—			—			—			251
	Long-Term Derivative Instruments			2,377			—			—			—			2,377
	Other Deposits and Liabilities			4,018			—			—			—			4,018
	Future Abandonment Cost			38,097			49			—			—			38,146
	Intercompany Payables			947,114			3,911			—			(951,025	)		—
	Total Liabilities			1,096,114			29,646			698,150			(953,562	)		870,348
	Stockholders’ Equity
	Preferred Stock			—			—			1			—			1
	Common Stock			—			—			54			—			54
	Additional Paid-In Capital			177,144			79,743			617,826			(256,887	)		617,826
	Accumulated Earnings (Deficit)			80,062			(69,253	)		(83,075	)		(18,483	)		(90,749	)
Rex Energy Stockholders’ Equity			257,206			10,490			534,806			(275,370	)		527,132
Noncontrolling Interests			—			202			—			4,039			4,241
Total Stockholders’ Equity			257,206			10,692			534,806			(271,331	)		531,373
Total Liabilities and Stockholders’ Equity		$	1,353,320		$	40,338		$	1,232,956		$	(1,224,893	)	$	1,401,721
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2014
($ in Thousands)
		Guarantor			Non-Guarantor			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Subsidiaries			Corporation						Balance
								(Note Issuer)
OPERATING REVENUE
Oil, Natural Gas and NGL Sales		$	297,710		$	159		$	—		$	—		$	297,869
Other Revenue			118			—			—			—			118
TOTAL OPERATING REVENUE			297,828			159			—			-			297,987
OPERATING EXPENSES
Production and Lease Operating Expense			100,261			21			—			-			100,282
General and Administrative Expense			30,317			83			5,737			-			36,137
Loss on Disposal of Asset			644			-			—			—			644
Impairment Expense			126,662			5,956			—			—			132,618
Exploration Expense			9,165			281			—			—			9,446
Depreciation, Depletion, Amortization and Accretion			94,643			513			—			(689	)		94,467
Other Operating (Income) Expense			134			—			—			—			134
TOTAL OPERATING EXPENSES			361,826			6,854			5,737			(689	)		373,728
INCOME (LOSS) FROM OPERATIONS			(63,998	)		(6,695	)		(5,737	)		689			(75,741	)
OTHER INCOME (EXPENSE)
Interest Expense			(142	)		-			(36,835	)		—			(36,977	)
Gain (Loss) on Derivatives, Net			37,359			—			1,517			—			38,876
Other Income			90			—			—			-			90
Loss From Equity Method Investments			(813	)		—			—			—			(813	)
Income (Loss) From Equity in Consolidated Subsidiaries			(4,278	)		4,278			(20,204	)		20,204			—
TOTAL OTHER INCOME (EXPENSE)			32,216			4,278			(55,522	)		20,204			1,176
INCOME (LOSS) FROM CONTINUING			(31,782	)		(2,417	)		(61,259	)		20,893			(74,565	)
OPERATIONS BEFORE INCOME TAX
Income Tax (Expense) Benefit			9,928			2,417			14,570			—			26,915
NET INCOME (LOSS) FROM CONTINUING OPERATIONS			(21,854	)		-			(46,689	)		20,893			(47,650	)
Loss From Discontinued Operations, Net of Income Tax						9,330						(4,330	)		5,000
NET INCOME (LOSS)			(21,854	)		9,330			(46,689	)		16,563			(42,650	)
Net Income Attributable to Noncontrolling Interests of Discontinued Operations			—			4,039			—			—			4,039
NET INCOME (LOSS) ATTRIBUTABLE TO		$	(21,854	)	$	5,291		$	(46,689	)	$	16,563		$	(46,689	)
REX ENERGY
Preferred Stock Dividends			—			-			2,335			—			2,335
NET INCOME (LOSS) ATTRIBUTABLE TO		$	(21,854	)	$	5,291		$	(49,024	)	$	16,563		$	(49,024	)
COMMON SHAREHOLDERS
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDING DECEMBER 31, 2014
($ in Thousands)
		Guarantor			Non-Guarantor			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Subsidiaries			Corporation						Balance
								(Note Issuer)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)		$	(21,854	)	$	9,330		$	(46,689	)	$	16,563		$	(42,650	)
Adjustments to Reconcile Net Income (Loss) to Net
Cash Provided by Operating Activities
Loss on Equity Method Investments			813			—			—			—			813
Non-Cash Expenses (Income)			(273	)		278			6,784			—			6,789
Depreciation, Depletion, Amortization and Accretion			94,643			4,217			—			(689	)		98,171
Deferred Income Tax Benefit			(9,928	)		(1,649	)		(14,415	)		—			(25,992	)
Gain on Derivatives			(37,359	)		—			(1,517	)		—			(38,876	)
Cash Settlements of Derivatives			5,969			—			1,312			—			7,281
Dry Hole Expense			3,797			267			—			—			4,064
(Gain) Loss on Sale of Asset			644			(55	)		—			—			589
Impairment Expense			126,662			6,022			—			—			132,684
Changes in operating assets and liabilities
Accounts Receivable			(11,450	)		(6,090	)		4,686			(766	)		(13,620	)
Inventory, Prepaid Expenses and Other Assets			(1,283	)		(74	)		(2	)		—			(1,359	)
Accounts Payable and Accrued Liabilities			23,768			3,488			9,252			766			37,274
Other Assets and Liabilities			(2,127	)		(335	)		—			—			(2,462	)
NET CASH PROVIDED BY (USED IN)			172,022			15,399			(40,589	)		15,874			162,706
OPERATING ACTIVITIES
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries			397,382			(5,412	)		(371,768	)		(20,202	)		—
Proceeds from Joint Venture Acreage Management			263			—			—			—			263
Proceeds from the Sale of Oil and Gas Properties,			254			292			—			—			546
Prospects and Other Assets
Acquisitions of Undeveloped Acreage			(168,713	)		(710	)		—			—			(169,423	)
Capital Expenditures for Development of Oil			(382,889	)		(12,861	)		—			4,328			(391,422	)
and Gas Properties and Equipment
NET CASH USED IN INVESTING ACTIVITIES			(153,703	)		(18,691	)		(371,768	)		(15,874	)		(560,036	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit			—			38,895			171,000			—			209,895
Repayments of Long-Term Debt and Lines of Credit			—			(33,152	)		(230,000	)		—			(263,152	)
Repayments of Loans and Other Notes Payable			(1,727	)		(994	)		—			—			(2,721	)
Proceeds from Senior Notes, Net of Discounts and Premiums			—			—			325,000			—			325,000
Debt Issuance Costs			—			(8	)		(6,816	)		—			(6,824	)
Proceeds from the Issuance of Preferred Stock, Net			—			—			154,988			—			154,988
Proceeds from Exercise of Stock Options			—			—			515			—			515
Distributions by the Partners of Consolidated Subsidiary			—			(1,840	)		—			—			(1,840	)
Dividends Paid on Preferred Stock									(2,335	)					(2,335	)
NET CASH PROVIDED BY (USED IN)			(1,727	)		2,901			412,352			—			413,526
FINANCING ACTIVITIES
NET INCREASE (DECREASE) IN CASH			16,592			(391	)		(5	)		—			16,196
CASH – BEGINNING			1,386			509			5			—			1,900
CASH - ENDING		$	17,978		$	118		$	-		$	-		$	18,096
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
FOR THE YEAR ENDED DECEMBER 31, 2013
($ in Thousands, Except Share and Per Share Data)
		Guarantor			Non-Guarantor			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Subsidiaries			Corporation						Balance
								(Note Issuer)
ASSETS
Current Assets
Cash and Cash Equivalents		$	1,386		$	(84	)	$	5		$	—		$	1,307
Accounts Receivable			32,284			—			—			—			32,284
Taxes Receivable			—			—			5,189			—			5,189
Short-Term Derivative Instruments			5,180			—			488			—			5,668
Current Deferred Tax Asset			—			—			3,451			—			3,451
Assets Held For Sale			—			21,645			—			(3,302	)		18,343
Inventory, Prepaid Expenses and Other			2,092			—			26			—			2,118
Total Current Assets			40,942			21,561			9,159			(3,302	)		68,360
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			908			—			—			58,317
Wells and Facilities in Progress			70,759			5,545			—			(790	)		75,514
Pipelines			7,678			—			—			—			7,678
Total Property and Equipment			1,078,012			6,453			—			(3,891	)		1,080,574
Less: Accumulated Depreciation, Depletion and Amortization			(188,699	)		(219	)		—			350			(188,568	)
Net Property and Equipment			889,313			6,234			—			(3,541	)		892,006
Deferred Financing Costs and Other Assets—Net			2,421			—			9,366			—			11,787
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		$	956,361		$	28,992		$	863,987		$	(857,944	)	$	991,396
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable		$	33,613		$	36		$	—		$	(3,304	)	$	30,345
Current Maturities of Long-Term Debt			1,340			—			—			—			1,340
Accrued Liabilities			45,196			41			2,967			—			48,204
Short-Term Derivative Instruments			4,663			—			—			—			4,663
Liabilities Related to Assets Held For Sale			—			15,461			—			—			15,461
Total Current Liabilities			84,812			15,538			2,967			(3,304	)		100,013
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			—			59,000			—			59,137
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			671,368			89,739			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		$	956,361		$	28,992		$	863,987		$	(857,944	)	$	991,396
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2013
($ in Thousands)
		Guarantor			Non-Guarantor			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Subsidiaries			Corporation						Balance
								(Note Issuer)
OPERATING REVENUE
Oil, Natural Gas and NGL Sales		$	213,919		$	—		$	—		$	—		$	213,919
Other Revenue			200			—			—			—			200
TOTAL OPERATING REVENUE			214,119			—			—			—			214,119
OPERATING EXPENSES
Production and Lease Operating Expense			62,138			12			—			—			62,150
General and Administrative Expense			25,376			43			5,420			—			30,839
Loss on Disposal of Asset			1,601			1			—			—			1,602
Impairment Expense			32,072			—			—			—			32,072
Exploration Expense			11,395			13			—			—			11,408
Depreciation, Depletion, Amortization and Accretion			62,540			46			—			(200	)		62,386
Other Operating Expense			592			—			—			—			592
TOTAL OPERATING EXPENSES			195,714			115			5,420			(200	)		201,049
INCOME (LOSS) FROM OPERATIONS			18,405			(115	)		(5,420	)		200			13,070
OTHER INCOME (EXPENSE)
Interest Expense			(64	)		—			(22,612	)		—			(22,676	)
Gain on Derivatives, Net			(2,703	)		—			(205	)		—			(2,908	)
Other Income (Expense)			6,739			—			—			—			6,739
Loss From Equity Method Investments			(763	)		—			—			—			(763	)
Income (Loss) From Equity in Consolidated Subsidiaries			(33	)		33			5,703			(5,703	)		—
TOTAL OTHER INCOME (EXPENSE)			3,176			33			(17,114	)		(5,703	)		(19,608	)
INCOME (LOSS) FROM CONTINUING			21,581			(82	)		(22,534	)		(5,503	)		(6,538	)
OPERATIONS BEFORE INCOME TAX
Income Tax (Expense) Benefit			(14,409	)		(1,841	)		20,404			—			4,154
NET INCOME (LOSS) FROM CONTINUING			7,172			(1,923	)		(2,130	)		(5,503	)		(2,384	)
OPERATIONS
Income From Discontinued Operations, Net of Income Taxes			—			4,385			—			(2,574	)		1,811
NET INCOME (LOSS)			7,172			2,462			(2,130	)		(8,077	)		(573	)
Net Income Attributable to Noncontrolling Interests of Discontinued Operations			—			1,557			—			—			1,557
NET INCOME (LOSS) ATTRIBUTABLE TO		$	7,172		$	905		$	(2,130	)	$	(8,077	)	$	(2,130	)
REX ENERGY
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDING DECEMBER 31, 2013
($ in Thousands)
		Guarantor			Non-Guarantor			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Subsidiaries			Corporation						Balance
								(Note Issuer)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)		$	7,172		$	2,462		$	(2,130	)	$	(8,077	)	$	(573	)
Adjustments to Reconcile Net Income (Loss) to Net
Cash Provided by Operating Activities
Loss on Equity Method Investments			763			—			—			—			763
Non-Cash Expenses			(194	)		55			6,369			—			6,230
Depreciation, Depletion, Amortization and Accretion			62,540			1,604			—			(200	)		63,944
Deferred Income Tax Expense (Benefit)			14,409			2,210			(14,340	)		—			2,279
Gain on Derivatives			2,703			—			205			—			2,908
Cash Settlements of Derivatives			7,128			—			—			—			7,128
Dry Hole Expense			2,993			—			—			—			2,993
(Gain) Loss on Sale of Asset			(5,289	)		(922	)		—			—			(6,211	)
Impairment Expense			32,072			—			—			—			32,072
Changes in operating assets and liabilities
Accounts Receivable			(5,877	)		(6,515	)		1,241			(1,575	)		(12,726	)
Inventory, Prepaid Expenses and Other Assets			(826	)		(59	)		—			—			(885	)
Accounts Payable and Accrued Liabilities			8,554			874			1,481			1,982			12,891
Other Assets and Liabilities			(2,272	)		(88	)		(137	)		—			(2,497	)
NET CASH PROVIDED BY (USED IN)			123,876			(379	)		(7,311	)		(7,870	)		108,316
OPERATING ACTIVITIES
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries			186,089			1,619			(193,015	)		5,307			—
Proceeds from Joint Venture Acreage Management			458			—			—			—			458
Contributions to Equity Method Investments			(2,493	)		—			—			—			(2,493	)
Proceeds from the Sale of Oil and Gas Properties,			8,071			3,234			—			—			11,305
Prospects and Other Assets
Acquisitions of Undeveloped Acreage			(41,782	)		(2	)		—			—			(41,784	)
Capital Expenditures for Development of Oil and			(275,697	)		(7,870	)		—			2,563			(281,004	)
Gas Properties and Equipment
NET CASH PROVIDED BY (USED IN)			(125,354	)		(3,019	)		(193,015	)		7,870			(313,518	)
INVESTING ACTIVITIES
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit			—			7,249			65,000			—			72,249
Repayments of Long-Term Debt and Lines of Credit			—			(2,480	)		(6,000	)		—			(8,480	)
Repayments of Loans and Other Notes Payable			(1,363	)		(642	)		—			—			(2,005	)
Proceeds from Senior Notes, net of Discounts and Premiums			—			—			105,000			—			105,000
Debt Issuance Costs			—			(8	)		(3,126	)		—			(3,134	)
Proceeds from the Exercise of Stock Options			—			—			533			—			533
Purchase of Non-Controlling Interests			—			(150	)		—			—			(150	)
Distributions by the Partners of Consolidated Subsidiary			—			(886	)		—			—			(886	)
NET CASH PROVIDED BY (USED IN)			(1,363	)		3,083			161,407			—			163,127
FINANCING ACTIVITIES
NET INCREASE (DECREASE) IN CASH			(2,841	)		(315	)		(38,919	)		—			(42,075	)
CASH – BEGINNING			4,227			824			38,924			—			43,975
CASH - ENDING		$	1,386		$	509		$	5		$	—		$	1,900
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2012
($ in Thousands)
		Guarantor			Non-Guarantor			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Subsidiaries			Corporation						Balance
								(Note Issuer)
OPERATING REVENUE
Oil, Natural Gas and NGL Sales		$	134,574		$	—		$	—		$	—		$	134,574
Other Revenue			218			—			—			—			218
TOTAL OPERATING REVENUE			134,792			—			—			—			134,792
OPERATING EXPENSES
Production and Lease Operating Expense			47,618			20			—			—			47,638
General and Administrative Expense			19,283			16			3,159			—			22,458
Loss on Disposal of Asset			50			-			—			—			50
Impairment Expense			20,505			66			—			—			20,571
Exploration Expense			4,782			—			—			—			4,782
Depreciation, Depletion, Amortization and Accretion			44,993			45			—			(83	)		44,955
Other Operating Expense			1,136			—			—			—			1,136
TOTAL OPERATING EXPENSES			138,367			147			3,159			(83	)		141,590
INCOME (LOSS) FROM OPERATIONS			(3,575	)		(147	)		(3,159	)		83			(6,798	)
OTHER INCOME (EXPENSE)
Interest Expense			(55	)		(1	)		(6,362	)		—			(6,418	)
Gain on Derivatives, Net			10,687			—			—			—			10,687
Other Income (Expense)			99,575			—			(922	)		—			98,653
Loss From Equity Method Investments			(3,921	)		—			—			—			(3,921	)
Income (Loss) From Equity in Consolidated			(68	)		68			51,363			(51,363	)		—
Subsidiaries
TOTAL OTHER INCOME (EXPENSE)			106,218			67			44,079			(51,363	)		99,001
INCOME (LOSS) FROM CONTINUING			102,643			(80	)		40,920			(51,280	)		92,203
OPERATIONS BEFORE INCOME TAX
Income Tax (Expense) Benefit			(41,772	)		(69	)		4,559			—			(37,282	)
NET INCOME (LOSS) FROM CONTINUING			60,871			(149	)		45,479			(51,280	)		54,921
OPERATIONS
Income From Discontinued Operations, Net of			—			(7,952	)		—			(671	)		(8,623	)
Income Taxes
NET INCOME (LOSS)			60,871			(8,101	)		45,479			(51,951	)		46,298
Net Income Attributable to Noncontrolling Interests of Discontinued Operations			—			819			—			—			819
NET INCOME (LOSS) ATTRIBUTABLE TO		$	60,871		$	(8,920	)	$	45,479		$	(51,951	)	$	45,479
REX ENERGY
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDING DECEMBER 31, 2012
($ in Thousands)
		Guarantor			Non-Guarantor			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Subsidiaries			Corporation						Balance
								(Note Issuer)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)		$	60,871		$	(8,101	)	$	45,479		$	(51,951	)	$	46,298
Adjustments to Reconcile Net Income (Loss) to Net
Cash Provided by Operating Activities
Loss on Equity Method Investments			3,921			—			—			—			3,921
Non-Cash Expenses			33			14			3,144			—			3,191
Depreciation, Depletion, Amortization and Accretion			44,993			527			1,004			(83	)		46,441
Deferred Income Tax Expense (Benefit)			35,376			(7,152	)		(4,559	)		—			23,665
Gain on Derivatives			(10,687	)		—			—			—			(10,687	)
Cash Settlements of Derivatives			16,219			—			—			—			16,219
Dry Hole Expense			320			336			—			—			656
(Gain) Loss on Sale of Asset			(99,355	)		(2,118	)		922			—			(100,551	)
Impairment Expense			20,505			19,850			—			—			40,355
Changes in operating assets and liabilities
Accounts Receivable			29,564			(3,736	)		(39,325	)		(201	)		(13,698	)
Inventory, Prepaid Expenses and Other Assets			(139	)		32			15			—			(92	)
Accounts Payable and Accrued Liabilities			(8,875	)		(766	)		916			(107	)		(8,832	)
Other Assets and Liabilities			(1,146	)		(64	)		—			29			(1,181	)
NET CASH PROVIDED BY (USED IN)			91,600			(1,178	)		7,596			(52,313	)		45,705
OPERATING ACTIVITIES
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries			2,915			1,931			(56,489	)		51,643			—
Proceeds from Joint Venture Acreage Management			260			—			—			—			260
Contributions to Equity Method Investments			—			(4,087	)		—			—			(4,087	)
Proceeds from the Sale of Oil and Gas Properties,			128,554			4,871			—			—			133,425
Prospects and Other Assets
Acquisitions of Undeveloped Acreage			(51,783	)		(19	)		—			—			(51,802	)
Capital Expenditures for Development of Oil			(177,892	)		(1,316	)		—			670			(178,538	)
and Gas Properties and Equipment
NET CASH PROVIDED BY (USED IN)			(97,946	)		1,380			(56,489	)		52,313			(100,742	)
INVESTING ACTIVITIES
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit			—			730			126,000			—			126,730
Repayments of Long-Term Debt and Lines of Credit			—			—			(351,000	)		—			(351,000	)
Repayments of Loans and Other Notes Payable			(764	)		(198	)		—			—			(962	)
Proceeds from Senior Notes, net of Discounts and Premiums			—			—			248,250			—			248,250
Debt Issuance Costs			—			—			(6,397	)		—			(6,397	)
Proceeds from the Exercise of Stock Options			—			—			565			—			565
Proceeds from the Issuance of Common Stock, Net of Issuance Costs			—			—			70,583			—			70,583
Settlement of Tax Withholdings Related to Share-Based Compensation Awards			—			—			(234	)		—			(234	)
Distributions by the Partners of Consolidated Subsidiary			—			(319	)		—			—			(319	)
NET CASH PROVIDED BY (USED IN)			(764	)		213			87,767			—			87,216
FINANCING ACTIVITIES
NET INCREASE (DECREASE) IN CASH			(7,110	)		415			38,874			—			32,179
CASH – BEGINNING			11,337			409			50			—			11,796
CASH - ENDING		$	4,227		$	824		$	38,924		$	—		$	43,975

Subsequent_Event

Subsequent Event	12 Months Ended
	Dec. 31, 2014
Subsequent Events [Abstract]
Subsequent Event	28. SUBSEQUENT EVENT
	In January 2015, we entered a settlement and release agreement to cancel an existing drilling rig contract. Under the provisions of the settlement and release agreement, we are obligated to pay $5.0 million in cancellation fees. We paid an initial installment of $2.5 million in January 2015 with a second and final installment of $2.5 million due on January 30, 2016. The settlement and release agreement contains provisions under which we can earn credits towards the second payment if the drilling rig is utilized by us or an unrelated third-party over the term of the original contract, which was January 1, 2015 through December 31, 2016.

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.
	Significant estimates made in preparing these Consolidated Financial Statements include, among other things, estimates of the proved oil, NGL and natural gas reserve volumes used in calculating Depletion, Depreciation and Amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment; fair values of financial derivative instruments; volumes and prices for revenues accrued; estimates of the fair value of equity-based compensation awards; deferred tax valuation allowance and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods. The significant estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates and our ability to generate future income.
Cash and Cash Equivalents	Cash and Cash Equivalents
	We consider all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents. As of December 31, 2014 and 2013, our Cash and Cash Equivalents consisted of only cash.
Accounts Receivable	Accounts Receivable
	Our trade accounts receivable, which are primarily from oil, NGLs and natural gas sales and joint interest billings, are recorded at the invoiced amount and include production receivables. The production receivable is valued at the invoiced amount and does not bear interest. Accounts receivable also include joint interest billing receivables which represent billings to the non-operators associated with the drilling and operation of wells and are based on those owners’ working interests in the wells. We have assessed the financial strength of our customers and joint owners and record an allowance for bad debts as necessary. Our allowance for bad debts as of December 31, 2014 and 2013, was negligible.
	To the extent actual quantities and values of oil, NGLs and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Accounts Receivable in the accompanying Consolidated Balance Sheets.
	At December 31, 2014, we carried approximately $25.2 million in production receivable, of which approximately $21.4 million were production receivables due from four purchasers. At December 31, 2013, we carried approximately $26.3 million in production receivables, of which approximately $22.7 million were production receivables due from four purchasers. In addition, we carried approximately $6.7 million in receivables from Sumitomo Corporation at December 31, 2014 and $4.4 million at December 31, 2013 that was in relation to our joint operations.
Inventory	Inventory
	Inventory is valued at the lower of cost or market value and consists of our ownership interest in oil and NGLs held in terminal tanks located in the field. Oil and NGL cost basis is calculated using the average cost method, with average cost defined as production and lease operating expenses net of DD&A. General and Administrative expenses are not allocated to the cost of inventory for the purpose of valuing inventory.
Oil, NGL and Natural Gas Property, Depreciation and Depletion	Oil, NGL and Natural Gas Property, Depreciation and Depletion
	We account for oil, NGL and natural gas exploration and production activities under the successful efforts method of accounting. Proved developed natural gas and oil property acquisition costs are capitalized when incurred, including our estimate of the fair value of future abandonment costs. Unproved properties with individually significant acquisition costs are assessed periodically on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop estimated proved reserves, including the costs of all development well and related equipment used in the production of oil, NGLs and natural gas, are capitalized. We capitalize interest on capital projects, most notably during the drilling and completion of oil and natural gas wells. For the years ended December 31, 2014, 2013 and 2012, we capitalized interest costs of $7.3 million, $7.5 million and $3.0 million, respectively.
	Depletion is calculated using the unit-of-production method. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. We periodically review estimated proved reserve estimates and make changes as needed to depletion expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in our estimated proved reserves. The costs of unproved properties are withheld from the depletion base until such time as they are proved. When estimated proved reserves are assigned, the cost of the property is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is allocated to the associated producing properties as the undeveloped acreage is developed. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of three to 40 years.
	We review assets for impairment when events or circumstances indicate a possible decline in the recoverability of the carrying value of such property. When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future oil, NGL and natural gas prices, operating costs, anticipated production from estimated proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Our estimates of future oil, NGL and natural gas prices are based on forward strip prices for NYMEX oil and Henry Hub natural gas. For unproved oil and gas properties, we analyze activity on the acreage prior to evaluating any fair value indicators, such as current drilling activity, drilling success, future development plans and the likelihood of expiration. Unproved oil and gas properties are impaired when it becomes more likely than not that a property will expire before it can be developed or an extension can be agreed upon. When evaluating the value of our unproved oil, NGL and natural gas properties, we analyze the level and success of current development, future development plans and changes in market value. Performing the impairment evaluations requires use of judgments and estimates since the results are dependent on future events, including estimates of future proved and unproved reserves, future commodity prices, the timing of future production, capital expenditures and the intent to develop properties, among others.
	We recognized approximately $132.6 million, $32.1 million and $20.6 million of impairment from continuing operations on certain oil, NGL and natural gas properties for the years ending December 31, 2014, 2013 and 2012, respectively. We recorded these charges as Impairment Expense on our Consolidated Statements of Operations. For additional information, see Note 18, Impairment Expense, to our Consolidated Financial Statements.
	Expenditures for repairs and maintenance to sustain production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense.
	Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reservoirs are capitalized.
	Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated DD&A are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.
Natural Gas and Oil Reserve Quantities	Natural Gas and Oil Reserve Quantities
	Our estimate of proved reserves is based on the quantities of oil, NGLs and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. For the years ended December 31, 2014 and 2013, Netherland Sewell and Associates, Inc. (“NSAI”) prepared a consolidated reserve and economic evaluation of our proved oil and gas reserves. The preparation of our proved reserve estimates are completed in accordance with our internal control procedures, which include the verification of input data used by NSAI, as well as management review and approval.
	Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Estimates of our crude oil, NGL and natural gas reserves, and the projected cash flows derived from these reserve estimates, are prepared by our engineers in accordance with guidelines established by the SEC. The independent reserve engineer estimates reserves annually on December 31. This annual estimate results in a new depletion rate, which we use for the preceding fourth quarter after adjusting for fourth quarter production.
Deferred Financing Costs and Other Assets-Net	Deferred Financing Costs and Other Assets—Net
	At December 31, 2014, we had deferred financing costs and other assets consisting of $17.1 million, which is primarily made up of bond costs and loan costs that are amortized using the effective interest method and the straight line method, respectively, over their estimated lives, which is, on average, five to eight years. We amortize any costs incurred to renew or extend the terms of existing debt over the contract term or estimated useful life, as applicable. For the years ended December 31, 2014, 2013 and 2012, we recorded amortization expense from continuing operations of $1.5 million, $1.2 million and $1.0 million, respectively.
	The following is a summary of our deferred financing costs at the dates indicated:
		December 31,			December 31,
		2014			2013
		(in thousands)			(in thousands)
	Deferred Financing Costs - Gross	$	19,212		$	12,396
	Accumulated Amortization		(4,564	)		(3,030	)
	Deferred Financing Costs - Net	$	14,648		$	9,366
	Specific to our deferred financing costs, we have incurred gross debt issuance costs of approximately $6.8 million and $3.1 million for the years ended December 31, 2014 and 2013, respectively, which are presented net of accumulated amortization of $4.6 million and $3.0 million, respectively, and include deferred financing from our senior notes.
Future Abandonment Cost	Future Abandonment Cost
	Future abandonment costs are recognized as obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost.
	Accretion expense from continuing operations during the years ended December 31, 2014, 2013 and 2012 totaled approximately $3.6 million, $3.0 million and $2.1 million, respectively. These amounts are recorded as DD&A on our Consolidated Statements of Operations. As of December 31, 2014 and 2013, approximately $2.0 million and $2.5 million, respectively, of our Future Abandonment Costs were classified as short-term liabilities under the caption Accrued Expenses on our Consolidated Balance Sheets. During 2014 and 2013, we recognized an increase of $8.4 million and $1.3 million, respectively, in the estimated present value of our asset retirement obligations, representing an increase in the estimate to plug and abandon our oil and natural gas wells. The revised estimates were primarily the result of increased abandonment cost estimates, which were driven by the trends of actual outcomes. We account for asset retirement obligations that relate to wells that are drilled jointly based on our interest in those wells.
		December 31,			December 31,
		2014			2013
		(in thousands)			(in thousands)
	Beginning Balance	$	28,525		$	24,822
	Asset Retirement Obligation Incurred		1,480			1,750
	Asset Retirement Obligation Settled		(1,943	)		(2,452	)
	Asset Retirement Obligation Cancelled or Sold Properties		(10	)		—
	Asset Retirement Obligation Revision of Estimated Obligation		8,426			1,311
	Asset Retirement Obligation Accretion Expense		3,621			3,094
	Total Future Abandonment Costs	$	40,099		$	28,525
Revenue Recognition	Revenue Recognition
	Oil, NGL and natural gas revenue is recognized when the oil, NGL or natural gas is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil and NGL sales, title is transferred to the purchaser when the oil or NGLs leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. It is the measurement of the purchaser that determines the amount of oil, NGL or natural gas purchased. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for oil, NGLs and natural gas purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our oil, NGL and natural gas production is at its applicable field gathering system. We do not recognize revenue for oil and NGL production held in stock tanks before delivery to the purchaser.
	To the extent actual quantities and values of oil, NGLs and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Oil, Natural Gas and NGL Sales on the Statements of Operations.
	For Water Solutions, our services are generally sold based upon purchase orders, contracts or other agreements with customers that include fixed or determinable prices. We recognize revenue when services are performed and collection of the relevant receivables is probable. We contract for services either on a day rate or other contracted rate. In certain situations, revenue is generated from transactions that may include multiple products and services under one contract or agreement and which may be delivered to the customer over an extended period of time. Revenue from these arrangements is recognized in accordance with the above criteria and as each item or service is delivered.
Derivative Instruments	Derivative Instruments
	We use put and call options (collars), fixed rate swap contracts, swaptions, puts, deferred put spreads, cap swaps, call protected swaps, basis swaps and three-way collars to manage price risks in connection with the sale of oil, natural gas and NGLs. We have also used interest rate swap agreements to manage interest rate exposure associated with our fixed rate senior notes. We have established the fair value of all derivative instruments using estimates determined by our counterparties and other third-parties. These values are based upon, among other things, future prices, volatility, time to maturity and credit risk. The values we report in our Consolidated Financial Statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.
	We report our derivative instruments at fair value and include them in the Consolidated Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated for hedge accounting, for financial accounting purposes, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness are recognized immediately in earnings. During 2014, 2013 and 2012 we did not have any derivative instruments designated for hedge accounting.
	For derivative instruments designated as fair value hedges, changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Derivative effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. For derivatives on oil, natural gas and NGL production activity, our evaluations are not documented, and as a result, we record changes on the derivative valuations through earnings. For additional information on our derivative instruments, see Note 12, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements.
Contingent Liabilities	Contingent Liabilities
	A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information.
Income Taxes	Income Taxes
	We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed several months after the close of a calendar year, tax returns are subject to audit which can take years to complete, and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards and other deductible differences and deferred tax liabilities that relate to oil and gas properties and other taxable differences.
	Deferred tax assets and liabilities are computed based on the difference between the financial statement and income tax bases of assets and liabilities using the enacted tax rate. Net deferred tax assets are required to be reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the net deferred tax asset will not be realized.
	This process requires our management to make assessments regarding the timing and probability of the ultimate tax impact. We record valuation allowances on deferred tax assets if we determine it is more likely than not that the asset will not be realized. Actual income taxes could vary from these estimates due to future changes in income tax law, significant changes in the jurisdictions in which we operate, our inability to generate sufficient future taxable income, or unpredicted results from the final determination of each year’s liability by taxing authorities. These changes could have a significant impact on our financial position.
	The accounting estimate related to the tax valuation allowance requires us to make assumptions regarding the timing of future events, including the probability of expected future taxable income and available tax planning opportunities. These assumptions require significant judgment because actual performance has fluctuated in the past and may do so in the future. The impact that changes in actual performance versus these estimates could have on the realization of tax benefits as reported in our results of operations could be material. We continuously evaluate facts and circumstances representing positive and negative evidence in the determination of our ability to realize the deferred tax assets.
	We recognize a tax position if it is more likely than not that it will be sustained upon examination. If we determine it is more likely than not a tax position will be sustained based on its technical merits, we record the impact of the position in our Consolidated Financial Statements at the largest amount that is greater than fifty percent likely of being realized upon ultimate settlement. These estimates are updated at each reporting date based on the facts, circumstances and information available. We are also required to assess at each reporting date whether it is reasonably possible that any significant increases or decreases to the unrecognized tax benefits will occur during the next twelve months (for additional information, see Note 13, Income Taxes, to our Consolidated Financial Statements). Our policy is to recognize interest and penalties on any unrecognized tax benefits in interest expense and general and administrative expense, respectively.
Stock-based Compensation	Stock-based Compensation
	We recognize in the Consolidated Financial Statements the cost of employee and non-employee director services received in exchange for awards of equity instruments based on the grant date fair value of those awards. We use a standard option pricing model (i.e. Black-Scholes) to measure the fair value of employee stock options and stock appreciation rights and a Monte Carlo simulation technique to value restricted stock awards that are tied to market performance. The fair value of non-market based restricted stock awards is determined based on the fair market value of our common stock on the date of the grant.
	The benefits associated with the tax deductions in excess of recognized compensation cost are reported as a financing cash flow when realized. We recognize compensation costs related to awards with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award were, in-substance, multiple awards (for additional information, see Note 17, Employee Benefit and Equity Plans, to our Consolidated Financial Statements). Stock appreciation rights are classified as a liability and are re-measured at fair value each reporting period.
Earnings per Common Share	Earnings per Common Share
	Earnings per common share are computed by dividing consolidated net income attributable to us by the weighted average number of common shares outstanding. Diluted earnings per common share are computed based upon the weighted average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities, including the assumed conversion of preferred stock. At December 31, 2014, we had 54,174,763 common shares outstanding, 402,561 options outstanding and 20,500 stock appreciation rights outstanding with no outstanding warrants or other potentially dilutive securities. The total common shares outstanding include 1,519,301 restricted stock awards, of which approximately 848,447 shares are performance-based awards. For additional information, see Note 14, Earnings per Common Share, to our Consolidated Financial Statements.
Recent Accounting Pronouncements	Recent 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.

Summary_Of_Significant_Account2

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Summary of Deferred Financing Costs	The following is a summary of our deferred financing costs at the dates indicated:
		December 31,			December 31,
		2014			2013
		(in thousands)			(in thousands)
	Deferred Financing Costs - Gross	$	19,212		$	12,396
	Accumulated Amortization		(4,564	)		(3,030	)
	Deferred Financing Costs - Net	$	14,648		$	9,366
Asset Retirement Obligations	We account for asset retirement obligations that relate to wells that are drilled jointly based on our interest in those wells.
		December 31,			December 31,
		2014			2013
		(in thousands)			(in thousands)
	Beginning Balance	$	28,525		$	24,822
	Asset Retirement Obligation Incurred		1,480			1,750
	Asset Retirement Obligation Settled		(1,943	)		(2,452	)
	Asset Retirement Obligation Cancelled or Sold Properties		(10	)		—
	Asset Retirement Obligation Revision of Estimated Obligation		8,426			1,311
	Asset Retirement Obligation Accretion Expense		3,621			3,094
	Total Future Abandonment Costs	$	40,099		$	28,525

Business_and_Oil_and_Gas_Prope1

Business and Oil and Gas Property Acquisitions and Dispositions (Tables)	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Summary of Acquisition Price Allocated	The acquisition price was allocated as follows:
	($ in Thousands)	December 31,
		2014
	Evaluated Oil and Gas Properties	$	6,968
	Unevaluated Oil and Gas Properties		88,351
	Wells and Facilities in Progress		25,244
	Purchase Price	$	120,563

Discontinued_OperationsAssets_1

Discontinued Operations/Assets Held For Sale (Tables)	12 Months Ended
	Dec. 31, 2014
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Summary of Financial Information for Discontinued Operations	The carrying value of the assets and liabilities of Water Solutions Holdings, LLC that are classified as held for sale in the accompanying Consolidated Balance Sheets at December 31, 2014 and December 31, 2013 are as follows:
		December 31,
	($ in Thousands)	2014			2013
	Assets:
	Cash and Cash Equivalents	$	118		$	593
	Accounts Receivable		13,226			6,579
	Inventory, Prepaid Expenses and Other		163			89
	Total Current Assets		13,507			7,261
	Other Property and Equipment, Net		19,690			9,845
	Wells and Facilities in Progress		688			1,031
	Intangible Assets, Net		372			206
	Total Long-Term Assets		20,750			11,082
	Total Assets Held for Sale	$	34,257		$	18,343
	Liabilities:
	Accounts Payable		3,694			758
	Current Maturities of Long-Term Debt		6,236			5,403
	Accrued Liabilities		6,304			6,246
	Total Current Liabilities		16,234			12,407
	Senior Secured Line of Credit and Long-Term Debt		8,881			3,054
	Long-Term Liabilities		8,881			3,054
	Total Liabilities Related to Assets Held for Sale	$	25,115		$	15,461
	Net Assets Held for Sale:	$	9,142		$	2,882
Water Solutions Holdings, LLC
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Summary of Financial Information for Discontinued Operations	Summarized financial information for Discontinued Operations related to Water Solutions is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support.
		December 31,
	($ in Thousands)	2014			2013			2012
	Revenues:
	Field Services Revenue	$	58,627		$	23,812		$	13,403
	Other Revenue (Expense)		—			—			(56	)
	Total Operating Revenue		58,627			23,812			13,347
	Costs and Expenses:
	General and Administrative Expense		4,081			2,287			887
	Depreciation, Depletion, Amortization and Accretion		3,703			1,559			482
	Impairment Expense		67			—			14
	Field Service Operating Expense		44,369			17,318			8,240
	(Gain) Loss on Disposal of Asset		(55	)		46			8
	Interest Expense		628			106			26
	Other Expense		66			84			103
	Total Costs and Expenses		52,859			21,400			9,760
	Income from Discontinued Operations Before Income Taxes		5,768			2,412			3,587
	Income Tax Expense		(768	)		(369	)		(1,267	)
	Income from Discontinued Operations, net of taxes	$	5,000		$	2,043		$	2,320
DJ Basin
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Summary of Financial Information for Discontinued Operations	Summarized financial information for Discontinued Operations related to our DJ Basin assets is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support.
		December 31,
	($ in Thousands)	2014			2013			2012
	Revenues:
	Oil, Natural Gas and NGL Sales	$	—		$	25		$	97
	Total Operating Revenue		—			25			97
	Costs and Expenses:
	Production and Lease Operating Expense		—			104			353
	General and Administrative Expense		—			23			660
	Exploration Expense		—			97			867
	Impairment Expense		—			—			19,770
	Other Operating Expense (Income)		—			(3	)		8
	Gain on Disposal of Asset		—			(969	)		(2,126	)
	Other Income		—			—			(3	)
	Total Costs and Expenses (Income)		—			(748	)		19,529
	Income (Loss) from Discontinued Operations Before Income Taxes		—			773			(19,432	)
	Income Tax (Expense) Benefit		—			(1,005	)		8,489
	Income (Loss) from Discontinued Operations, net of taxes	$	—		$	(232	)	$	(10,943	)
	Production:
	Crude Oil (Bbls)		—			356			1,272

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments And Contingencies Disclosure [Abstract]
Lease Commitments for Each of Next Five Years	At December 31, 2014 we have lease commitments for various real estate leases. Rent expense from continuing operations has been recorded in General and Administrative expense as $0.8 million, $0.6 million and $0.3 million for the years ended December 31, 2014, 2013 and 2012, respectively. Lease commitments by year for each of the next five years are presented in the table below.
	($ in Thousands)
	2015		$	1,075
	2016			1,129
	2017			1,143
	2018			721
	2019			721
	Thereafter			180
	Total		$	4,969
Minimum Net Obligations under Sales, Gathering and Transportation Agreements	Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows:
	($ in Thousands)		Total
	2015		$	21,951
	2016			34,199
	2017			52,296
	2018			55,113
	2019			53,963
	Thereafter			692,320
	Total		$	909,842
Fee for Unconventional Gas Wells	The fee for each unconventional natural gas well is determined using the following matrix, with vertical unconventional natural 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 fees is based on the arithmetic mean of the NYMEX settled price for the near-month contract as reported by the Wall Street Journal for the last trading day of each month of a calendar year for the year ending December 31.

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Components of Long-Term Debt and Lines of Credit	Long-term debt and other obligations consisted of the following at December 31, 2014 and December 31, 2013:
	($ in Thousands)		December 31,			December 31,
			2014			2013
	8.875% Senior Notes Due 2020		$	350,000		$	350,000
	6.25% Senior Notes Due 2022			325,000			—
	Premium on Senior Notes, Net			2,725			3,078
	Senior Line of Credit(a)			—			59,000
	Capital Leases and Other Obligations(a)			1,427			1,477
	Total Debt			679,152			413,555
	Less Current Portion of Long-Term Debt			(1,176	)		(1,340	)
	Total Long-Term Debt		$	677,976		$	412,215
	(a)	The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2014 and 2013 was approximately 2.2 % and 1.9%, respectively. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2014 and 2013 was approximately 4.0% and 5.3%, respectively.
Principal Maturity Schedule for Total Debt Outstanding	The following is the principal maturity schedule for total debt outstanding as of December 31, 2014:
	($ in thousands)		Year Ended
			December 31,
	2015		$	1,176
	2016			251
	2017			—
	2018			—
	2019			—
	Thereafter			675,000
	Total1		$	676,427
	1	Does not include $2.7 million net premium on Senior Notes.

Fair_Value_Of_Financial_Instru1

Fair Value Of Financial Instruments And Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 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 years ended December 31, 2014, 2013 and 2012:
		For the Year Ended December 31,
	($ in Thousands)	2014				2013				2012
	Oil	$	8,613			$	(2,798	)		$	1,579
	Natural Gas		18,406				1,807				8,162
	NGLs		10,340				(1,711	)			946
	Interest Rate		1,517				(206	)			—
	Gain (Loss) on Derivatives, Net	$	38,876			$	(2,908	)		$	10,687
Asset or Liability Financial Commodity Derivative Instrument Positions	Our open asset/(liability) financial commodity derivative instrument positions at December 31, 2014 consisted of the following:
	Period	Volume		Put Option				Floor				Ceiling				Swap			Long Call		Fair Market
																					Value ($ in
																					Thousands)
	Oil
	2015 - Deferred Put Spreads	180,000 Bbls		$	73.08			$	83.33			$	—			$	—		$	—	$	1,413
	2015 - Call Protected Swaps	30,000 Bbls			—				—				—				95.76			110		1,227
	2015 - Three-Way Collars	675,000 Bbls			53.44				67.89				75.67				—			—		4,596
		885,000 Bbls																			$	7,236
	Natural Gas
	2015 - Swaps	6,300,000 Mcf		$	—			$	—			$	—			$	3.96		$	—	$	4,522
	2015 - Swaptions	0 Mcf			—				—				—				—			—		(154	)
	2015 - Cap Swaps	8,400,000 Mcf			3.43				—				—				4.13			—		3,430
	2015 - Three-Way Collars	13,500,000 Mcf			3.59				4.12				4.52				—			—		5,081
	2015 - Calls	2,400,000 Mcf			—				—				4.4				—			—		(74	)
	2015 - Basis Swaps	10,380,000 Mcf			—				—				—				(0.77	)		—		2,622
	2016 - Swaps	1,500,000 Mcf			—				—				—				4.05			—		194
	2016 - Cap Swaps	3,600,000 Mcf			3.45				—				—				4.11			—		884
	2016 - Three-Way Collars	4,500,000 Mcf			3.56				4.09				4.43				—			—		1,277
	2016 - Calls	7,320,000 Mcf			—				—				4.35				—			—		(1,096	)
	2016 - Basis Swaps	7,320,000 Mcf			—				—				—				(0.83	)		—		(257	)
	2017 - Swaps	1,500,000 Mcf			—				—				—				4.05			—		194
	2017 - Cap Swaps	2,100,000 Mcf			3.34				—				—				4.07			—		412
	2017 - Three-Way Collars	1,800,000 Mcf			3.58				4.1				4.5				—			—		456
	2017 - Basis Swaps	7,300,000 Mcf			—				—				—				(0.83	)		—		(256	)
	2018 - Swaps	2,100,000 Mcf			—				—				—				4.05			—		272
	2018 - Cap Swaps	1,800,000 Mcf			3.3				—				—				4.05			—		321
	2018 - Basis Swaps	7,300,000 Mcf			—				—				—				(0.83	)		—		(256	)
	2019 - Swaps	2,100,000 Mcf			—				—				—				4.05			—		272
	2019 - Basis Swaps	7,300,000 Mcf			—				—				—				(0.83	)		—		(256	)
	2020 - Swaps	2,400,000 Mcf			—				—				—				4.05			—		311
	2020 - Basis Swaps	7,320,000 Mcf			—				—				—				(0.83	)		—		(256	)
	2021 - Swaps	2,400,000 Mcf			—				—				—				4.05			—		311
		110,640,000 Mcf																			$	17,954
	NGLs
	2015 - Propane Swaps	258,000 Bbls		$	—			$	—			$	—			$	44.52		$	—	$	5,897
	2015 - Ethane Swaps	109,500 Bbls			—				—				—				10.08			—		284
		367,500 Bbls																			$	6,181
Combined Fair Value of Derivatives	The combined fair value of our derivatives included in our Consolidated Balance Sheets as of December 31, 2014 and December 31, 2013 is summarized below.
		December 31,				December 31,
	($ in Thousands)	2014				2013
	Short-Term Derivative Assets:
	Crude Oil—Collars	$	—			$	380
	Crude Oil—Call Protected Swap		1,227				—
	Crude Oil—Deferred Put Spread		1,413				—
	Crude Oil—Three-Way Collars		4,596				104
	NGL—Swaps		6,181				83
	Natural Gas—Swaps		4,522				106
	Natural Gas—Cap Swaps		3,430				5
	Natural Gas—Basis Swaps		2,815				3,984
	Natural Gas—Three-Way Collars		5,081				518
	Interest Rate—Swap		—				488
	Total Short-Term Derivative Assets	$	29,265			$	5,668
	Long-Term Derivative Assets:
	Natural Gas—Cap Swaps	$	1,617			$	5
	Natural Gas—Swaps		1,554				22
	Natural Gas—Basis Swaps		—				339
	Natural Gas—Three-Way Collars		1,733				169
	Total Long-Term Derivative Assets	$	4,904			$	535
	Total Derivative Assets	$	34,169			$	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		—				(585	)
	NGL—Swaps		—				(995	)
	Natural Gas—Three-Way Collars		—				(125	)
	Natural Gas—Collars		—				(235	)
	Natural Gas—Basis Swaps		(193	)			—
	Natural Gas—Call		(74	)			(150	)
	Natural Gas—Cap Swaps		—				(496	)
	Natural Gas—Swaption		(154	)			(717	)
	Natural Gas—Swaps		—				(1,170	)
	Total Short - Term Derivative Liabilities	$	(421	)		$	(4,663	)
	Long-Term Derivative Liabilities:
	Natural Gas—Swaps	$	—			$	(4	)
	Natural Gas—Cap Swaps		—				(307	)
	Natural Gas—Basis Swaps		(1,281	)			—
	Natural Gas—Call		(1,096	)			(761	)
	Interest Rate—Swap		—				(693	)
	Total Long-Term Derivative Liabilities	$	(2,377	)		$	(1,765	)
	Total Derivative Liabilities	$	(2,798	)		$	(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 December 31, 2014 are included in the table below.
		As of December 31, 2014
		Range		Weighted				Fair Value
		(price per Mcf)		Average				(in thousands)
				(price per Mcf)
	Natural Gas Basis Differential Forward Curve	($0.27) - ($1.39)		$	(0.84	)		$	1,341
		As of December 31, 2013
		Range		Weighted				Fair Value
		(price per Mcf)		Average				(in thousands)
				(price per Mcf)
	Natural Gas Basis Differential Forward Curve	($0.78) - ($1.08)		$	(0.91	)		$	4,323
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 December 31, 2014 Using:
	($ in Thousands)	Total Carrying				Quoted Prices				Significant				Significant
		Value as of				in Active				Other				Unobservable
		December 31,				Markets for				Observable				Inputs
		2014				Identical Assets				Inputs				(Level 3)
						(Level 1)				(Level 2)
	Commodity Derivatives	$	31,371			$	—			$	30,030			$	1,341
						Fair Value Measurements at December 31, 2013 Using:
	($ in Thousands)	Total Carrying				Quoted Prices				Significant				Significant
		Value as of				in Active				Other				Unobservable
		December 31,				Markets for				Observable				Inputs
		2013				Identical Assets				Inputs				(Level 3)
						(Level 1)				(Level 2)
	Commodity Derivatives	$	(20	)		$	—			$	(4,343	)		$	(4,323	)
	Interest Rate Swap	$	(205	)		$	—			$	(205	)		$	—
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 years ended December 31, 2014 and 2013 (in thousands):
		For the Year Ended December 31,
	($ in Thousands)	2014				2013
	Beginning Balance of Level 3	$	4,323			$	—
	Changes in Fair Value		(1,670	)			4,328
	Purchases		—				—
	Settlements Received		(1,312	)			(5	)
	Ending Balance of Level 3	$	1,341			$	4,323
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:
		31-Dec-14								31-Dec-13
	($ in Thousands)	Carrying				Fair Value				Carrying				Fair Value
		Amount								Amount
	8.875% Senior Notes due 2020	$	350,000			$	311,955			$	350,000			$	385,000
	6.25% Senior Notes due 2022		325,000				241,313				—				—
	Secured Lines of Credit		—				—				59,000				59,000
	Capital Leases and Other Obligations		1,427				1,393				1,477				1,449
	Total	$	676,427			$	554,661			$	410,477			$	445,449

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Tax Expense (Benefit) from Continuing Operations	Our income tax expense (benefit) from continuing operations consisted of the following:
			For the Years Ended December 31,
	($ in Thousands)		2014			2013			2012
	Current:
	Federal		$	—		$	(1,936	)	$	2,350
	State			6			(4,105	)		5,608
	Deferred:
	Federal			-23,691			509			27,312
	State			-3,230			1,378			2,012
	Income Expense (Benefit)		$	-26,915		$	(4,154	)	$	37,282
Reconciliation of Income Tax Expense (Benefit) Using Statutory Rate Compared With Actual Income Tax Expense	A reconciliation of income tax expense (benefit) using the statutory U.S. income tax rate compared with actual income tax expense is as follows:
	($ in Thousands)		Year Ended			Year Ended			Year Ended
			December 31,			December 31,			December 31,
			2014			2013			2012
	Income (loss) from continuing operations before		$	(74,565	)	$	(6,538	)	$	92,203
	noncontrolling interests and income taxes
	Statutory U.S. income tax rate			35	%		35	%		35	%
	Tax expense recognized using statutory U.S. income tax rate		$	(26,098	)	$	(2,288	)	$	32,271
	Change in estimated future state rates			(1,015	)		(484	)		(7	)
	Permanent differences			363			83			52
	Change in valuation allowances			2,450			(160	)		(131	)
	Other			608			(500	)		(493	)
	Adjusted federal income tax expense (benefit)		$	(23,692	)	$	(3,349	)	$	31,692
	State income tax expense  (benefit)			(3,223	)		(805	)		5,590
	Total income tax expense (benefit)		$	(26,915	)	$	(4,154	)	$	37,282
	Effective income tax rate			36.1	%		63.5	%		40.4	%
Components of Deferred Tax Assets (Liabilities)	Deferred tax assets (liabilities) are comprised of the following at December 31, 2014 and 2013:
			For the Years Ended
			December 31,
	($ in Thousands)		2014			2013
	Tax effects of temporary differences for:
	Current:
	Assets:
	Asset retirement obligation		$	772		$	997
	Deferred compensation plans			695			2,593
	Compensation accruals			2,087			—
	Valuation allowances			(71	)		—
	Other			68			370
	Total gross current deferred tax assets			3,551			3,960
	Liabilities:
	Unrealized gain on derivatives			(11,410	)		(404	)
	Other			(442	)		(105	)
	Total gross current deferred tax liabilities			(11,852	)		(509	)
	Net total current deferred tax asset (liability)		$	(8,301	)	$	3,451
	Long-Term:
	Assets:
	Asset retirement obligation		$	15,091		$	10,445
	Deferred compensation plans			2,218			1,513
	Net operating loss carryforward(a)			73,531			48,703
	Organization costs			525			602
	Deferred revenue			1,209			1,338
	AMT credits			292			292
	Unrealized gain on derivatives			—			493
	Valuation allowances			(4,318	)		(1,965	)
	Other			269			232
	Total gross long-term deferred tax assets			88,817			61,653
	Liabilities:
	Timing differences - tax partnerships			(7,135	)		(7,474	)
	Book basis of oil and gas properties in excess of			(71,402	)		(83,594	)
	tax basis
	Unrealized gain on derivatives			(999	)		—
	Other			(980	)	$	(31	)
	Total gross long-term deferred tax liabilities			(80,516	)		(91,099	)
	Net total long-term deferred tax asset (liability)		$	8,301		$	(29,446	)
	(a)	As a result of certain realization requirements of FASB ASC 718, the table of deferred tax assets and liabilities does not include $1.3 million and $0.4 million at December 31, 2014 and 2013, respectively, of excess tax benefits that arose directly from tax deductions related to stock-based compensation greater than compensation recognized for financial reporting. Total stockholders’ equity will be increased by $1.3 million if and when such excess tax benefits are ultimately realized.
Expirations by Year for Federal and State Net Operating Loss Carryforwards	The following table shows expirations by year for federal and state net operating loss carryforwards (all figures presented are tax effected):
	Year of Expiration		Net Operating
			Loss Carryforwards
			(in thousands)
	2020		$	134
	2021			175
	2022			—
	2023			899
	2024			—
	2025			531
	2026			600
	2027			—
	2028			3,333
	2029			767
	2030			751
	2031			19,746
	2032			253
	2033			19,703
	2034			26,639
	Total			73,531

Earnings_Per_Common_Share_Tabl

Earnings Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Computation of Basic and Diluted Earning Per Common Share	The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share data):
		Year Ended			Year Ended			Year Ended
		December 31,			December 31,			December 31,
	(in thousands, except per share amounts)	2014			2013			2012
	Numerator:
	Net Income (Loss) From Continuing Operations	$	(47,650	)	$	(2,384	)	$	54,921
	Net Income (Loss) From Discontinued Operations, Less Noncontrolling Interests		961			254			(9,442	)
	Less: Preferred Stock Dividends		2,335			—
	Net Income (Loss) Attributable to Common Shareholders	$	(49,024	)	$	(2,130	)	$	45,479
	Denominator:
	Weighted Average Common Shares Outstanding - Basic		53,150			52,572			51,543
	Effect of Dilutive Securities:
	Employee Stock Options		—			—			69
	Employee Performance-Based Restricted Stock Awards		—			—			413
	Effect of Assumed Conversions of Preferred Stock		—			—			—
	Weighted Average Common Shares Outstanding - Diluted		53,150			52,572			52,025
	Earnings per Common Share Attributable to Rex Energy Common Shareholders (a):
	Basic — Net Income (Loss) From Continuing Operations	$	(0.94	)	$	(0.05	)	$	1.06
	— Net Income (Loss) From Discontinued Operations		0.02			0.01			(0.18	)
	— Net Income (Loss) Attributable to Rex Energy Common Shareholders	$	(0.92	)	$	(0.04	)	$	0.88
	Diluted — Net Income (Loss) From Continuing Operations	$	(0.94	)	$	(0.05	)	$	1.06
	— Net Income (Loss) From Discontinued Operations		0.02			0.01			(0.18	)
	— Net Income (Loss) Attributable to Rex Energy Common Shareholders	$	(0.92	)	$	(0.04	)	$	0.88

Recovered_Sheet1

Employee Benefit And Equity Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Stock Option Activity	A summary of the stock option activity is as follows:
			Number of				Weighted-Average				Weighted-Average				Aggregate Intrinsic
			Shares				Exercise Price				Remaining Term				Value
											(in years)				(in thousands)
	Options outstanding December 31, 2011			698,327			$	12.94
	Granted			—				—
	Exercised			(52,287	)			10.8
	Cancelled/Forfeited			(143,787	)			20.71
	Options outstanding December 31, 2012			502,253			$	10.95
	Granted			—				—
	Exercised			(49,166	)			10.85
	Cancelled/Forfeited			(4,000	)			23.28
	Options outstanding December 31, 2013			449,087			$	10.85
	Granted			—				—
	Exercised			(46,526	)			11.09
	Cancelled/Forfeited			—				—
	Options Outstanding December 31, 2014			402,561			$	10.82				2.9			$	2.8
	Options Exercisable December 31, 2014			402,561			$	10.82				2.9			$	2.8
Summary of Issued and Outstanding Stock Options	A summary of the status of our issued and outstanding stock options as of December 31, 2014 is as follows:
					Outstanding								Exercisable
	Exercise Price				Number				Weighted-Average				Number				Weighted-Average
					Outstanding				Exercise Price				Exercisable				Exercise Price
					At 12/31/14								At 12/31/14
	$	5.04				46,041			$	5.04				46,041			$	5.04
	$	9.5				75,000			$	9.5				75,000			$	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				50,000			$	13.19
	$	22.34				30,000			$	22.34				30,000			$	22.34
						402,561			$	10.82				402,561			$	10.82
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 and 2014
			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	Average fair values were estimated on the date of each grant using a Monte Carlo Simulation model that estimates the most likely outcome based on the terms of the award and used the following assumptions:
			Year Ended				Year Ended
			December 31,				31-Dec-13
			2014
	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 years ended December 31, 2014, 2013 and 2012 is as follows:
			Number of				Weighted-Average
			Shares				Grant Date
							Fair Value
	Restricted stock awards, as of January 1, 2012			1,229,826			$	12.11
	Awards			425,209				11.59
	Vested			(70,750	)			2.05
	Forfeitures			(152,712	)			12.13
	Restricted stock awards, as of December 31, 2012			1,431,573			$	12.45
	Awards			981,544				16.03
	Vested			(182,994	)			11.59
	Forfeitures			(57,484	)			11.84
	Restricted stock awards, as of December 31, 2013			2,172,639			$	14.16
	Awards			131,610				8.76
	Vested			(595,085	)			13.09
	Forfeitures			(189,863	)			14.6
	Restricted stock awards, as of December 31, 2014			1,519,301			$	14.05

Suspended_Exploratory_Well_Cos1

Suspended Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Net Change in Capitalized Exploratory Well Costs	The following table reflects the net change in capitalized exploratory well costs, excluding those related to Assets Held for Sale on our Consolidated Balance Sheets for the years ended December 31, 2014, 2013 and 2012 ($ in thousands):
		2014			2013			2012
	Beginning Balance at January 1,	$	5,731		$	36,968		$	11,756
	Additions to capitalized exploratory well costs		258,097			171,087			95,980
	pending the determination of estimated
	proved reserves
	Divested wells		—			—			—
	Reclassification of wells, facilities, and equipment		(240,494	)		(202,323	)		(70,518	)
	based on the determination of estimated
	proved reserves
	Capitalized exploratory well costs charged to expense		(233	)		(1	)		(250	)
	Ending Balance at December 31,		23,101			5,731			36,968
	Less exploratory well costs that have been capitalized		(20,407	)		(3,597	)		(36,630	)
	for a period of one year or less
	Capitalized exploratory well costs for a period of greater	$	2,694		$	2,134		$	338
	than one year
	Number of projects that have exploratory well costs		6			3			2
	capitalized for a period of more than one year

Costs_Incurred_In_Oil_And_Natu1

Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities (Tables)	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Costs Incurred in Oil and Natural Gas Property Acquisitions and Development	Costs incurred in oil and natural gas property acquisitions and development are presented below and exclude any costs incurred related to Assets Held for Sale (in thousands):
			2014			2013			2012
	Consolidated Entities:
	Acquisition of Properties
	Proved		$	161		$	2,445		$	1,474
	Unproved			169,408			39,291			49,331
	Exploration Costs(a)			316,235			231,112			128,748
	Development Costs(a)			71,383			64,661			57,149
	Subtotal			557,187			337,509			236,702
	Asset Retirement Obligations			9,110			3,031			4,480
	Total Costs Incurred		$	566,297		$	340,540		$	241,182
	Share of Equity Method Investments:
	Acquisition of Properties
	Proved		$	—		$	—		$	—
	Unproved			—			—			—
	Exploration Costs			—			—			—
	Development Costs(a)			438			1,958			4,316
	Total		$	438		$	1,958		$	4,316
	(a)	Includes Depreciation expense for support equipment and facilities
Reconciliation of Total Costs Incurred for Consolidated Entities to Reported Capital Expenditures	The following table provides a reconciliation of the total costs incurred for our consolidated entities to our reported capital expenditures (in thousands):
			2014			2013			2012
	Total Costs Incurred by Consolidated Entities		$	566,297		$	340,540		$	241,182
	Equity Method Investments			—			2,493			4,087
	DJ Basin Expenditures			—			2			3,146
	Exploration Expense			(9,446	)		(11,408	)		(4,782	)
	Asset Retirement Obligations			(9,110	)		(3,031	)		(4,480	)
	Depreciation for Support Equipment and Facilities			(6,075	)		(5,024	)		(4,187	)
	Corporate Expenditures			869			3,651			1,156
	Other (a)			7,223			10,391			2,732
	Total Capital Expenditures		$	549,758		$	337,614		$	238,854
	(a)	Represents R.E. Disposal, LLC capital and intercompany capital transactions.

Oil_And_Natural_Gas_Capitalize1

Oil And Natural Gas Capitalized Costs (Tables)	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Capitalized Costs for Natural Gas and Oil Production Activities	Our aggregate capitalized costs for natural gas and oil production activities with applicable accumulated depreciation, depletion and amortization are presented below and exclude any properties classified as Assets Held for Sale (in thousands):
		2014			2013
	Consolidated Entities:
	Proven Oil and Natural Gas Properties	$	1,079,039		$	749,680
	Pipelines and Support Equipment		24,248			33,119
	Field Operation Vehicles and Other Equipment		27,030			21,608
	Wells and Facilities in Progress		127,597			69,886
	Unproven Properties		322,413			189,385
	Total		1,580,327			1,063,678
	Less Accumulated Depreciation and Depletion		(362,804	)		(184,836	)
	Total	$	1,217,523		$	878,842
	Share of Equity Method Investments:
	Pipelines and Support Equipment		19,946			19,270
	Wells and Facilities in Progress		—			238
	Total		19,946			19,508
	Less Accumulated Depreciation and Depletion		(2,611	)		(1,818	)
	Total	$	17,335		$	17,690

Oil_and_Natural_Gas_Reserve_Qu1

Oil and Natural Gas Reserve Quantities (Tables)	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Summary of Changes in Estimated Reserves of Oil and Natural Gas Wells	Presented below is a summary of changes in estimated reserves of the oil and natural gas wells at December 31, 2014, 2013 and 2012:
		2014
		Oil (MBbls)			NGL (MBbls)			Natural Gas			(MMcf)
								(MMcf)			Equivalents
	Estimated Proved Reserves-Beginning of Period		8,619.60			46,130.70			521,282.80			849,784.60
	Extensions, Discoveries and Additions		1,723.10			31,160.30			326,464.20			523,764.60
	Revisions of Previous Estimates		471.1			(2,889.1	)		9,971.00			(4,537.0	)
	Purchases		12			933			18,478.30			24,148.30
	Production		(1,141.1	)		(2,082.4	)		(37,011.2	)		(56,352.2	)
	Estimated Proved Reserves-End of Period		9,684.70			73,252.50			839,185.10			1,336,808.30
		2013
		Oil (MBbls)			NGL (MBbls)			Natural Gas			(MMcf)
								(MMcf)			Equivalents
	Estimated Proved Reserves-Beginning of Period		9,375.70			31,679.90			371,716.40			618,050.00
	Extensions, Discoveries and Additions		595.6			19,956.10			189,150.90			312,461.10
	Revisions of Previous Estimates		(438.5	)		(4,685.6	)		(16,137.7	)		(46,882.3	)
	Purchases		1			—			—			6
	Production		(914.2	)		(819.7	)		(23,446.8	)		(33,850.2	)
	Estimated Proved Reserves-End of Period		8,619.60			46,130.70			521,282.80			849,784.60
		2012
		Oil (MBbls)			NGL (MBbls)			Natural Gas			(MMcf)
								(MMcf)			Equivalents
	Estimated Proved Reserves-Beginning of Period		8,181.20			7,134.80			274,292.30			366,188.30
	Extensions, Discoveries and Additions		474.6			12,813.60			116,854.40			196,583.60
	Revisions of Previous Estimates		650.5			12,089.50			(1,413.6	)		75,026.40
	Improved Recovery		758.3			—			—			4,549.80
	Purchases		43.2			—			—			259.2
	Production		(732.1	)		(358.0	)		(18,016.7	)		(24,557.3	)
	Estimated Proved Reserves-End of Period		9,375.70			31,679.90			371,716.40			618,050.00
		Oil (MBbls)			NGL (MBbls)			Natural Gas			(MMcf)
								(MMcf)			Equivalents
	Proved Developed Reserves
	31-Dec-14		7,628.10			29,215.00			365,673.30			586,731.90
	31-Dec-13		7,742.50			16,322.50			212,061.40			356,451.40
	31-Dec-12		9,216.10			10,143.70			141,754.60			257,913.40
	Proved Undeveloped Reserves
	31-Dec-14		2,056.60			44,037.50			473,511.80			750,076.40
	31-Dec-13		877.1			29,808.20			309,221.40			493,333.20
	31-Dec-12		159.6			21,536.20			229,961.80			360,136.60

Standardized_Measure_Of_Discou1

Standardized Measure Of Discounted Future Net Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Summary of Future Net Cash Flows Relating to Prove Oil and Natural Gas Reserves	The following summary sets forth our future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by FASB ASC 932 at December 31, 2014, 2013 and 2012 ($ in thousands):
			2014				2013				2012
	Future Cash Inflows		$	5,824,231		(a)	$	3,899,878		(b)	$	2,988,231		(c)
	Future Costs:
	Production			(2,332,151	)			(1,619,629	)			(1,387,653	)
	Abandonment			(134,308	)			(95,183	)			(85,859	)
	Development			(686,676	)			(517,875	)			(324,873	)
	Net Future Cash Inflow Before Income Taxes			2,671,096				1,667,191				1,189,846
	Future Income Tax Expense			(468,597	)			(359,322	)			(245,078	)
	Total Future Net Cash Flows Before 10.0% Discount			2,202,499				1,307,869				944,768
	Less: Effect of 10.0% Discount Factor			(1,177,135	)			(778,756	)			(548,645	)
	Standardized Measure of Discounted Future Net Cash Flows		$	1,025,364			$	529,113			$	396,123
	(a)	Calculated using weighted average prices of $3.455 per Mcf, $88.02 per barrel of oil and $28.30 per barrel of NGLs
	(b)	Calculated using weighted average prices of $3.588 per Mcf, $94.28 per barrel of oil and $26.37 per barrel of NGLs
	(c)	Calculated using weighted average prices of $2.94 per Mcf, $90.92 per barrel of oil and $32.91 per barrel of NGLs
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flows	The principal sources of change in the standardized measure of discounted future net cash flows are as follows:
			2014				2013				2012
	Standardized Measure – Beginning of Period		$	529,113			$	396,123			$	413,935
	Revisions of Previous Estimates:
	Changes in Prices and Production Costs			253,865				72,503				(198,433	)
	Revisions in Quantities			(5,970	)			(51,289	)			91,462
	Changes in Future Development Costs			(51,794	)			22,341				(3,885	)
	Accretion of Discount and Timing of Future Cash Flows			64,013				47,571				52,093
	Net Change in Income Tax			28,756				31,433				27,405
	Purchase of Reserves in Place			28,316				—				1,188
	Plus Extensions, Discoveries, and Other Additions			430,252				170,846				88,749
	Development Costs Incurred			71,383				64,661				57,149
	Sales of Product – Net of Production Costs			(197,587	)			(151,781	)			(86,936	)
	Changes in Timing and Other			(124,983	)			(73,295	)			(46,604	)
	Standardized Measure – End of Period		$	1,025,364			$	529,113			$	396,123

Results_Of_Operations_For_Oil_1

Results Of Operations For Oil And Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2014
Income Statement [Abstract]
Results of Operations	Results of operations are equal to revenues, less (a) production costs, (b) impairment expenses, (c) exploration expenses, (d) DD&A expenses, and (e) income tax expense (benefit) (certain prior year amounts have been reclassified to conform to current presentation):
			2014			2013			2012
	Consolidated Entities (in thousands):
	Revenues
	Oil and Natural Gas Sales		$	297,869		$	213,919		$	134,574
	Expenses
	Production and Lease Operating Expense			100,282			62,150			47,638
	Impairment Expense			132,618			32,072			20,505
	Exploration Expense			9,446			11,408			4,782
	Depletion, Depreciation, Amortization and Accretion			94,467			62,386			44,955
	Total Costs			336,813			168,016			117,880
	Pre-Tax Operating Income (Loss)			(38,944	)		45,903			16,694
	Income Tax (Expense) Benefit  (a)			14,059			(29,148	)		(6,750	)
	Results of Operations for Oil and Gas Producing Activities		$	(24,885	)	$	16,755		$	9,944
	Share of Equity Method Investments (in thousands):
	Expenses
	Depletion, Depreciation, Amortization and Accretion		$	805		$	752		$	1,082
	Total Costs			805			752			1,082
	Pre-Tax Operating Income (Loss)			(805	)		(752	)		(1,082	)
	Income Tax Benefit  (a)			291			478			438
	Results of Operations for Oil and Gas Producing Activities		$	(514	)	$	(274	)	$	(644	)
	Total Consolidated and Equity Method Investees Results of		$	(25,399	)	$	16,481		$	9,300
	Operations for Oil and Gas Producing Activities
	(a)	Computed using the effective rate for continuing operations for each period: 36.1% in 2014; 63.5% in 2013 and; 40.4% in 2012.

Selected_Quarterly_Financial_D1

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Unaudited Financial Information on Quarterly Basis	The following tables set forth unaudited financial information on a quarterly basis for each of the last two years.
	REX ENERGY CORPORATION
	CONSOLIDATED STATEMENTS OF OPERATIONS
	($ and Shares in Thousands Except per Share Data)
			2014
			March			June		September		December
	Revenues		$	81,343		$	72,933	$	73,466	$	70,245
	Costs and Expenses			72,587			65,290		67,847		139,913(a)
	Net Income (Loss) From Continuing Operations			8,756			7,643		5,619		-69,668
	Net Income From Discontinued Operations, Net of Income Taxes			1,681			1,312		970		1,037
	Net Income (Loss)			10,437			8,955		6,589		-68,631
	Net Income Attributable to Noncontrolling Interests			1,569			877		895		698
	Net Income (Loss) Attributable to Rex Energy			8,868			8,078		5,694		-69,329
	Preferred Stock Dividends			—			—		—		2,335
	Net Income (Loss) Attributable to Common Shareholders		$	8,868		$	8,078	$	5,694	$	-71,664
	Income (Loss) per Common Share Attributable to Rex Energy
	Common Shareholders:
	Basic — Continuing Operations		$	0.17		$	0.14	$	0.11	$	-1.35
	Basic — Discontinued Operations			—			0.01		—		—
	Basic — Net Income (Loss)		$	0.17		$	0.15	$	0.11	$	-1.35
	Basic — Weighted Average Shares Outstanding			52,984			53,164		53,214		53,261
	Diluted — Continuing Operations		$	0.17		$	0.14	$	0.1	$	-1.35
	Diluted — Discontinued Operations			—			0.01		—		—
	Diluted — Net Income (Loss)		$	0.17		$	0.15	$	0.1	$	-1.35
	Diluted — Weighted Average Shares Outstanding			53,503			53,509		57,991		53,261
			2013
			March			June		September		December
	Revenues		$	40,964		$	51,520	$	58,127	$	63,508
	Costs and Expenses			44,488			38,280		56,469		77,265(a)
	Net Income (Loss) From Continuing Operations			(3,524	)		13,240		1,658		(13,757	)
	Net Income (Loss) From Discontinued Operations, Net of Income Taxes			1,123			721		174		(208	)
	Net Income (Loss)			(2,401	)		13,961		1,832		(13,965	)
	Net Income Attributable to Noncontrolling Interests			433			221		258		645
	Net Income (Loss) Attributable to Rex Energy		$	(2,834	)	$	13,740	$	1,574	$	(14,610	)
	Income (Loss) per Common Share Attributable to Rex Energy
	Common Shareholders:
	Basic — Continuing Operations		$	(0.06	)	$	0.25	$	0.03	$	(0.26	)
	Basic — Discontinued Operations			0.01			0.01		—		(0.02	)
	Basic — Net Income (Loss)		$	(0.05	)	$	0.26	$	0.03	$	(0.28	)
	Basic — Weighted Average Shares Outstanding			52,367			52,555		52,626		52,705
	Diluted — Continuing Operations		$	(0.06	)	$	0.25	$	0.03	$	(0.26	)
	Diluted — Discontinued Operations			0.01			0.01		—		(0.02	)
	Diluted — Net Income (Loss)		$	(0.05	)	$	0.26	$	0.03	$	(0.28	)
	Diluted — Weighted Average Shares Outstanding			52,367			52,911		53,293		52,705
	(a)	For the three-month periods ended December 31, 2014 and 2013, we incurred impairment expense of approximately $132.6 million and $29.7 million, respectively.

Condensed_Consolidating_Financ1

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Balance Sheets	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING BALANCE SHEETS
	FOR THE YEAR ENDED DECEMBER 31, 2014
	($ in Thousands, Except Share and Per Share Data)
		Guarantor			Non-Guarantor			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Subsidiaries			Corporation						Balance
								(Note Issuer)
	ASSETS
	Current Assets
	Cash and Cash Equivalents	$	17,978		$	—		$	—		$	—		$	17,978
	Accounts Receivable		43,726			210			—			—			43,936
	Taxes Receivable		—			—			504			—			504
	Short-Term Derivative Instruments		29,265			—			—			—			29,265
	Assets Held For Sale		—			36,794			—			(2,537	)		34,257
	Inventory, Prepaid Expenses and Other		3,374			—			29			—			3,403
	Total Current Assets		94,343			37,004			533			(2,537	)		129,343
	Property and Equipment (Successful Efforts Method)
	Evaluated Oil and Gas Properties		1,084,332			467			—			(5,760	)		1,079,039
	Unevaluated Oil and Gas Properties		321,708			705			—			—			322,413
	Other Property and Equipment		45,466			895			—			—			46,361
	Wells and Facilities in Progress		127,759			456			—			(560	)		127,655
	Pipelines		17,555			—			—			(1,898	)		15,657
	Total Property and Equipment		1,596,820			2,523			—			(8,218	)		1,591,125
	Less: Accumulated Depreciation, Depletion and Amortization		(367,224	)		(730	)		—			1,037			(366,917	)
	Net Property and Equipment		1,229,596			1,793			—			(7,181	)		1,224,208
	Deferred Financing Costs and Other Assets—Net		2,421			—			14,649			—			17,070
	Equity Method Investments		17,895			—			—			—			17,895
	Long-Term Deferred Tax Asset		—			—			8,301			—			8,301
	Intercompany Receivables		—			—			951,025			(951,025	)		—
	Investment in Subsidiaries – Net		4,161			1,541			258,448			(264,150	)		—
	Long-Term Derivative Instruments		4,904			—			—			—			4,904
	Total Assets	$	1,353,320		$	40,338		$	1,232,956		$	(1,224,893	)	$	1,401,721
	LIABILITIES AND EQUITY
	Current Liabilities
	Accounts Payable	$	55,877		$	—		$	—		$	(2,537	)	$	53,340
	Current Maturities of Long-Term Debt		1,176			—			—			—			1,176
	Accrued Liabilities		46,783			571			12,124			—			59,478
	Short-Term Derivative Instruments		421			—			—			—			421
	Current Deferred Tax Liability		—			—			8,301			—			8,301
	Liabilities Related to Assets Held For Sale		—			25,115			—			—			25,115
	Total Current Liabilities		104,257			25,686			20,425			(2,537	)		147,831
	8.875% Senior Notes Due 2020		—			—			350,000			—			350,000
	6.25% Senior Notes Due 2022		—			—			325,000			—			325,000
	Premium on Senior Notes – Net		—			—			2,725			—			2,725
	Senior Secured Line of Credit and Other Long-Term Debt		251			—			—			—			251
	Long-Term Derivative Instruments		2,377			—			—			—			2,377
	Other Deposits and Liabilities		4,018			—			—			—			4,018
	Future Abandonment Cost		38,097			49			—			—			38,146
	Intercompany Payables		947,114			3,911			—			(951,025	)		—
	Total Liabilities		1,096,114			29,646			698,150			(953,562	)		870,348
	Stockholders’ Equity
	Preferred Stock		—			—			1			—			1
	Common Stock		—			—			54			—			54
	Additional Paid-In Capital		177,144			79,743			617,826			(256,887	)		617,826
	Accumulated Earnings (Deficit)		80,062			(69,253	)		(83,075	)		(18,483	)		(90,749	)
	Rex Energy Stockholders’ Equity		257,206			10,490			534,806			(275,370	)		527,132
	Noncontrolling Interests		—			202			—			4,039			4,241
	Total Stockholders’ Equity		257,206			10,692			534,806			(271,331	)		531,373
	Total Liabilities and Stockholders’ Equity	$	1,353,320		$	40,338		$	1,232,956		$	(1,224,893	)	$	1,401,721
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING BALANCE SHEETS
	FOR THE YEAR ENDED DECEMBER 31, 2013
	($ in Thousands, Except Share and Per Share Data)
		Guarantor			Non-Guarantor			Rex Energy			Eliminations			Consolidated
Subsidiaries		Subsidiaries			Corporation			Balance
					(Note Issuer)
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,386		$	(84	)	$	5		$	—		$	1,307
Accounts Receivable		32,284			—			—			—			32,284
Taxes Receivable		—			—			5,189			—			5,189
Short-Term Derivative Instruments		5,180			—			488			—			5,668
Current Deferred Tax Asset		—			—			3,451			—			3,451
Assets Held For Sale		—			21,645			—			(3,302	)		18,343
Inventory, Prepaid Expenses and Other		2,092			—			26			—			2,118
Total Current Assets		40,942			21,561			9,159			(3,302	)		68,360
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			908			—			—			58,317
Wells and Facilities in Progress		70,759			5,545			—			(790	)		75,514
Pipelines		7,678			—			—			—			7,678
Total Property and Equipment		1,078,012			6,453			—			(3,891	)		1,080,574
Less: Accumulated Depreciation, Depletion and Amortization		(188,699	)		(219	)		—			350			(188,568	)
Net Property and Equipment		889,313			6,234			—			(3,541	)		892,006
Deferred Financing Costs and Other Assets—Net		2,421			—			9,366			—			11,787
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	$	956,361		$	28,992		$	863,987		$	(857,944	)	$	991,396
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	33,613		$	36		$	—		$	(3,304	)	$	30,345
Current Maturities of Long-Term Debt		1,340			—			—			—			1,340
Accrued Liabilities		45,196			41			2,967			—			48,204
Short-Term Derivative Instruments		4,663			—			—			—			4,663
Liabilities Related to Assets Held For Sale		—			15,461			—			—			15,461
Total Current Liabilities		84,812			15,538			2,967			(3,304	)		100,013
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			—			59,000			—			59,137
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		671,368			89,739			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	$	956,361		$	28,992		$	863,987		$	(857,944	)	$	991,396
Condensed Consolidating Statements of Operations	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
	FOR THE YEAR ENDED DECEMBER 31, 2014
	($ in Thousands)
		Guarantor			Non-Guarantor			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Subsidiaries			Corporation						Balance
								(Note Issuer)
	OPERATING REVENUE
	Oil, Natural Gas and NGL Sales	$	297,710		$	159		$	—		$	—		$	297,869
	Other Revenue		118			—			—			—			118
	TOTAL OPERATING REVENUE		297,828			159			—			-			297,987
	OPERATING EXPENSES
	Production and Lease Operating Expense		100,261			21			—			-			100,282
	General and Administrative Expense		30,317			83			5,737			-			36,137
	Loss on Disposal of Asset		644			-			—			—			644
	Impairment Expense		126,662			5,956			—			—			132,618
	Exploration Expense		9,165			281			—			—			9,446
	Depreciation, Depletion, Amortization and Accretion		94,643			513			—			(689	)		94,467
	Other Operating (Income) Expense		134			—			—			—			134
	TOTAL OPERATING EXPENSES		361,826			6,854			5,737			(689	)		373,728
	INCOME (LOSS) FROM OPERATIONS		(63,998	)		(6,695	)		(5,737	)		689			(75,741	)
	OTHER INCOME (EXPENSE)
	Interest Expense		(142	)		-			(36,835	)		—			(36,977	)
	Gain (Loss) on Derivatives, Net		37,359			—			1,517			—			38,876
	Other Income		90			—			—			-			90
	Loss From Equity Method Investments		(813	)		—			—			—			(813	)
	Income (Loss) From Equity in Consolidated Subsidiaries		(4,278	)		4,278			(20,204	)		20,204			—
	TOTAL OTHER INCOME (EXPENSE)		32,216			4,278			(55,522	)		20,204			1,176
	INCOME (LOSS) FROM CONTINUING		(31,782	)		(2,417	)		(61,259	)		20,893			(74,565	)
	OPERATIONS BEFORE INCOME TAX
	Income Tax (Expense) Benefit		9,928			2,417			14,570			—			26,915
	NET INCOME (LOSS) FROM CONTINUING OPERATIONS		(21,854	)		-			(46,689	)		20,893			(47,650	)
	Loss From Discontinued Operations, Net of Income Tax					9,330						(4,330	)		5,000
	NET INCOME (LOSS)		(21,854	)		9,330			(46,689	)		16,563			(42,650	)
	Net Income Attributable to Noncontrolling Interests of Discontinued Operations		—			4,039			—			—			4,039
	NET INCOME (LOSS) ATTRIBUTABLE TO	$	(21,854	)	$	5,291		$	(46,689	)	$	16,563		$	(46,689	)
	REX ENERGY
	Preferred Stock Dividends		—			-			2,335			—			2,335
	NET INCOME (LOSS) ATTRIBUTABLE TO	$	(21,854	)	$	5,291		$	(49,024	)	$	16,563		$	(49,024	)
	COMMON SHAREHOLDERS
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
	FOR THE YEAR ENDED DECEMBER 31, 2013
	($ in Thousands)
		Guarantor			Non-Guarantor			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Subsidiaries			Corporation						Balance
								(Note Issuer)
	OPERATING REVENUE
	Oil, Natural Gas and NGL Sales	$	213,919		$	—		$	—		$	—		$	213,919
	Other Revenue		200			—			—			—			200
	TOTAL OPERATING REVENUE		214,119			—			—			—			214,119
	OPERATING EXPENSES
	Production and Lease Operating Expense		62,138			12			—			—			62,150
	General and Administrative Expense		25,376			43			5,420			—			30,839
	Loss on Disposal of Asset		1,601			1			—			—			1,602
	Impairment Expense		32,072			—			—			—			32,072
	Exploration Expense		11,395			13			—			—			11,408
	Depreciation, Depletion, Amortization and Accretion		62,540			46			—			(200	)		62,386
	Other Operating Expense		592			—			—			—			592
	TOTAL OPERATING EXPENSES		195,714			115			5,420			(200	)		201,049
	INCOME (LOSS) FROM OPERATIONS		18,405			(115	)		(5,420	)		200			13,070
	OTHER INCOME (EXPENSE)
	Interest Expense		(64	)		—			(22,612	)		—			(22,676	)
	Gain on Derivatives, Net		(2,703	)		—			(205	)		—			(2,908	)
Other Income (Expense)		6,739			—			—			—			6,739
Loss From Equity Method Investments		(763	)		—			—			—			(763	)
Income (Loss) From Equity in Consolidated Subsidiaries		(33	)		33			5,703			(5,703	)		—
TOTAL OTHER INCOME (EXPENSE)		3,176			33			(17,114	)		(5,703	)		(19,608	)
INCOME (LOSS) FROM CONTINUING		21,581			(82	)		(22,534	)		(5,503	)		(6,538	)
OPERATIONS BEFORE INCOME TAX
Income Tax (Expense) Benefit		(14,409	)		(1,841	)		20,404			—			4,154
NET INCOME (LOSS) FROM CONTINUING		7,172			(1,923	)		(2,130	)		(5,503	)		(2,384	)
OPERATIONS
Income From Discontinued Operations, Net of Income Taxes		—			4,385			—			(2,574	)		1,811
NET INCOME (LOSS)		7,172			2,462			(2,130	)		(8,077	)		(573	)
Net Income Attributable to Noncontrolling Interests of Discontinued Operations		—			1,557			—			—			1,557
NET INCOME (LOSS) ATTRIBUTABLE TO	$	7,172		$	905		$	(2,130	)	$	(8,077	)	$	(2,130	)
REX ENERGY
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2012
($ in Thousands)
	Guarantor			Non-Guarantor			Rex Energy			Eliminations			Consolidated
	Subsidiaries			Subsidiaries			Corporation						Balance
							(Note Issuer)
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	134,574		$	—		$	—		$	—		$	134,574
Other Revenue		218			—			—			—			218
TOTAL OPERATING REVENUE		134,792			—			—			—			134,792
OPERATING EXPENSES
Production and Lease Operating Expense		47,618			20			—			—			47,638
General and Administrative Expense		19,283			16			3,159			—			22,458
Loss on Disposal of Asset		50			-			—			—			50
Impairment Expense		20,505			66			—			—			20,571
Exploration Expense		4,782			—			—			—			4,782
Depreciation, Depletion, Amortization and Accretion		44,993			45			—			(83	)		44,955
Other Operating Expense		1,136			—			—			—			1,136
TOTAL OPERATING EXPENSES		138,367			147			3,159			(83	)		141,590
INCOME (LOSS) FROM OPERATIONS		(3,575	)		(147	)		(3,159	)		83			(6,798	)
OTHER INCOME (EXPENSE)
Interest Expense		(55	)		(1	)		(6,362	)		—			(6,418	)
Gain on Derivatives, Net		10,687			—			—			—			10,687
Other Income (Expense)		99,575			—			(922	)		—			98,653
Loss From Equity Method Investments		(3,921	)		—			—			—			(3,921	)
Income (Loss) From Equity in Consolidated		(68	)		68			51,363			(51,363	)		—
Subsidiaries
TOTAL OTHER INCOME (EXPENSE)		106,218			67			44,079			(51,363	)		99,001
INCOME (LOSS) FROM CONTINUING		102,643			(80	)		40,920			(51,280	)		92,203
OPERATIONS BEFORE INCOME TAX
Income Tax (Expense) Benefit		(41,772	)		(69	)		4,559			—			(37,282	)
NET INCOME (LOSS) FROM CONTINUING		60,871			(149	)		45,479			(51,280	)		54,921
OPERATIONS
Income From Discontinued Operations, Net of		—			(7,952	)		—			(671	)		(8,623	)
Income Taxes
NET INCOME (LOSS)		60,871			(8,101	)		45,479			(51,951	)		46,298
Net Income Attributable to Noncontrolling Interests of Discontinued Operations		—			819			—			—			819
NET INCOME (LOSS) ATTRIBUTABLE TO	$	60,871		$	(8,920	)	$	45,479		$	(51,951	)	$	45,479
REX ENERGY
Condensed Consolidating Statements of Cash Flows	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
	FOR THE YEAR ENDING DECEMBER 31, 2014
	($ in Thousands)
		Guarantor			Non-Guarantor			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Subsidiaries			Corporation						Balance
								(Note Issuer)
	CASH FLOWS FROM OPERATING ACTIVITIES
	Net Income (Loss)	$	(21,854	)	$	9,330		$	(46,689	)	$	16,563		$	(42,650	)
	Adjustments to Reconcile Net Income (Loss) to Net
	Cash Provided by Operating Activities
	Loss on Equity Method Investments		813			—			—			—			813
	Non-Cash Expenses (Income)		(273	)		278			6,784			—			6,789
	Depreciation, Depletion, Amortization and Accretion		94,643			4,217			—			(689	)		98,171
	Deferred Income Tax Benefit		(9,928	)		(1,649	)		(14,415	)		—			(25,992	)
	Gain on Derivatives		(37,359	)		—			(1,517	)		—			(38,876	)
	Cash Settlements of Derivatives		5,969			—			1,312			—			7,281
	Dry Hole Expense		3,797			267			—			—			4,064
	(Gain) Loss on Sale of Asset		644			(55	)		—			—			589
	Impairment Expense		126,662			6,022			—			—			132,684
	Changes in operating assets and liabilities
	Accounts Receivable		(11,450	)		(6,090	)		4,686			(766	)		(13,620	)
	Inventory, Prepaid Expenses and Other Assets		(1,283	)		(74	)		(2	)		—			(1,359	)
	Accounts Payable and Accrued Liabilities		23,768			3,488			9,252			766			37,274
	Other Assets and Liabilities		(2,127	)		(335	)		—			—			(2,462	)
	NET CASH PROVIDED BY (USED IN)		172,022			15,399			(40,589	)		15,874			162,706
	OPERATING ACTIVITIES
	CASH FLOWS FROM INVESTING ACTIVITIES
	Intercompany Loans to Subsidiaries		397,382			(5,412	)		(371,768	)		(20,202	)		—
	Proceeds from Joint Venture Acreage Management		263			—			—			—			263
	Proceeds from the Sale of Oil and Gas Properties,		254			292			—			—			546
	Prospects and Other Assets
	Acquisitions of Undeveloped Acreage		(168,713	)		(710	)		—			—			(169,423	)
	Capital Expenditures for Development of Oil		(382,889	)		(12,861	)		—			4,328			(391,422	)
	and Gas Properties and Equipment
	NET CASH USED IN INVESTING ACTIVITIES		(153,703	)		(18,691	)		(371,768	)		(15,874	)		(560,036	)
	CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from Long-Term Debt and Lines of Credit		—			38,895			171,000			—			209,895
	Repayments of Long-Term Debt and Lines of Credit		—			(33,152	)		(230,000	)		—			(263,152	)
	Repayments of Loans and Other Notes Payable		(1,727	)		(994	)		—			—			(2,721	)
	Proceeds from Senior Notes, Net of Discounts and Premiums		—			—			325,000			—			325,000
	Debt Issuance Costs		—			(8	)		(6,816	)		—			(6,824	)
	Proceeds from the Issuance of Preferred Stock, Net		—			—			154,988			—			154,988
	Proceeds from Exercise of Stock Options		—			—			515			—			515
	Distributions by the Partners of Consolidated Subsidiary		—			(1,840	)		—			—			(1,840	)
	Dividends Paid on Preferred Stock								(2,335	)					(2,335	)
	NET CASH PROVIDED BY (USED IN)		(1,727	)		2,901			412,352			—			413,526
	FINANCING ACTIVITIES
	NET INCREASE (DECREASE) IN CASH		16,592			(391	)		(5	)		—			16,196
	CASH – BEGINNING		1,386			509			5			—			1,900
	CASH - ENDING	$	17,978		$	118		$	-		$	-		$	18,096
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
	FOR THE YEAR ENDING DECEMBER 31, 2013
	($ in Thousands)
		Guarantor			Non-Guarantor			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Subsidiaries			Corporation						Balance
								(Note Issuer)
	CASH FLOWS FROM OPERATING ACTIVITIES
	Net Income (Loss)	$	7,172		$	2,462		$	(2,130	)	$	(8,077	)	$	(573	)
	Adjustments to Reconcile Net Income (Loss) to Net
	Cash Provided by Operating Activities
	Loss on Equity Method Investments		763			—			—			—			763
	Non-Cash Expenses		(194	)		55			6,369			—			6,230
Depreciation, Depletion, Amortization and Accretion		62,540			1,604			—			(200	)		63,944
Deferred Income Tax Expense (Benefit)		14,409			2,210			(14,340	)		—			2,279
Gain on Derivatives		2,703			—			205			—			2,908
Cash Settlements of Derivatives		7,128			—			—			—			7,128
Dry Hole Expense		2,993			—			—			—			2,993
(Gain) Loss on Sale of Asset		(5,289	)		(922	)		—			—			(6,211	)
Impairment Expense		32,072			—			—			—			32,072
Changes in operating assets and liabilities
Accounts Receivable		(5,877	)		(6,515	)		1,241			(1,575	)		(12,726	)
Inventory, Prepaid Expenses and Other Assets		(826	)		(59	)		—			—			(885	)
Accounts Payable and Accrued Liabilities		8,554			874			1,481			1,982			12,891
Other Assets and Liabilities		(2,272	)		(88	)		(137	)		—			(2,497	)
NET CASH PROVIDED BY (USED IN)		123,876			(379	)		(7,311	)		(7,870	)		108,316
OPERATING ACTIVITIES
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries		186,089			1,619			(193,015	)		5,307			—
Proceeds from Joint Venture Acreage Management		458			—			—			—			458
Contributions to Equity Method Investments		(2,493	)		—			—			—			(2,493	)
Proceeds from the Sale of Oil and Gas Properties,		8,071			3,234			—			—			11,305
Prospects and Other Assets
Acquisitions of Undeveloped Acreage		(41,782	)		(2	)		—			—			(41,784	)
Capital Expenditures for Development of Oil and		(275,697	)		(7,870	)		—			2,563			(281,004	)
Gas Properties and Equipment
NET CASH PROVIDED BY (USED IN)		(125,354	)		(3,019	)		(193,015	)		7,870			(313,518	)
INVESTING ACTIVITIES
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			7,249			65,000			—			72,249
Repayments of Long-Term Debt and Lines of Credit		—			(2,480	)		(6,000	)		—			(8,480	)
Repayments of Loans and Other Notes Payable		(1,363	)		(642	)		—			—			(2,005	)
Proceeds from Senior Notes, net of Discounts and Premiums		—			—			105,000			—			105,000
Debt Issuance Costs		—			(8	)		(3,126	)		—			(3,134	)
Proceeds from the Exercise of Stock Options		—			—			533			—			533
Purchase of Non-Controlling Interests		—			(150	)		—			—			(150	)
Distributions by the Partners of Consolidated Subsidiary		—			(886	)		—			—			(886	)
NET CASH PROVIDED BY (USED IN)		(1,363	)		3,083			161,407			—			163,127
FINANCING ACTIVITIES
NET INCREASE (DECREASE) IN CASH		(2,841	)		(315	)		(38,919	)		—			(42,075	)
CASH – BEGINNING		4,227			824			38,924			—			43,975
CASH - ENDING	$	1,386		$	509		$	5		$	—		$	1,900
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDING DECEMBER 31, 2012
($ in Thousands)
	Guarantor			Non-Guarantor			Rex Energy			Eliminations			Consolidated
	Subsidiaries			Subsidiaries			Corporation						Balance
							(Note Issuer)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	60,871		$	(8,101	)	$	45,479		$	(51,951	)	$	46,298
Adjustments to Reconcile Net Income (Loss) to Net
Cash Provided by Operating Activities
Loss on Equity Method Investments		3,921			—			—			—			3,921
Non-Cash Expenses		33			14			3,144			—			3,191
Depreciation, Depletion, Amortization and Accretion		44,993			527			1,004			(83	)		46,441
Deferred Income Tax Expense (Benefit)		35,376			(7,152	)		(4,559	)		—			23,665
Gain on Derivatives		(10,687	)		—			—			—			(10,687	)
Cash Settlements of Derivatives		16,219			—			—			—			16,219
Dry Hole Expense		320			336			—			—			656
(Gain) Loss on Sale of Asset		(99,355	)		(2,118	)		922			—			(100,551	)
Impairment Expense		20,505			19,850			—			—			40,355
Changes in operating assets and liabilities
Accounts Receivable		29,564			(3,736	)		(39,325	)		(201	)		(13,698	)
Inventory, Prepaid Expenses and Other Assets		(139	)		32			15			—			(92	)
Accounts Payable and Accrued Liabilities		(8,875	)		(766	)		916			(107	)		(8,832	)
Other Assets and Liabilities		(1,146	)		(64	)		—			29			(1,181	)
NET CASH PROVIDED BY (USED IN)		91,600			(1,178	)		7,596			(52,313	)		45,705
OPERATING ACTIVITIES
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries		2,915			1,931			(56,489	)		51,643			—
Proceeds from Joint Venture Acreage Management		260			—			—			—			260
Contributions to Equity Method Investments		—			(4,087	)		—			—			(4,087	)
Proceeds from the Sale of Oil and Gas Properties,		128,554			4,871			—			—			133,425
Prospects and Other Assets
Acquisitions of Undeveloped Acreage		(51,783	)		(19	)		—			—			(51,802	)
Capital Expenditures for Development of Oil		(177,892	)		(1,316	)		—			670			(178,538	)
and Gas Properties and Equipment
NET CASH PROVIDED BY (USED IN)		(97,946	)		1,380			(56,489	)		52,313			(100,742	)
INVESTING ACTIVITIES
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			730			126,000			—			126,730
Repayments of Long-Term Debt and Lines of Credit		—			—			(351,000	)		—			(351,000	)
Repayments of Loans and Other Notes Payable		(764	)		(198	)		—			—			(962	)
Proceeds from Senior Notes, net of Discounts and Premiums		—			—			248,250			—			248,250
Debt Issuance Costs		—			—			(6,397	)		—			(6,397	)
Proceeds from the Exercise of Stock Options		—			—			565			—			565
Proceeds from the Issuance of Common Stock, Net of Issuance Costs		—			—			70,583			—			70,583
Settlement of Tax Withholdings Related to Share-Based Compensation Awards		—			—			(234	)		—			(234	)
Distributions by the Partners of Consolidated Subsidiary		—			(319	)		—			—			(319	)
NET CASH PROVIDED BY (USED IN)		(764	)		213			87,767			—			87,216
FINANCING ACTIVITIES
NET INCREASE (DECREASE) IN CASH		(7,110	)		415			38,874			—			32,179
CASH – BEGINNING		11,337			409			50			—			11,796
CASH - ENDING	$	4,227		$	824		$	38,924		$	—		$	43,975

Basis_of_Presentation_and_Prin1

Basis of Presentation and Principles of Consolidation - Additional Information (Details) (Water Solutions Holdings, LLC)	Dec. 31, 2014
Water Solutions Holdings, LLC
Organization Consolidation And Presentation Of Financial Statements [Line Items]
Ownership percentage by parent	60.00%

Recovered_Sheet2

Summary of Significant Accounting Policies - Additional Information (Details) (USD $)	3 Months Ended		12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
			Customer	Customer
Accounting Policies [Line Items]
Accounts Receivable	$43,936,000	$32,284,000	$43,936,000	$32,284,000
Number of customers			4	4
Capitalized interest costs			7,300,000	7,500,000	3,000,000
Impairment Expense	132,600,000	29,700,000	132,618,000	32,072,000	20,571,000
Deferred financing costs and other assets	17,100,000		17,100,000
Amortization expense			1,500,000	1,200,000	1,000,000
Debt issuance costs			6,800,000	3,100,000
Debt issuance costs, accumulated amortization	4,564,000	3,030,000	4,564,000	3,030,000
Accretion expense			3,621,000	3,094,000	2,100,000
Increase in estimated present value of asset retirement obligations			8,426,000	1,311,000
Future Abandonment Costs	40,099,000	28,525,000	40,099,000	28,525,000	24,822,000
Income tax examination minimum likelihood of tax benefits being realized upon ultimate settlement			50.00%
Common Stock, shares outstanding	54,174,763	54,186,490	54,174,763	54,186,490
Options outstanding	402,561	449,087	402,561	449,087	502,253	698,327
Stock Appreciation Rights (SARs)
Accounting Policies [Line Items]
Other than Options outstanding	20,500		20,500
Restricted Stock
Accounting Policies [Line Items]
Other than Options outstanding	1,519,301	2,172,639	1,519,301	2,172,639	1,431,573	1,229,826
Performance Shares
Accounting Policies [Line Items]
Other than Options outstanding	848,447		848,447
Warrants
Accounting Policies [Line Items]
Share based compensation, warrants outstanding	0		0
Accrued Expenses
Accounting Policies [Line Items]
Future Abandonment Costs	2,000,000	2,500,000	2,000,000	2,500,000
Minimum
Accounting Policies [Line Items]
Service properties, equipment and other assets, estimated useful lives			3 years
Payment period for oil and natural gas purchases after end of each production month			30 days
Minimum | Deferred Financing Costs
Accounting Policies [Line Items]
Estimated lives of intangible assets			5 years
Maximum
Accounting Policies [Line Items]
Service properties, equipment and other assets, estimated useful lives				40 years
Payment period for oil and natural gas purchases after end of each production month			60 days
Maximum | Deferred Financing Costs
Accounting Policies [Line Items]
Estimated lives of intangible assets			8 years
Sumitomo Corporation
Accounting Policies [Line Items]
Receivable from related party	6,700,000	4,400,000	6,700,000	4,400,000
Oil And Gas Production
Accounting Policies [Line Items]
Accounts Receivable	25,200,000	26,300,000	25,200,000	26,300,000
Oil And Gas Production | Major Customers
Accounting Policies [Line Items]
Accounts Receivable	$21,400,000	$22,700,000	$21,400,000	$22,700,000

Summary_of_Deferred_Financing_

Summary of Deferred Financing Costs (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accounting Policies [Abstract]
Deferred Financing Costs - Gross	$19,212	$12,396
Accumulated Amortization	-4,564	-3,030
Deferred Financing Costs - Net	$14,648	$9,366

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation Disclosure [Abstract]
Beginning Balance	$28,525	$24,822
Asset Retirement Obligation Incurred	1,480	1,750
Asset Retirement Obligation Settled	-1,943	-2,452
Asset Retirement Obligation Cancelled or Sold Properties	-10
Asset Retirement Obligation Revision of Estimated Obligation	8,426	1,311
Asset Retirement Obligation Accretion Expense	3,621	3,094	2,100
Total Future Abandonment Costs	$40,099	$28,525	$24,822

Business_Segment_Information_A

Business Segment Information - Additional Information (Details)	12 Months Ended
	Dec. 31, 2014
	Segment
Segment Reporting [Abstract]
Principal reportable segments	2

Business_and_Oil_and_Gas_Prope2

Business and Oil and Gas Property Acquisitions and Dispositions - Additional Information (Detail) (USD $)	0 Months Ended		3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Sep. 09, 2014	29-May-12	Sep. 30, 2012	Dec. 31, 2013	Dec. 31, 2012
	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
Keystone Midstream Services
Significant Acquisitions And Disposals [Line Items]
Base consideration for sale		483.2
Proceeds from sale of equity method investment		121.4	120.9
Gain (loss) on equity method investments		99.4		6.9
Cash held in escrow and paid out over the next 12 months		14.3
Proceeds from escrow amount				6.9	7.2
Funds by other sellers in transaction				3.8
Keystone Midstream Services | Transaction Cost
Significant Acquisitions And Disposals [Line Items]
Gain (loss) on equity method investments		3.3
Keystone Midstream Services | Post-closing Settlement Charges
Significant Acquisitions And Disposals [Line Items]
Gain (loss) on equity method investments			$0.50

Summary_of_Acquisition_Price_A

Summary of Acquisition Price Allocated (Details) (USD $)	0 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Significant Acquisitions And Disposals [Line Items]
Purchase Price	$120,563	$391,422	$281,004	$178,538
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

Discontinued_Operations_Assets

Discontinued Operations/ Assets Held for Sale - Additional Information (Details) (USD $)	12 Months Ended	3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Jun. 30, 2013	Mar. 31, 2013
Water Solutions Holdings, LLC
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Ownership percentage by parent	60.00%
Capital expenditures on facilities and equipment	$11.70
Capital lease obligations incurred	1.6
DJ Basin
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Sale of the remaining DJ Basin assets			3.1
Gain on asset held for sale		$1

Summary_of_Financial_Informati

Summary of Financial Information for Discontinued Operations (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Oil, Natural Gas and NGL Sales									$297,869	$213,919	$134,574
Other Revenue									118	200	218
TOTAL OPERATING REVENUE	70,245	73,466	72,933	81,343	63,508	58,127	51,520	40,964	297,987	214,119	134,792
Other Revenue (Expense)									118	200	218
Costs and Expenses:
Production and Lease Operating Expense									100,282	62,150	47,638
General and Administrative Expense									36,137	30,839	22,458
Depreciation, Depletion, Amortization and Accretion									94,467	62,386	44,955
Exploration Expense									9,446	11,408	4,782
Impairment Expense	132,600				29,700				132,618	32,072	20,571
Other Operating Expense (Income)									134	592	1,136
(Gain) Loss on Disposal of Asset									644	1,602	50
Interest Expense									36,977	22,676	6,418
Other (Income) Expense									-90	-6,739	-98,653
Income (Loss) from Discontinued Operations, net of taxes									5,000	1,811	-8,623
Discontinued Operations Assets Held For Sale
Revenues:
Oil, Natural Gas and NGL Sales										25	97
TOTAL OPERATING REVENUE										25	97
Costs and Expenses:
Production and Lease Operating Expense										104	353
General and Administrative Expense										23	660
Exploration Expense										97	867
Impairment Expense											19,770
Other Operating Expense (Income)										-3	8
(Gain) Loss on Disposal of Asset										-969	-2,126
Other (Income) Expense											-3
Total Costs and Expenses (Income)										-748	19,529
Income (Loss) from Discontinued Operations Before Income Taxes										773	-19,432
Income Tax (Expense) Benefit										-1,005	8,489
Income (Loss) from Discontinued Operations, net of taxes										-232	-10,943
Discontinued Operations Assets Held For Sale | Water Solutions Holdings, LLC
Revenues:
Field Services Revenue									58,627	23,812	13,403
Other Revenue											-56
TOTAL OPERATING REVENUE									58,627	23,812	13,347
Other Revenue (Expense)											-56
Costs and Expenses:
General and Administrative Expense									4,081	2,287	887
Depreciation, Depletion, Amortization and Accretion									3,703	1,559	482
Impairment Expense									67		14
Field Service Operating Expense									44,369	17,318	8,240
(Gain) Loss on Disposal of Asset									-55	46	8
Interest Expense									628	106	26
Other (Income) Expense									66	84	103
Total Costs and Expenses (Income)									52,859	21,400	9,760
Income (Loss) from Discontinued Operations Before Income Taxes									5,768	2,412	3,587
Income Tax (Expense) Benefit									-768	-369	-1,267
Income (Loss) from Discontinued Operations, net of taxes									$5,000	$2,043	$2,320
Crude Oil (Bbls) | Discontinued Operations Assets Held For Sale
Production:
Production Units										356,000	1,272,000

Summary_of_Carrying_Value_of_A

Summary of Carrying Value of Assets and Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Assets:
Cash and Cash Equivalents	$118	$593	$741
Total Current Assets	34,257	18,343
Liabilities:
Total Liabilities Related to Assets Held for Sale	25,115	15,461
Water Solutions Holdings, LLC
Assets:
Cash and Cash Equivalents	118	593
Accounts Receivable	13,226	6,579
Inventory, Prepaid Expenses and Other	163	89
Total Current Assets	13,507	7,261
Other Property and Equipment, Net	19,690	9,845
Wells and Facilities in Progress	688	1,031
Intangible Assets, Net	372	206
Total Long-Term Assets	20,750	11,082
Total Assets Held for Sale	34,257	18,343
Liabilities:
Accounts Payable	3,694	758
Current Maturities of Long-Term Debt	6,236	5,403
Accrued Liabilities	6,304	6,246
Total Current Liabilities	16,234	12,407
Senior Secured Line of Credit and Long-Term Debt	8,881	3,054
Long-Term Liabilities	8,881	3,054
Total Liabilities Related to Assets Held for Sale	25,115	15,461
Net Assets Held for Sale:	$9,142	$2,882

Equity_Method_Investments_Addi

Equity Method Investments - Additional Information (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Schedule Of Equity Method Investments [Line Items]
Equity Method Investments	$17,895	$18,708
Contributions to Equity Method Investments		2,493	4,087
Loss on Equity Method Investments	-813	-763	-3,921
RW Gathering, LLC
Schedule Of Equity Method Investments [Line Items]
Ownership percentage	40.00%
Contributions to Equity Method Investments	0	2,500
Loss on Equity Method Investments	$2,000	$1,900	$1,700

Concentrations_of_Credit_Risk_

Concentrations of Credit Risk - Additional Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	Entity	Customer
	Customer
Concentration Risk [Line Items]
Federal Deposit Insurance Corporation's limit for cash balances	$250,000	$250,000
Number Of Counterparties	5
Accounts Receivable	43,936,000	32,284,000
Number of major customers	4	4
Oil And Gas Production
Concentration Risk [Line Items]
Accounts Receivable	25,200,000	26,300,000
Oil And Gas Production | Four Purchasers
Concentration Risk [Line Items]
Accounts Receivable	$21,400,000	$22,700,000

Commitments_and_Contingencies_1

Commitments and Contingencies - Additional Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Loss Contingencies [Line Items]
Letters of credit	$6,000,000	$1,400,000
Rent expense	800,000	600,000	300,000
Maximum guarantee of payment of obligations	416,100,000
Transportation, processing and marketing expenses of oil natural gas and natural gas liquids	55,400,000	26,400,000	14,100,000
Production and Lease Operating Expense	100,282,000	62,150,000	47,638,000
Capacity Reservation
Loss Contingencies [Line Items]
Estimated working interest	70.00%
Charges incurred for unused processing capacity	200,000	300,000	500,000
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 | 2019
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	214,700,000
Drilling Commitments
Loss Contingencies [Line Items]
Number of rigs to support Appalachian Basin operations	3
Drilling Commitments | 2015
Loss Contingencies [Line Items]
Minimum cost to retain drilling rigs	7,600,000
Minimum cost to retain the completion services	11,000,000
Drilling Commitments | 2016
Loss Contingencies [Line Items]
Minimum cost to retain drilling rigs	4,600,000
Pennsylvania Impact Fee
Loss Contingencies [Line Items]
Rate in which unconventional wells are charged	20.00%
Production and Lease Operating Expense	4,100,000	3,200,000	5,400,000
Expenses related to wells spud			$2,800,000

Lease_Commitments_for_Each_of_

Lease Commitments for Each of Next Five Years (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Commitments And Contingencies Disclosure [Abstract]
2015	$1,075
2016	1,129
2017	1,143
2018	721
2019	721
Thereafter	180
Total	$4,969

Minimum_Net_Obligations_under_

Minimum Net Obligations under Sales, Gathering and Transportation Agreements (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Commitments And Contingencies Disclosure [Abstract]
2015	$21,951
2016	34,199
2017	52,296
2018	55,113
2019	53,963
Thereafter	692,320
Total	$909,842

Fee_for_Unconventional_Gas_Wel

Fee for Unconventional Gas Wells (Details) (Pennsylvania Impact Fee, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014
Less than $2.25
Unconventional Gas Wells [Line Items]
Year One	$40	[1]
Year Two	30	[1]
Year Three	25	[1]
Year 4 – 10	10	[1]
Year 11 – 15	5	[1]
$2.26 - $2.99
Unconventional Gas Wells [Line Items]
Year One	45	[1]
Year Two	35	[1]
Year Three	30	[1]
Year 4 – 10	15	[1]
Year 11 – 15	5	[1]
$3.00 - $4.99
Unconventional Gas Wells [Line Items]
Year One	50	[1]
Year Two	40	[1]
Year Three	30	[1]
Year 4 – 10	20	[1]
Year 11 – 15	10	[1]
$5.00 - $5.99
Unconventional Gas Wells [Line Items]
Year One	55	[1]
Year Two	45	[1]
Year Three	40	[1]
Year 4 – 10	20	[1]
Year 11 – 15	10	[1]
More than $5.99
Unconventional Gas Wells [Line Items]
Year One	60	[1]
Year Two	55	[1]
Year Three	50	[1]
Year 4 – 10	20	[1]
Year 11 – 15	$10	[1]
[1]	Pricing utilized for determining annual fees is based on the arithmetic mean of the NYMEX settled price for the near-month contract as reported by the Wall Street Journal for the last trading day of each month of a calendar year for the year ending December 31.

Related_Party_Transactions_Add

Related Party Transactions - Additional Information (Details) (USD $)	0 Months Ended	3 Months Ended	12 Months Ended	1 Months Ended		12 Months Ended		1 Months Ended
	Jun. 27, 2012	Sep. 30, 2013	Dec. 31, 2014	Apr. 30, 2011	Sep. 30, 2010	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2007
Related Party Transaction [Line Items]
Monthly rental payments	$35,000
Annual CPI adjustment capped	2.50%
Lease term	5 years
Shaner Hotel Group Limited Partnership
Related Party Transaction [Line Items]
Due to or from related party			0
Operating lease annual rent			500,000
Land acquired from related party		600,000
Charlie Brown Air Corp
Related Party Transaction [Line Items]
Number of aircrafts in related party transaction			2
Ownership interest				50.00%	50.00%
Aircraft use right, interest purchased				600,000	600,000
Payments for use of aircrafts			100,000
Charlie Brown Air Corp | Minimum
Related Party Transaction [Line Items]
Aircraft use right, variable per hour flight rate			400
Charlie Brown Air Corp | Maximum
Related Party Transaction [Line Items]
Aircraft use right, variable per hour flight rate			800
Charlie Brown Air Two Llc
Related Party Transaction [Line Items]
Number of aircrafts in related party transaction			500
Percentage of membership interest			25.00%
Percentage of loan guaranteed								25.00%
Amount of loan guaranteed								400,000
Loan interest and retainer fees			200,000			200,000	200,000
Charlie Brown Air Two Llc | Related Party Debt
Related Party Transaction [Line Items]
Bank loan			1,100,000			1,200,000		1,500,000
Maturity period of bank loan			21-Jun-17
Amortization period of bank loan			180 months
Charlie Brown Air Two Llc | Related Party Debt | LIBOR
Related Party Transaction [Line Items]
Interest rate on bank loan								2.50%
Charlie Brown Air Two Llc | Shaner Hotel Group Limited Partnership
Related Party Transaction [Line Items]
Percentage of membership interest			25.00%
Charlie Brown Air Two Llc | Unrelated Third Party
Related Party Transaction [Line Items]
Percentage of membership interest			50.00%
RW Gathering, LLC
Related Party Transaction [Line Items]
Production and Lease Operating Expense			700,000			800,000	800,000
Ownership interest percentage			40.00%
Due from related party			0			0	0
Due to related party			0			0	0
Keystone Midstream Services
Related Party Transaction [Line Items]
Production and Lease Operating Expense							2,400,000
Water Solutions Holding
Related Party Transaction [Line Items]
Due to related party			1,300,000			1,500,000
Water transfer and water purification expenses			20,100,000			10,700,000	3,200,000
Water transfer and water purification expenses eliminated in consolidation			$16,200,000			$8,800,000	$2,200,000

LongTerm_Debt_Senior_Credit_Fa

Long-Term Debt - Senior Credit Facility - Additional Information (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013		Mar. 27, 2013
Debt Instrument [Line Items]
Line of credit facility, amount outstanding	$0	$59	[1]
Effective rate	0.50%
Additional percentage with LIBOR	1.00%
Duration of developed producing reserve	5 years
Minimum | Adjusted LIBO Rate
Debt Instrument [Line Items]
Margin rate	1.50%
Maximum | Adjusted LIBO Rate
Debt Instrument [Line Items]
Margin rate	2.50%
Senior Credit Facility
Debt Instrument [Line Items]
Line of credit facility, current borrowing capacity	400			400
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
Percentage of reasonably anticipated projected production	85.00%
Liens covering the oil and gas properties, percentage	80.00%
Current ratio	3.3
Total debt to EBITAX	0
Senior Credit Facility | Crude Oil (Bbls)
Debt Instrument [Line Items]
Percentage of reasonably anticipated projected production	75.00%
Senior Credit Facility | Natural Gas
Debt Instrument [Line Items]
Percentage of reasonably anticipated projected production	75.00%
Senior Credit Facility | Minimum
Debt Instrument [Line Items]
Percentage of purchase price of reserves for which interim borrowing base re-determinations may be requested				10.00%
Criteria Current ratio	1.00%
Senior Credit Facility | Minimum | Alternate Base Rate
Debt Instrument [Line Items]
Margin rate	0.50%
Senior Credit Facility | Maximum
Debt Instrument [Line Items]
Duration of developed producing reserve	36 months
Outstanding principal amount of debt for borrowed money, percentage	75.00%
Criteria Total debt to EBITAX"	1.75
Senior Credit Facility | Maximum | Interest Rate Swap
Debt Instrument [Line Items]
Notional amounts of interest rate swap	20
Senior Credit Facility | Maximum | Alternate Base Rate
Debt Instrument [Line Items]
Margin rate	1.50%
Senior Credit Facility | Letter of Credit
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	500
Senior Credit Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$60
Senior Credit Facility | Defaulted Loans
Debt Instrument [Line Items]
Margin rate	2.00%
[1]	The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2014 and 2013 was approximately 2.2 % and 1.9%, respectively. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2014 and 2013 was approximately 4.0% and 5.3%, respectively

LongTerm_Debt_Senior_Notes_Due

Long-Term Debt - Senior Notes Due Twenty Twenty and Senior Notes Due Twenty Twenty Two - Additional Information (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Apr. 26, 2013	Dec. 12, 2012	Jul. 17, 2014
Debt Instrument [Line Items]
Proceeds from Senior Notes, Net of Discounts and Premiums	$325,000,000	$105,000,000	$248,250,000
Senior notes, issuance cost	6,824,000	3,134,000	6,397,000
Debt issuance costs	14,648,000	9,366,000
Senior notes	677,700,000	353,100,000
Premium on Senior Notes - Net	2,725,000	3,078,000
Amortization of net premium	400,000	200,000
2020 Senior Notes
Debt Instrument [Line Items]
Debt issued aggregate principal amount				100,000,000
Senior notes at an issue price				105.00%
Proceeds from Senior Notes, Net of Discounts and Premiums				102,800,000
Accrued interest				3,300,000
Debt issuance costs				2,300,000
Percentage of notes that can be redeemed	35.00%
Debt instrument redemption date	1-Dec-16
Latest date for equity proceeds to be applied to optional Note redemption	1-Dec-15
8.875% Senior Notes
Debt Instrument [Line Items]
Debt issued aggregate principal amount					250,000,000
Senior notes at an issue price					99.30%
Debt instrument maturity date	1-Dec-20	1-Dec-20			1-Dec-20
Proceeds from Senior Notes, Net of Discounts and Premiums					242,200,000
Senior notes, issuance cost					6,400,000
Interest rate	8.88%	8.88%			8.88%
6.25% Senior Notes
Debt Instrument [Line Items]
Debt issued aggregate principal amount						325,000,000
Debt instrument maturity date	1-Aug-22	1-Aug-22
Proceeds from Senior Notes, Net of Discounts and Premiums						318,800,000
Interest rate	6.25%	6.25%				6.25%
Debt issuance costs						$6,300,000
Offering price as percentage of issue price						100.00%
2022 Senior Notes
Debt Instrument [Line Items]
Percentage of notes that can be redeemed	35.00%
Debt instrument redemption date	1-Aug-17
Latest date for equity proceeds to be applied to optional Note redemption	1-Aug-17

Components_of_LongTerm_Debt_an

Components of Long-Term Debt and Lines of Credit (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
Debt Instrument [Line Items]
Senior Notes	$675,000,000
Premium on Senior Notes, Net	2,725,000		3,078,000
Senior Line of Credit	0		59,000,000	[1]
Capital Leases and Other Obligations	1,427,000	[1]	1,477,000	[1]
Total Debt	679,152,000		413,555,000
Less Current Portion of Long-Term Debt	-1,176,000		-1,340,000
Total Long-Term Debt	677,976,000		412,215,000
8.875% Senior Notes
Debt Instrument [Line Items]
Senior Notes	350,000,000		350,000,000
6.25% Senior Notes
Debt Instrument [Line Items]
Senior Notes	$325,000,000
[1]	The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2014 and 2013 was approximately 2.2 % and 1.9%, respectively. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2014 and 2013 was approximately 4.0% and 5.3%, respectively

Components_of_LongTerm_Debt_an1

Components of Long-Term Debt and Lines of Credit (Parenthetical) (Details)	12 Months Ended		0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 12, 2012	Jul. 17, 2014
Senior Credit Facility
Debt Instrument [Line Items]
Average interest rate	2.20%	1.90%
Other Loans and Notes Payable
Debt Instrument [Line Items]
Average interest rate	4.00%	5.30%
8.875% Senior Notes
Debt Instrument [Line Items]
Interest rate	8.88%	8.88%	8.88%
Debt instrument maturity date	1-Dec-20	1-Dec-20	1-Dec-20
6.25% Senior Notes
Debt Instrument [Line Items]
Interest rate	6.25%	6.25%		6.25%
Debt instrument maturity date	1-Aug-22	1-Aug-22

Principal_Maturity_Schedule_fo

Principal Maturity Schedule for Debt Outstanding (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Debt Disclosure [Abstract]
2015	$1,176
2016	251
2017	0
2018	0
2019	0
Thereafter	675,000
Total	$676,427	[1]	$410,477
[1]	Does not include $2.7 million net premium on Senior Notes.

Principal_Maturity_Schedule_fo1

Principal Maturity Schedule for Debt Outstanding (Parenthetical) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Debt Disclosure [Abstract]
Senior notes, net premium	$2.70

Fair_Value_of_Financial_and_De

Fair Value of Financial and Derivative Instruments - Additional Information (Details) (USD $)	3 Months Ended			12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives				($7,281,000)	($7,128,000)		($16,219,000)
Senior Line of Credit	0	59,000,000	[1]	0	59,000,000	[1]
Senior Notes	675,000,000			675,000,000
Fair value of interest rate swap, liability	200,000			200,000
Derivatives asset (liability)	31,400,000	-200,000		31,400,000	-200,000
Unrealized gain on commodity derivative contracts				1,700,000	4,300,000
Impairment Expense	132,600,000	29,700,000		132,618,000	32,072,000		20,571,000
Other Than Temporary Impairment
Derivatives Fair Value [Line Items]
Impairment Expense				132,600,000
Crude Oil
Derivatives Fair Value [Line Items]
Derivatives asset (liability)	7,236,000			7,236,000
Crude Oil | Minimum
Derivatives Fair Value [Line Items]
Commodity hedged on annualized basis hedge through 2015	75.00%			75.00%
Natural Gas
Derivatives Fair Value [Line Items]
Derivatives asset (liability)	17,954,000			17,954,000
Natural Gas | Minimum
Derivatives Fair Value [Line Items]
Commodity hedged on annualized basis hedge through 2015	75.00%			75.00%
Commodity hedged on annualized basis hedge through 2016	25.00%			25.00%
Natural Gas Liquids
Derivatives Fair Value [Line Items]
Derivatives asset (liability)	6,181,000			6,181,000
Natural Gas Liquids | Minimum
Derivatives Fair Value [Line Items]
Commodity hedged on annualized basis hedge through 2015	15.00%			15.00%
Commodity derivatives
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives				6,000,000	7,100,000		16,200,000
Derivatives asset (liability)	31,371,000	-20,000		31,371,000	-20,000
Fixed To Floating Interest Rate Swap
Derivatives Fair Value [Line Items]
Derivative, amount of hedged item	25,000,000			25,000,000
Interest Rate Swap
Derivatives Fair Value [Line Items]
Cash Settlements of Derivatives				1,300,000
Derivatives asset (liability)		($205,000)			($205,000)
[1]	The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2014 and 2013 was approximately 2.2 % and 1.9%, respectively. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2014 and 2013 was approximately 4.0% and 5.3%, respectively

Schedule_of_Location_and_Amoun

Schedule of Location and Amounts of Gains and Losses on Derivative Instruments (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	$38,876	($2,908)	$10,687
Crude Oil
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	8,613	-2,798	1,579
Natural Gas
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	18,406	1,807	8,162
Natural Gas Liquids
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	10,340	-1,711	946
Interest Rate Swap
Derivative Instruments Gain Loss [Line Items]
Gain (Loss) on Derivatives, Net	$1,517	($206)

Asset_or_Liability_Financial_C

Asset or Liability Financial Commodity Derivative Instrument Positions (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
	bbl
Derivatives Fair Value [Line Items]
Derivatives asset (liability)	$31,400	($200)
Crude Oil
Derivatives Fair Value [Line Items]
Volume	885,000
Derivatives asset (liability)	7,236
Crude Oil | 2015 | Deferred Put Spreads
Derivatives Fair Value [Line Items]
Volume	180,000
Put Option	73.08
Floor	83.33
Derivatives asset (liability)	1,413
Crude Oil | 2015 | Call Protected Swaps
Derivatives Fair Value [Line Items]
Volume	30,000
Swap	95.76
Long Call	110
Derivatives asset (liability)	1,227
Crude Oil | 2015 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume	675,000
Put Option	53.44
Floor	67.89
Ceiling	75.67
Derivatives asset (liability)	4,596
Natural Gas
Derivatives Fair Value [Line Items]
Volume	110,640,000
Derivatives asset (liability)	17,954
Natural Gas | 2015 | Swaps
Derivatives Fair Value [Line Items]
Volume	6,300,000
Swap	3.96
Derivatives asset (liability)	4,522
Natural Gas | 2015 | Swaptions
Derivatives Fair Value [Line Items]
Volume	0
Derivatives asset (liability)	-154
Natural Gas | 2015 | Cap Swaps
Derivatives Fair Value [Line Items]
Volume	8,400,000
Put Option	3.43
Swap	4.13
Derivatives asset (liability)	3,430
Natural Gas | 2015 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume	13,500,000
Put Option	3.59
Floor	4.12
Ceiling	4.52
Derivatives asset (liability)	5,081
Natural Gas | 2015 | Calls Option
Derivatives Fair Value [Line Items]
Volume	2,400,000
Ceiling	4.4
Derivatives asset (liability)	-74
Natural Gas | 2015 | Basis Swaps
Derivatives Fair Value [Line Items]
Volume	10,380,000
Swap	-0.77
Derivatives asset (liability)	2,622
Natural Gas | 2016 | Swaps
Derivatives Fair Value [Line Items]
Volume	1,500,000
Swap	4.05
Derivatives asset (liability)	194
Natural Gas | 2016 | Cap Swaps
Derivatives Fair Value [Line Items]
Volume	3,600,000
Put Option	3.45
Swap	4.11
Derivatives asset (liability)	884
Natural Gas | 2016 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume	4,500,000
Put Option	3.56
Floor	4.09
Ceiling	4.43
Derivatives asset (liability)	1,277
Natural Gas | 2016 | Calls Option
Derivatives Fair Value [Line Items]
Volume	7,320,000
Ceiling	4.35
Derivatives asset (liability)	-1,096
Natural Gas | 2016 | Basis Swaps
Derivatives Fair Value [Line Items]
Volume	7,320,000
Swap	-0.83
Derivatives asset (liability)	-257
Natural Gas | 2017 | Swaps
Derivatives Fair Value [Line Items]
Volume	1,500,000
Swap	4.05
Derivatives asset (liability)	194
Natural Gas | 2017 | Cap Swaps
Derivatives Fair Value [Line Items]
Volume	2,100,000
Put Option	3.34
Swap	4.07
Derivatives asset (liability)	412
Natural Gas | 2017 | Three Way Collars
Derivatives Fair Value [Line Items]
Volume	1,800,000
Put Option	3.58
Floor	4.1
Ceiling	4.5
Derivatives asset (liability)	456
Natural Gas | 2017 | Basis Swaps
Derivatives Fair Value [Line Items]
Volume	7,300,000
Swap	-0.83
Derivatives asset (liability)	-256
Natural Gas | 2018 | Swaps
Derivatives Fair Value [Line Items]
Volume	2,100,000
Swap	4.05
Derivatives asset (liability)	272
Natural Gas | 2018 | Cap Swaps
Derivatives Fair Value [Line Items]
Volume	1,800,000
Put Option	3.3
Swap	4.05
Derivatives asset (liability)	321
Natural Gas | 2018 | Basis Swaps
Derivatives Fair Value [Line Items]
Volume	7,300,000
Swap	-0.83
Derivatives asset (liability)	-256
Natural Gas | 2019 | Swaps
Derivatives Fair Value [Line Items]
Volume	2,100,000
Swap	4.05
Derivatives asset (liability)	272
Natural Gas | 2019 | Basis Swaps
Derivatives Fair Value [Line Items]
Volume	7,300,000
Swap	-0.83
Derivatives asset (liability)	-256
Natural Gas | 2020 | Swaps
Derivatives Fair Value [Line Items]
Volume	2,400,000
Swap	4.05
Derivatives asset (liability)	311
Natural Gas | 2020 | Basis Swaps
Derivatives Fair Value [Line Items]
Volume	7,320,000
Swap	-0.83
Derivatives asset (liability)	-256
Natural Gas | 2021 | Swaps
Derivatives Fair Value [Line Items]
Volume	2,400,000
Swap	4.05
Derivatives asset (liability)	311
Natural Gas Liquids
Derivatives Fair Value [Line Items]
Volume	367,500
Derivatives asset (liability)	6,181
Natural Gas Liquids | 2015 | Propane Swaps
Derivatives Fair Value [Line Items]
Volume	258,000
Swap	44.52
Derivatives asset (liability)	5,897
Natural Gas Liquids | 2015 | Ethane Swaps
Derivatives Fair Value [Line Items]
Volume	109,500
Swap	10.08
Derivatives asset (liability)	$284

Combined_Fair_Value_of_Derivat

Combined Fair Value of Derivatives (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	$29,265	$5,668
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	4,904	535
Total Derivative Assets	34,169	6,203
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	-421	-4,663
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	-2,377	-1,765
Total Derivative Liabilities	-2,798	-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		380
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities		-42
Crude Oil | Call Protected Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	1,227
Crude Oil | Deferred Put Spreads
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	1,413
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities		-585
Crude Oil | Three Way Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	4,596	104
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities		-29
Crude Oil | Swaps
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities		-119
Natural Gas Liquids | Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	6,181	83
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities		-995
Natural Gas | Collars
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities		-235
Natural Gas | Three Way Collars
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	5,081	518
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	1,733	169
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities		-125
Natural Gas | Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	4,522	106
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	1,554	22
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities		-1,170
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities		-4
Natural Gas | Cap Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	3,430	5
Long-Term Derivative Assets:
Total Long-Term Derivative Assets	1,617	5
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities		-496
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities		-307
Natural Gas | Basis Swaps
Short-Term Derivative Assets:
Total Short-Term Derivative Assets	2,815	3,984
Long-Term Derivative Assets:
Total Long-Term Derivative Assets		339
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	-193
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	-1,281
Natural Gas | Calls Option
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	-74	-150
Long-Term Derivative Liabilities:
Total Long-Term Derivative Liabilities	-1,096	-761
Natural Gas | Swaptions
Short-Term Derivative Liabilities:
Total Short - Term Derivative Liabilities	($154)	($717)

Significant_Unobservable_Input

Significant Unobservable Inputs Used in Fair Value Measurements of Natural Gas Basis Swaps (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Derivatives asset (liability)	$31,400	($200)
Natural Gas
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Derivatives asset (liability)	17,954
Natural Gas | Basis Swaps
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Weighted Average (price per Mcf)	-0.84	-0.91
Derivatives asset (liability)	$1,341	$4,323
Natural Gas | Basis Swaps | Minimum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)	-0.27	-0.78
Natural Gas | Basis Swaps | Maximum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Range (price per Mcf)	-1.39	-1.08

Fair_Value_Hierarchy_Table_for

Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value (Details) (USD $)	Dec. 31, 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)	$31,400	($200)
Commodity derivatives
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	31,371	-20
Commodity derivatives | Significant Other Observable Inputs (Level 2)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	30,030	-4,343
Commodity derivatives | Significant Unobservable Inputs (Level 3)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)	1,341	-4,323
Interest Rate Swap
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)		-205
Interest Rate Swap | Significant Other Observable Inputs (Level 2)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives asset (liability)		($205)

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 $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 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	-1,670	4,328
Settlements Received	-1,312	-5
Ending Balance of Level 3	$1,341	$4,323

Financial_Instruments_Not_Reco

Financial Instruments Not Recorded at Fair Value (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
Derivatives Fair Value [Line Items]
Senior Notes	$675,000,000
Senior Line of Credit	0		59,000,000	[1]
Capital Leases and Other Obligations	1,427,000	[1]	1,477,000	[1]
Total	676,427,000	[2]	410,477,000
Fair Value
Derivatives Fair Value [Line Items]
Secured Lines of Credit			59,000,000
Capital Leases and Other Obligations	1,393,000		1,449,000
Total	554,661,000		445,449,000
8.875% Senior Notes
Derivatives Fair Value [Line Items]
Senior Notes	350,000,000		350,000,000
8.875% Senior Notes | Fair Value
Derivatives Fair Value [Line Items]
Senior Notes	311,955,000		385,000,000
6.25% Senior Notes
Derivatives Fair Value [Line Items]
Senior Notes	325,000,000
6.25% Senior Notes | Fair Value
Derivatives Fair Value [Line Items]
Senior Notes	$241,313,000
[1]	The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2014 and 2013 was approximately 2.2 % and 1.9%, respectively. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2014 and 2013 was approximately 4.0% and 5.3%, respectively
[2]	Does not include $2.7 million net premium on Senior Notes.

Financial_Instruments_Not_Reco1

Financial Instruments Not Recorded at Fair Value (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 12, 2012	Jul. 17, 2014
8.875% Senior Notes
Derivatives Fair Value [Line Items]
Senior Notes, interest rate	8.88%	8.88%	8.88%
Due date	2020	2020
8.875% Senior Notes | Carrying Amount
Derivatives Fair Value [Line Items]
Senior Notes, interest rate	8.88%	8.88%
Due date	2020	2020
8.875% Senior Notes | Fair Value
Derivatives Fair Value [Line Items]
Senior Notes, interest rate	8.88%	8.88%
Due date	2020	2020
6.25% Senior Notes
Derivatives Fair Value [Line Items]
Senior Notes, interest rate	6.25%	6.25%		6.25%
Due date	2022	2022
6.25% Senior Notes | Carrying Amount
Derivatives Fair Value [Line Items]
Senior Notes, interest rate	6.25%	6.25%
Due date	2022	2022
6.25% Senior Notes | Fair Value
Derivatives Fair Value [Line Items]
Senior Notes, interest rate	6.25%	6.25%
Due date	2022	2022

Income_Tax_Expense_Benefit_fro

Income Tax Expense (Benefit) from Continuing Operations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current:
Federal		($1,936)	$2,350
State	6	-4,105	5,608
Deferred:
Federal	-23,691	509	27,312
State	-3,230	1,378	2,012
Income Tax Expense (Benefit)	($26,915)	($4,154)	$37,282

Reconciliation_of_Income_Tax_E

Reconciliation of Income Tax Expense (Benefit) Using Statutory Rate Compared with Actual Income Tax Expense (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Income (loss) from continuing operations before noncontrolling interests and income taxes	($74,565)	($6,538)	$92,203
Statutory U.S. income tax rate	35.00%	35.00%	35.00%
Tax expense recognized using statutory U.S. income tax rate	-26,098	-2,288	32,271
Change in estimated future state rates	-1,015	-484	-7
Permanent differences	363	83	52
Change in valuation allowances	2,450	-160	-131
Other	608	-500	-493
Adjusted federal income tax expense (benefit)	-23,692	-3,349	31,692
State income tax expense (benefit)	-3,223	-805	5,590
Income Tax Expense (Benefit)	($26,915)	($4,154)	$37,282
Effective income tax rate	36.10%	63.50%	40.40%

Components_of_Deferred_Tax_Ass

Components of Deferred Tax Assets (Liabilities) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Assets:
Asset retirement obligation	$772		$997
Deferred compensation plans	695		2,593
Compensation accruals	2,087
Valuation allowances	-71
Other	68		370
Total gross current deferred tax assets	3,551		3,960
Liabilities:
Unrealized gain on derivatives	-11,410		-404
Other	-442		-105
Total gross current deferred tax liabilities	-11,852		-509
Net total current deferred tax asset (liability)	-8,301		3,451
Assets:
Asset retirement obligation	15,091		10,445
Deferred compensation plans	2,218		1,513
Net operating loss carryforward	73,531	[1]	48,703	[1]
Organization costs	525		602
Deferred revenue	1,209		1,338
AMT credits	292		292
Unrealized gain on derivatives			493
Valuation allowances	-4,318		-1,965
Other	269		232
Total gross long-term deferred tax assets	88,817		61,653
Liabilities:
Timing differences - tax partnerships	-7,135		-7,474
Book basis of oil and gas properties in excess of tax basis	-71,402		-83,594
Unrealized gain on derivatives	-999
Other	-980		-31
Total gross long-term deferred tax liabilities	-80,516		-91,099
Net total long-term deferred tax asset (liability)	$8,301		($29,446)
[1]	As a result of certain realization requirements of FASB ASC 718, the table of deferred tax assets and liabilities does not include $1.3 million and $0.4 million at December 31, 2014 and 2013, respectively, of excess tax benefits that arose directly from tax deductions related to stock-based compensation greater than compensation recognized for financial reporting. Total stockholders’ equity will be increased by $1.3 million if and when such excess tax benefits are ultimately realized.

Components_of_Deferred_Tax_Ass1

Components of Deferred Tax Assets (Liabilities) (Parenthetical) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Excess tax benefit from share-based compensation	$1.30	$0.40
Stockholders equity increased	$1.30

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Line Items]
Valuation allowance for statutory depletion carryforwards and charitable contributions	4,300,000	$2,000,000
Net operating loss carryforwards	144,500,000
Minimum
Income Tax Disclosure [Line Items]
Federal net operating loss carryforwards, expiration year	2020
Maximum
Income Tax Disclosure [Line Items]
Federal net operating loss carryforwards, expiration year	2034
Federal
Income Tax Disclosure [Line Items]
Net operating loss carryforwards	186,400,000

Expirations_by_Year_for_Federa

Expirations by Year for Federal and State Net Operating Loss Carryforwards (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	$144,500
Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	73,531
Expiration Year, 2020 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	134
Expiration Year, 2021 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	175
Expiration Year, 2023 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	899
Expiration Year, 2025 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	531
Expiration Year, 2026 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	600
Expiration Year, 2028 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	3,333
Expiration Year, 2029 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	767
Expiration Year, 2030 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	751
Expiration Year, 2031 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	19,746
Expiration Year, 2032 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	253
Expiration Year, 2033 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	19,703
Expiration Year, 2034 | Federal and state
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	$26,639

Earnings_Per_Common_Share_Addi

Earnings Per Common Share - Additional Information (Details)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
6.0% convertible perpetual preferred stock, Series A
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Dividend per share percentage	6.00%
Conversion of Preferred Stock
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share	3.3
Employee Stock Option
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share	0.4	0.4	0.4
Performance Based Restricted Stock Awards
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share	0.8	1.3	1

Earnings_Per_Share_Computation

Earnings Per Share - Computation of Basic and Diluted Earning (Loss) Per Common Share (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Numerator:
Net Income (Loss) From Continuing Operations	($69,668)	$5,619	$7,643	$8,756	($13,757)	$1,658	$13,240	($3,524)	($47,650)		($2,384)		$54,921
Net Income (Loss) From Discontinued Operations, Less Noncontrolling Interests	1,037	970	1,312	1,681	-208	174	721	1,123	961		254		-9,442
Preferred Stock Dividends	2,335								2,335
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	($71,664)	$5,694	$8,078	$8,868					($49,024)		($2,130)		$45,479
Denominator:
Weighted Average Common Shares Outstanding - Basic	53,261	53,214	53,164	52,984	52,705	52,626	52,555	52,367	53,150		52,572		51,543
Effect of Dilutive Securities:
Employee Stock Options													69
Employee Performance-Based Restricted Stock Awards													413
Weighted Average Common Shares Outstanding - Diluted	53,261	57,991	53,509	53,503	52,705	53,293	52,911	52,367	53,150		52,572		52,025
Earnings per Common Share Attributable to Rex Energy Common Shareholders
Basic — Net Income (Loss) From Continuing Operations	($1.35)	$0.11	$0.14	$0.17	($0.26)	$0.03	$0.25	($0.06)	($0.94)	[1]	($0.05)	[1]	$1.06	[1]
Basic — Net Income (Loss) From Discontinued Operations			$0.01		($0.02)		$0.01	$0.01	$0.02	[1]	$0.01	[1]	($0.18)	[1]
Basic – Net Income (Loss) Attributable to Rex Energy Common Shareholders	($1.35)	$0.11	$0.15	$0.17	($0.28)	$0.03	$0.26	($0.05)	($0.92)	[1]	($0.04)	[1]	$0.88	[1]
Diluted — Net Income (Loss) From Continuing Operations	($1.35)	$0.10	$0.14	$0.17	($0.26)	$0.03	$0.25	($0.06)	($0.94)	[1]	($0.05)	[1]	$1.06	[1]
Diluted — Net Income (Loss) From Discontinued Operations			$0.01		($0.02)		$0.01	$0.01	$0.02	[1]	$0.01	[1]	($0.18)	[1]
Diluted – Net Income (Loss) Attributable to Rex Energy Common Shareholders	($1.35)	$0.10	$0.15	$0.17	($0.28)	$0.03	$0.26	($0.05)	($0.92)	[1]	($0.04)	[1]	$0.88	[1]
[1]	All earnings per share amounts are attributable to Rex common shareholders.

Capital_Stock_Additional_Infor

Capital Stock - Additional Information (Details) (USD $)	12 Months Ended	0 Months Ended	1 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Aug. 18, 2014	Oct. 31, 2014	Dec. 31, 2013	Aug. 12, 2014
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	54,174,763			54,186,490
Preferred Stock, shares issued	16,100			0
Preferred Stock, par value	$0.00			$0.00
Proceeds from the Issuance of Preferred Stock, Net	$154,988
Dividend declared	$145
Dividends declared on Preferred Stock	2,335
6.0% convertible perpetual preferred stock, Series A
Schedule Of Capitalization Equity [Line Items]
Preferred Stock, shares issued		16,100
Preferred Stock, par value		$0.00
Proceeds from the Issuance of Preferred Stock, Net		155,000
Dividend per share in amount	$600
Dividend per share percentage	6.00%
Dividend declared			$145
Dividends declared on Preferred Stock	$2,300
Initial conversion price per share of common stock	$18
Premium percentage over market closing sale price	25.20%
Closing sale price per share of common stock					$14.38
Sale of shares transaction date	12-Aug-14
Depositary shares
Schedule Of Capitalization Equity [Line Items]
Preferred Stock, shares issued		1,610,000
Liquidation preference per share	$10,000
Preferred stock to common stock conversion ratio	5.5556
Common Stock
Schedule Of Capitalization Equity [Line Items]
Preferred stock to common stock conversion ratio	555.56

Major_Customers_Additional_Inf

Major Customers - Additional Information (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Customer	Customer	Customer
Revenue, Major Customer [Line Items]
Number of customers	4	4
Sales
Revenue, Major Customer [Line Items]
Number of customers	4	4	5
Sales | Largest single purchaser
Revenue, Major Customer [Line Items]
Sales revenue	96.4	73.8	64.7
Sales | Customer Concentration Risk | Four customers
Revenue, Major Customer [Line Items]
Sales revenue	253.6	179.5
Percentage of revenue from major customers	85.10%	83.90%
Sales | Customer Concentration Risk | Five customers
Revenue, Major Customer [Line Items]
Sales revenue			128.3
Percentage of revenue from major customers			95.30%
Sales | Customer Concentration Risk | Largest single purchaser
Revenue, Major Customer [Line Items]
Percentage of revenue from major customers	32.40%	34.50%	48.10%

Employee_Benefit_and_Equity_Pl1

Employee Benefit and Equity Plans - Additional Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Employer contribution to the plan	$900,000	$700,000	$500,000
Intrinsic value of stock options exercised	300,000	400,000	100,000
Total tax benefit	100,000	200,000
Outstanding weighted average remaining term (in years)	2 years 10 months 24 days	3 years 10 months 24 days
Weighted average remaining term of options exercisable (in years)	2 years 10 months 24 days
Aggregate intrinsic value of options outstanding		4,100,000
Aggregate intrinsic value of options exercisable	0
Expected dividend yield	0.00%	0.00%
Stock Options
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	100,000	200,000	200,000
Stock Options | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expiration period for outstanding stock options	5 years
Stock Options | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expiration period for outstanding stock options	10 years
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	5,800,000	5,100,000	2,900,000
Common stock issued by compensation committee	131,610	981,544	425,209
Number of companies in peer group	15	13
Fair value of TSR awards of per share estimated on date of grant	$8.76	$16.03	$11.59
Expected dividend yield	0.00%
Unrecognized compensation expense weighted average period, in years	1 year 8 months 12 days
Total fair value of stock awards vested in period	7,700,000	3,000,000
Unrecognized compensation expense	$5,800,000
2007 Long Term Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares authorized for issuance	5,979,470
Shares available for grant	2,825,260	2,785,836
TSR | Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value of TSR awards of per share estimated on date of grant	$10.15	$12.59	$7.80

Summary_of_Stock_Option_Activi

Summary of Stock Option Activity (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Beginning Balance, Number of Shares	449,087	502,253	698,327
Exercised, Number of Shares	-46,526	-49,166	-52,287
Cancelled/Forfeited, Number of Shares		-4,000	-143,787
Ending Balance, Number of Shares	402,561	449,087	502,253
Options Exercisable, Number of Shares	402,561
Beginning Balance, Weighted Average Exercise Price	$10.85	$10.95	$12.94
Exercised, Weighted Average Exercise Price	$11.09	$10.85	$10.80
Cancelled/Forfeited, Weighted Average Exercise Price		$23.28	$20.71
Ending Balance, Weighted Average Exercise Price	$10.82	$10.85	$10.95
Options Exercisable, Weighted Average Exercise Price	$10.82
Options Outstanding December 31, 2014, Weighted Average Remaining Term (in years)	2 years 10 months 24 days	3 years 10 months 24 days
Options Exercisable December 31, 2014, Weighted Average Remaining Term (in years)	2 years 10 months 24 days
Options Outstanding December 31, 2014, Aggregate Intrinsic Value	$2,800
Options Exercisable December 31, 2014, Aggregate Intrinsic Value	$2,800

Summary_of_Issued_and_Outstand

Summary of Issued and Outstanding Stock Options (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$10.82	$10.85	$10.95	$12.94
Number Outstanding	402,561	449,087	502,253	698,327
Weighted-Average Exercise Price, Outstanding	$10.82
Number Exercisable	402,561
Weighted-Average Exercise Price, Exercisable	$10.82
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	75,000
Weighted-Average Exercise Price, Outstanding	$9.50
Number Exercisable	75,000
Weighted-Average Exercise Price, Exercisable	$9.50
Exercise Price Range 9.99
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$9.99
Number Outstanding	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
Number Exercisable	50,000
Weighted-Average Exercise Price, Exercisable	$13.19
Exercise Price Range 22.34
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price	$22.34
Number Outstanding	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, 2014	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%	100.00%
TSR Rank 4 - 6
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of Awards to Vest	75.00%	75.00%
TSR Rank 7 - 10
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of Awards to Vest	50.00%	50.00%
TSR Rank 11 - 13
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of Awards to Vest	25.00%	25.00%
TSR Rank 14 - 16
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of Awards to Vest	0.00%	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)	12 Months Ended
	Dec. 31, 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 $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock awards, beginning balance, Number of Shares	2,172,639	1,431,573	1,229,826
Awards, Number of Shares	131,610	981,544	425,209
Vested, Number of Shares	-595,085	-182,994	-70,750
Forfeitures, Number of Shares	-189,863	-57,484	-152,712
Stock awards, ending balance, Number of Shares	1,519,301	2,172,639	1,431,573
Stock awards, beginning balance, Weighted Average Grant Date Fair Value	$14.16	$12.45	$12.11
Awards, Weighted Average Grant Date Fair Value	$8.76	$16.03	$11.59
Vested, Weighted Average Grant Date Fair Value	$13.09	$11.59	$2.05
Forfeitures, Weighted Average Grant Date Fair Value	$14.60	$11.84	$12.13
Stock awards, ending balance, Weighted Average Grant Date Fair Value	$14.05	$14.16	$12.45

Impairment_Expense_Additional_

Impairment Expense - Additional Information (Details) (USD $)	3 Months Ended		12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense	$132,600	$29,700	$132,618	$32,072	$20,571
Proved Properties
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense			113,400
Illinois Basin
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense				29,300
Production from oil and gas properties			100.00%
Illinois Basin | Proved Properties
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense			103,900
Illinois Basin | Unproved Property Impairments
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense			8,500
Appalachian Basin
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense			3,600		13,700
Appalachian Basin | Regulatory and environmental climate
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense			5,900
Appalachian Basin | Proved Properties
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense			9,500
Appalachian Basin | Unproved Property Impairments
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense			18,900
Appalachian Basin | Unproved Property Impairments | Expiring leases
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense			10,400
Undeveloped Acreage in Clearfield County, Pennsylvania
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items]
Impairment Expense					$5,800

Net_Change_in_Capitalized_Expl

Net Change in Capitalized Exploratory Well Costs (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Project	Project	Project
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Beginning Balance at January 1,	$5,731	$36,968	$11,756
Additions to capitalized exploratory well costs pending the determination of estimated proved reserves	258,097	171,087	95,980
Reclassification of wells, facilities, and equipment based on the determination of estimated proved reserves	-240,494	-202,323	-70,518
Capitalized exploratory well costs charged to expense	-233	-1	-250
Ending Balance at December 31,	23,101	5,731	36,968
Less exploratory well costs that have been capitalized for a period of one year or less	-20,407	-3,597	-36,630
Capitalized exploratory well costs for a period of greater than one year	$2,694	$2,134	$338
Number of projects that have exploratory well costs capitalized for a period of more than one year	6	3	2

Suspended_Exploratory_Well_Cos2

Suspended Exploratory Well Costs - Additional Information (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Oil and Gas In Process Activities [Line Items]
Capitalized exploratory well costs for a period of greater than one year	$2,694	$2,134	$338
Appalachian Basin in Butler County, Pennsylvania
Oil and Gas In Process Activities [Line Items]
Capitalized Exploratory Number of Wells	3
Appalachian Basin in Clearfield County, Pennsylvania
Oil and Gas In Process Activities [Line Items]
Capitalized Exploratory Number of Wells	3

Recovered_Sheet3

Costs Incurred in Oil and Natural Gas Property Acquisitions and Development (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Acquisition of Properties
Exploration Costs	$9,446		$11,408		$4,782
Development Costs	869		3,651		1,156
Subtotal	549,758		337,614		238,854
Asset Retirement Obligations	9,110		3,031		4,480
Total Costs Incurred	566,297		340,540		241,182
Consolidated Entities
Acquisition of Properties
Proved	161		2,445		1,474
Unproved	169,408		39,291		49,331
Exploration Costs	316,235	[1]	231,112	[1]	128,748	[1]
Development Costs	71,383	[1]	64,661	[1]	57,149	[1]
Subtotal	557,187		337,509		236,702
Asset Retirement Obligations	9,110		3,031		4,480
Total Costs Incurred	566,297		340,540		241,182
Equity Method Investee
Acquisition of Properties
Development Costs	438	[1]	1,958	[1]	4,316	[1]
Subtotal	$438		$1,958		$4,316
[1]	Includes Depreciation expense for support equipment and facilities

Reconciliation_of_Total_Costs_

Reconciliation of Total Costs Incurred for Consolidated Entities to Reported Capital Expenditures (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Total Costs Incurred	$566,297		$340,540		$241,182
Contributions to Equity Method Investments			2,493		4,087
DJ Basin Expenditures			2		3,146
Exploration Expense	-9,446		-11,408		-4,782
Asset Retirement Obligations	-9,110		-3,031		-4,480
Depreciation for Support Equipment and Facilities	-6,075		-5,024		-4,187
Corporate Expenditures	869		3,651		1,156
Other	7,223	[1]	10,391	[1]	2,732	[1]
Subtotal	$549,758		$337,614		$238,854
[1]	Represents R.E. Disposal, LLC capital and intercompany capital transactions.

Capitalized_Costs_for_Natural_

Capitalized Costs for Natural Gas and Oil Production Activities (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Consolidated Entities
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proven Oil and Natural Gas Properties	$1,079,039	$749,680
Pipelines and Support Equipment	24,248	33,119
Field Operation Vehicles and Other Equipment	27,030	21,608
Wells and Facilities in Progress	127,597	69,886
Unproven Properties	322,413	189,385
Total	1,580,327	1,063,678
Less Accumulated Depreciation and Depletion	-362,804	-184,836
Total	1,217,523	878,842
Equity Method Investee
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Pipelines and Support Equipment	19,946	19,270
Wells and Facilities in Progress		238
Total	19,946	19,508
Less Accumulated Depreciation and Depletion	-2,611	-1,818
Total	$17,335	$17,690

Summary_of_Changes_in_Estimate

Summary of Changes in Estimated Reserves of Oil and Natural Gas Wells (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	MMcfe	MMcfe	MMcfe
	Mcf
Reserve Quantities [Line Items]
Estimated Proved Reserves-End of Period	2,100,000
Estimated Proved Reserves-Beginning of Period	849,784,600	618,050,000	366,188,300
Extensions, Discoveries and Additions	523,764,600	312,461,100	196,583,600
Revisions of Previous Estimates	-4,537,000	-46,882,300	75,026,400
Purchases	24,148,300	6,000	259,200
Production	-56,352,200	-33,850,200	-24,557,300
Estimated Proved Reserves-End of Period	1,336,808,300	849,784,600	618,050,000
Improved Recovery			4,549,800
Proved Developed Reserves Energy Equivalents	586,731,900	356,451,400	257,913,400
Proved Undeveloped Reserves Energy Equivalents	750,076,400	493,333,200	360,136,600
Crude Oil
Reserve Quantities [Line Items]
Estimated Proved Reserves-Beginning of Period	8,619,600	9,375,700	8,181,200
Extensions, Discoveries and Additions	1,723,100	595,600	474,600
Revisions of Previous Estimates	471,100	-438,500	650,500
Improved Recovery			758,300
Purchases	12,000	1,000	43,200
Production	-1,141,100	-914,200	-732,100
Estimated Proved Reserves-End of Period	9,684,700	8,619,600	9,375,700
Proved Developed Reserves	7,628,100	7,742,500	9,216,100
Proved Undeveloped Reserves	2,056,600	877,100	159,600
Natural Gas Liquids
Reserve Quantities [Line Items]
Estimated Proved Reserves-Beginning of Period	46,130,700	31,679,900	7,134,800
Extensions, Discoveries and Additions	31,160,300	19,956,100	12,813,600
Revisions of Previous Estimates	-2,889,100	-4,685,600	12,089,500
Purchases	933,000
Production	-2,082,400	-819,700	-358,000
Estimated Proved Reserves-End of Period	73,252,500	46,130,700	31,679,900
Proved Developed Reserves	29,215,000	16,322,500	10,143,700
Proved Undeveloped Reserves	44,037,500	29,808,200	21,536,200
Natural Gas
Reserve Quantities [Line Items]
Estimated Proved Reserves-Beginning of Period	521,282,800	371,716,400	274,292,300
Extensions, Discoveries and Additions	326,464,200	189,150,900	116,854,400
Revisions of Previous Estimates	9,971,000	-16,137,700	-1,413,600
Purchases	18,478,300
Production	-37,011,200	-23,446,800	-18,016,700
Estimated Proved Reserves-End of Period	839,185,100	521,282,800	371,716,400
Proved Developed Reserves	365,673,300	212,061,400	141,754,600
Proved Undeveloped Reserves	473,511,800	309,221,400	229,961,800

Oil_and_Natural_Gas_Reserve_Qu2

Oil and Natural Gas Reserve Quantities - Additional Information (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013
	Location			MMBoe
	MMcfe			bbl
	Mcf
Reserve Quantities [Line Items]
Estimated proved undeveloped reserves, gross	5
Estimated proved undeveloped reserves, net	5
Discount rate	10.00%
Net reserve volume associated with locations	2,100,000
Net reserve volume percentage of total estimated proved reserves	0.20%
Period of development of proved locations	5 years
Weighted Average Natural Gas Price		2.94	4.55
Proved Undeveloped Reserves Extensions Discoveries And Additions	27,300
Crude Oil
Reserve Quantities [Line Items]
Net reserve volume associated with locations	9,684,700	9,375,700	8,181,200	8,619,600
Proved Undeveloped Reserves Extensions Discoveries And Additions	1.7	0.5		0.6
Natural Gas Liquids
Reserve Quantities [Line Items]
Net reserve volume associated with locations	73,252,500	31,679,900	7,134,800	46,130,700
Proved Undeveloped Reserves Extensions Discoveries And Additions	31.2	12.8		20
Natural Gas
Reserve Quantities [Line Items]
Net reserve volume associated with locations	839,185,100	371,716,400	274,292,300	521,282,800
Proved Undeveloped Reserves Extensions Discoveries And Additions	326,500	116,900		189,100
Proved Undeveloped with in Five Years
Reserve Quantities [Line Items]
Revisions	-58,500
Commodity Pricing
Reserve Quantities [Line Items]
Revisions	-1,600
Technical Revisions
Reserve Quantities [Line Items]
Revisions	38,000
Operating Expense
Reserve Quantities [Line Items]
Revisions	17,600
Butler
Reserve Quantities [Line Items]
Revisions	51,000
Warrior South Prospect and Westmoreland
Reserve Quantities [Line Items]
Revisions	-15,500
Appalachian Basin
Reserve Quantities [Line Items]
Estimated proved undeveloped reserves, gross	177	100		136
Proved Undeveloped Locations Net	117	58.1		85.5
Marcellus Shale
Reserve Quantities [Line Items]
Estimated proved undeveloped reserves, gross	162	97		120
Proved Undeveloped Locations Net	105.4	56.4		73.5

Recovered_Sheet4

Standardized Measure of Discounted Future Net Cash Flows - Additional Information (Details)	12 Months Ended
	Dec. 31, 2014
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Annual discount factor	10.00%

Summary_of_Future_Net_Cash_Flo

Summary of Future Net Cash Flows Relating to Prove Oil and Natural Gas Reserves (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
In Thousands, unless otherwise specified
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Future Cash Inflows	$5,824,231	[1]	$3,899,878	[2]	$2,988,231	[3]
Production	-2,332,151		-1,619,629		-1,387,653
Abandonment	-134,308		-95,183		-85,859
Development	-686,676		-517,875		-324,873
Net Future Cash Inflow Before Income Taxes	2,671,096		1,667,191		1,189,846
Future Income Tax Expense	-468,597		-359,322		-245,078
Total Future Net Cash Flows Before 10.0% Discount	2,202,499		1,307,869		944,768
Less: Effect of 10.0% Discount Factor	-1,177,135		-778,756		-548,645
Standardized Measure of Discounted Future Net Cash Flows	$1,025,364		$529,113		$396,123		$413,935
[1]	Calculated using weighted average prices of $3.455 per Mcf, $88.02 per barrel of oil and $28.30 per barrel of NGLs
[2]	Calculated using weighted average prices of $3.588 per Mcf, $94.28 per barrel of oil and $26.37 per barrel of NGLs
[3]	Calculated using weighted average prices of $2.94 per Mcf, $90.92 per barrel of oil and $32.91 per barrel of NGLs

Summary_of_Future_Net_Cash_Flo1

Summary of Future Net Cash Flows Relating to Prove Oil and Natural Gas Reserves (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
weighted average prices	3.455	3.588	2.94
Crude Oil
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
weighted average prices	88.02	94.28	90.92
Natural Gas Liquids
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
weighted average prices	28.3	26.37	32.91

Principal_Sources_of_Change_in

Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Standardized Measure – Beginning of Period	$529,113	$396,123	$413,935
Changes in Prices and Production Costs	253,865	72,503	-198,433
Revisions in Quantities	-5,970	-51,289	91,462
Changes in Future Development Costs	-51,794	22,341	-3,885
Accretion of Discount and Timing of Future Cash Flows	64,013	47,571	52,093
Net Change in Income Tax	28,756	31,433	27,405
Purchase of Reserves in Place	28,316		1,188
Plus Extensions, Discoveries, and Other Additions	430,252	170,846	88,749
Development Costs Incurred	71,383	64,661	57,149
Sales of Product – Net of Production Costs	-197,587	-151,781	-86,936
Changes in Timing and Other	-124,983	-73,295	-46,604
Standardized Measure – End of Period	$1,025,364	$529,113	$396,123

Results_of_Operations_Details

Results of Operations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Expenses
Results of Operations for Oil and Gas Producing Activities	($25,399)		$16,481		$9,300
Consolidated Entities
Revenues
Oil and Natural Gas Sales	297,869		213,919		134,574
Expenses
Production and Lease Operating Expense	100,282		62,150		47,638
Impairment Expense	132,618		32,072		20,505
Exploration Expense	9,446		11,408		4,782
Depletion, Depreciation, Amortization and Accretion	94,467		62,386		44,955
Total Costs	336,813		168,016		117,880
Pre-Tax Operating Income (Loss)	-38,944		45,903		16,694
Income Tax (Expense) Benefit	14,059	[1]	-29,148	[1]	-6,750	[1]
Results of Operations for Oil and Gas Producing Activities	-24,885		16,755		9,944
Equity Method Investee
Expenses
Depletion, Depreciation, Amortization and Accretion	805		752		1,082
Total Costs	805		752		1,082
Pre-Tax Operating Income (Loss)	-805		-752		-1,082
Income Tax (Expense) Benefit	291	[1]	478	[1]	438	[1]
Results of Operations for Oil and Gas Producing Activities	($514)		($274)		($644)
[1]	Computed using the effective rate for continuing operations for each period: 36.1% in 2014; 63.5% in 2013 and; 40.4% in 2012.

Results_of_Operations_Parenthe

Results of Operations (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Results Of Operations Revenue From Oil And Gas Producing Activities [Abstract]
Effective tax rate	36.10%	63.50%	40.40%

Litigation_Additional_Informat

Litigation - Additional Information (Details)	1 Months Ended	12 Months Ended
	Jul. 31, 2012	Dec. 31, 2014	Oct. 31, 2011
	Case		Plaintiff
Commitments And Contingencies Disclosure [Abstract]
Number of plaintiffs			2
Case dismissed date		2012-05
Case revised decision date		3-May-13
Additional lawsuits	2

Unaudited_Financial_Informatio

Unaudited Financial Information on Quarterly Basis (Details) (USD $)	3 Months Ended										12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Revenues	$70,245		$73,466	$72,933	$81,343	$63,508		$58,127	$51,520	$40,964	$297,987		$214,119		$134,792
Costs and Expenses	139,913	[1]	67,847	65,290	72,587	77,265	[1]	56,469	38,280	44,488	373,728		201,049		141,590
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	-69,668		5,619	7,643	8,756	-13,757		1,658	13,240	-3,524	-47,650		-2,384		54,921
Net Income (Loss) From Discontinued Operations, Net of Income Taxes	1,037		970	1,312	1,681	-208		174	721	1,123	961		254		-9,442
NET INCOME (LOSS)	-68,631		6,589	8,955	10,437	-13,965		1,832	13,961	-2,401	-42,650		-573		46,298
Net Income Attributable to Noncontrolling Interests	698		895	877	1,569	645		258	221	433	4,039		1,557		819
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	-69,329		5,694	8,078	8,868	-14,610		1,574	13,740	-2,834	-46,689		-2,130		45,479
Preferred Stock Dividends	2,335										2,335
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	($71,664)		$5,694	$8,078	$8,868						($49,024)		($2,130)		$45,479
Income (Loss) per Common Share Attributable to Rex Energy Common Shareholders:
Basic — Continuing Operations	($1.35)		$0.11	$0.14	$0.17	($0.26)		$0.03	$0.25	($0.06)	($0.94)	[2]	($0.05)	[2]	$1.06	[2]
Basic — Net Income (Loss) From Discontinued Operations				$0.01		($0.02)			$0.01	$0.01	$0.02	[2]	$0.01	[2]	($0.18)	[2]
Basic — Net Income (Loss)	($1.35)		$0.11	$0.15	$0.17	($0.28)		$0.03	$0.26	($0.05)	($0.92)	[2]	($0.04)	[2]	$0.88	[2]
Basic – Weighted Average Shares of Common Stock Outstanding	53,261		53,214	53,164	52,984	52,705		52,626	52,555	52,367	53,150		52,572		51,543
Diluted — Continuing Operations	($1.35)		$0.10	$0.14	$0.17	($0.26)		$0.03	$0.25	($0.06)	($0.94)	[2]	($0.05)	[2]	$1.06	[2]
Diluted — Net Income (Loss) From Discontinued Operations				$0.01		($0.02)			$0.01	$0.01	$0.02	[2]	$0.01	[2]	($0.18)	[2]
Diluted — Net Income (Loss)	($1.35)		$0.10	$0.15	$0.17	($0.28)		$0.03	$0.26	($0.05)	($0.92)	[2]	($0.04)	[2]	$0.88	[2]
Diluted – Weighted Average Shares of Common Stock Outstanding	53,261		57,991	53,509	53,503	52,705		53,293	52,911	52,367	53,150		52,572		52,025
[1]	For the three-month periods ended December 31, 2014 and 2013, we incurred impairment expense of approximately $132.6 million and $29.7 million, respectively.
[2]	All earnings per share amounts are attributable to Rex common shareholders.

Unaudited_Financial_Informatio1

Unaudited Financial Information on Quarterly Basis (Parenthetical) (Details) (USD $)	3 Months Ended		12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Impairment Expense	$132,600	$29,700	$132,618	$32,072	$20,571

Condensed_Consolidating_Financ2

Condensed Consolidating Financial Information - Additional Information (Details) (USD $)	Dec. 31, 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 $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Current Assets
Cash and Cash Equivalents	$17,978	$1,307	$43,234
Accounts Receivable	43,936	32,284
Taxes Receivable	504	5,189
Short-Term Derivative Instruments	29,265	5,668
Assets Held for Sale	34,257	18,343
Inventory, Prepaid Expenses and Other	3,403	2,118
Total Current Assets	129,343	68,360
Current Deferred Tax Asset		3,451
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties	1,079,039	749,680
Unevaluated Oil and Gas Properties	322,413	189,385
Other Property and Equipment	46,361	58,317
Wells and Facilities in Progress	127,655	75,514
Pipelines	15,657	7,678
Total Property and Equipment	1,591,125	1,080,574
Less: Accumulated Depreciation, Depletion and Amortization	-366,917	-188,568
Net Property and Equipment	1,224,208	892,006
Deferred Financing Costs and Other Assets – Net	17,070	11,787
Equity Method Investments	17,895	18,708
Long-Term Deferred Tax Asset	8,301
Long-Term Derivative Instruments	4,904	535
Total Assets	1,401,721	991,396
Current Liabilities
Accounts Payable	53,340	30,345
Current Maturities of Long-Term Debt	1,176	1,340
Accrued Liabilities	59,478	48,204
Short-Term Derivative Instruments	421	4,663
Current Deferred Tax Liability	8,301
Liabilities Related to Assets Held for Sale	25,115	15,461
Total Current Liabilities	147,831	100,013
Noncurrent Liabilities
Senior Notes	675,000
Premium on Senior Notes, Net	2,725	3,078
Senior Secured Line of Credit and Other Long-Term Debt	251	59,137
Long-Term Derivative Instruments	2,377	1,765
Other Deposits and Liabilities	4,018	4,992
Future Abandonment Cost	38,146	26,040
Long-Term Deferred Tax Liability		29,446
Total Liabilities	870,348	574,471
Stockholders’ Equity
Preferred Stock	1
Common Stock	54	54
Additional Paid-In Capital	617,826	456,554
Accumulated Earnings (Deficit)	-90,749	-41,725
Rex Energy Stockholders’ Equity	527,132	414,883
Noncontrolling Interests	4,241	2,042
Total Stockholders’ Equity	531,373	416,925	412,294	292,274
Total Liabilities and Stockholders’ Equity	1,401,721	991,396
Eliminations
Current Assets
Assets Held for Sale	-2,537	-3,302
Total Current Assets	-2,537	-3,302
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties	-5,760	-3,101
Wells and Facilities in Progress	-560	-790
Pipelines	-1,898
Total Property and Equipment	-8,218	-3,891
Less: Accumulated Depreciation, Depletion and Amortization	1,037	350
Net Property and Equipment	-7,181	-3,541
Intercompany Receivables	-951,025	-628,517
Investment in Subsidiaries – Net	-264,150	-222,584
Total Assets	-1,224,893	-857,944
Current Liabilities
Accounts Payable	-2,537	-3,304
Total Current Liabilities	-2,537	-3,304
Noncurrent Liabilities
Intercompany Payables	-951,025	-628,517
Total Liabilities	-953,562	-631,821
Stockholders’ Equity
Additional Paid-In Capital	-256,887	-183,632
Accumulated Earnings (Deficit)	-18,483	-44,048
Rex Energy Stockholders’ Equity	-275,370	-227,680
Noncontrolling Interests	4,039	1,557
Total Stockholders’ Equity	-271,331	-226,123
Total Liabilities and Stockholders’ Equity	-1,224,893	-857,944
Guarantor Subsidiaries
Current Assets
Cash and Cash Equivalents	17,978	1,386
Accounts Receivable	43,726	32,284
Short-Term Derivative Instruments	29,265	5,180
Inventory, Prepaid Expenses and Other	3,374	2,092
Total Current Assets	94,343	40,942
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties	1,084,332	752,781
Unevaluated Oil and Gas Properties	321,708	189,385
Other Property and Equipment	45,466	57,409
Wells and Facilities in Progress	127,759	70,759
Pipelines	17,555	7,678
Total Property and Equipment	1,596,820	1,078,012
Less: Accumulated Depreciation, Depletion and Amortization	-367,224	-188,699
Net Property and Equipment	1,229,596	889,313
Deferred Financing Costs and Other Assets – Net	2,421	2,421
Equity Method Investments	17,895	18,708
Investment in Subsidiaries – Net	4,161	4,442
Long-Term Derivative Instruments	4,904	535
Total Assets	1,353,320	956,361
Current Liabilities
Accounts Payable	55,877	33,613
Current Maturities of Long-Term Debt	1,176	1,340
Accrued Liabilities	46,783	45,196
Short-Term Derivative Instruments	421	4,663
Total Current Liabilities	104,257	84,812
Noncurrent Liabilities
Senior Secured Line of Credit and Other Long-Term Debt	251	137
Long-Term Derivative Instruments	2,377	1,071
Other Deposits and Liabilities	4,018	4,992
Future Abandonment Cost	38,097	26,027
Intercompany Payables	947,114	554,329
Total Liabilities	1,096,114	671,368
Stockholders’ Equity
Additional Paid-In Capital	177,144	177,144
Accumulated Earnings (Deficit)	80,062	107,849
Rex Energy Stockholders’ Equity	257,206	284,993
Total Stockholders’ Equity	257,206	284,993
Total Liabilities and Stockholders’ Equity	1,353,320	956,361
Non-Guarantor Subsidiaries
Current Assets
Cash and Cash Equivalents		-84
Accounts Receivable	210
Assets Held for Sale	36,794	21,645
Total Current Assets	37,004	21,561
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties	467
Unevaluated Oil and Gas Properties	705
Other Property and Equipment	895	908
Wells and Facilities in Progress	456	5,545
Total Property and Equipment	2,523	6,453
Less: Accumulated Depreciation, Depletion and Amortization	-730	-219
Net Property and Equipment	1,793	6,234
Investment in Subsidiaries – Net	1,541	1,197
Total Assets	40,338	28,992
Current Liabilities
Accounts Payable		36
Accrued Liabilities	571	41
Liabilities Related to Assets Held for Sale	25,115	15,461
Total Current Liabilities	25,686	15,538
Noncurrent Liabilities
Future Abandonment Cost	49	13
Intercompany Payables	3,911	74,188
Total Liabilities	29,646	89,739
Stockholders’ Equity
Additional Paid-In Capital	79,743	6,488
Accumulated Earnings (Deficit)	-69,253	-67,720
Rex Energy Stockholders’ Equity	10,490	-61,232
Noncontrolling Interests	202	485
Total Stockholders’ Equity	10,692	-60,747
Total Liabilities and Stockholders’ Equity	40,338	28,992
Parent Company
Current Assets
Cash and Cash Equivalents		5
Taxes Receivable	504	5,189
Short-Term Derivative Instruments		488
Inventory, Prepaid Expenses and Other	29	26
Total Current Assets	533	9,159
Current Deferred Tax Asset		3,451
Property and Equipment (Successful Efforts Method)
Deferred Financing Costs and Other Assets – Net	14,649	9,366
Long-Term Deferred Tax Asset	8,301
Intercompany Receivables	951,025	628,517
Investment in Subsidiaries – Net	258,448	216,945
Total Assets	1,232,956	863,987
Current Liabilities
Accrued Liabilities	12,124	2,967
Current Deferred Tax Liability	8,301
Total Current Liabilities	20,425	2,967
Noncurrent Liabilities
Premium on Senior Notes, Net	2,725	3,078
Senior Secured Line of Credit and Other Long-Term Debt		59,000
Long-Term Derivative Instruments		694
Long-Term Deferred Tax Liability		29,446
Total Liabilities	698,150	445,185
Stockholders’ Equity
Preferred Stock	1
Common Stock	54	54
Additional Paid-In Capital	617,826	456,554
Accumulated Earnings (Deficit)	-83,075	-37,806
Rex Energy Stockholders’ Equity	534,806	418,802
Total Stockholders’ Equity	534,806	418,802
Total Liabilities and Stockholders’ Equity	1,232,956	863,987
8.875% Senior Notes
Noncurrent Liabilities
Senior Notes	350,000	350,000
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)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 12, 2012	Jul. 17, 2014
8.875% Senior Notes
Condensed Balance Sheet Statements Captions [Line Items]
Interest rate	8.88%	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%		6.25%
Due date	2022	2022

Condensed_Consolidating_Statem

Condensed Consolidating Statements of Operations (Details) (USD $)	3 Months Ended										12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
OPERATING REVENUE
Oil, Natural Gas and NGL Sales											$297,869	$213,919	$134,574
Other Revenue											118	200	218
TOTAL OPERATING REVENUE	70,245		73,466	72,933	81,343	63,508		58,127	51,520	40,964	297,987	214,119	134,792
OPERATING EXPENSES
Production and Lease Operating Expense											100,282	62,150	47,638
General and Administrative Expense											36,137	30,839	22,458
Loss on Disposal of Asset											644	1,602	50
Impairment Expense	132,600					29,700					132,618	32,072	20,571
Exploration Expense											9,446	11,408	4,782
Depreciation, Depletion, Amortization and Accretion											94,467	62,386	44,955
Other Operating Expense											134	592	1,136
TOTAL OPERATING EXPENSES	139,913	[1]	67,847	65,290	72,587	77,265	[1]	56,469	38,280	44,488	373,728	201,049	141,590
INCOME (LOSS) FROM OPERATIONS											-75,741	13,070	-6,798
OTHER INCOME (EXPENSE)
Interest Expense											-36,977	-22,676	-6,418
Gain (Loss) on Derivatives, Net											38,876	-2,908	10,687
Other Income											90	6,739	98,653
Loss on Equity Method Investments											-813	-763	-3,921
TOTAL OTHER INCOME (EXPENSE)											1,176	-19,608	99,001
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX											-74,565	-6,538	92,203
Income Tax (Expense) Benefit											26,915	4,154	-37,282
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	-69,668		5,619	7,643	8,756	-13,757		1,658	13,240	-3,524	-47,650	-2,384	54,921
Income (Loss) From Discontinued Operations, Net of Income Taxes											5,000	1,811	-8,623
NET INCOME (LOSS)	-68,631		6,589	8,955	10,437	-13,965		1,832	13,961	-2,401	-42,650	-573	46,298
Net Income Attributable to Noncontrolling Interests of Discontinued Operations	698		895	877	1,569	645		258	221	433	4,039	1,557	819
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	-69,329		5,694	8,078	8,868	-14,610		1,574	13,740	-2,834	-46,689	-2,130	45,479
Preferred Stock Dividends	2,335										2,335
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	-71,664		5,694	8,078	8,868						-49,024	-2,130	45,479
Eliminations
OPERATING EXPENSES
Depreciation, Depletion, Amortization and Accretion											-689	-200	-83
TOTAL OPERATING EXPENSES											-689	-200	-83
INCOME (LOSS) FROM OPERATIONS											689	200	83
OTHER INCOME (EXPENSE)
Income (Loss) From Equity in Consolidated Subsidiaries											20,204	-5,703	-51,363
TOTAL OTHER INCOME (EXPENSE)											20,204	-5,703	-51,363
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX											20,893	-5,503	-51,280
NET INCOME (LOSS) FROM CONTINUING OPERATIONS											20,893	-5,503	-51,280
Income (Loss) From Discontinued Operations, Net of Income Taxes											-4,330	-2,574	-671
NET INCOME (LOSS)											16,563	-8,077	-51,951
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY											16,563	-8,077	-51,951
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS											16,563
Guarantor Subsidiaries
OPERATING REVENUE
Oil, Natural Gas and NGL Sales											297,710	213,919	134,574
Other Revenue											118	200	218
TOTAL OPERATING REVENUE											297,828	214,119	134,792
OPERATING EXPENSES
Production and Lease Operating Expense											100,261	62,138	47,618
General and Administrative Expense											30,317	25,376	19,283
Loss on Disposal of Asset											644	1,601	50
Impairment Expense											126,662	32,072	20,505
Exploration Expense											9,165	11,395	4,782
Depreciation, Depletion, Amortization and Accretion											94,643	62,540	44,993
Other Operating Expense											134	592	1,136
TOTAL OPERATING EXPENSES											361,826	195,714	138,367
INCOME (LOSS) FROM OPERATIONS											-63,998	18,405	-3,575
OTHER INCOME (EXPENSE)
Interest Expense											-142	-64	-55
Gain (Loss) on Derivatives, Net											37,359	-2,703	10,687
Other Income											90	6,739	99,575
Loss on Equity Method Investments											-813	-763	-3,921
Income (Loss) From Equity in Consolidated Subsidiaries											-4,278	-33	-68
TOTAL OTHER INCOME (EXPENSE)											32,216	3,176	106,218
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX											-31,782	21,581	102,643
Income Tax (Expense) Benefit											9,928	-14,409	-41,772
NET INCOME (LOSS) FROM CONTINUING OPERATIONS											-21,854	7,172	60,871
Income (Loss) From Discontinued Operations, Net of Income Taxes												0	0
NET INCOME (LOSS)											-21,854	7,172	60,871
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY											-21,854	7,172	60,871
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS											-21,854
Non-Guarantor Subsidiaries
OPERATING REVENUE
Oil, Natural Gas and NGL Sales											159
TOTAL OPERATING REVENUE											159
OPERATING EXPENSES
Production and Lease Operating Expense											21	12	20
General and Administrative Expense											83	43	16
Loss on Disposal of Asset												1
Impairment Expense											5,956		66
Exploration Expense											281	13
Depreciation, Depletion, Amortization and Accretion											513	46	45
TOTAL OPERATING EXPENSES											6,854	115	147
INCOME (LOSS) FROM OPERATIONS											-6,695	-115	-147
OTHER INCOME (EXPENSE)
Interest Expense													-1
Income (Loss) From Equity in Consolidated Subsidiaries											4,278	33	68
TOTAL OTHER INCOME (EXPENSE)											4,278	33	67
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX											-2,417	-82	-80
Income Tax (Expense) Benefit											2,417	-1,841	-69
NET INCOME (LOSS) FROM CONTINUING OPERATIONS												-1,923	-149
Income (Loss) From Discontinued Operations, Net of Income Taxes											9,330	4,385	-7,952
NET INCOME (LOSS)											9,330	2,462	-8,101
Net Income Attributable to Noncontrolling Interests of Discontinued Operations											4,039	1,557	819
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY											5,291	905	-8,920
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS											5,291
Parent Company
OPERATING EXPENSES
General and Administrative Expense											5,737	5,420	3,159
TOTAL OPERATING EXPENSES											5,737	5,420	3,159
INCOME (LOSS) FROM OPERATIONS											-5,737	-5,420	-3,159
OTHER INCOME (EXPENSE)
Interest Expense											-36,835	-22,612	-6,362
Gain (Loss) on Derivatives, Net											1,517	-205
Other Income													-922
Income (Loss) From Equity in Consolidated Subsidiaries											-20,204	5,703	51,363
TOTAL OTHER INCOME (EXPENSE)											-55,522	-17,114	44,079
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX											-61,259	-22,534	40,920
Income Tax (Expense) Benefit											14,570	20,404	4,559
NET INCOME (LOSS) FROM CONTINUING OPERATIONS											-46,689	-2,130	45,479
Income (Loss) From Discontinued Operations, Net of Income Taxes												0	0
NET INCOME (LOSS)											-46,689	-2,130	45,479
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY											-46,689	-2,130	45,479
Preferred Stock Dividends											2,335
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS											($49,024)
[1]	For the three-month periods ended December 31, 2014 and 2013, we incurred impairment expense of approximately $132.6 million and $29.7 million, respectively.

Condensed_Consolidating_Statem1

Condensed Consolidating Statements of Cash Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	($42,650)	($573)	$46,298
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss on Equity Method Investments	813	763	3,921
Non-Cash Expenses (Income)	6,789	6,230	3,191
Depreciation, Depletion, Amortization and Accretion	98,171	63,944	46,441
Deferred Income Tax Expense (Benefit)	-25,992	2,279	23,665
(Gain) Loss on Derivatives	-38,876	2,908	-10,687
Cash Settlements of Derivatives	7,281	7,128	16,219
Dry Hole Expense	4,064	2,993	656
(Gain) Loss on Sale of Asset	589	-6,211	-100,551
Impairment Expense	132,684	32,072	40,355
Changes in operating assets and liabilities
Accounts Receivable	-13,620	-12,726	-13,698
Inventory, Prepaid Expenses and Other Assets	-1,359	-885	-92
Accounts Payable and Accrued Liabilities	37,274	12,891	-8,832
Other Assets and Liabilities	-2,462	-2,497	-1,181
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	162,706	108,316	45,705
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management	263	458	260
Contributions to Equity Method Investments		-2,493	-4,087
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	546	11,305	133,425
Acquisitions of Undeveloped Acreage	-169,423	-41,784	-51,802
Capital Expenditures for Development of Oil and Gas Properties and Equipment	-391,422	-281,004	-178,538
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	-560,036	-313,518	-100,742
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds of Long-Term Debt and Lines of Credit	209,895	72,249	126,730
Repayments from Long-Term Debt and Lines of Credit	-263,152	-8,480	-351,000
Repayments of Loans and Other Notes Payable	-2,721	-2,005	-962
Proceeds from Senior Notes, Net of Discounts and Premiums	325,000	105,000	248,250
Debt Issuance Costs	-6,824	-3,134	-6,397
Proceeds from the Issuance of Preferred Stock, Net	154,988
Proceeds from the Exercise of Stock Options	515	533	565
Proceeds from the Issuance of Common Stock, Net			70,583
Settlement of Tax Withholdings Related to Share-Based Compensation Awards			-234
Purchase of Noncontrolling Interests		-150
Distributions by the Partners of Consolidated Subsidiary	-1,840	-886	-319
Dividends Paid on Preferred Stock	-2,335
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	413,526	163,127	87,216
NET INCREASE (DECREASE) IN CASH	16,196	-42,075	32,179
CASH AND CASH EQUIVALENTS – BEGINNING	1,900	43,975	11,796
CASH AND CASH EQUIVALENTS – ENDING	18,096	1,900	43,975
Eliminations
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	16,563	-8,077	-51,951
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Depreciation, Depletion, Amortization and Accretion	-689	-200	-83
Changes in operating assets and liabilities
Accounts Receivable	-766	-1,575	-201
Accounts Payable and Accrued Liabilities	766	1,982	-107
Other Assets and Liabilities			29
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	15,874	-7,870	-52,313
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries	-20,202	5,307	51,643
Capital Expenditures for Development of Oil and Gas Properties and Equipment	4,328	2,563	670
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	-15,874	7,870	52,313
Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	-21,854	7,172	60,871
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss on Equity Method Investments	813	763	3,921
Non-Cash Expenses (Income)	-273	-194	33
Depreciation, Depletion, Amortization and Accretion	94,643	62,540	44,993
Deferred Income Tax Expense (Benefit)	-9,928	14,409	35,376
(Gain) Loss on Derivatives	-37,359	2,703	-10,687
Cash Settlements of Derivatives	5,969	7,128	16,219
Dry Hole Expense	3,797	2,993	320
(Gain) Loss on Sale of Asset	644	-5,289	-99,355
Impairment Expense	126,662	32,072	20,505
Changes in operating assets and liabilities
Accounts Receivable	-11,450	-5,877	29,564
Inventory, Prepaid Expenses and Other Assets	-1,283	-826	-139
Accounts Payable and Accrued Liabilities	23,768	8,554	-8,875
Other Assets and Liabilities	-2,127	-2,272	-1,146
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	172,022	123,876	91,600
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries	397,382	186,089	2,915
Proceeds from Joint Venture Acreage Management	263	458	260
Contributions to Equity Method Investments		-2,493
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	254	8,071	128,554
Acquisitions of Undeveloped Acreage	-168,713	-41,782	-51,783
Capital Expenditures for Development of Oil and Gas Properties and Equipment	-382,889	-275,697	-177,892
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	-153,703	-125,354	-97,946
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Loans and Other Notes Payable	-1,727	-1,363	-764
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	-1,727	-1,363	-764
NET INCREASE (DECREASE) IN CASH	16,592	-2,841	-7,110
CASH AND CASH EQUIVALENTS – BEGINNING	1,386	4,227	11,337
CASH AND CASH EQUIVALENTS – ENDING	17,978	1,386	4,227
Non-Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	9,330	2,462	-8,101
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Non-Cash Expenses (Income)	278	55	14
Depreciation, Depletion, Amortization and Accretion	4,217	1,604	527
Deferred Income Tax Expense (Benefit)	-1,649	2,210	-7,152
Dry Hole Expense	267		336
(Gain) Loss on Sale of Asset	-55	-922	-2,118
Impairment Expense	6,022		19,850
Changes in operating assets and liabilities
Accounts Receivable	-6,090	-6,515	-3,736
Inventory, Prepaid Expenses and Other Assets	-74	-59	32
Accounts Payable and Accrued Liabilities	3,488	874	-766
Other Assets and Liabilities	-335	-88	-64
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	15,399	-379	-1,178
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries	-5,412	1,619	1,931
Contributions to Equity Method Investments			-4,087
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	292	3,234	4,871
Acquisitions of Undeveloped Acreage	-710	-2	-19
Capital Expenditures for Development of Oil and Gas Properties and Equipment	-12,861	-7,870	-1,316
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	-18,691	-3,019	1,380
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds of Long-Term Debt and Lines of Credit	38,895	7,249	730
Repayments from Long-Term Debt and Lines of Credit	-33,152	-2,480
Repayments of Loans and Other Notes Payable	-994	-642	-198
Debt Issuance Costs	-8	-8
Purchase of Noncontrolling Interests		-150
Distributions by the Partners of Consolidated Subsidiary	-1,840	-886	-319
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	2,901	3,083	213
NET INCREASE (DECREASE) IN CASH	-391	-315	415
CASH AND CASH EQUIVALENTS – BEGINNING	509	824	409
CASH AND CASH EQUIVALENTS – ENDING	118	509	824
Parent Company
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	-46,689	-2,130	45,479
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Non-Cash Expenses (Income)	6,784	6,369	3,144
Depreciation, Depletion, Amortization and Accretion			1,004
Deferred Income Tax Expense (Benefit)	-14,415	-14,340	-4,559
(Gain) Loss on Derivatives	-1,517	205
Cash Settlements of Derivatives	1,312
(Gain) Loss on Sale of Asset			922
Changes in operating assets and liabilities
Accounts Receivable	4,686	1,241	-39,325
Inventory, Prepaid Expenses and Other Assets	-2		15
Accounts Payable and Accrued Liabilities	9,252	1,481	916
Other Assets and Liabilities		-137
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	-40,589	-7,311	7,596
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries	-371,768	-193,015	-56,489
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	-371,768	-193,015	-56,489
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds of Long-Term Debt and Lines of Credit	171,000	65,000	126,000
Repayments from Long-Term Debt and Lines of Credit	-230,000	-6,000	-351,000
Proceeds from Senior Notes, Net of Discounts and Premiums	325,000	105,000	248,250
Debt Issuance Costs	-6,816	-3,126	-6,397
Proceeds from the Issuance of Preferred Stock, Net	154,988
Proceeds from the Exercise of Stock Options	515	533	565
Proceeds from the Issuance of Common Stock, Net			70,583
Settlement of Tax Withholdings Related to Share-Based Compensation Awards			-234
Dividends Paid on Preferred Stock	-2,335
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	412,352	161,407	87,767
NET INCREASE (DECREASE) IN CASH	-5	-38,919	38,874
CASH AND CASH EQUIVALENTS – BEGINNING	5	38,924	50
CASH AND CASH EQUIVALENTS – ENDING		$5	$38,924

Subsequent_Event_Additional_In

Subsequent Event - Additional Information (Details) (Subsequent Event, USD $)	1 Months Ended
In Millions, unless otherwise specified	Jan. 31, 2015
Subsequent Event [Line Items]
Cancellation fees on drilling rig agreement	$5
Contract cancellation condition	The settlement and release agreement contains provisions under which we can earn credits towards the second payment if the drilling rig is utilized by us or an unrelated third-party over the term of the original contract, which was January 1, 2015 through December 31, 2016.
First Installment
Subsequent Event [Line Items]
Cancellation fees on drilling rig agreement	2.5
Second and Final Installment
Subsequent Event [Line Items]
Cancellation fees on drilling rig agreement	$2.50
Cancellation fees due date	30-Jan-16