Rex Energy 10-K 3 Mar 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 27, 2014	Jun. 28, 2013
Document Information [Line Items]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Trading Symbol	'REXX	'	'
Entity Registrant Name	'REX ENERGY CORP	'	'
Entity Central Index Key	'0001397516	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Common Stock, Shares Outstanding	'	54,180,193	'
Entity Public Float	'	'	$800,680,133

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current Assets	'	'
Cash and Cash Equivalents	$1,900	$43,975
Accounts Receivable	38,863	24,980
Taxes Receivable	5,189	6,429
Short-Term Derivative Instruments	5,668	12,005
Current Deferred Tax Asset	3,451	0
Assets Held For Sale	0	2,279
Inventory, Prepaid Expenses and Other	2,207	1,316
Total Current Assets	57,278	90,984
Property and Equipment (Successful Efforts Method)	'	'
Evaluated Oil and Gas Properties	749,680	485,448
Unevaluated Oil and Gas Properties	189,385	165,503
Other Property and Equipment	70,115	50,073
Wells and Facilities in Progress	76,545	92,913
Pipelines	7,678	6,116
Total Property and Equipment	1,093,403	800,053
Less: Accumulated Depreciation, Depletion and Amortization	-190,521	-146,038
Net Property and Equipment	902,882	654,015
Deferred Financing Costs and Other Assets-Net	11,993	10,029
Equity Method Investments	18,708	16,978
Long-Term Derivative Instruments	535	704
Total Assets	991,396	772,710
Current Liabilities	'	'
Accounts Payable	31,103	29,448
Current Maturities of Long-Term Debt	6,743	1,686
Accrued Liabilities	54,450	23,019
Short-Term Derivative Instruments	4,663	1,389
Current Deferred Tax Liability	0	539
Liabilities Related to Assets Held for Sale	0	52
Total Current Liabilities	96,959	56,133
8.875% Senior Notes Due 2020	350,000	250,000
Premium (Discount) on Senior Notes-Net	3,078	-1,742
Senior Secured Line of Credit and Long-Term Debt	62,191	991
Long-Term Derivative Instruments	1,765	1,510
Long-Term Deferred Tax Liability	29,446	23,625
Other Deposits and Liabilities	4,992	5,675
Future Abandonment Cost	26,040	24,224
Total Liabilities	574,471	360,416
Commitments and Contingencies (See Note 9)	'	'
Stockholders' Equity	'	'
Common Stock	54	52
Additional Paid-In Capital	456,554	451,062
Accumulated Deficit	-41,725	-39,595
Rex Energy Stockholders' Equity	414,883	411,519
Noncontrolling Interests	2,042	775
Total Stockholders' Equity	416,925	412,294
Total Liabilities and Stockholders' Equity	$991,396	$772,710

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Common Stock, par value	0.001	0.001
Authorized capital stock, common stock	100,000,000	100,000,000
Common Stock, shares issued	54,186,490	53,213,264
Common Stock, shares outstanding	54,186,490	53,213,264
8.875% Senior Notes	'	'
Interest rate	8.88%	8.88%
Due date	'2020	'2020

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, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
OPERATING REVENUE	'	'	'	'	'	'	'	'	'		'		'
Oil, Natural Gas and NGL Sales	'	'	'	'	'	'	'	'	$213,919		$134,574		$111,879
Field Services Revenue	'	'	'	'	'	'	'	'	23,812		13,403		2,518
Other Revenue	'	'	'	'	'	'	'	'	200		162		209
TOTAL OPERATING REVENUE	72,127	62,974	55,360	47,470	45,119	38,929	30,257	33,834	237,931		148,139		114,606
OPERATING EXPENSES	'	'	'	'	'	'	'	'	'		'		'
Production and Lease Operating Expense	'	'	'	'	'	'	'	'	62,138		47,638		33,116
General and Administrative Expense	'	'	'	'	'	'	'	'	33,126		23,345		23,636
Loss on Disposal of Asset	'	'	'	'	'	'	'	'	1,647		58		502
Impairment Expense	'	'	'	'	'	'	'	'	32,072		20,585		14,631
Exploration Expense	'	'	'	'	'	'	'	'	11,408		4,782		2,507
Depreciation, Depletion, Amortization and Accretion	'	'	'	'	'	'	'	'	63,944		45,437		27,856
Field Services Operating Expense	'	'	'	'	'	'	'	'	17,330		8,240		1,750
Other Operating Expense	'	'	'	'	'	'	'	'	592		1,136		819
TOTAL OPERATING EXPENSES	85,401	61,142	41,919	49,810	46,157	40,671	-25,936	30,006	222,257		151,221		104,817
INCOME (LOSS) FROM OPERATIONS	'	'	'	'	'	'	'	'	15,674		-3,082		9,789
OTHER INCOME (EXPENSE)	'	'	'	'	'	'	'	'	'		'		'
Interest Expense	'	'	'	'	'	'	'	'	-22,782		-6,443		-2,514
Gain (Loss) on Derivatives, Net	'	'	'	'	'	'	'	'	-2,908		10,687		18,916
Other Income	'	'	'	'	'	'	'	'	6,653		98,549		79
Income (Loss) from Equity Method Investments	'	'	'	'	'	'	'	'	-763		-3,921		81
TOTAL OTHER INCOME (LOSS)	'	'	'	'	'	'	'	'	-19,800		98,872		16,562
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX	'	'	'	'	'	'	'	'	-4,126		95,790		26,351
Income Tax (Expense) Benefit	'	'	'	'	'	'	'	'	3,785		-38,549		-8,270
INCOME (LOSS) FROM CONTINUING OPERATIONS	'	'	'	'	'	'	'	'	-341		57,241		18,081
Loss From Discontinued Operations, Net of Income Taxes	-691	0	520	-61	-2,280	-258	-3,050	-5,355	-232		-10,943		-33,457
NET INCOME (LOSS)	-13,965	1,832	13,961	-2,401	-3,318	-2,000	53,143	-1,527	-573		46,298		-15,376
Net Income (Loss) Attributable to Noncontrolling Interests	645	258	221	433	303	193	222	101	1,557		819		-7
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	($14,610)	$1,574	$13,740	($2,834)	($3,621)	($2,193)	$52,921	($1,628)	($2,130)		$45,479		($15,369)
Earnings Per Common Share:	'	'	'	'	'	'	'	'	'		'		'
Basic-income (loss) from continuing operations attributable to Rex common shareholders	($0.26)	$0.03	$0.25	($0.05)	($0.03)	($0.04)	$1.08	$0.08	($0.04)	[1]	$1.09	[1]	$0.41	[1]
Basic-loss from discontinued operations attributable to Rex common shareholders	($0.01)	$0	$0.01	$0	($0.04)	$0	($0.06)	($0.11)	$0	[1]	($0.21)	[1]	($0.76)	[1]
Basic-net income (loss) attributable to Rex common shareholders	($0.27)	$0.03	$0.26	($0.05)	($0.07)	($0.04)	$1.02	($0.03)	($0.04)	[1]	$0.88	[1]	($0.35)	[1]
Basic-weighted average shares of common stock outstanding	52,705	52,626	52,555	52,367	52,278	52,036	52,009	48,744	52,572		51,543		43,930
Diluted-income (loss) from continuing operations attributable to Rex common shareholders	($0.26)	$0.03	$0.25	($0.05)	($0.03)	($0.04)	$1.06	$0.08	($0.04)	[1]	$1.08	[1]	$0.41	[1]
Diluted-loss from discontinued operations attributable to Rex common shareholders	($0.01)	$0	$0.01	$0	($0.04)	$0	($0.06)	($0.11)	$0	[1]	($0.21)	[1]	($0.76)	[1]
Diluted-net income (loss) attributable to Rex common shareholders	($0.27)	$0.03	$0.26	($0.05)	($0.07)	($0.04)	$1	($0.03)	($0.04)	[1]	$0.87	[1]	($0.35)	[1]
Diluted-weighted average shares of common stock outstanding	52,705	53,293	52,911	52,367	52,278	52,036	52,876	49,693	52,572		52,025		44,476
[1]	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	Additional Paid-In Capital	Accumulated Deficit	Rex Energy Stockholders' Equity	Noncontrolling Interests
In Thousands, except Share data
Balance at Dec. 31, 2010	$304,676	$44	$373,856	($69,519)	$304,381	$295
Balance (in shares) at Dec. 31, 2010	'	44,307,000	'	'	'	'
Non-cash compensation expense (in shares)	'	0	'	'	'	'
Non-cash compensation expense	1,625	0	1,625	0	1,625	0
Capital distributions	-13	0	0	0	0	-13
Restricted stock, net (in shares)	'	413,000	'	'	'	'
Restricted stock, net	0	0	0	0	0	0
Stock option exercises (in shares)	139,682	139,000	'	'	'	'
Stock option exercises	1,362	0	1,362	0	1,362	0
Net Income (Loss)	-15,376	0	0	-15,369	-15,369	-7
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 expense (in shares)	'	0	'	'	'	'
Non-cash compensation expense	2,893	0	3,079	-186	2,893	0
Capital distributions	-319	0	0	0	0	-319
Restricted stock, net (in shares)	'	252,000	'	'	'	'
Restricted stock, net	0	0	0	0	0	0
Stock option exercises (in shares)	52,287	52,000	'	'	'	'
Stock option exercises	565	0	565	0	565	0
Issuance of common stock, net of issuance costs (in shares)	'	8,050,000	'	'	'	'
Issuance of common stock, net of issuance costs	70,583	8	70,575	0	70,583	0
Net Income (Loss)	46,298	0	0	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 expense (in shares)	'	0	'	'	'	'
Non-cash compensation expense	5,418	0	5,418	0	5,418	0
Capital distributions	-886	0	0	0	0	-886
Restricted stock, net (in shares)	'	924,000	'	'	'	'
Restricted stock, net	0	0	0	0	0	0
Stock option exercises (in shares)	49,166	49,000	'	'	'	'
Stock option exercises	536	2	534	0	536	0
Change in Ownership of Noncontrolling Interests	136	0	-460	0	-460	596
Net Income (Loss)	-573	0	0	-2,130	-2,130	1,557
Balance at Dec. 31, 2013	$416,925	$54	$456,554	($41,725)	$414,883	$2,042
Balance (in shares) at Dec. 31, 2013	'	54,186,000	'	'	'	'

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES	'	'	'
Net Income (Loss)	($573)	$46,298	($15,376)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities	'	'	'
(Gain) Loss from Equity Method Investments	763	3,921	-81
Non-Cash Expenses	6,230	3,191	1,745
Depreciation, Depletion, Amortization and Accretion	63,944	46,441	28,446
Deferred Income Tax Expense (Benefit)	2,279	23,665	-7,339
(Gain) Loss on Derivatives	2,908	-10,687	-18,916
Cash Settlements of Derivatives	7,128	16,219	6,212
Dry Hole Expense	2,993	656	32,769
(Gain) Loss on Sale of Assets and Equity Method Investments	-6,211	-100,551	502
Impairment Expense	32,072	40,355	27,808
Changes in operating assets and liabilities	'	'	'
Accounts Receivable	-12,726	-13,698	11,118
Inventory, Prepaid Expenses and Other Assets	-885	-92	86
Accounts Payable and Accrued Liabilities	12,891	-8,832	-1,996
Other Assets and Liabilities	-2,497	-1,181	-471
NET CASH PROVIDED BY OPERATING ACTIVITIES	108,316	45,705	64,507
CASH FLOWS FROM INVESTING ACTIVITIES	'	'	'
Proceeds from Joint Venture Leasing Initiatives	458	260	3,209
Change in Restricted Cash	0	0	16,086
Contributions to Equity Method Investments	-2,493	-4,087	-23,204
Proceeds from the Sale of Assets and Equity Method Investments	11,305	133,425	2,729
Acquisitions of Undeveloped Acreage	-41,784	-51,802	-78,569
Capital Expenditures for Development of Oil & Gas Properties and Equipment	-281,004	-178,538	-196,825
NET CASH USED IN INVESTING ACTIVITIES	-313,518	-100,742	-276,574
CASH FLOWS FROM FINANCING ACTIVITIES	'	'	'
Proceeds from Long-Term Debt and Lines of Credit	72,249	126,730	240,000
Repayments of Long-Term Debt and Lines of Credit	-8,480	-351,000	-25,000
Repayments of Loans and Other Long-Term Debt	-2,005	-962	-879
Proceeds from Senior Notes, Including Premiums	105,000	248,250	0
Debt Issuance Costs	-3,134	-6,397	-2,615
Settlement of Tax Withholdings Related to Share-Based Compensation Awards	0	-234	0
Proceeds from the Issuance of Common Stock, Net of Issuance Costs	0	70,583	0
Proceeds from the Exercise of Stock Options	533	565	1,362
Purchase of Noncontrolling Interests	-150	0	0
Capital Distributions by the Partners of Consolidated Joint Ventures	-886	-319	-20
Capital Contributions by the Partners of Equity Method Investments and Consolidated Joint Ventures	0	0	7
NET CASH PROVIDED BY FINANCING ACTIVITIES	163,127	87,216	212,855
NET INCREASE (DECREASE) IN CASH	-42,075	32,179	788
CASH-BEGINNING	43,975	11,796	11,008
CASH-ENDING	1,900	43,975	11,796
SUPPLEMENTAL DISCLOSURES	'	'	'
Interest Paid	31,153	7,568	1,549
Cash Paid for Income Taxes, Net of Refunds	-6,390	12,824	312
NON-CASH ACTIVITIES	'	'	'
Increase in Accrued Capital Expenditures	$22,138	$4,430	$1,342

Basis_Of_Presentation_And_Prin

Basis Of Presentation And Principles Of Consolidation	12 Months Ended
	Dec. 31, 2013
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, in addition to our developmental oil drilling, we are focused on 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. In addition to our drilling and exploration activities, we are also engaged in oil and natural gas field services, where we provide water sourcing, water disposal and water transfer solutions for completion operations.
	The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of all of our wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries together. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies.
	Certain prior year amounts have been reclassified to conform to the report classifications for the year ended December 31, 2013, with no effect on previously reported net income, net income per share, accumulated deficit or stockholders’ equity. For purposes of consistency with current presentation, we have reclassified approximately $3.9 million from Wells and Facilities in Progress to Unevaluated Oil and Gas Properties and approximately $0.6 million from Future Abandonment Costs to Accrued Liabilities on our Consolidated Balance Sheet as of December 31, 2012. For the years ended December 31, 2012 and 2011, we reclassified approximately $2.1 million and $0.9 million from changes in Other Assets and Liabilities to changes in Accounts Payable and Accrued Liabilities, respectively, with no effect to Cash Provided by Operating Activities.
	We consolidate all of our subsidiaries in the accompanying Consolidated Balance Sheets as of December 31, 2013 and 2012 and the Consolidated Statements of Operations, Cash Flows and Changes in Noncontrolling Interests and Stockholders’ Equity for the years ended December 31, 2013, 2012 and 2011. Investments in unconsolidated affiliates in which we are able to exercise significant influence are accounted for using the equity method. All intercompany transactions and accounts have been eliminated.
	Discontinued Operations
	During December 2011, our board of directors approved a formal plan to sell our DJ Basin assets located in the states of Wyoming and Colorado. Pursuant to the rules for discontinued operations, these assets have been classified as Assets Held for Sale on our Consolidated Balance Sheet as of December 31, 2012, and the results of operations are reflected as Discontinued Operations in our Consolidated Statements of Operations. Unless otherwise noted, all disclosures and tables reflect the results of continuing operations and exclude any assets, liabilities or results from our discontinued operations. For additional information see Note 5, Discontinued Operations/Assets Held for Sale, to our Consolidated Financial Statements.

Summary_Of_Significant_Account

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
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, 2013 and 2012, 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, 2013 and 2012, 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, 2013, we carried approximately $28.8 million in production receivable, of which approximately $22.7 million were production receivables due from four purchasers. At December 31, 2012, we carried approximately $18.1 million in production receivables, of which approximately $16.3 million were production receivables due from four purchasers. In addition, we carried approximately $4.4 million in receivables from Sumitomo Corporation at December 31, 2013 and $2.1 million at December 31, 2012 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. 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.
	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.
	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. 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 and future development plans. When evaluating the value of our unproved oil, NGL and natural gas properties, we utilize active market prices for similar acreage to use as a comparison tool against the carrying value of our properties. If the active market prices for similar acreage do not support our carrying values we then utilize estimates of future value that will be created from the future development of these properties. If future estimated fair value of these properties is lower than the capitalized cost, the capitalized cost is reduced to the estimated future fair value. We recognized approximately $32.1 million, $20.6 million and $14.6 million of impairment from continuing operations on certain oil, NGL and natural gas properties for the years ending December 31, 2013, 2012 and 2011, 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, 2013 and 2012, 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, 2013, we had deferred financing costs and other assets consisting of $12.0 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, three 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, 2013, 2012 and 2011, we recorded amortization expense from continuing operations of $1.3 million, $1.2 million and $0.8 million, respectively.
	The following is a summary of our deferred financing costs at the dates indicated:
			December 31,			December 31,
			2013			2012
			(in thousands)			(in thousands)
	Deferred Financing Costs—Gross		$	12,404		$	9,270
	Accumulated Amortization			(3,031	)		(1,866	)
	Deferred Financing Costs—Net		$	9,373		$	7,404
	Specific to our deferred financing costs, we have incurred gross debt issuance costs of approximately $3.1 million and $6.4 million for the years ended December 31, 2013 and 2012, respectively, which are presented net of accumulated amortization of $3.0 million and $1.9 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, 2013, 2012 and 2011 totaled approximately $3.0 million, $2.1 million and $1.5 million, respectively. These amounts are recorded as DD&A on our Consolidated Statements of Operations. As of December 31, 2013 and 2012, approximately $2.5 million and $0.6 million, respectively, of our Future Abandonment Costs were classified as short-term liabilities under the caption Accrued Expenses on our Consolidated Balance Sheets. During 2013 and 2012, we recognized an increase of $1.3 million and $4.0 million, respectively, in the estimated present value of our asset retirement obligations, representing an increase in the estimate to plug and abandon our oil and natural gas wells. The revised estimates were primarily the result of increased abandonment estimates, which were driven by the trends of actual outcomes. We account for asset retirement obligations that relate to wells that are drilled jointly based on our interest in those wells.
			December 31,			December 31,
			2013			2012
			($  in Thousands)			($  in Thousands)
	Beginning Balance		$	24,822		$	18,670
	Asset Retirement Obligation Incurred			1,750			598
	Asset Retirement Obligation Settled			(2,452	)		(428	)
	Asset Retirement Obligation Cancelled or Sold Well Properties			0			0
	Asset Retirement Obligation Revision of Estimated Obligation			1,311			3,953
	Asset Retirement Obligation Accretion Expense			3,094			2,029
	Total Future Abandonment Costs1		$	28,525		$	24,822
	1	As of December 31, 2013 and 2012, approximately $2.5 million and $0.6 million, respectively of our Future Abandonment Costs were classified as short-term liabilities under the caption Accrued Expenses on our Consolidated Balance Sheets.
	Revenue Recognition
	As it pertains to our exploration and production business segment, 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 our field services segment, 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, basis swaps and three-way collars to manage price risks in connection with the sale of oil, natural gas and NGLs. We have also, use 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 2013, 2012 and 2011 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 other temporary 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.
Capitalization of Interest
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, 2013, 2012 and 2011, we capitalized interest costs of $7.5 million, $3.0 million and $1.2 million, respectively.
Earnings per 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 by dividing consolidated net income attributable to us by the weighted average number of common shares outstanding during the period, including any potentially dilutive outstanding securities, such as options and warrants. The potentially dilutive outstanding securities are calculated using the treasury stock method. At December 31, 2013, we had 54,186,490 common shares outstanding, 449,087 options outstanding and 20,500 stock appreciation rights outstanding with no outstanding warrants or other potentially dilutive securities. The total common shares outstanding include 2,172,639 restricted stock awards, of which approximately 1,279,050 shares are performance-based awards. For additional information, see Note 14, Earnings per Common Share, to our Consolidated Financial Statements.
Capital Leases
As a lessee, we determine if a lease is a capital lease if it meets one of four of the following criteria:
	•		The ownership of the leased property transfers to us by the end of the lease term, or shortly thereafter, in exchange for the payment of a nominal fee.
	•		The lease contains a bargain purchase option.
	•		The lease term is equal to 75% or more of the estimated economic life of the leased property.
	•		The present value at the beginning of the lease term of the minimum lease payments, excluding that portion of the payments representing executor costs such as insurance, maintenance, and taxes to be paid by the lessor, including any profit thereon, equals or exceeds 90% of the excess of the fair value of the leased property to the lessor at the lease inception over any related investment tax credit retained by the lessor and expected to be realized by the lessor.
As of December 31, 2013 we had capital leases on field vehicles being used in our field services operating segment. We recorded these leases as Other Property and Equipment on our Consolidated Balance Sheets in the amount of $3.0 million as of December 31, 2013, and $1.6 million as of December 31, 2012. The remaining obligation to be paid on these leases totaled approximately $2.2 million, of which $1.4 million was classified as Senior Secured Line of Credit and Long-Term Debt under Long-Term Liabilities and $0.8 million was classified as Current Maturities of Long-Term Debt under Current Liabilities on our Consolidated Balance Sheets, all of which is expected to be paid by 2017. The amortization of our capital leases is recorded as Depreciation, Depletion, Amortization and Accretion on our Consolidated Statements of Operations.
Recent Accounting Pronouncements
In January 2013, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. ASU 2013-01 was issued to address implementation issues regarding the scope of ASU 2011-11. The amendments clarify that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with Section 210-20-45 or Section 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. We adopted this ASU on January 1, 2013 with no material effect on our Consolidated Financial Statements.
In July 2013, the FASB issued ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. This ASU clarifies the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The ASU is effective for fiscal years, and interim period within those years, beginning after December 15, 2013. We do not expect this update to have a material impact on our Consolidated Financial Statements.
In December 2011, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. ASU 2011-11 provides new disclosure requirements related to offsetting arrangements to allow investors to better compare financial statements prepared in accordance with IFRS and U.S. GAAP. The amendment requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. We adopted these amendments on January 1, 2013, including retrospective application for all comparative periods presented. Although we currently are not engaged in any arrangements that would be effected by these disclosure requirements, we believe that ASU 2011-11 may have a material impact on future disclosures pending our entrance into an offsetting arrangement.

Business_Segment_Information

Business Segment Information	12 Months Ended
	Dec. 31, 2013
Business Segment Information	'
	3. BUSINESS SEGMENT INFORMATION
	We have two principal reportable segments, which are segregated based on the products and services that each provide: (a) exploration and production, and (b) field services. Our exploration and production segment engages in the exploration, acquisition, development and production of oil, natural gas and NGLs. We have a single, company-wide management team that oversee all properties as a whole rather than isolated operating segments; however we do track basic operational data by area. Our financial performance is measured as a single enterprise and not by individual area. Our field services segment operates and manages water sourcing, water transfer, equipment rental and water disposal services, primarily in the Appalachian Basin. Our field services segment is comprised of operations that have economic characteristics that are distinct from those of our exploration and production segment and is managed by its own unique management team.
	We evaluate the performance of our business segments based on net income (loss) from continuing operations, before income taxes. All intercompany transactions, including those between consolidated business segments, are eliminated in consolidation. Summarized financial information concerning our segments is shown in the following table for 2013, 2012 and 2011 (in thousands):
			Exploration			Field			Intercompany			Consolidated
			and			Services			Eliminations			Total
			Production
	For the Year Ended December 31, 2013
	Revenues		$	214,119		$	32,583		$	(8,771	)	$	237,931
	Inter-Segment Revenues			0			(8,771	)		8,771			0
	Total Revenues			214,119			23,812			0			237,931
	Depreciation, Depletion and Amortization			62,585			1,559			(200	)		63,944
	Impairment Expense			32,072			0			0			32,072
	Other Operating Expense(a)			106,591			25,945			(6,295	)		126,241
	Interest Expense			22,719			106			0			22,825
	Other (Income) Expense(b)			(3,111	)		0			86			(3,025	)
	Income (Loss) From Continuing Operations, Before Income Taxes		$	(6,737	)	$	(3,798	)	$	6,409		$	(4,126	)
	Total Assets		$	971,973		$	26,266		$	(6,843	)	$	991,396
	Expenditures for Long-Lived Assets		$	317,481		$	7,870		$	(2,563	)	$	322,788
	Equity Method Investments		$	18,708		$	0		$	0		$	18,708
	For the Year Ended December 31, 2012
	Revenues		$	134,736		$	15,637		$	(2,234	)	$	148,139
	Inter-Segment Revenues			0			(2,234	)		2,234			0
	Total Revenues			134,736			13,403			0			148,139
	Depreciation, Depletion and Amortization			44,955			482			0			45,437
	Impairment Expense			20,505			80			0			20,585
	Other Operating Expense(a)			76,063			10,859			(1,723	)		85,199
	Interest Expense			6,424			26			0			6,450
	Other (Income) Expense(b)			(105,426	)		0			104			(105,322	)
	Income (Loss) From Continuing Operations, Before Income Taxes		$	92,215		$	1,956		$	1,619		$	95,790
	Total Assets		$	766,599		$	12,166		$	(6,055	)	$	772,710
	Expenditures for Long-Lived Assets		$	227,913		$	3,134		$	(707	)	$	230,340
	Equity Method Investments		$	16,978		$	0		$	0		$	16,978
	For the Year Ended December 31, 2011
	Revenues		$	112,088		$	3,546		$	(1,028	)	$	114,606
	Inter-Segment Revenues			0			(1,028	)		1,028			0
	Total Revenues			112,088			2,518			0			114,606
	Depreciation, Depletion and Amortization			27,670			186			0			27,856
	Impairment Expense			14,316			315			0			14,631
	Other Operating Expense(a)			59,917			3,169			(756	)		62,330
	Interest Expense			2,523			1			0			2,524
	Other (Income) Expense(b)			(19,021	)		(100	)		35			(19,086	)
	Income (Loss) From Continuing Operations, Before Income Taxes		$	26,683		$	(1,053	)	$	721		$	26,351
	Total Assets		$	600,049		$	7,143		$	(5,641	)	$	601,551
	Expenditures for Long-Lived Assets		$	269,823		$	5,571		$	0		$	275,394
	Equity Method Investments		$	41,683		$	0		$	0		$	41,683
	(a)	Includes the following expenses: production and lease operating expenses, general and administrative expenses, (gain) loss on disposal of assets, exploration expense, field services operating expenses and other operating expenses.
	(b)	Includes the following expenses: interest income, gain (loss) on derivative, net, other income (expense) and gain (loss) on equity method investments.

Business_and_Oil_and_Gas_Prope

Business and Oil and Gas Property Acquisitions and Dispositions	12 Months Ended
	Dec. 31, 2013
Business and Oil and Gas Property Acquisitions and Dispositions	'
	4. BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS AND DISPOSITIONS
	Acquisitions
	We have made no significant acquisitions for the years ended December 31, 2013, 2012 and 2011.
	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 that we expect to incur, 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, 2013
Discontinued Operations/Assets Held For Sale	'
	5. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE
	During December 2011, our board of directors approved a formal plan to sell our DJ Basin assets located in the states of Wyoming and Colorado. During 2012, we sold various parcels of acreage throughout our DJ Basin holdings at varying prices, much of which was lower than the existing carrying value of similar remaining acreage at the time of sale. During the first quarter of 2013, we entered an agreement to sell our remaining DJ Basin assets for $3.1 million. This transaction closed during the second quarter of 2013 and resulted in a gain of approximately $1.0 million. As of December 31, 2013, we had no assets or liabilities related to the DJ Basin or continuing cash flows from this region.
	Prior to the sale, these assets were classified as Assets Held for Sale on our Balance Sheet as of December 31, 2012, and the results of operations are reflected in Discontinued Operations in our Consolidated Statements of Operations. We included $2.3 million of net assets located in the DJ Basin as Assets Held for Sale on our Consolidated Balance Sheet as of December 31, 2012. We included approximately $0.1 million of liabilities as Liabilities Related to Assets Held for Sale on our Consolidated Balance Sheet as of December 31, 2012. These liabilities primarily relate to Accounts Payable and Accrued Liabilities.
	Summarized financial information for Discontinued Operations is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support.
		December 31,
	($ in thousands)	2013			2012			2011
	Revenues:
	Oil and Gas Sales	$	25		$	97		$	556
	Total Operating Revenue		25			97			556
	Costs and Expenses:
	Production and Lease Operating Expense		104			353			493
	General and Administrative Expense		23			660			1,745
	Exploration Expense		97			867			33,812
	Impairment Expense		0			19,770			13,177
	Depreciation, Depletion, Amortization and Accretion		0			0			85
	Other Operating Expense (Income)		(3	)		8			1
	Gain on Disposal of Asset		(969	)		(2,126	)		0
	Interest Expense		0			0			1
	Other (Income) Expense		0			(3	)		1
	Total Expenses (Income)		(748	)		19,529			49,315
	Income (Loss) from Discontinued Operations Before Income Taxes		773			(19,432	)		(48,759	)
	Income Tax (Expense) Benefit		(1,005	)		8,489			15,302
	Loss from Discontinued Operations, Net of Income Taxes	$	(232	)	$	(10,943	)	$	(33,457	)
	Production
	Crude Oil (Bbls)		356			1,272			6,939

Consolidated_Subsidiaries

Consolidated Subsidiaries	12 Months Ended
	Dec. 31, 2013
Consolidated Subsidiaries	'
	6. CONSOLIDATED SUBSIDIARIES
	Our consolidated subsidiaries make up 100.0% of our field services segment. For additional information, see Note 3, Business Segment Information, to our Consolidated Financial Statements.
	Water Solutions Holdings, LLC and Keystone Clearwater Solutions, LLC
	In November 2009, we entered into a limited liability agreement with Sand Hills Management, LLC (“Sand Hills”) to form Water Solutions Holdings, LLC and its wholly-owned subsidiary, Keystone Clearwater Solutions, LLC (collectively “Water Solutions”) for the purpose of acquiring, managing and operating water treatment, disposal and transportation facilities that are designed to treat, dispose or transport brine and fresh waters used and produced in oil and gas well development activities. Upon a change in membership interest that occurred on April 1, 2013, the members of Water Solutions are Rex Energy Corporation, which owns an 60% membership interest, and Sand Hills, which owns a 40% membership interest and serves as the operator of the entity. The change in membership interests occurred in accordance with the original operating agreement which stipulated that the change would occur upon the return of our initial capital investments. The change in ownership transaction, in which we retained our controlling financial interest, was accounted for as an equity transaction with no impact to our Consolidated Statements of Operations. Prior to the change in membership interests, the entity was owned 80% by us and 20% by Sand Hills.
	We fully consolidate the accounts of Water Solutions in our financial statements and account for the 40% equity interest owned by Sand Hills as a noncontrolling interest. Water Solutions is financed through cash contributions from its members, a revolving line of credit upon which $4.0 million was drawn as of December 31, 2013, and an equipment line of credit upon which $1.5 million was drawn as of December 31, 2013. At December 31, 2012, Water Solutions maintained a credit facility under which approximately $0.7 million was drawn. There were no cash contributions during the 12 months ending December 31, 2013 and 2012. The table below sets forth the carrying amount and classifications of Water Solutions’ assets and liabilities as of December 31, 2013 and 2012, with no restrictions or obligations to use certain assets to settle associated liabilities:
		December 31,
	($ in thousands)	2013			2012
	Assets
	Cash and Cash Equivalents	$	593		$	741
	Accounts Receivable		9,882			3,360
	Inventory, Prepaid Expenses and Other		89			13
	Other Property and Equipment		11,798			3,560
	Wells and Facilities in Progress		1,031			221
	Accumulated Depreciation, Depletion and Amortization		(1,954	)		(501	)
	Deferred Financing Costs and Other Assets – Net		206			199
	Total Assets	$	21,645		$	7,593
	Liabilities
	Accounts Payable	$	758		$	456
	Current Maturities of Long-Term Debt		5,404			1,098
	Accrued Liabilities		6,247			1,036
	Senior Secured Line of Credit and Long-Term Debt		3,053			965
	Total Liabilities	$	15,462		$	3,555
	R.E. Disposal, LLC (formerly known as NorthStar #3, LLC)
	In August 2011, our wholly owned subsidiary, R.E. Gas Development, LLC (“R.E. Gas”) and NorthStar Water Management (“NorthStar”) formed NorthStar #3, LLC (“NorthStar #3”) to construct, own and operate a water disposal well in Mahoning County, Ohio. At December 31, 2012, R.E. Gas owned a 51% membership interest in NorthStar #3 and the remaining 49% membership interest was owned by NorthStar. During the second quarter of 2013, we purchased the remaining 49% membership interest owned by NorthStar for $0.2 million in cash and now own 100% of NorthStar #3, which was renamed R.E. Disposal, LLC. Upon NorthStar #3’s original formation, a note was issued from us to NorthStar #3 to assist in supplementing the operations. The note, which at the time of ownership change had a balance of $4.6 million, was terminated as a part of the change in ownership transaction. Prior to the change in ownership transaction, the financial results of NorthStar #3 were fully consolidated into our Consolidated Financial Statements while also eliminating any intercompany transactions, including the note payable to us. The change in ownership transaction, in which we retained our controlling financial interest, was accounted for as an equity transaction with no impact to our Consolidated Statements of Operations. The promissory note held with NorthStar #3 had a balance of $4.6 million as of December 31, 2012 (for additional information see Note 10, Related Party Transactions, to our Consolidated Financial Statements).
	The carrying amount and classifications of R.E. Disposal, LLC (formerly NorthStar #3) assets and liabilities as of December 31, 2012 are as follows, with no restrictions or obligations to use certain assets to settle associated liabilities:
	($ in thousands)	December 31,
		2012
	Assets
	Cash and Cash Equivalents	$	14
	Wells and Facilities in Progress		4,559
	Total Assets	$	4,573
	Liabilities
	Accounts Payable	$	6
	Note Payable		4,633
	Total Liabilities	$	4,639

Equity_Method_Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2013
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 $18.7 million and $17.0 million as of December 31, 2013 and 2012, respectively, on our Consolidated Balance Sheets as Equity Method Investments. During 2013, we contributed approximately $2.5 million in cash to RW Gathering to support current pipeline and gathering line construction, compared to $2.0 million during the same period in 2012. RW Gathering recorded net losses from continuing operations of $1.9 million, $1.7 million and $0.4 million for the years ended December 31, 2013, 2012 and 2011, 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 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, 2013, we determined that we had the ability to recover the carrying amount of our investment in RW Gathering.
	Keystone Midstream
	On May 29, 2012, we closed the sale of our ownership in Keystone Midstream, which we had accounted for as an equity method investment. For additional information on the sale of Keystone Midstream, see Note 4, Business and Oil and Gas Property Acquisitions and Dispositions, to our Consolidated Financial Statements.
	Prior to May 29, 2012, we owned a 28% non-operating interest in Keystone Midstream, which was a midstream joint venture focused on building, owning and operating high pressure gathering systems and cryogenic gas processing plants in Butler County, Pennsylvania. We recorded our investment in Keystone Midstream of approximately $28.1 million as of the date of sale on our Consolidated Balance Sheets as Equity Method Investments. In 2012, we contributed approximately $2.1 million to Keystone Midstream primarily to support the construction of cryogenic gas processing plants. Keystone Midstream recorded a net loss from continuing operations of $11.5 million as of May 29, 2012 and net income of $1.6 million as of December 31, 2011. Included in the net loss recorded in 2012 were approximately $12.0 million of transaction expenses related to the sale of the entity. Our share of net income and net loss realized under the equity method of accounting are primarily due to project management costs, general and administrative expenses, and DD&A expenses and totaled approximately $3.2 million of net loss, and $0.5 million of net income for the period ended May 29, 2012 and for the year ended December 31, 2011, respectively.

Concentrations_of_Credit_Risk

Concentrations of Credit Risk	12 Months Ended
	Dec. 31, 2013
Concentrations of Credit Risk	'
	8. CONCENTRATIONS OF CREDIT RISK
	At times during the years ended December 31, 2013 and 2012, 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, 2013, we carried approximately $28.8 million in production receivables, of which approximately $22.7 million were production receivables due from four purchasers. At December 31, 2012, we carried approximately $18.1 million in production receivable, of which approximately $16.3 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, 2013
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, 2013 and 2012, 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 are 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 H2S emissions in the Lawrence Field, we know of no significant probable or possible environmental contingent liabilities.
	Letters of Credit
	As of December 31, 2013 and 2012, we had posted $1.4 million and $0.8 million, respectively, in various letters of credit to secure our drilling and related operations.
	Lease Commitments
	At December 31, 2013 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, $0.3 million and $0.4 million for the years ended December 31, 2013, 2012 and 2011, respectively. Lease commitments by year for each of the next five years are presented in the table below ($ in thousands).
	2014		$	859
	2015			807
	2016			815
	2017			823
	2018			133
	Thereafter			0
	Total		$	3,437
	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 $10.4 million in 2014, $13.0 million in 2015, $14.6 million in 2016, $14.6 million in 2017, $14.6 million in 2018 and $100.7 million thereafter, assuming our working interest in the region of approximately 70.0%. For the years ended December 31, 2013, 2012 and 2011, we incurred capacity reservation charges of $0.3 million, $0.5 million and $0.1 million, respectively. Charges for the capacity reservation are recorded as Production and Lease Operating Expense on our Consolidated Statements of Operations.
	Operational Commitments
	Pursuant to agreements reached during the fourth quarter of 2010 and the third quarter of 2013, we have contracted drilling rig services on two rigs to support our Appalachian Basin operations. The minimum cost to retain these rigs would require payments of approximately $4.9 million in 2014, $3.2 million in 2015 and $1.5 million in 2016, which is consistent with our estimated working interest in this project area. We have agreements for contracted completion services in the Appalachian Basin. The minimum cost to retain the completion services is approximately $9.8 million in 2014, which is consistent with our estimated working interest in this project area.
	Natural Gas Gathering, Processing and Sales Agreements
	During the normal course of business we have entered into certain agreements to ensure the gathering, transportation, processing and sales of specified quantities of our oil, natural gas and NGLs. In some instances, we are obligated to pay shortfall fees, whereby we would pay a fee for any difference between actual volumes provided as compared to volumes that have been committed. In other instances, we are obligated to pay a fee on all volumes that are subject to the related agreement. In connection with our entry into certain of these agreements, we concurrently entered into a guaranty whereby we have guaranteed the payment of obligations under the specified agreements up to a maximum of $406.4 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, 2013, 2012 and 2011, we incurred expenses related to the transportation, processing and marketing our oil, natural gas and natural gas liquids of approximately $26.4 million, $14.1 million and $4.6 million, respectively.
	Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows ($ in thousands):
			Total
	2014		$	7,463
	2015			16,525
	2016			23,654
	2017			29,495
	2018			31,724
	Thereafter			294,571
	Total		$	403,432
	Drilling Commitments
	During the first quarter of 2012, we entered into a drill-to-earn agreement with MFC Drilling, Inc. (“MFC”). Under the terms and conditions of the agreement, we will acquire a minimum, through a drill-to-earn structure, a 62.5% working interest in approximately 4,510 acres in Belmont, Guernsey and Noble Counties, Ohio. The agreement provides that in order for us to earn the 62.5% working interest, we will bear the cost for our 62.5% working interest and 100% of the 15% working interest of MFC until such time that we have met the $14.1 million drilling carry obligation. As of December 31, 2013, the remaining drilling carry obligation balance was approximately $5.2 million. Our 2014 capital budget includes additional development in this area.
	In addition to the drilling carry obligation, we are required to meet drilling commitments. Amounts incurred toward the attainment of the drilling commitments are credited towards the drilling carry obligation. Our drilling commitments require us to commence the drilling of at least three Utica Shale wells by November 15 of each year until the carry obligation has been satisfied, with credits given to additional wells drilled beyond the annual commitment. We currently estimate the commitment for each well drilled and completed for our working interest and that of MFC to be approximately $8.0 million to $9.0 million. Should we not comply with the drilling commitments or terminate the agreement, we would be responsible for payment of any remaining drilling carry obligation at that time.
	Pennsylvania Impact Fee
	During the first quarter of 2012, Pennsylvania state legislators instituted a natural gas impact fee on producers of unconventional natural gas. The fee will be imposed on every producer of unconventional 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
	(b)	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 12-month period ending December 31.
	For the year ended December 31, 2013, we incurred approximately $3.2 million in fees related to the natural gas impact fee. For the twelve months 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, 2013
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, 2011, we paid Charlie Brown $0.2 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, 2013 and 2012 was approximately $1.2 million and $1.3 million, respectively. For the years ended December 31, 2013, 2012 and 2011, 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, 2013, there were no 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 five-year lease term. For the year 2013, we paid Shaner Office Holdings, L.P. approximately $0.4 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 $0.8 million in compression expenses that were charged to us from Williams Appalachia, LLC, for each of the years ended December 31, 2013, 2012 and 2011. 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, 2013, 2012 and 2011, there were no receivables or payables in relation to RW Gathering due to or from us.
	Keystone Midstream
	We incurred approximately $2.4 million and $4.6 million in transportation and processing expenses that were charged to us from Keystone Midstream during 2012 and 2011, respectively, 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 $10.7 million, $3.2 million and $1.6 million in gross water transfer and equipment rental expenses that were charged to us from Water Solutions during 2013, 2012 and 2011, respectively (see Note 6, Consolidated Subsidiaries, to our Consolidated Financial Statements). Of the amounts incurred, we have eliminated approximately $8.8 million, $2.2 million and $1.0 million in consolidation for the years 2013, 2012 and 2011, respectively. As of December 31, 2013 and 2012, we had payables of approximately $1.5 million and $0.2 million, respectively, due to Water Solutions for work performed during the periods.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2013
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 KeyBank National Association, 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 $325.0 million; however, the revolving credit facility may be increased to up to $500 million upon re-determinations of the borrowing base, consent of the lenders and other conditions prescribed in the agreement. In connection with our offering of 8.875% senior notes in April 2013, we gave notice to the administrative agent under our Senior Credit Facility of our election to reduce the maximum commitments of the lenders to $215.0 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 2013, resulting in no significant changes to the current Senior Credit Facility. As of December 31, 2013, loans made under the Senior Credit Facility were set to mature on March 27, 2018. 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, 2013 and 2012, we had approximately $59.0 million and $0.0 million, respectively, 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) KeyBank’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 175 to 275 basis points, and the applicable per annum margin, in the case of loans bearing interest at the Alternate Base Rate, ranges from 50 to 150 basis points, in each case, determined based upon our borrowing utilization at such date of determination. Upon the occurrence and continuance of an event of default all outstanding loans shall bear interest at a rate equal to 200 basis points per annum plus the then effective rate of interest. Interest is payable on the last day of the relevant interest period (or at least every three months), in the case of loans bearing interest at the Adjusted LIBO Rate, and quarterly, in the case of loans bearing interest at the Alternate Base Rate.
	Under the Senior Credit Facility, we may enter into commodity swap agreements with counterparties approved by the lenders, provided that the notional volumes for such agreements, when aggregated with other commodity swap agreements then in effect (other than basis differential swaps on volumes already hedged pursuant to other swap agreements), do not exceed, as of the date the swap agreement is executed, 85% of the reasonably anticipated projected production from our proved developed producing reserves for the 36 months following the date such agreement is entered into, and 75% thereafter, for each of crude oil and natural gas, calculated separately. We may also enter into interest rate swap agreements with counterparties approved by the lenders that convert interest rates from floating to fixed provided that the notional amounts of those agreements, when aggregated with all other similar interest rate swap agreements then in effect, do not exceed the greater of $20 million 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, Illinois and Indiana. We are required to maintain liens covering our oil and gas properties representing at least 80% of our total value of all oil and gas properties.
	The Senior Credit Facility also requires we meet, on a quarterly basis, minimum financial requirements of consolidated current ratio, EBITDAX to interest expense and total debt to EBITDAX. EBITDAX is a non-GAAP financial measure used by our management team and by other users of our financial statements, such as our commercial bank lenders, which adds to or subtracts from net income the following expenses or income for a given period to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, depletion, amortization, unrealized gains and losses from derivatives, exploration expense and other similar non-cash activity. The Senior Credit Facility requires that as of the last day of any fiscal quarter, our ratio of consolidated current assets, which includes the unused portion of our borrowing base, as of such day to consolidated current liabilities as of such day, known as our current ratio, must not be less than 1.0 to 1.0. Our current ratio as of December 31, 2013 was approximately 2.2 to 1.0. Additionally, the Senior Credit Facility requires that as of the last day of any fiscal quarter, our ratio of EBITDAX for the trailing twelve months to interest expense for such period, known as our interest coverage ratio, must not be less than 3.0 to 1.0. Our interest coverage ratio as of December 31, 2013 was approximately 4.4 to 1.0. Additionally, as of the last day of any fiscal quarter, our ratio of total debt to EBITDAX for the trailing twelve months must not exceed 4.25 to 1.0. Our ratio of total debt to EBITDAX as of December 31, 2013 was approximately 3.1 to 1.0.
	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 “Senior Notes”). The net proceeds of the 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 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 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 Senior Notes as Interest Expense on our Consolidated Statements of Operations using the effective interest method. As of December 31, 2013 and 2012, we had recorded on our Consolidated Balance Sheet approximately $353.1 million and $248.3 million of Senior Notes, which is inclusive of a net premium of $3.1 million and net discount of $1.7 million, respectively. The amortization of our net premium in 2013, which follows the effective interest method, was approximately $0.2 million and was recorded as a credit to Interest Expense on our Consolidated Statement of Operations. The amortization of our discount during 2012 was negligible.
	On October 31, 2013, substantially all of the outstanding 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.
	We may redeem, at specified redemption prices, some or all of the 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 Senior Notes from the holders.
	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.
	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, 2013 and December 31, 2012:
			December 31,			December 31,
			2013			2012
			(in  thousands)			(in  thousands)
	8.875% Senior Notes		$	350,000		$	250,000
	Premium (Discount) on Senior Notes			3,078			(1,742	)
	Senior Lines of Credit(a)			59,000			0
	Capital Leases and Other Obligations(a)			9,934			2,677
	Total Debt			422,012			250,935
	Less Current Portion of Long-Term Debt			(6,743	)		(1,686	)
	Total Long-Term Debt		$	415,269		$	249,249
	(a)	The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2013 and 2012 was approximately 1.9 % and 2.5%, respectively. The weighted average interest rate on borrowings under the Demand Note and the Equipment Note for the year ended December 31, 2013 was approximately 3.0%. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2013 and 2012 was approximately 5.3% and 4.5%, respectively.
	Water Solutions
	On October 18, 2013, Water Solutions Holdings entered into agreements with M&T Bank (“M&T”) to obtain a revolving line of credit (“Demand Note”) and an equipment line of credit (“Equipment Note”).
	The borrowing base for the Demand Note is the lesser of (a) $4.0 million or (b) 80% of Water Solutions’ Accounts Receivable which are less than 90 days old. Borrowings under the Demand Note are to be used for working capital and general corporate purposes. At Water Solutions’ election, borrowings under the Demand Note bear interest per annum equal to an adjusted LIBOR rate or an adjusted base rate, as defined below. The adjusted LIBOR rate is equal 2.75 percentage points above the greater of (a) one-month LIBOR, adjusting daily, or (b) one-day LIBOR. The adjusted base rate is equal to 2.0 percentage points above the rate of interest announced by M&T as its prime rate. All interest that is accrued through the last day of any calendar month will be due and payable by the tenth day of the next calendar month. While there is no stated maturity date for amounts outstanding under the Demand Note, in certain circumstances, Water Solutions may be required to repay amounts outstanding on demand from M&T. As of December 31, 2013, there was approximately $4.0 million outstanding under the Demand Note.
	The Demand Note agreement does not contain any collateral requirements on behalf of Water Solutions, nor does it contain any financial covenant requirements.
	Maximum borrowings under the Equipment Note are equal to $6.0 million and are to be used for purposes of making equipment or vehicle acquisitions up to a maximum of 80% of the costs of such assets. Borrowings under the Equipment Note bear interest per annum equal to the three month LIBOR plus 3.0 percentage points. All interest is due and payable on the first day of each fiscal quarter. Maturity dates will vary with each borrowing, but will generally be three to four years from the date of borrowing. In certain circumstances, Water Solutions may be required to prepay any loans that are outstanding. As of December 31, there was approximately $1.5 million outstanding under the Equipment Note.
	The Equipment Note contains covenants that restrict Water Solutions’ ability to, among other things, materially change their business; incur indebtedness; make loans to others; incur liens; make investments; or become a guarantor. Borrowings under the Equipment Note are collateralized with liens covering 80% of the value of assets purchased with associated loans under the Equipment Note. The Equipment Note also requires that Water Solutions meet certain financial covenants regarding tangible net worth, fixed charge coverage ratio and a debt to EBITDA ratio (as defined in the Equipment Note). EBITDA is a non-GAAP financial measure used by the management of Water Solutions and by other users of Water Solutions’ financial statements, such as commercial bank lenders, which adds to or subtracts from net income the following expenses or income for a given period to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, amortization and other similar non-cash activity. The Equipment Note requires that tangible net worth (i) not be less than $2.5 million measured annually, and (ii) not be less than $2.5 million plus 30% of annual net income commencing with the fiscal year ended December 31, 2013 and each fiscal year thereafter. As of December 31, 2013, Water Solutions’ net worth was approximately $6.0 million. Also, Water Solutions’ fixed charge coverage ratio for four consecutive fiscal quarters ending at the end of each fiscal quarter shall not be less than 1.75 to 1.0. As of December 31, 2013, Water Solutions’ fixed charge coverage ratio was approximately 2.4 to 1.0. Water Solutions’ debt to EBITDA ratio for the trailing 12 month period ending on the last day of the measurement period shall not be greater than 2.25 to 1.0. As of December 31, 2013, Water Solutions’ debt to EBITDA ratio was approximately 1.3 to 1.0.
	The following is the principal maturity schedule for debt outstanding as of December 31, 2013:
			Year Ended
			December 31,
			(in thousands)
	2014		$	6,743
	2015			1,467
	2016			1,270
	2017			292
	2018			59,162
	Thereafter			350,000
	Total1		$	418,934
	1	Does not include $3.1 million net premium on Senior Notes.

Fair_Value_Of_Financial_Instru

Fair Value Of Financial Instruments And Derivative Instruments	12 Months Ended
	Dec. 31, 2013
Fair Value Of Financial Instruments And Derivative Instruments	'
	12. FAIR VALUE OF FINANCIAL INSTRUMENTS AND DERIVATIVE INSTRUMENTS
	Natural Gas, Oil and NGL Derivatives
	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, 2013, 2012 and 2011, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, swaptions, deferred put spreads, cap 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. 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 $7.1 million, $16.2 million and $6.2 million in relation to our commodity derivatives for the years ended December 31, 2013, 2012 and 2011, respectively.
	As of December 31, 2013, we had over 100.0% of our 2013 oil production hedged through 2014, over 90.0% and 30.0% of our 2013 natural gas production hedged through 2014 and 2015, and over 40.0% of our 2013 NGL production hedged through 2014, respectively. 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, 2013, we had approximately $59.0 million outstanding under our Senior Credit Facility which is subject to variable rates of interest and $350.0 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. Prior to 2013, we did not have any interest rate swap agreements. We utilize the mark-to-market accounting method to account for our interest rate swap. We recognize all gains and losses related to this contract in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Income (Expense). During 2013, there were no cash settlements related to our interest rate swap agreement. The fair value of our interest rate swap as of December 31, 2013, was a liability of approximately $0.2 million.
	The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011:
		For the Year Ended December 31,
	In thousands	2013				2012				2011
	Oil	$	(2,798	)		$	1,579			$	(308	)
	Natural Gas		1,807				8,162				19,224
	Natural Gas Liquids		(1,711	)			946				0
	Interest Rate		(206	)			0				0
	Gain (Loss) on Derivatives, Net	$	(2,908	)		$	10,687			$	18,916
	Our derivative instruments are recorded on the balance sheet as either an asset, or a liability, measured at its fair value. The fair value associated with our derivative instruments was a liability of $0.2 million as of December 31, 2013, and an asset of $9.8 million at December 31, 2012, respectively. Our open asset/(liability) financial commodity derivative instrument positions at December 31, 2013 consisted of the following:
	Period	Volume				Sold				Floor			Ceiling		Swap		Basis			Fair Market
						Put Option											Differential			Value
																				($ in Thousands)
	Oil
	2014—Collar		60,000 Bbl			$	0			$	90		$	97.65	$	0	$	0		$	(42	)
	2014—Deferred Put Spread		168,000 Bbl				75				90			0		0		0			(585	)
	2014—Swap		30,000 Bbl				0				0			0		93.75		0			(119	)
	2014—Cap Swap		360,000 Bbl				80.83				0			0		97.72		0			380
	2014—Three Way Collar		372,000 Bbl				76.61				87.6			103.85		0		0			75
			990,000 Bbl																	$	(291	)
	Natural Gas
	2014—Sold Call		1,800,000 Mcf			$	0			$	0		$	5	$	0	$	0		$	(150	)
	2014—Three Way Collar		7,800,000 Mcf				3.32				4.08			4.59		0		0			393
	2014—Swap		4,830,000 Mcf				0				0			0		3.97		0			(1,064	)
	2014—Swaption		2,400,000 Mcf				0				0			0		4.45		0			(717	)
	2014—Cap Swap		3,600,000 Mcf				3.3				0			0		4.09		0			(491	)
	2014—Basis Swap		7,200,000 Mcf				0				0			0		0		(0.36	)		3,984
	2014—Collar		1,800,000 Mcf				0				3.51			4.43		0		0			(235	)
	2015—Swap		1,200,000 Mcf				0				0			0		4.18		0			18
	2015—Cap Swap		2,400,000 Mcf				3.28				0			0		4.1		0			(302	)
	2015—Three Way Collar		2,400,000 Mcf				3.4				4.16			4.63		0		0			169
	2015—Sold Call		2,400,000 Mcf				0				0			4.4		0		0			(761	)
	2015—Basis Swap		600,000 Mcf				0				0			0		0		(0.35	)		339
			38,430,000 Mcf																	$	1,183
	Natural Gas Liquids
	2014—Swap		357,000 Bbl			$	0			$	0		$	0	$	48.49	$	0		$	(912	)
			357,000 Bbl																	$	(912	)
	The combined fair value of our derivatives included in our Consolidated Balance Sheets as of December 31, 2013 and December 31, 2012 is summarized below.
		December 31,				December 31,
		2013				2012
		(in thousands)				(in thousands)
	Short-Term Derivative Assets:
	Crude Oil—Cap Swaps	$	380			$	90
	Crude Oil—Three Way Collars		104				0
	Natural Gas Liquids—Swaps		83				535
	Natural Gas—Swaps		106				2,416
	Natural Gas—Swaption		0				354
	Natural Gas—Cap Swap		5				0
	Natural Gas—Basis Swaps		3,984				0
	Natural Gas—Three Way Collars		518				1,021
	Natural Gas Collars		0				4,211
	Natural Gas—Puts		0				3,378
	Interest Rate—Swap		488				0
	Total Short-Term Derivative Assets	$	5,668			$	12,005
Long-Term Derivative Assets:
Crude Oil—Collars	$	0			$	0
Natural Gas—Swaps		22				239
Natural Gas—Cap Swap		5				0
Natural Gas—Basis Swap		339				0
Natural Gas—Collars		0				0
Natural Gas—Three Way Collars		169				465
Natural Gas—Puts		0				0
Total Long-Term Derivative Assets	$	535			$	704
Total Derivative Assets	$	6,203			$	12,709
Short-Term Derivative Liabilities:
Crude Oil—Collars	$	(42	)		$	(307	)
Crude Oil—Swaps		(119	)			(217	)
Crude Oil—Three Way Collars		(29	)			(45	)
Crude Oil—Deferred Put Spread		(585	)			0
Natural Gas Liquids—Swaps		(995	)			0
Natural Gas—Three Way Collars		(125	)			(35	)
Natural Gas—Call		(150	)			0
Natural Gas—Collars		(235	)			0
Natural Gas—Cap Swaps		(496	)			0
Natural Gas—Swaptions		(717	)			0
Natural Gas—Swaps		(1,170	)			(785	)
Total Short-Term Derivative Liabilities	$	(4,663	)		$	(1,389	)
Long-Term Derivative Liabilities:
Crude Oil—Three Way Collars	$	0			$	(509	)
Natural Gas—Swaps		(4	)			(434	)
Natural Gas—Three Way Collars		0				(35	)
Natural Gas—Cap Swap		(307	)			0
Natural Gas—Call		(761	)			(366	)
Natural Gas—Collars		0				(166	)
Interest Rate—Swap		(693	)			0
Total Long-Term Derivative Liabilities	$	(1,765	)		$	(1,510	)
Total Derivative Liabilities	$	(6,428	)		$	(2,899	)
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. We utilize a fair value hierarchy that gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:
Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.
Level 2—Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars 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—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, 2013 and 2012, 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, 2013 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, 2013 are included in the table below.
Unobservable Input	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
During the year ended December 31, 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 ($ in thousands):
	Fair Value Measurements at December 31, 2013 Using:
	Total				Quoted Prices				Significant			Significant
	Carrying				in Active				Other			Unobservable
	Value as of				Markets for				Observable			Inputs
	December 31,				Identical				Inputs			(Level 3)
	2013				Assets				(Level 2)
					(Level 1)
Commodity Derivatives	$	(20	)		$	0			$	(4,343	)	$	4,323
Interest Rate Swap	$	(205	)		$	0			$	(205	)	$	0
The value of our oil derivatives are comprised of collar, three-way collar, swap, cap swap and deferred put spread contracts for notional barrels of oil at interval New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) oil prices. The fair value of our oil derivatives as of December 31, 2013 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil and (iii) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our gas derivatives are comprised of puts, swaps, swaptions, collars, three way collars, basis swaps, cap swaps, and deferred put spreads contracts for notional volumes of gas contracted at NYMEX Henry Hub (“HH”). The fair values attributable to our gas derivative contracts as of December 31, 2013 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, 2013 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 12 months ended December 31, 2013 and 2012 (in thousands):
	For the Year Ended December 31,
	2013				2012
Beginning Balance of Level 3	$	0			$	0
Changes in Fair Value		4,328				0
Purchases		0				0
Settlements Received		(5	)			0
Ending Balance of Level 3	$	4,323			$	0
Changes in fair value on our Level 3 commodity derivative contracts outstanding for the year ended December 31, 2013, resulted in a gain of approximately $4.3 million. This amount has been included in Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations. There were no outstanding Level 3 commodity derivatives as of December 31, 2012
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; estimated probabilities, 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:
	December 31, 2013								December 31, 2012
In thousands	Carrying				Fair Value				Carrying			Fair Value
	Amount								Amount
8.875% Senior Notes	$	350,000			$	385,000			$	250,000		$	249,074
Secured Lines of Credit		59,000				59,000				0			0
Capital Leases and Other Obligations		9,934				9,731				2,677			2,524
Total	$	418,934			$	453,731			$	252,677		$	251,598
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.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
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)	2013			2012			2011
	Current:
	Federal	$	(1,916	)	$	2,329		$	63
	State		(4,104	)		5,825			244
	Deferred:
	Federal		808			28,216			8,524
	State		1,427			2,179			(561	)
	Income Tax Expense	$	(3,785	)	$	38,549		$	8,270
	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,
		2013			2012			2011
	Income before noncontrolling interests and income taxes	$	(5,683	)	$	94,971		$	26,358
	Statutory U.S. income tax rate		35	%		35	%		35	%
	Tax expense recognized using statutory U.S. income tax rate	$	(1,989	)	$	33,240		$	9,225
	Change in estimated future state rate		(484	)		(7	)		612
	Permanent differences		83			52			176
	Change in valuation allowances		(160	)		(131	)		1,031
	Other		(479	)		(493	)		(4,092	)
	Adjusted federal income tax expense (benefit)	$	(3,029	)	$	32,661		$	6,952
	State income tax expense (benefit)		(756	)		5,888			1,318
	Total income tax expense (benefit)	$	(3,785	)	$	38,549		$	8,270
	Effective income tax rate		66.6	%		40.6	%		31.4	%
	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, 2013 and 2012:
		For the Years Ended December 31,
	(in thousands)	2013			2012
	Tax effects of temporary differences for:
	Current:
	Assets:
	Asset retirement obligation	$	997		$	0
	Future sale proceeds held in escrow		0			2,947
	Non-cash compensation plans		2,593			714
	Other		370			306
	Total current deferred tax assets		3,960			3,967
	Liabilities:
	Unrealized gain on derivatives		(404	)		(4,365	)
	Other		(105	)		(141	)
	Total current deferred tax liabilities		(509	)		(4,506	)
	Net total current deferred tax asset (liability)	$	3,451		$	(539	)
	Long-Term:
	Assets:
	Asset retirement obligation	$	10,445		$	10,211
	Non-cash compensation plans		1,513			2,090
	Net operating loss carryforward		48,703			4,384
	Organization costs		602			689
	Deferred revenue		1,338			1,487
	AMT credits		292			1,380
	Unrealized loss on derivatives		493			0
	Other		232			593
	Total long-term deferred tax assets		63,618			20,834
	Liabilities:
	Timing differences—tax partnerships		(7,474	)		(5,873	)
	Valuation allowances		(1,965	)		(1,732	)
	Book basis of oil and gas properties in excess of tax basis		(83,594	)		(36,805	)
	Other		(31	)		(49	)
	Total long-term deferred tax liabilities		(93,064	)		(44,459	)
	Net total long-term deferred tax liability	$	(29,446	)	$	(23,625	)
	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, 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. As of December 31, 2012, we recorded a valuation allowance of approximately $1.7 million for statutory depletion carryforwards and charitable contributions.
	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, 2013, we had available unused gross federal net operating loss carryforwards of $121.1 million and gross state net operating loss carryforwards of $111.0 million that may be applied against future taxable income that expire from 2023 through 2033. 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)
2023	$	256
2024		53
2025		0
2026		898
2027		0
2028		4,179
2029		798
2030		803
2031		19,769
2032		60
2033		21,887
Total		48,703
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, 2013, 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, 2013 and 2012.
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, 2013
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 year ended December 31, 2013, we excluded stock options to purchase 0.4 million shares of our common stock due to our Net Loss From Continuing Operations. For the years ended December 31, 2012 and 2011, we excluded stock options to purchase 0.4 million shares and 0.6 million shares, respectively, 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, 2013, we excluded performance-based restricted stock of 1.3 million shares due to our Net Loss From Continuing Operations. For the years ended December 31, 2012 and 2011, we excluded 1.0 million shares and 0.8 million shares, respectively, 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). 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,
			2013			2012			2011
	Numerator (in thousands):
	Net Income (Loss) From Continuing Operations		$	(1,898	)	$	56,422		$	18,088
	Net Loss From Discontinued Operations			(232	)		(10,943	)		(33,457	)
	Net Income (Loss)		$	(2,130	)	$	45,479		$	(15,369	)
	Denominator (in thousands):
	Weighted Average Common Shares Outstanding—Basic			52,572			51,543			43,930
	Effect of Dilutive Securities:
	Employee Stock Options			0			69			95
	Employee Performance-Based Restricted Stock Awards			0			413			451
	Weighted Average Common Shares Outstanding—Diluted			52,572			52,025			44,476
	Earnings per Common Share(a):
	Basic—Net Income (Loss) From Continuing Operations		$	(0.04	)	$	1.09		$	0.41
	—Net Loss From Discontinued Operations			0			(0.21	)		(0.76	)
	—Net Income (Loss)		$	(0.04	)	$	0.88		$	(0.35	)
	Diluted—Net Income (Loss) From Continuing Operations		$	(0.04	)	$	1.08		$	0.41
	—Net Loss From Discontinued Operations			0			(0.21	)		(0.76	)
	—Net Income (Loss)		$	(0.04	)	$	0.87		$	(0.35	)
	(a)	All earnings per share amounts are attributable to Rex common shareholders.

Capital_Stock

Capital Stock	12 Months Ended
	Dec. 31, 2013
Capital Stock	'
	15. CAPITAL 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. In February 2012, we completed a public offering of 8,050,000 shares of common stock at an offering price of $9.25 per share. The net proceeds from the offering were approximately $70.6 million, after deducting underwriting discounts, commissions and offering expenses. We used a portion of the proceeds to repay outstanding borrowings under our Senior Credit Facility and used the remaining net proceeds to fund a portion of our capital expenditure program for 2012 and for other general corporate purposes. As of December 31, 2013 and 2012, we had 54,186,490 and 53,213,264 shares of common stock outstanding, respectively.

Major_Customers

Major Customers	12 Months Ended
	Dec. 31, 2013
Major Customers	'
	16. MAJOR CUSTOMERS
	For the year ended December 31, 2011, approximately $103.6 million, or 92.6%, of our commodity sales from continuing operations were derived from four customers, with the largest customer being responsible for approximately $62.9 million, or 56.2%, of total commodity sales. For the year ended December 31, 2012, approximately $128.3 million, or 95.3%, of our commodity sales from continuing operations were attributable to five customers with the largest single purchaser accounting for $64.7 million, or 48.1%. 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%. All of the aforementioned customers are found within our exploration and production segment.

Employee_Benefit_And_Equity_Pl

Employee Benefit And Equity Plans	12 Months Ended
	Dec. 31, 2013
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 $0.7 million, $0.5 million and $0.4 million for the years ended December 31, 2013, 2012 and 2011, 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 2,785,836 and 813,475 still available as of December 31, 2013 and 2012, 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, 2013 and 2012, we did not issue options to purchase shares of our common stock.
	A summary of the stock option activity is as follows:
		Number of Shares			Weighted		Weighted		Aggregate
					Average Exercise		Average		Intrinsic Value
					Price		Remaining		(in thousands)
							Term (in years)
	Options outstanding December 31, 2010		826,511		$	12.5
	Granted		90,074			12.74
	Exercised		(139,682	)		9.75
	Cancelled/Forfeited		(78,576	)		13.75
	Options Outstanding December 31, 2011		698,327		$	12.94
	Granted		0			0
	Exercised		(52,287	)		10.8
	Cancelled/Forfeited		(143,787	)		20.71
	Options Outstanding December 31, 2012		502,253		$	10.95
	Granted		0			0
	Exercised		(49,166	)		10.85
	Cancelled/Forfeited		(4,000	)		23.28
	Options Outstanding December 31, 2013		449,087		$	10.85		3.9	$	4,060
	Options Exercisable December 31, 2013		397,921		$	10.55		4.1	$	3,725
	Stock-based compensation expense from continuing operations relating to stock options for the years ended December 31, 2013, 2012 and 2011 totaled $0.2 million, $0.2 million and $0.7 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, 2013, 2012 and 2011 was $0.4 million, $0.1 million and $0.3 million, respectively. The total tax benefit for the year ended December 31, 2013 was approximately $0.2 million and negligible in 2012 and 2011.
	A summary of the status of our issued and outstanding stock options as of December 31, 2013 is as follows:
		Outstanding							Exercisable
	Exercise	Number			Weighted		Weighted		Number		Weighted
	Price	Outstanding			Average		Average		Exercisable at		Average
		at 12/31/13			Remaining		Exercise		12/31/13		Exercise
					Contractual		Price				Price
					Life (Years)
	$5.04		46,041			5.4	$	5.04		46,041	$	5.04
	$9.50		85,000			3.9	$	9.5		85,000	$	9.5
	$9.99		167,333			3.9	$	9.99		167,333	$	9.99
	$10.42		29,548			6.5	$	10.42		29,548	$	10.42
	$11.87		3,500			2.3	$	11.87		2,333	$	11.87
	$12.50		19,139			1.9	$	12.5		19,139	$	12.5
	$13.01		18,526			1.8	$	13.01		18,526	$	13.01
	$13.19		50,000			2.8	$	13.19		0	$	0
	$22.34		30,000			4.3	$	22.34		30,000	$	22.34
	Total		449,087			3.9	$	10.85		397,920	$	10.55
	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. The weighted average remaining contractual term and the aggregate intrinsic value for options exercisable at December 31, 2012 were 4.6 years and $1.4 million, respectively. As of December 31, 2013, unrecognized compensation expense related to stock options totaled approximately $0.1 million, which will be recognized over a weighted average period of 0.8 years.
	Restricted Stock Awards
	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. During the year ended December 31, 2012, the Compensation Committee issued 425,209 shares of restricted common stock to selected employees, non-employee directors and non-employee contractors. The shares granted in 2013 and 2012 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 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 15 and 13 companies, respectively, over a three-year period. The number of shares ultimately awarded will correspond with the final TSR rank amongst the peer group in accordance with the following schedule:
	TSR Rank	Percentage
		of 2013 Awards
		to Vest
	1 – 3		100	%
	4 – 6		75	%
	7 – 10		50	%
	11 – 13		25	%
	14 – 16		0	%
	TSR Rank	Percentage
		of 2012 Awards
		to Vest
	1 – 3		100	%
4 – 5		75	%
6 – 8		50	%
9 – 11		25	%
12 – 14		0	%
The weighted average fair value of the TSR awards as of December 31, 2013 and 2012 were $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,		December 31,
	2013		2012
Expected Dividend Yield	0.00%		0.00%
Risk-Free Interest Rate	0.70%		0.30%
Expected Volatility—Rex Energy	50.50%		54.40%
Expected Volatility—Peer Group	28.4% - 63.5%		31.2% - 58.6%
Market Index	35.30%		37.00%
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 $5.1 million, $2.9 million and $0.9 million for the years ended December 31, 2013, 2012 and 2011, respectively. As of December 31, 2013, total unrecognized compensation cost related to the restricted common stock grants was approximately $8.3 million to be recognized over a weighted average of 2.3 years. The total fair value of restricted common stock awards that vested in 2013 was approximately $3.0 million as compared to $0.7 million for restricted common stock awards that vested in 2012.
A summary of the restricted stock activity for the years ended December 31, 2013, 2012 and 2011 is as follows:
	Number of			Weighted-
	Shares			Average  Grant
				Date Fair
				Value
Restricted stock awards, as of January 1, 2011		814,965		$	11.01
Awards		757,816			13.07
Forfeitures		(342,955	)		11.6
Restricted stock awards, as of December 31, 2011		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

Impairment_Expense

Impairment Expense	12 Months Ended
	Dec. 31, 2013
Impairment Expense	'
	18. IMPAIRMENT EXPENSE
	For the years ended December 31, 2013, 2012 and 2011, we incurred impairment expense from continuing operations of approximately $32.1 million, $20.6 million and $14.6 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). 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 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. During 2011, we incurred approximately $11.6 million of expense related to the impairment of proved conventional shallow natural gas wells in the Appalachian Basin. In addition to the impairment related to our conventional shallow natural gas properties, we incurred approximately $1.4 million in impairment expense related to the expiration or surrender of undeveloped acreage and $1.6 million in impairment expense related to a refrigeration plant in the Appalachian Basin which was formerly in use before the commencement of operations at the cryogenic gas processing plants in Butler County, Pennsylvania. With larger scale gas processing capabilities in the region there is no further value for the refrigeration plant.

Suspended_Exploratory_Well_Cos

Suspended Exploratory Well Costs	12 Months Ended
	Dec. 31, 2013
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, 2013, 2012 and 2011 ($ in thousands):
		2013			2012			2011
	Beginning Balance at January 1,	$	36,968		$	11,756		$	1,637
	Additions to capitalized exploratory well costs pending the determination of estimated proved reserves		171,087			95,980			106,045
	Divested wells		0			0			0
	Reclassification of wells, facilities, and equipment based on the determination of estimated proved reserves		(202,323	)		(70,518	)		(95,926	)
	Capitalized exploratory well costs charged to expense		(1	)		(250	)		0
	Ending Balance at December 31,		5,731			36,968			11,756
	Less exploratory well costs that have been capitalized for a period of one year or less		(3,597	)		(36,630	)		(11,756	)
	Capitalized exploratory well costs for a period of greater than one year	$	2,134		$	338		$	0
	Number of projects that have exploratory well costs capitalized for a period of more than one year		3			2			0
	As of December 31, 2013 we had approximately $2.1 million in capitalized exploratory well costs that were capitalized for a period greater than one year. These costs are related to three proposed wells 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 several months in advance of commencing drilling operations and pad construction that was undertaken to extend certain leases. 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 Sheet 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, 2013
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):
			2013			2012			2011
	Consolidated Entities:
	Acquisition of Properties
	Proved		$	2,445		$	1,474		$	9
	Unproved			39,291			49,331			76,852
	Exploration Costs(a)			231,112			128,748			113,075
	Development Costs(a)			64,661			57,149			61,920
	Subtotal			337,509			236,702			251,856
	Asset Retirement Obligations			3,031			4,480			316
	Total Costs Incurred		$	340,540		$	241,182		$	252,172
	Share of Equity Method Investments:
	Acquisition of Properties
	Proved		$	0		$	0		$	0
	Unproved			0			0			0
	Exploration Costs			0			0			0
	Development Costs(a)			1,958			4,316			12,682
	Total		$	1,958		$	4,316		$	12,682
	(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):
			2013			2012			2011
	Total Costs Incurred by Consolidated Entities		$	340,540		$	241,182		$	252,172
	Equity Method Investments			2,493			4,087			23,204
	DJ Basin Expenditures			2			3,146			24,029
	Exploration Expense			(11,408	)		(4,782	)		(2,507	)
	Asset Retirement Obligations			(3,031	)		(4,480	)		(316	)
	Depreciation for Support Equipment and Facilities			(5,024	)		(4,187	)		(3,308	)
	Corporate Expenditures			3,651			1,156			1,126
	Other(a)			10,391			2,732			8,016
	Total Capital Expenditures		$	337,614		$	238,854		$	302,416
	(a)	Represents corporate capital, 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, 2013
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):
		2013			2012
	Consolidated Entities:
	Proven Oil and Natural Gas Properties	$	749,680		$	485,448
	Pipelines and Support Equipment		33,119			31,231
	Field Operation Vehicles and Other Equipment		21,608			13,412
	Wells and Facilities in Progress		69,886			87,800
	Unproven Properties		189,385			165,503
	Total		1,063,678			783,394
	Less Accumulated Depreciation and Depletion		(184,836	)		(141,769	)
	Total	$	878,842		$	641,625
	Share of Equity Method Investments:
	Pipelines and Support Equipment	$	19,270		$	17,524
	Field Operation Vehicles and Other Equipment		0			0
	Wells and Facilities in Progress		238			26
	Total		19,508			17,550
	Less Accumulated Depreciation and Depletion		(1,818	)		(1,077	)
	Total	$	17,690		$	16,473

Oil_and_Natural_Gas_Reserve_Qu

Oil and Natural Gas Reserve Quantities	12 Months Ended
	Dec. 31, 2013
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, 2013, 2012 and 2011. 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, 2013, 2012 and 2011.
			2013
			Oil			NGLs			Natural Gas			MMcf
			(MBbls)			(MBbls)			(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			(438.5	)		(4,685.6	)		(16,137.7	)		(46,882.3	)
	Purchases			1			0			0			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			NGLs			Natural Gas			MMcf
			(MBbls)			(MBbls)			(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			650.5			12,089.50			(1,413.6	)		75,026.40
	Improved Recovery			758.3			0			0			4,549.80
	Purchases			43.2			0			0			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
			2011
			Oil			NGLs			Natural Gas			MMcf
			(MBbls)			(MBbls)			(MMcf)			Equivalents
	Estimated Proved Reserves—Beginning of Period			8,142.80			4,200.00			127,621.90			201,678.70
	Extensions, Discoveries and Additions			156.5			2,640.40			139,067.70			155,849.10
	Revisions(a)			576.4			484.6			16,515.00			22,881.00
	Production(b)			(694.5	)		(190.2	)		(8,912.3	)		(14,220.5	)
	Estimated Proved Reserves—End of Period			8,181.20			7,134.80			274,292.30			366,188.30
	(a)	Revisions includes 120.9 MBbls and 725.4 MMcfe related to our successful ASP pilot in the Illinois Basin.
	(b)	Gas production excludes certain production associated with gas sales contracts for which we do not recognize reserves.
			Oil			NGLs			Natural Gas			Mcf
			(MBbls)			(MBbls)			(MMcf)			Equivalents
	Proved Developed Reserves
	December 31, 2013			7,742.50			16,322.50			212,061.40			356,451.40
	December 31, 2012			9,216.10			10,143.70			141,754.60			257,913.40
	December 31, 2011			8,181.20			2,218.40			110,853.30			173,250.90
	Proved Undeveloped Reserves
	December 31, 2013			877.1			29,808.20			309,221.40			493,333.20
	December 31, 2012			159.6			21,536.20			229,961.80			360,136.60
	December 31, 2011			0			4,916.40			163,439.00			192,937.40
	Our estimated proved undeveloped reserves included 21.0 gross (15.7 net) locations that generated positive future net revenue but negative present value discounted at 10%. Net reserve volumes associated with these locations were 65.5 Bcfe (approximately 7.7% 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, operating costs.
	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 is currently 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. We had significant revisions in our oil, NGL and natural gas reserves for the year ended December 31, 2011. The majority of our positive revision of estimated proved reserves occurred in our Marcellus Shale properties, where our average per well estimated ultimate recovery (“EUR”) increased from 4.4 Bcfe to 5.3 Bcfe in our operated areas and from 3.0 Bcf to 4.2 Bcf in our non-operated Marcellus areas. These increases were due to additional field production data demonstrating better well performance compared to prior year performance. We believe that the increased performance was primarily the result of improved completion techniques. In total, the positive revisions in our Marcellus operations accounted for 84% of all revisions. Also impacting our revisions during 2011 was a change in the oil pricing from $76.03 per barrel in 2010 to $92.45 per barrel in 2011.
	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, 2013, of 0.6 MMBOE of oil, 20.0 MMBOE of NGLs and 189.1 Bcf of natural gas. These additions were primarily related to our continued success in the Appalachian Basin specifically within the Marcellus, Utica and Burkett Shales where we recorded 136.0 gross proved undeveloped drilling locations. We had significant extensions, discoveries and other additions for the year ended December 31, 2012, of 0.5 MMBOE of oil, 12.8 MMBOE of NGLs and 116.9 Bcf of natural gas. These additions were primarily due to the additional proved undeveloped locations that were added to our proved reserve estimates that were a result of our continued drilling success in the Marcellus Shale. A portion of the extension and discoveries were booked as a result of successful efforts from exploration wells drilled in the Utica Shale and the development of stacked reservoirs through the drilling of previously undeveloped acreage in the Illinois Basin. We had significant extensions, discoveries and other additions for the year ended December 31, 2011, of 0.2 MMBOE of oil, 2.6 MMBOE of NGLs and 139.1 Bcf of natural gas. These additions were primarily due to the additional proved undeveloped locations that were added to our proved reserve estimates that were a result of our continued drilling success in the Marcellus Shale. A portion of the extension and discoveries were booked as a result of successful efforts from exploration wells drilled in the Burkett and Utica Shales. In the Illinois Basin, we successfully booked estimated proved reserves as a result of our ASP pilot, which were classified as revisions.

Standardized_Measure_Of_Discou

Standardized Measure Of Discounted Future Net Cash Flows	12 Months Ended
	Dec. 31, 2013
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, 2013, 2012 and 2011 ($ in thousands):
			2013			2012			2011
	Future Cash Inflows		$	3,899,878	(a)	$	2,988,231	(b)	$	2,333,513	(c)
	Future Costs:
	Production			(1,619,629	)		(1,387,653	)		(880,077	)
	Abandonment			(95,183	)		(85,859	)		(65,560	)
	Development			(517,875	)		(324,873	)		(251,821	)
	Net Future Cash Inflow Before Income Taxes			1,667,191			1,189,846			1,136,055
	Future Income Tax Expense			(359,322	)		(245,078	)		(277,568	)
	Total Future Net Cash Flows Before 10.0% Discount			1,307,869			944,768			858,487
	Less: Effect of a 10.0% Discount Factor			(778,756	)		(548,645	)		(444,552	)
	Standardized Measure of Discounted Future Net Cash Flows		$	529,113		$	396,123		$	413,935
	(a)	Calculated using weighted average prices of $3.588 per Mcf, $94.28 per barrel of oil and $26.37 per barrel of NGLs
	(b)	Calculated using weighted average prices of $2.94 per Mcf, $90.92 per barrel of oil and $32.91 per barrel of NGLs
	(c)	Calculated using weighted average prices of $4.55 per Mcf, $92.45 per barrel of oil and $46.34 per barrel of NGLs
	The principal sources of change in the standardized measure of discounted future net cash flows are as follows:
			2013			2012			2011
	Standardized Measure—Beginning of Period		$	396,123		$	413,935		$	188,065
	Revisions of Previous Estimates:
	Changes in Prices and Production Costs			72,503			(198,433	)		29,223
	Revisions in Quantities			(51,289	)		91,462			40,525
	Changes in Future Development Costs			22,341			(3,885	)		(19,539	)
	Accretion of Discount and Timing of Future Cash Flows			47,571			52,093			25,218
	Net Change in Income Tax			31,433			27,405			(42,875	)
	Purchase (Sale) of Reserves in Place			0			1,188			0
	Plus Extensions, Discoveries, and Other Additions			170,846			88,749			159,047
	Development Costs Incurred			64,661			57,149			61,290
	Sales of Product—Net of Production Costs			(151,781	)		(86,936	)		(78,763	)
	Changes in Timing and Other			(73,295	)		(46,604	)		51,744
	Standardized Measure—End of Period		$	529,113		$	396,123		$	413,935

Results_Of_Operations_For_Oil_

Results Of Operations For Oil And Gas Producing Activities	12 Months Ended
	Dec. 31, 2013
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):
			2013			2012			2011
	Consolidated Entities (in thousands):
	Revenues
	Oil and Natural Gas Sales		$	213,919		$	134,574		$	111,879
	Expenses
	Production and Lease Operating Expense			62,138			47,638			33,116
	Impairment Expense			32,072			20,505			14,316
	Exploration Expense			11,408			4,782			2,507
	Depletion, Depreciation, Amortization and Accretion			62,386			44,955			27,670
	Total Costs			168,004			117,880			77,609
	Pre-Tax Operating Income (Loss)			45,915			16,694			34,270
	Income Tax Expense(a)			30,579			6,778			10,760
	Results of Operations for Oil and Gas Producing Activities		$	15,336		$	9,916		$	23,510
	Share of Equity Method Investments (in thousands):
	Expenses
	Depletion, Depreciation, Amortization and Accretion		$	752		$	1,082		$	1,568
	Total Costs			752			1,082			1,568
	Pre-Tax Operating Loss			(752	)		(1,082	)		(1,568	)
	Income Tax Benefit (a)			501			435			519
	Results of Operations for Oil and Gas Producing Activities		$	(251	)	$	(647	)	$	(1,049	)
	Total Consolidated and Equity Method Investees Results of Operations for Oil and Gas Producing Activities		$	15,085		$	9,269		$	22,461
	(a)	Computed using the effective rate for continuing operations for each period: 66.6% in 2013; 40.6% in 2012 and; 31.4% in 2011.

Litigation

Litigation	12 Months Ended
	Dec. 31, 2013
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 January 2010, we submitted certain proposed revisions to a Directed Inspection and Maintenance Plan previously implemented by us pursuant to the terms of the consent decree. In general, the proposed revisions update the plan to reflect changes in hydrogen sulfide control measures and procedures implemented in the field and changes in procedures for responding to resident complaints of hydrogen sulfide odors. The EPA, DOJ and Illinois EPA all approved these revisions. In 2013, we communicated the consent decree, which were ongoing as of December 31, 2013.
	Litigation Related to Proposed Oil and Gas Leases in Westmoreland County, Pennsylvania
	In July 2009, we were named as defendants in a proposed class action lawsuit filed in the Court of Common Pleas of Westmoreland County, Pennsylvania (the “Snyder case”). The named plaintiffs were five individuals who sued on behalf of themselves and all persons who are alleged to be similarly situated. The complaint in the Snyder case generally asserted that a binding contract to lease oil and gas property was formed between the Company and each proposed class member when representatives of Duncan Land & Energy, Inc. (“Duncan Land”), a leasing agent that we engaged, presented a form of proposed oil and gas lease to each person, and each person signed the proposed oil and gas lease form and delivered the executed proposed lease to representatives of Duncan Land. We rejected these leases and never signed them. The plaintiffs sought a judgment declaring the rights of the parties with respect to those proposed leases, as well as damages and other relief, together with interest, costs, expenses and attorneys’ fees.
	In May 2011, we entered into a Settlement Agreement with respect to these legal proceedings. In July 2011, the court approved the Settlement Agreement, pursuant to which we offered each eligible class member an oil and gas lease, in a form agreed to by the parties, with a prepaid rental of $2,500 per acre for a five-year term with a 15% royalty. We also agreed to pay $30,000 to plaintiffs’ attorneys for the anticipated expenses of administration of the Settlement Agreement. Additionally, we deposited $2.5 million into a fund for distribution to class members and for attorney’s fees, costs and expenses of counsel for the class. The final order regarding the Settlement Agreement dismissed all claims against us with prejudice and without any admission of liability, and provided a release by all class members of all claims against us in connection with the litigation.
	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 and the parties filed briefs and responses 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 procedures.
	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. We expect to make a determination as to the consolidation of these cases with the Cardinale case as the Cardinale case proceeds.
	We intend to vigorously defend against each of these claims. We expect to enter a case management plan with the Cardinale plaintiffs’ counsel within the next several months, which will outline the timing for class discovery, class certification, trial discovery and the trial. In the meantime, we are preparing for discovery. 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, 2013
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)
		2013
		March			June			September			December
	Revenues	$	47,470		$	55,360		$	62,974		$	72,127
	Costs and Expenses		49,810			41,919			61,142			85,401
	Net Income (Loss) From Continuing Operations		(2,340	)		13,441			1,832			(13,274	)
	Net Loss From Discontinued Operations		(61	)		520			0			(691	)
	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 Common Shareholders:
	Basic—Continuing Operations Attributable to Rex Energy	$	(0.05	)	$	0.25		$	0.03		$	(0.26	)
	Basic—Discontinued Operations		0			0.01			0			(0.01	)
	Basic—Net Income (Loss)	$	(0.05	)	$	0.26		$	0.03		$	(0.27	)
	Basic—Weighted Average Shares Outstanding		52,367			52,555			52,626			52,705
	Diluted—Continuing Operations Attributable to Rex Energy	$	(0.05	)	$	0.25		$	0.03		$	(0.26	)
	Diluted—Discontinued Operations		0			0.01			0			(0.01	)
	Diluted—Net Income (Loss)	$	(0.05	)	$	0.26		$	0.03		$	(0.27	)
	Diluted—Weighted Average Shares Outstanding		52,367			52,911			53,293			52,705
		2012
		March			June			September			December
	Revenues	$	33,834		$	30,257		$	38,929		$	45,119
	Costs and Expenses		30,006			(25,936	)		40,671			46,157
	Net Income (Loss) From Continuing Operations		3,828			56,193			(1,742	)		(1,038	)
	Net Loss From Discontinued Operations		(5,355	)		(3,050	)		(258	)		(2,280	)
	Net Income (Loss)		(1,527	)		53,143			(2,000	)		(3,318	)
	Net Income (Loss) Attributable to Noncontrolling Interests		101			222			193			303
	Net Income (Loss) Attributable to Rex Energy	$	(1,628	)	$	52,921		$	(2,193	)	$	(3,621	)
	Income (Loss) per Common Share Attributable to Rex Common Shareholders:
	Basic—Continuing Operations Attributable to Rex Energy	$	0.08		$	1.08		$	(0.04	)	$	(0.03	)
	Basic—Discontinued Operations		(0.11	)		(0.06	)		0			(0.04	)
	Basic—Net Income (Loss)	$	(0.03	)	$	1.02		$	(0.04	)	$	(0.07	)
	Basic—Weighted Average Shares Outstanding		48,744			52,009			52,036			52,278
	Diluted—Continuing Operations Attributable to Rex Energy	$	0.08		$	1.06		$	(0.04	)	$	(0.03	)
	Diluted—Discontinued Operations		(0.11	)		(0.06	)		0			(0.04	)
	Diluted—Net Income (Loss)	$	(0.03	)	$	1		$	(0.04	)	$	(0.07	)
	Diluted—Weighted Average Shares Outstanding		49,693			52,876			52,036			52,278

Condensed_Consolidating_Financ

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2013
Condensed Consolidating Financial Information	'
	27. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
	As of December 31, 2013, we had outstanding $350.0 million of Senior Notes due 2020, as shown in Note 11, 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, 2013;
		•		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 (formerly known as NorthStar #3, LLC) and Rex Energy Rockies, 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, 2013, 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, 2013 and 2012, 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, 2013.
	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-			Rex Energy			Eliminations			Consolidated
			Subsidiaries			Guarantor			Corporation						Balance
						Subsidiaries			(Note Issuer)
	ASSETS
	Current Assets
	Cash and Cash Equivalents		$	1,386		$	509		$	5		$	0		$	1,900
	Accounts Receivable			32,283			9,882			0			(3,302	)		38,863
	Taxes Receivable			0			0			5,189			0			5,189
	Short-Term Derivative Instruments			5,180			0			488			0			5,668
	Current Deferred Tax Asset			0			0			3,451			0			3,451
	Inventory, Prepaid Expenses and Other			2,092			89			26			0			2,207
	Total Current Assets			40,941			10,480			9,159			(3,302	)		57,278
	Property and Equipment (Successful Efforts Method)
	Evaluated Oil and Gas Properties			752,781			0			0			(3,101	)		749,680
	Unevaluated Oil and Gas Properties			189,385			0			0			0			189,385
	Other Property and Equipment			57,409			12,706			0			0			70,115
	Wells and Facilities in Progress			70,759			6,576			0			(790	)		76,545
	Pipelines			7,678			0			0			0			7,678
	Total Property and Equipment			1,078,012			19,282			0			(3,891	)		1,093,403
	Less: Accumulated Depreciation, Depletion and Amortization			(188,699	)		(2,172	)		0			350			(190,521	)
	Net Property and Equipment			889,313			17,110			0			(3,541	)		902,882
	Deferred Financing Costs and Other Assets—Net			2,421			206			9,366			0			11,993
	Equity Method Investments			18,708			0			0			0			18,708
	Intercompany Receivables			0			0			628,517			(628,517	)		0
	Investment in Subsidiaries—Net			4,442			1,197			216,945			(222,584	)		0
	Long-Term Derivative Instruments			535			0			0			0			535
	Total Assets		$	956,360		$	28,993		$	863,987		$	(857,944	)	$	991,396
	LIABILITIES AND STOCKHOLDERS’ EQUITY
	Current Liabilities
	Accounts Payable		$	33,613		$	794		$	0		$	(3,304	)	$	31,103
	Current Maturities of Long-Term Debt			1,339			5,404			0			0			6,743
	Accrued Liabilities			45,196			6,287			2,967			0			54,450
	Short-Term Derivative Instruments			4,663			0			0			0			4,663
	Total Current Liabilities			84,811			12,485			2,967			(3,304	)		96,959
	8.875% Senior Notes Due 2020			0			0			350,000			0			350,000
	Premium (Discount) on Senior Notes			0			0			3,078			0			3,078
	Senior Secured Line of Credit and Long-Term Debt			137			3,054			59,000			0			62,191
	Long-Term Derivative Instruments			1,071			0			694			0			1,765
	Long-Term Deferred Tax Liability			0			0			29,446			0			29,446
	Other Deposits and Liabilities			4,992			0			0			0			4,992
	Future Abandonment Cost			26,027			13			0			0			26,040
	Intercompany Payables			554,329			74,188			0			(628,517	)		0
	Total Liabilities			671,367			89,740			445,185			(631,821	)		574,471
	Stockholders’ Equity
	Common Stock			0			0			54			0			54
	Additional Paid-In Capital			177,144			6,488			456,554			(183,632	)		456,554
	Accumulated 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			0			485			0			1,557			2,042
Total Stockholders’ Equity			284,993			(60,747	)		418,802			(226,123	)		416,925
Total Liabilities and Stockholders’ Equity		$	956,360		$	28,993		$	863,987		$	(857,944	)	$	991,396
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2013
($ in Thousands)
		Guarantor			Non-			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Guarantor			Corporation						Balance
					Subsidiaries			(Note Issuer)
OPERATING REVENUE
Oil, Natural Gas and NGL Sales		$	213,919		$	0		$	0		$	0		$	213,919
Field Services Revenue			0			32,583			0			(8,771	)		23,812
Other Revenue			200			0			0			0			200
TOTAL OPERATING REVENUE			214,119			32,583			0			(8,771	)		237,931
OPERATING EXPENSES
Production and Lease Operating Expense			62,138			0			0			0			62,138
General and Administrative Expense			25,376			2,416			5,420			(86	)		33,126
Loss on Disposal of Asset			1,601			46			0			0			1,647
Impairment Expense			32,072			0			0			0			32,072
Exploration Expense			11,395			13			0			0			11,408
Depreciation, Depletion, Amortization and Accretion			62,540			1,604			0			(200	)		63,944
Field Services Operating Expense			0			23,527			0			(6,197	)		17,330
Other Operating Expense			592			0			0			0			592
TOTAL OPERATING EXPENSES			195,714			27,606			5,420			(6,483	)		222,257
INCOME (LOSS) FROM OPERATIONS			18,405			4,977			(5,420	)		(2,288	)		15,674
OTHER INCOME (EXPENSE)
Interest Expense			(64	)		(106	)		(22,612	)		0			(22,782	)
Loss on Derivatives, Net			(2,703	)		0			(205	)		0			(2,908	)
Other Income			6,739			0			0			(86	)		6,653
Loss From Equity Method Investments			(763	)		0			0			0			(763	)
Income (Loss) From Equity in Consolidated Subsidiaries			(33	)		33			5,703			(5,703	)		0
TOTAL OTHER INCOME (LOSS)			3,176			(73	)		(17,114	)		(5,789	)		(19,800	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX			21,581			4,904			(22,534	)		(8,077	)		(4,126	)
Income Tax (Expense) Benefit			(14,409	)		(2,210	)		20,404			0			3,785
INCOME (LOSS) FROM CONTINUING OPERATIONS			7,172			2,694			(2,130	)		(8,077	)		(341	)
Loss From Discontinued Operations, Net of Income Taxes			0			(232	)		0			0			(232	)
NET INCOME (LOSS)			7,172			2,462			(2,130	)		(8,077	)		(573	)
Net Income Attributable to Noncontrolling Interests			0			1,557			0			0			1,557
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY		$	7,172		$	905		$	(2,130	)	$	(8,077	)	$	(2,130	)
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDING DECEMBER 31, 2013
($ in Thousands)
		Guarantor			Non-			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Guarantor			Corporation						Balance
					Subsidiaries			(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 From Equity Method Investments			763			0			0			0			763
Non-Cash Expenses			(194	)		55			6,369			0			6,230
Depreciation, Depletion, Amortization and Accretion			62,540			1,604			0			(200	)		63,944
Deferred Income Tax Expense (Benefit)			14,409			2,210			(14,340	)		0			2,279
Loss on Derivatives			2,703			0			205			0			2,908
Cash Settlement of Derivatives			7,128			0			0			0			7,128
Dry Hole Expense			2,993			0			0			0			2,993
Gain on Sale of Assets and Equity Method Investments			(5,289	)		(922	)		0			0			(6,211	)
Impairment Expense			32,072			0			0			0			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	)		0			0			(885	)
Accounts Payable and Accrued Liabilities			8,554			874			1,481			1,982			12,891
Other Assets and Liabilities			(2,272	)		(88	)		(137	)		0			(2,497	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES			123,876			(379	)		(7,311	)		(7,870	)		108,316
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries			186,089			1,619			(193,015	)		5,307			0
Proceeds from Joint Venture Leasing Initiatives			458			0			0			0			458
Contributions to Equity Method Investments			(2,493	)		0			0			0			(2,493	)
Proceeds from the Sale of Assets and Equity Method Investments			8,071			3,234			0			0			11,305
Acquisitions of Undeveloped Acreage			(41,782	)		(2	)		0			0			(41,784	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment			(275,697	)		(7,870	)		0			2,563			(281,004	)
NET CASH USED IN INVESTING ACTIVITIES			(125,354	)		(3,019	)		(193,015	)		7,870			(313,518	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit			0			7,249			65,000			0			72,249
Repayments of Long-Term Debt and Lines of Credit			0			(2,480	)		(6,000	)		0			(8,480	)
Repayments of Loans and Other Notes Payable			(1,363	)		(642	)		0			0			(2,005	)
Proceeds from 8.875% Senior Notes, net of Discount			0			0			105,000			0			105,000
Debt Issuance Costs			0			(8	)		(3,126	)		0			(3,134	)
Proceeds from the Exercise of Stock Options			0			0			533			0			533
Capital Distributions by the Partners of Consolidated Joint Ventures			0			(886	)		0			0			(886	)
Purchase of Noncontrolling Interests			0			(150	)		0			0			(150	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES			(1,363	)		3,083			161,407			0			163,127
NET INCREASE (DECREASE) IN CASH			(2,841	)		(315	)		(38,919	)		0			(42,075	)
CASH—BEGINNING			4,227			824			38,924			0			43,975
CASH—ENDING		$	1,386		$	509		$	5		$	0		$	1,900
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
FOR THE YEAR ENDED DECEMBER 31, 2012
($ in Thousands, Except Share and Per Share Data)
		Guarantor			Non-			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Guarantor			Corporation						Balance
					Subsidiaries			(Note Issuer)
ASSETS
Current Assets
Cash and Cash Equivalents		$	4,227		$	824		$	38,924		$	0		$	43,975
Accounts Receivable			26,490			3,367			0			(4,877	)		24,980
Taxes Receivable			0			0			6,429			0			6,429
Short-Term Derivative Instruments			12,005			0			0			0			12,005
Assets Held For Sale			0			2,279			0			0			2,279
Inventory, Prepaid Expenses and Other			1,277			13			26			0			1,316
Total Current Assets			43,999			6,483			45,379			(4,877	)		90,984
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties			486,706			0			0			(1,258	)		485,448
Unevaluated Oil and Gas Properties			165,503			0			0			0			165,503
Other Property and Equipment			45,613			4,455			0			5			50,073
Wells and Facilities in Progress			88,204			4,780			0			(71	)		92,913
Pipelines			6,116			0			0			0			6,116
Total Property and Equipment			792,142			9,235			0			(1,324	)		800,053
Less: Accumulated Depreciation, Depletion and Amortization			(145,514	)		(674	)		0			150			(146,038	)
Net Property and Equipment			646,628			8,561			0			(1,174	)		654,015
Deferred Financing Costs and Other Assets—Net			2,427			199			7,403			0			10,029
Equity Method Investments			16,978			0			0			0			16,978
Intercompany Receivables			3,795			0			440,269			(444,064	)		0
Investment in Subsidiaries—Net			(227	)		(232	)		193,790			(193,331	)		0
Long-Term Derivative Instruments			704			0			0			0			704
Total Assets		$	714,304		$	15,011		$	686,841		$	(643,446	)	$	772,710
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable		$	29,230		$	462		$	0		$	(244	)	$	29,448
Current Maturities of Long-Term Debt			588			1,098			0			0			1,686
Accrued Liabilities			20,489			1,036			1,494			0			23,019
Short-Term Derivative Instruments			1,389			0			0			0			1,389
Current Deferred Tax Liability			0			0			539			0			539
Liabilities Related to Assets Held For Sale			0			52			0			0			52
Total Current Liabilities			51,696			2,648			2,033			(244	)		56,133
8.875% Senior Notes Due 2020			0			0			250,000			0			250,000
Discount on Senior Notes			0			0			(1,742	)		0			(1,742	)
Senior Secured Line of Credit and Long-Term Debt			26			5,598			0			(4,633	)		991
Long-Term Derivative Instruments			1,510			0			0			0			1,510
Long-Term Deferred Tax Liability			0			0			23,625			0			23,625
Other Deposits and Liabilities			5,675			0			0			0			5,675
Future Abandonment Cost			24,224			0			0			0			24,224
Intercompany Payables			367,704			76,360			0			(444,064	)		0
Total Liabilities			450,835			84,606			273,916			(448,941	)		360,416
Stockholders’ Equity
Common Stock			0			0			52			0			52
Additional Paid-In Capital			177,143			(407	)		451,062			(176,736	)		451,062
Accumulated Deficit			86,326			(69,144	)		(38,189	)		(18,588	)		(39,595	)
Rex Energy Stockholders’ Equity			263,469			(69,551	)		412,925			(195,324	)		411,519
Noncontrolling Interests			0			(44	)		0			819			775
Total Stockholders’ Equity			263,469			(69,595	)		412,925			(194,505	)		412,294
Total Liabilities and Stockholders’ Equity		$	714,304		$	15,011		$	686,841		$	(643,446	)	$	772,710
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2012
($ in Thousands)
		Guarantor			Non-			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Guarantor			Corporation						Balance
					Subsidiaries			(Note Issuer)
OPERATING REVENUE
Oil, Natural Gas and NGL Sales		$	134,574		$	0		$	0		$	0		$	134,574
Field Services Revenue			0			15,637			0			(2,234	)		13,403
Other Revenue			218			0			0			(56	)		162
TOTAL OPERATING REVENUE			134,792			15,637			0			(2,290	)		148,139
OPERATING EXPENSES
Production and Lease Operating Expense			47,618			20			0			0			47,638
General and Administrative Expense			19,283			1,007			3,159			(104	)		23,345
Loss on Disposal of Asset			50			8			0			0			58
Impairment Expense			20,505			80			0			0			20,585
Exploration Expense			4,782			0			0			0			4,782
Depreciation, Depletion, Amortization and Accretion			44,993			527			0			(83	)		45,437
Field Services Operating Expense			0			9,859			0			(1,619	)		8,240
Other Operating Expense			1,136			0			0			0			1,136
TOTAL OPERATING EXPENSES			138,367			11,501			3,159			(1,806	)		151,221
INCOME (LOSS) FROM OPERATIONS			(3,575	)		4,136			(3,159	)		(484	)		(3,082	)
OTHER INCOME (EXPENSE)
Interest Expense			(55	)		(26	)		(6,362	)		0			(6,443	)
Gain on Derivatives, Net			10,687			0			0			0			10,687
Other Income (Expense)			99,575			0			(922	)		(104	)		98,549
Loss From Equity Method Investments			(3,921	)		0			0			0			(3,921	)
Income (Loss) From Equity in Consolidated Subsidiaries			(68	)		68			51,363			(51,363	)		0
TOTAL OTHER INCOME (LOSS)			106,218			42			44,079			(51,467	)		98,872
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX			102,643			4,178			40,920			(51,951	)		95,790
Income Tax (Expense) Benefit			(41,772	)		(1,336	)		4,559			0			(38,549	)
INCOME (LOSS) FROM CONTINUING OPERATIONS			60,871			2,842			45,479			(51,951	)		57,241
Loss From Discontinued Operations, Net of Income Taxes			0			(10,943	)		0			0			(10,943	)
NET INCOME (LOSS)			60,871			(8,101	)		45,479			(51,951	)		46,298
Net Income Attributable to Noncontrolling Interests			0			819			0			0			819
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY		$	60,871		$	(8,920	)	$	45,479		$	(51,951	)	$	45,479
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDING DECEMBER 31, 2012
($ in Thousands)
		Guarantor			Non-			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Guarantor			Corporation						Balance
					Subsidiaries			(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 From Equity Method Investments			3,921			0			0			0			3,921
Non-Cash Expenses			33			14			3,144			0			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	)		0			23,665
Gain on Derivatives			(10,687	)		0			0			0			(10,687	)
Cash Settlement of Derivatives			16,219			0			0			0			16,219
Dry Hole Expense			320			336			0			0			656
(Gain) Loss on Sale of Assets and Equity Method Investments			(99,355	)		(2,118	)		922			0			(100,551	)
Impairment Expense			20,505			19,850			0			0			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			0			(92	)
Accounts Payable and Accrued Liabilities			(8,875	)		(766	)		916			(107	)		(8,832	)
Other Assets and Liabilities			(1,146	)		(64	)		0			29			(1,181	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES			91,600			(1,178	)		7,596			(52,313	)		45,705
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries			2,915			1,931			(56,489	)		51,643			0
Proceeds from Joint Venture Leasing Initiatives			260			0			0			0			260
Contributions to Equity Method Investments			0			(4,087	)		0			0			(4,087	)
Proceeds from the Sale of Assets and Equity Method Investments			128,554			4,871			0			0			133,425
Acquisitions of Undeveloped Acreage			(51,783	)		(19	)		0			0			(51,802	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment			(177,892	)		(1,316	)		0			670			(178,538	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES			(97,946	)		1,380			(56,489	)		52,313			(100,742	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit			0			730			126,000			0			126,730
Repayments of Long-Term Debt and Lines of Credit			0			0			(351,000	)		0			(351,000	)
Repayments of Loans and Other Notes Payable			(764	)		(198	)		0			0			(962	)
Proceeds from 8.875% Senior Notes, net of Discount			0			0			248,250			0			248,250
Debt Issuance Costs			0			0			(6,397	)		0			(6,397	)
Settlement of Tax Withholdings Related to Share-Based Compensation Awards			0			0			(234	)		0			(234	)
Proceeds from the Issuance of Common Stock, Net of Issuance Costs			0			0			70,583			0			70,583
Proceeds from the Exercise of Stock Options			0			0			565			0			565
Capital Distributions by the Partners of Consolidated Joint Ventures			0			(319	)		0			0			(319	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES			(764	)		213			87,767			0			87,216
NET INCREASE (DECREASE) IN CASH			(7,110	)		415			38,874			0			32,179
CASH—BEGINNING			11,337			409			50			0			11,796
CASH—ENDING		$	4,227		$	824		$	38,924		$	0		$	43,975
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2011
($ in Thousands)
		Guarantor			Non-			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Guarantor			Corporation						Balance
					Subsidiaries			(Note Issuer)
OPERATING REVENUE
Oil, Natural Gas and NGL Sales		$	111,879		$	0		$	0		$	0		$	111,879
Field Services Revenue			0			3,546			0			(1,028	)		2,518
Other Revenue			209			0			0			0			209
TOTAL OPERATING REVENUE			112,088			3,546			0			(1,028	)		114,606
OPERATING EXPENSES
Production and Lease Operating Expense			33,106			10			0			0			33,116
General and Administrative Expense			21,424			586			1,662			(36	)		23,636
Loss on Disposal of Asset			353			149			0			0			502
Impairment Expense			14,316			315			0			0			14,631
Exploration Expense			2,507			0			0			0			2,507
Depreciation, Depletion, Amortization and Accretion			27,672			231			0			(47	)		27,856
Field Services Operating Expense			0			2,470			0			(720	)		1,750
Other Operating Expense			819			0			0			0			819
TOTAL OPERATING EXPENSES			100,197			3,761			1,662			(803	)		104,817
INCOME (LOSS) FROM OPERATIONS			11,891			(215	)		(1,662	)		(225	)		9,789
OTHER INCOME (EXPENSE)
Interest Expense			(107	)		(2	)		(2,405	)		0			(2,514	)
Gain on Derivatives, Net			18,916			0			0			0			18,916
Other Income (Expense)			13			101			0			(35	)		79
Income From Equity Method Investments			81			0			0			0			81
Income (Loss) From Equity in Consolidated Subsidiaries			(53	)		53			(12,925	)		12,925			0
TOTAL OTHER INCOME (LOSS)			18,850			152			(15,330	)		12,890			16,562
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX			30,741			(63	)		(16,992	)		12,665			26,351
Income Tax (Expense) Benefit			(9,927	)		33			1,624			0			(8,270	)
INCOME (LOSS) FROM CONTINUING OPERATIONS			20,814			(30	)		(15,368	)		12,665			18,081
Loss From Discontinued Operations, Net of Income Taxes			0			(33,457	)		0			0			(33,457	)
NET INCOME (LOSS)			20,814			(33,487	)		(15,368	)		12,665			(15,376	)
Net Loss Attributable to Noncontrolling Interests			0			(7	)		0			0			(7	)
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY		$	20,814		$	(33,480	)	$	(15,368	)	$	12,665		$	(15,369	)
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDING DECEMBER 31, 2011
($ in Thousands)
		Guarantor			Non-			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Guarantor			Corporation						Balance
					Subsidiaries			(Note Issuer)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)		$	20,814		$	(33,487	)	$	(15,368	)	$	12,665		$	(15,376	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
(Gain) Loss From Equity Method Investments			(81	)		0			0			0			(81	)
Non-Cash Expenses			118			2			1,625			0			1,745
Depreciation, Depletion, Amortization and Accretion			27,672			316			505			(47	)		28,446
Deferred Income Tax Expense (Benefit)			(10,234	)		1,271			1,624			0			(7,339	)
(Gain) Loss on Derivatives			(18,916	)		0			0			0			(18,916	)
Cash Settlements of Derivatives			6,212			0			0			0			6,212
Dry Hole Expense			6			32,763			0			0			32,769
(Gain) Loss on Sale of Assets and Equity Method Investments			353			149			0			0			502
Impairment Expense			14,316			13,492			0			0			27.808
Changes in operating assets and liabilities
Accounts Receivable			188,899			29,099			(211,952	)		5,072			11,118
Inventory, Prepaid Expenses and Other Assets			157			(56	)		(15	)		0			86
Accounts Payable and Accrued Liabilities			859			(3,124	)		405			(136	)		(1,996	)
Other Assets and Liabilities			(1,473	)		961			0			41			(471	)
NET CASH PROVIDED BY OPERATING ACTIVITIES			228,702			41,386			(223,176	)		17,595			64,507
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries			(2,337	)		10,811			9,121			(17,595	)		0
Proceeds from Joint Venture Leasing Initiatives			3,209			0			0			0			3,209
Change in Restricted Cash			16,086			0			0			0			16,086
Contributions to Equity Method Investments			0			(23,204	)		0			0			(23,204	)
Proceeds from the Sale of Assets and Equity Method Investments			2,293			436			0			0			2,729
Acquisitions of Undeveloped Acreage			(76,698	)		(1,871	)		0			0			(78,569	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment			(169,689	)		(27,444	)		308			0			(196,825	)
NET CASH USED IN INVESTING ACTIVITIES			(227,136	)		(41,272	)		9,429			(17,595	)		(276,574	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit			0			0			240,000			0			240,000
Repayments of Long-Term Debt and Lines of Credit			0			0			(25,000	)		0			(25,000	)
Repayments of Loans and Other Notes Payable			(831	)		(48	)		0			0			(879	)
Proceeds from 8.875% Senior Notes, net of Discount			0			0			0			0			0
Debt Issuance Costs			0			0			(2,615	)		0			(2,615	)
Proceeds from the Exercise of Stock Options			0			0			1,362			0			1,362
Capital Distributions by the Partners of Consolidated Joint Ventures			0			(20	)		0			0			(20	)
Capital Contributions by the Partners of Equity Method Investments and Consolidated Joint Ventures			7			0			0			0			7
NET CASH PROVIDED BY FINANCING ACTIVITIES			(824	)		(68	)		213,747			0			212,855
NET INCREASE IN CASH			742			46			0			0			788
CASH—BEGINNING			10,595			363			50			0			11,008
CASH—ENDING		$	11,337		$	409		$	50		$	0		$	11,796

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
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, 2013 and 2012, 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, 2013 and 2012, 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, 2013, we carried approximately $28.8 million in production receivable, of which approximately $22.7 million were production receivables due from four purchasers. At December 31, 2012, we carried approximately $18.1 million in production receivables, of which approximately $16.3 million were production receivables due from four purchasers. In addition, we carried approximately $4.4 million in receivables from Sumitomo Corporation at December 31, 2013 and $2.1 million at December 31, 2012 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. 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.
	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.
	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. 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 and future development plans. When evaluating the value of our unproved oil, NGL and natural gas properties, we utilize active market prices for similar acreage to use as a comparison tool against the carrying value of our properties. If the active market prices for similar acreage do not support our carrying values we then utilize estimates of future value that will be created from the future development of these properties. If future estimated fair value of these properties is lower than the capitalized cost, the capitalized cost is reduced to the estimated future fair value. We recognized approximately $32.1 million, $20.6 million and $14.6 million of impairment from continuing operations on certain oil, NGL and natural gas properties for the years ending December 31, 2013, 2012 and 2011, 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, 2013 and 2012, 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, 2013, we had deferred financing costs and other assets consisting of $12.0 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, three 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, 2013, 2012 and 2011, we recorded amortization expense from continuing operations of $1.3 million, $1.2 million and $0.8 million, respectively.
	The following is a summary of our deferred financing costs at the dates indicated:
			December 31,			December 31,
			2013			2012
			(in thousands)			(in thousands)
	Deferred Financing Costs—Gross		$	12,404		$	9,270
	Accumulated Amortization			(3,031	)		(1,866	)
	Deferred Financing Costs—Net		$	9,373		$	7,404
	Specific to our deferred financing costs, we have incurred gross debt issuance costs of approximately $3.1 million and $6.4 million for the years ended December 31, 2013 and 2012, respectively, which are presented net of accumulated amortization of $3.0 million and $1.9 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, 2013, 2012 and 2011 totaled approximately $3.0 million, $2.1 million and $1.5 million, respectively. These amounts are recorded as DD&A on our Consolidated Statements of Operations. As of December 31, 2013 and 2012, approximately $2.5 million and $0.6 million, respectively, of our Future Abandonment Costs were classified as short-term liabilities under the caption Accrued Expenses on our Consolidated Balance Sheets. During 2013 and 2012, we recognized an increase of $1.3 million and $4.0 million, respectively, in the estimated present value of our asset retirement obligations, representing an increase in the estimate to plug and abandon our oil and natural gas wells. The revised estimates were primarily the result of increased abandonment estimates, which were driven by the trends of actual outcomes. We account for asset retirement obligations that relate to wells that are drilled jointly based on our interest in those wells.
			December 31,			December 31,
			2013			2012
			($  in Thousands)			($  in Thousands)
	Beginning Balance		$	24,822		$	18,670
	Asset Retirement Obligation Incurred			1,750			598
	Asset Retirement Obligation Settled			(2,452	)		(428	)
	Asset Retirement Obligation Cancelled or Sold Well Properties			0			0
	Asset Retirement Obligation Revision of Estimated Obligation			1,311			3,953
	Asset Retirement Obligation Accretion Expense			3,094			2,029
	Total Future Abandonment Costs1		$	28,525		$	24,822
	1	As of December 31, 2013 and 2012, approximately $2.5 million and $0.6 million, respectively of our Future Abandonment Costs were classified as short-term liabilities under the caption Accrued Expenses on our Consolidated Balance Sheets.
Revenue Recognition	'
	Revenue Recognition
	As it pertains to our exploration and production business segment, 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 our field services segment, 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, basis swaps and three-way collars to manage price risks in connection with the sale of oil, natural gas and NGLs. We have also, use 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 2013, 2012 and 2011 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 other temporary 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.
Capitalization of Interest	'
	Capitalization of Interest
	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, 2013, 2012 and 2011, we capitalized interest costs of $7.5 million, $3.0 million and $1.2 million, respectively.
Earnings per Share	'
	Earnings per 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 by dividing consolidated net income attributable to us by the weighted average number of common shares outstanding during the period, including any potentially dilutive outstanding securities, such as options and warrants. The potentially dilutive outstanding securities are calculated using the treasury stock method. At December 31, 2013, we had 54,186,490 common shares outstanding, 449,087 options outstanding and 20,500 stock appreciation rights outstanding with no outstanding warrants or other potentially dilutive securities. The total common shares outstanding include 2,172,639 restricted stock awards, of which approximately 1,279,050 shares are performance-based awards. For additional information, see Note 14, Earnings per Common Share, to our Consolidated Financial Statements.
Capital Leases	'
	Capital Leases
	As a lessee, we determine if a lease is a capital lease if it meets one of four of the following criteria:
		•		The ownership of the leased property transfers to us by the end of the lease term, or shortly thereafter, in exchange for the payment of a nominal fee.
		•		The lease contains a bargain purchase option.
		•		The lease term is equal to 75% or more of the estimated economic life of the leased property.
		•		The present value at the beginning of the lease term of the minimum lease payments, excluding that portion of the payments representing executor costs such as insurance, maintenance, and taxes to be paid by the lessor, including any profit thereon, equals or exceeds 90% of the excess of the fair value of the leased property to the lessor at the lease inception over any related investment tax credit retained by the lessor and expected to be realized by the lessor.
	As of December 31, 2013 we had capital leases on field vehicles being used in our field services operating segment. We recorded these leases as Other Property and Equipment on our Consolidated Balance Sheets in the amount of $3.0 million as of December 31, 2013, and $1.6 million as of December 31, 2012. The remaining obligation to be paid on these leases totaled approximately $2.2 million, of which $1.4 million was classified as Senior Secured Line of Credit and Long-Term Debt under Long-Term Liabilities and $0.8 million was classified as Current Maturities of Long-Term Debt under Current Liabilities on our Consolidated Balance Sheets, all of which is expected to be paid by 2017. The amortization of our capital leases is recorded as Depreciation, Depletion, Amortization and Accretion on our Consolidated Statements of Operations.
Recent Accounting Pronouncements	'
	Recent Accounting Pronouncements
	In January 2013, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. ASU 2013-01 was issued to address implementation issues regarding the scope of ASU 2011-11. The amendments clarify that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with Section 210-20-45 or Section 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. We adopted this ASU on January 1, 2013 with no material effect on our Consolidated Financial Statements.
	In July 2013, the FASB issued ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. This ASU clarifies the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The ASU is effective for fiscal years, and interim period within those years, beginning after December 15, 2013. We do not expect this update to have a material impact on our Consolidated Financial Statements.
	In December 2011, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. ASU 2011-11 provides new disclosure requirements related to offsetting arrangements to allow investors to better compare financial statements prepared in accordance with IFRS and U.S. GAAP. The amendment requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. We adopted these amendments on January 1, 2013, including retrospective application for all comparative periods presented. Although we currently are not engaged in any arrangements that would be effected by these disclosure requirements, we believe that ASU 2011-11 may have a material impact on future disclosures pending our entrance into an offsetting arrangement.

Summary_Of_Significant_Account2

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Summary of Deferred Financing Costs	'
	The following is a summary of our deferred financing costs at the dates indicated:
			December 31,			December 31,
			2013			2012
			(in thousands)			(in thousands)
	Deferred Financing Costs—Gross		$	12,404		$	9,270
	Accumulated Amortization			(3,031	)		(1,866	)
	Deferred Financing Costs—Net		$	9,373		$	7,404
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,
			2013			2012
			($  in Thousands)			($  in Thousands)
	Beginning Balance		$	24,822		$	18,670
	Asset Retirement Obligation Incurred			1,750			598
	Asset Retirement Obligation Settled			(2,452	)		(428	)
	Asset Retirement Obligation Cancelled or Sold Well Properties			0			0
	Asset Retirement Obligation Revision of Estimated Obligation			1,311			3,953
	Asset Retirement Obligation Accretion Expense			3,094			2,029
	Total Future Abandonment Costs1		$	28,525		$	24,822
	1	As of December 31, 2013 and 2012, approximately $2.5 million and $0.6 million, respectively of our Future Abandonment Costs were classified as short-term liabilities under the caption Accrued Expenses on our Consolidated Balance Sheets.

Business_Segment_Information_T

Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2013
Performance of Business Segments Based on Net Income (Loss) from Continuing Operations, before Income Taxes	'
	Summarized financial information concerning our segments is shown in the following table for 2013, 2012 and 2011 (in thousands):
			Exploration			Field			Intercompany			Consolidated
			and			Services			Eliminations			Total
			Production
	For the Year Ended December 31, 2013
	Revenues		$	214,119		$	32,583		$	(8,771	)	$	237,931
	Inter-Segment Revenues			0			(8,771	)		8,771			0
	Total Revenues			214,119			23,812			0			237,931
	Depreciation, Depletion and Amortization			62,585			1,559			(200	)		63,944
	Impairment Expense			32,072			0			0			32,072
	Other Operating Expense(a)			106,591			25,945			(6,295	)		126,241
	Interest Expense			22,719			106			0			22,825
	Other (Income) Expense(b)			(3,111	)		0			86			(3,025	)
	Income (Loss) From Continuing Operations, Before Income Taxes		$	(6,737	)	$	(3,798	)	$	6,409		$	(4,126	)
	Total Assets		$	971,973		$	26,266		$	(6,843	)	$	991,396
	Expenditures for Long-Lived Assets		$	317,481		$	7,870		$	(2,563	)	$	322,788
	Equity Method Investments		$	18,708		$	0		$	0		$	18,708
	For the Year Ended December 31, 2012
	Revenues		$	134,736		$	15,637		$	(2,234	)	$	148,139
	Inter-Segment Revenues			0			(2,234	)		2,234			0
	Total Revenues			134,736			13,403			0			148,139
	Depreciation, Depletion and Amortization			44,955			482			0			45,437
	Impairment Expense			20,505			80			0			20,585
	Other Operating Expense(a)			76,063			10,859			(1,723	)		85,199
	Interest Expense			6,424			26			0			6,450
	Other (Income) Expense(b)			(105,426	)		0			104			(105,322	)
	Income (Loss) From Continuing Operations, Before Income Taxes		$	92,215		$	1,956		$	1,619		$	95,790
	Total Assets		$	766,599		$	12,166		$	(6,055	)	$	772,710
	Expenditures for Long-Lived Assets		$	227,913		$	3,134		$	(707	)	$	230,340
	Equity Method Investments		$	16,978		$	0		$	0		$	16,978
	For the Year Ended December 31, 2011
	Revenues		$	112,088		$	3,546		$	(1,028	)	$	114,606
	Inter-Segment Revenues			0			(1,028	)		1,028			0
	Total Revenues			112,088			2,518			0			114,606
	Depreciation, Depletion and Amortization			27,670			186			0			27,856
	Impairment Expense			14,316			315			0			14,631
	Other Operating Expense(a)			59,917			3,169			(756	)		62,330
	Interest Expense			2,523			1			0			2,524
	Other (Income) Expense(b)			(19,021	)		(100	)		35			(19,086	)
	Income (Loss) From Continuing Operations, Before Income Taxes		$	26,683		$	(1,053	)	$	721		$	26,351
	Total Assets		$	600,049		$	7,143		$	(5,641	)	$	601,551
	Expenditures for Long-Lived Assets		$	269,823		$	5,571		$	0		$	275,394
	Equity Method Investments		$	41,683		$	0		$	0		$	41,683
	(a)	Includes the following expenses: production and lease operating expenses, general and administrative expenses, (gain) loss on disposal of assets, exploration expense, field services operating expenses and other operating expenses.
	(b)	Includes the following expenses: interest income, gain (loss) on derivative, net, other income (expense) and gain (loss) on equity method investments.

Discontinued_OperationsAssets_1

Discontinued Operations/Assets Held For Sale (Tables)	12 Months Ended
	Dec. 31, 2013
Summary of Financial Information for Discontinued Operations	'
	Summarized financial information for Discontinued Operations is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support.
		December 31,
	($ in thousands)	2013			2012			2011
	Revenues:
	Oil and Gas Sales	$	25		$	97		$	556
	Total Operating Revenue		25			97			556
	Costs and Expenses:
	Production and Lease Operating Expense		104			353			493
	General and Administrative Expense		23			660			1,745
	Exploration Expense		97			867			33,812
	Impairment Expense		0			19,770			13,177
	Depreciation, Depletion, Amortization and Accretion		0			0			85
	Other Operating Expense (Income)		(3	)		8			1
	Gain on Disposal of Asset		(969	)		(2,126	)		0
	Interest Expense		0			0			1
	Other (Income) Expense		0			(3	)		1
	Total Expenses (Income)		(748	)		19,529			49,315
	Income (Loss) from Discontinued Operations Before Income Taxes		773			(19,432	)		(48,759	)
	Income Tax (Expense) Benefit		(1,005	)		8,489			15,302
	Loss from Discontinued Operations, Net of Income Taxes	$	(232	)	$	(10,943	)	$	(33,457	)
	Production
	Crude Oil (Bbls)		356			1,272			6,939

Consolidated_Subsidiaries_Tabl

Consolidated Subsidiaries (Tables)	12 Months Ended
	Dec. 31, 2013
Water Solutions	'
Schedule of Carrying Amount and Classification of Assets and Liabilities as Consolidated	'
	The table below sets forth the carrying amount and classifications of Water Solutions’ assets and liabilities as of December 31, 2013 and 2012, with no restrictions or obligations to use certain assets to settle associated liabilities:
		December 31,
	($ in thousands)	2013			2012
	Assets
	Cash and Cash Equivalents	$	593		$	741
	Accounts Receivable		9,882			3,360
	Inventory, Prepaid Expenses and Other		89			13
	Other Property and Equipment		11,798			3,560
	Wells and Facilities in Progress		1,031			221
	Accumulated Depreciation, Depletion and Amortization		(1,954	)		(501	)
	Deferred Financing Costs and Other Assets – Net		206			199
	Total Assets	$	21,645		$	7,593
	Liabilities
	Accounts Payable	$	758		$	456
	Current Maturities of Long-Term Debt		5,404			1,098
	Accrued Liabilities		6,247			1,036
	Senior Secured Line of Credit and Long-Term Debt		3,053			965
	Total Liabilities	$	15,462		$	3,555
NorthStar 3 LLC	'
Schedule of Carrying Amount and Classification of Assets and Liabilities as Consolidated	'
	The carrying amount and classifications of R.E. Disposal, LLC (formerly NorthStar #3) assets and liabilities as of December 31, 2012 are as follows, with no restrictions or obligations to use certain assets to settle associated liabilities:
	($ in thousands)	December 31,
		2012
	Assets
	Cash and Cash Equivalents	$	14
	Wells and Facilities in Progress		4,559
	Total Assets	$	4,573
	Liabilities
	Accounts Payable	$	6
	Note Payable		4,633
	Total Liabilities	$	4,639

Commitments_And_Contingencies_

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Lease Commitments for Each of Next Five Years	'
	Lease commitments by year for each of the next five years are presented in the table below ($ in thousands).
	2014		$	859
	2015			807
	2016			815
	2017			823
	2018			133
	Thereafter			0
	Total		$	3,437
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
	2014		$	7,463
	2015			16,525
	2016			23,654
	2017			29,495
	2018			31,724
	Thereafter			294,571
	Total		$	403,432
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
	(b)	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 12-month period ending December 31.

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Components of Long-Term Debt and Lines of Credit	'
	Long-term debt and other obligations consisted of the following at December 31, 2013 and December 31, 2012:
			December 31,			December 31,
			2013			2012
			(in  thousands)			(in  thousands)
	8.875% Senior Notes		$	350,000		$	250,000
	Premium (Discount) on Senior Notes			3,078			(1,742	)
	Senior Lines of Credit(a)			59,000			0
	Capital Leases and Other Obligations(a)			9,934			2,677
	Total Debt			422,012			250,935
	Less Current Portion of Long-Term Debt			(6,743	)		(1,686	)
	Total Long-Term Debt		$	415,269		$	249,249
	(a)	The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2013 and 2012 was approximately 1.9 % and 2.5%, respectively. The weighted average interest rate on borrowings under the Demand Note and the Equipment Note for the year ended December 31, 2013 was approximately 3.0%. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2013 and 2012 was approximately 5.3% and 4.5%, respectively.
Principal Maturity Schedule for Debt Outstanding	'
	The following is the principal maturity schedule for debt outstanding as of December 31, 2013:
			Year Ended
			December 31,
			(in thousands)
	2014		$	6,743
	2015			1,467
	2016			1,270
	2017			292
	2018			59,162
	Thereafter			350,000
	Total1		$	418,934
	1	Does not include $3.1 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, 2013
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, 2013, 2012 and 2011:
		For the Year Ended December 31,
	In thousands	2013				2012				2011
	Oil	$	(2,798	)		$	1,579			$	(308	)
	Natural Gas		1,807				8,162				19,224
	Natural Gas Liquids		(1,711	)			946				0
	Interest Rate		(206	)			0				0
	Gain (Loss) on Derivatives, Net	$	(2,908	)		$	10,687			$	18,916
Asset or Liability Financial Commodity Derivative Instrument Positions	'
	Our open asset/(liability) financial commodity derivative instrument positions at December 31, 2013 consisted of the following:
	Period	Volume				Sold				Floor			Ceiling		Swap		Basis			Fair Market
						Put Option											Differential			Value
																				($ in Thousands)
	Oil
	2014—Collar		60,000 Bbl			$	0			$	90		$	97.65	$	0	$	0		$	(42	)
	2014—Deferred Put Spread		168,000 Bbl				75				90			0		0		0			(585	)
	2014—Swap		30,000 Bbl				0				0			0		93.75		0			(119	)
	2014—Cap Swap		360,000 Bbl				80.83				0			0		97.72		0			380
	2014—Three Way Collar		372,000 Bbl				76.61				87.6			103.85		0		0			75
			990,000 Bbl																	$	(291	)
	Natural Gas
	2014—Sold Call		1,800,000 Mcf			$	0			$	0		$	5	$	0	$	0		$	(150	)
	2014—Three Way Collar		7,800,000 Mcf				3.32				4.08			4.59		0		0			393
	2014—Swap		4,830,000 Mcf				0				0			0		3.97		0			(1,064	)
	2014—Swaption		2,400,000 Mcf				0				0			0		4.45		0			(717	)
	2014—Cap Swap		3,600,000 Mcf				3.3				0			0		4.09		0			(491	)
	2014—Basis Swap		7,200,000 Mcf				0				0			0		0		(0.36	)		3,984
	2014—Collar		1,800,000 Mcf				0				3.51			4.43		0		0			(235	)
	2015—Swap		1,200,000 Mcf				0				0			0		4.18		0			18
	2015—Cap Swap		2,400,000 Mcf				3.28				0			0		4.1		0			(302	)
	2015—Three Way Collar		2,400,000 Mcf				3.4				4.16			4.63		0		0			169
	2015—Sold Call		2,400,000 Mcf				0				0			4.4		0		0			(761	)
	2015—Basis Swap		600,000 Mcf				0				0			0		0		(0.35	)		339
			38,430,000 Mcf																	$	1,183
	Natural Gas Liquids
	2014—Swap		357,000 Bbl			$	0			$	0		$	0	$	48.49	$	0		$	(912	)
			357,000 Bbl																	$	(912	)
Combined Fair Value of Derivatives	'
	The combined fair value of our derivatives included in our Consolidated Balance Sheets as of December 31, 2013 and December 31, 2012 is summarized below.
		December 31,				December 31,
		2013				2012
		(in thousands)				(in thousands)
	Short-Term Derivative Assets:
	Crude Oil—Cap Swaps	$	380			$	90
	Crude Oil—Three Way Collars		104				0
	Natural Gas Liquids—Swaps		83				535
	Natural Gas—Swaps		106				2,416
	Natural Gas—Swaption		0				354
	Natural Gas—Cap Swap		5				0
	Natural Gas—Basis Swaps		3,984				0
	Natural Gas—Three Way Collars		518				1,021
	Natural Gas Collars		0				4,211
	Natural Gas—Puts		0				3,378
	Interest Rate—Swap		488				0
	Total Short-Term Derivative Assets	$	5,668			$	12,005
	Long-Term Derivative Assets:
	Crude Oil—Collars	$	0			$	0
	Natural Gas—Swaps		22				239
	Natural Gas—Cap Swap		5				0
	Natural Gas—Basis Swap		339				0
	Natural Gas—Collars		0				0
	Natural Gas—Three Way Collars		169				465
	Natural Gas—Puts		0				0
	Total Long-Term Derivative Assets	$	535			$	704
	Total Derivative Assets	$	6,203			$	12,709
	Short-Term Derivative Liabilities:
	Crude Oil—Collars	$	(42	)		$	(307	)
	Crude Oil—Swaps		(119	)			(217	)
	Crude Oil—Three Way Collars		(29	)			(45	)
	Crude Oil—Deferred Put Spread		(585	)			0
	Natural Gas Liquids—Swaps		(995	)			0
	Natural Gas—Three Way Collars		(125	)			(35	)
	Natural Gas—Call		(150	)			0
	Natural Gas—Collars		(235	)			0
	Natural Gas—Cap Swaps		(496	)			0
	Natural Gas—Swaptions		(717	)			0
	Natural Gas—Swaps		(1,170	)			(785	)
	Total Short-Term Derivative Liabilities	$	(4,663	)		$	(1,389	)
	Long-Term Derivative Liabilities:
	Crude Oil—Three Way Collars	$	0			$	(509	)
	Natural Gas—Swaps		(4	)			(434	)
	Natural Gas—Three Way Collars		0				(35	)
	Natural Gas—Cap Swap		(307	)			0
	Natural Gas—Call		(761	)			(366	)
	Natural Gas—Collars		0				(166	)
	Interest Rate—Swap		(693	)			0
	Total Long-Term Derivative Liabilities	$	(1,765	)		$	(1,510	)
	Total Derivative Liabilities	$	(6,428	)		$	(2,899	)
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, 2013 are included in the table below.
	Unobservable Input	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 ($ in thousands):
		Fair Value Measurements at December 31, 2013 Using:
		Total				Quoted Prices				Significant			Significant
		Carrying				in Active				Other			Unobservable
		Value as of				Markets for				Observable			Inputs
		December 31,				Identical				Inputs			(Level 3)
		2013				Assets				(Level 2)
						(Level 1)
	Commodity Derivatives	$	(20	)		$	0			$	(4,343	)	$	4,323
	Interest Rate Swap	$	(205	)		$	0			$	(205	)	$	0
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 12 months ended December 31, 2013 and 2012 (in thousands):
		For the Year Ended December 31,
		2013				2012
	Beginning Balance of Level 3	$	0			$	0
	Changes in Fair Value		4,328				0
	Purchases		0				0
	Settlements Received		(5	)			0
	Ending Balance of Level 3	$	4,323			$	0
Financial Instruments Not Recorded at Fair Value	'
	The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements:
		December 31, 2013								December 31, 2012
	In thousands	Carrying				Fair Value				Carrying			Fair Value
		Amount								Amount
	8.875% Senior Notes	$	350,000			$	385,000			$	250,000		$	249,074
	Secured Lines of Credit		59,000				59,000				0			0
	Capital Leases and Other Obligations		9,934				9,731				2,677			2,524
	Total	$	418,934			$	453,731			$	252,677		$	251,598

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
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)	2013			2012			2011
	Current:
	Federal	$	(1,916	)	$	2,329		$	63
	State		(4,104	)		5,825			244
	Deferred:
	Federal		808			28,216			8,524
	State		1,427			2,179			(561	)
	Income Tax Expense	$	(3,785	)	$	38,549		$	8,270
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,
		2013			2012			2011
	Income before noncontrolling interests and income taxes	$	(5,683	)	$	94,971		$	26,358
	Statutory U.S. income tax rate		35	%		35	%		35	%
	Tax expense recognized using statutory U.S. income tax rate	$	(1,989	)	$	33,240		$	9,225
	Change in estimated future state rate		(484	)		(7	)		612
	Permanent differences		83			52			176
	Change in valuation allowances		(160	)		(131	)		1,031
	Other		(479	)		(493	)		(4,092	)
	Adjusted federal income tax expense (benefit)	$	(3,029	)	$	32,661		$	6,952
	State income tax expense (benefit)		(756	)		5,888			1,318
	Total income tax expense (benefit)	$	(3,785	)	$	38,549		$	8,270
	Effective income tax rate		66.6	%		40.6	%		31.4	%
Components of Deferred Tax Assets (Liabilities)	'
	Deferred tax assets (liabilities) are comprised of the following at December 31, 2013 and 2012:
		For the Years Ended December 31,
	(in thousands)	2013			2012
	Tax effects of temporary differences for:
	Current:
	Assets:
	Asset retirement obligation	$	997		$	0
	Future sale proceeds held in escrow		0			2,947
	Non-cash compensation plans		2,593			714
	Other		370			306
	Total current deferred tax assets		3,960			3,967
	Liabilities:
	Unrealized gain on derivatives		(404	)		(4,365	)
	Other		(105	)		(141	)
	Total current deferred tax liabilities		(509	)		(4,506	)
	Net total current deferred tax asset (liability)	$	3,451		$	(539	)
	Long-Term:
	Assets:
	Asset retirement obligation	$	10,445		$	10,211
	Non-cash compensation plans		1,513			2,090
	Net operating loss carryforward		48,703			4,384
	Organization costs		602			689
	Deferred revenue		1,338			1,487
	AMT credits		292			1,380
	Unrealized loss on derivatives		493			0
	Other		232			593
	Total long-term deferred tax assets		63,618			20,834
	Liabilities:
	Timing differences—tax partnerships		(7,474	)		(5,873	)
	Valuation allowances		(1,965	)		(1,732	)
	Book basis of oil and gas properties in excess of tax basis		(83,594	)		(36,805	)
	Other		(31	)		(49	)
	Total long-term deferred tax liabilities		(93,064	)		(44,459	)
	Net total long-term deferred tax liability	$	(29,446	)	$	(23,625	)
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)
	2023	$	256
	2024		53
	2025		0
	2026		898
	2027		0
	2028		4,179
	2029		798
	2030		803
	2031		19,769
	2032		60
	2033		21,887
	Total		48,703

Earnings_Per_Common_Share_Tabl

Earnings Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2013
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,
			2013			2012			2011
	Numerator (in thousands):
	Net Income (Loss) From Continuing Operations		$	(1,898	)	$	56,422		$	18,088
	Net Loss From Discontinued Operations			(232	)		(10,943	)		(33,457	)
	Net Income (Loss)		$	(2,130	)	$	45,479		$	(15,369	)
	Denominator (in thousands):
	Weighted Average Common Shares Outstanding—Basic			52,572			51,543			43,930
	Effect of Dilutive Securities:
	Employee Stock Options			0			69			95
	Employee Performance-Based Restricted Stock Awards			0			413			451
	Weighted Average Common Shares Outstanding—Diluted			52,572			52,025			44,476
	Earnings per Common Share(a):
	Basic—Net Income (Loss) From Continuing Operations		$	(0.04	)	$	1.09		$	0.41
	—Net Loss From Discontinued Operations			0			(0.21	)		(0.76	)
	—Net Income (Loss)		$	(0.04	)	$	0.88		$	(0.35	)
	Diluted—Net Income (Loss) From Continuing Operations		$	(0.04	)	$	1.08		$	0.41
	—Net Loss From Discontinued Operations			0			(0.21	)		(0.76	)
	—Net Income (Loss)		$	(0.04	)	$	0.87		$	(0.35	)
	(a)	All earnings per share amounts are attributable to Rex common shareholders.

Employee_Benefit_And_Equity_Pl1

Employee Benefit And Equity Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Summary of Stock Option Activity	'
	A summary of the stock option activity is as follows:
		Number of Shares			Weighted		Weighted		Aggregate
					Average Exercise		Average		Intrinsic Value
					Price		Remaining		(in thousands)
							Term (in years)
	Options outstanding December 31, 2010		826,511		$	12.5
	Granted		90,074			12.74
	Exercised		(139,682	)		9.75
	Cancelled/Forfeited		(78,576	)		13.75
	Options Outstanding December 31, 2011		698,327		$	12.94
	Granted		0			0
	Exercised		(52,287	)		10.8
	Cancelled/Forfeited		(143,787	)		20.71
	Options Outstanding December 31, 2012		502,253		$	10.95
	Granted		0			0
	Exercised		(49,166	)		10.85
	Cancelled/Forfeited		(4,000	)		23.28
	Options Outstanding December 31, 2013		449,087		$	10.85		3.9	$	4,060
	Options Exercisable December 31, 2013		397,921		$	10.55		4.1	$	3,725
Summary of Issued and Outstanding Stock Options	'
	A summary of the status of our issued and outstanding stock options as of December 31, 2013 is as follows:
		Outstanding							Exercisable
	Exercise	Number			Weighted		Weighted		Number		Weighted
	Price	Outstanding			Average		Average		Exercisable at		Average
		at 12/31/13			Remaining		Exercise		12/31/13		Exercise
					Contractual		Price				Price
					Life (Years)
	$5.04		46,041			5.4	$	5.04		46,041	$	5.04
	$9.50		85,000			3.9	$	9.5		85,000	$	9.5
	$9.99		167,333			3.9	$	9.99		167,333	$	9.99
	$10.42		29,548			6.5	$	10.42		29,548	$	10.42
	$11.87		3,500			2.3	$	11.87		2,333	$	11.87
	$12.50		19,139			1.9	$	12.5		19,139	$	12.5
	$13.01		18,526			1.8	$	13.01		18,526	$	13.01
	$13.19		50,000			2.8	$	13.19		0	$	0
	$22.34		30,000			4.3	$	22.34		30,000	$	22.34
	Total		449,087			3.9	$	10.85		397,920	$	10.55
Percentage of Awards to Vest	'
	The number of shares ultimately awarded will correspond with the final TSR rank amongst the peer group in accordance with the following schedule:
	TSR Rank	Percentage
		of 2013 Awards
		to Vest
	1 – 3		100	%
	4 – 6		75	%
	7 – 10		50	%
	11 – 13		25	%
	14 – 16		0	%
	TSR Rank	Percentage
		of 2012 Awards
		to Vest
	1 – 3		100	%
	4 – 5		75	%
	6 – 8		50	%
	9 – 11		25	%
	12 – 14		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,		December 31,
		2013		2012
	Expected Dividend Yield	0.00%		0.00%
	Risk-Free Interest Rate	0.70%		0.30%
	Expected Volatility—Rex Energy	50.50%		54.40%
	Expected Volatility—Peer Group	28.4% - 63.5%		31.2% - 58.6%
	Market Index	35.30%		37.00%
	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, 2013, 2012 and 2011 is as follows:
		Number of			Weighted-
		Shares			Average  Grant
					Date Fair
					Value
	Restricted stock awards, as of January 1, 2011		814,965		$	11.01
	Awards		757,816			13.07
	Forfeitures		(342,955	)		11.6
	Restricted stock awards, as of December 31, 2011		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

Suspended_Exploratory_Well_Cos1

Suspended Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013, 2012 and 2011 ($ in thousands):
		2013			2012			2011
	Beginning Balance at January 1,	$	36,968		$	11,756		$	1,637
	Additions to capitalized exploratory well costs pending the determination of estimated proved reserves		171,087			95,980			106,045
	Divested wells		0			0			0
	Reclassification of wells, facilities, and equipment based on the determination of estimated proved reserves		(202,323	)		(70,518	)		(95,926	)
	Capitalized exploratory well costs charged to expense		(1	)		(250	)		0
	Ending Balance at December 31,		5,731			36,968			11,756
	Less exploratory well costs that have been capitalized for a period of one year or less		(3,597	)		(36,630	)		(11,756	)
	Capitalized exploratory well costs for a period of greater than one year	$	2,134		$	338		$	0
	Number of projects that have exploratory well costs capitalized for a period of more than one year		3			2			0

Costs_Incurred_In_Oil_And_Natu1

Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities (Tables)	12 Months Ended
	Dec. 31, 2013
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):
			2013			2012			2011
	Consolidated Entities:
	Acquisition of Properties
	Proved		$	2,445		$	1,474		$	9
	Unproved			39,291			49,331			76,852
	Exploration Costs(a)			231,112			128,748			113,075
	Development Costs(a)			64,661			57,149			61,920
	Subtotal			337,509			236,702			251,856
	Asset Retirement Obligations			3,031			4,480			316
	Total Costs Incurred		$	340,540		$	241,182		$	252,172
	Share of Equity Method Investments:
	Acquisition of Properties
	Proved		$	0		$	0		$	0
	Unproved			0			0			0
	Exploration Costs			0			0			0
	Development Costs(a)			1,958			4,316			12,682
	Total		$	1,958		$	4,316		$	12,682
	(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):
			2013			2012			2011
	Total Costs Incurred by Consolidated Entities		$	340,540		$	241,182		$	252,172
	Equity Method Investments			2,493			4,087			23,204
	DJ Basin Expenditures			2			3,146			24,029
	Exploration Expense			(11,408	)		(4,782	)		(2,507	)
	Asset Retirement Obligations			(3,031	)		(4,480	)		(316	)
	Depreciation for Support Equipment and Facilities			(5,024	)		(4,187	)		(3,308	)
	Corporate Expenditures			3,651			1,156			1,126
	Other(a)			10,391			2,732			8,016
	Total Capital Expenditures		$	337,614		$	238,854		$	302,416
	(a)	Represents corporate capital, 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, 2013
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):
		2013			2012
	Consolidated Entities:
	Proven Oil and Natural Gas Properties	$	749,680		$	485,448
	Pipelines and Support Equipment		33,119			31,231
	Field Operation Vehicles and Other Equipment		21,608			13,412
	Wells and Facilities in Progress		69,886			87,800
	Unproven Properties		189,385			165,503
	Total		1,063,678			783,394
	Less Accumulated Depreciation and Depletion		(184,836	)		(141,769	)
	Total	$	878,842		$	641,625
	Share of Equity Method Investments:
	Pipelines and Support Equipment	$	19,270		$	17,524
	Field Operation Vehicles and Other Equipment		0			0
	Wells and Facilities in Progress		238			26
	Total		19,508			17,550
	Less Accumulated Depreciation and Depletion		(1,818	)		(1,077	)
	Total	$	17,690		$	16,473

Oil_and_Natural_Gas_Reserve_Qu1

Oil and Natural Gas Reserve Quantities (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013, 2012 and 2011.
			2013
			Oil			NGLs			Natural Gas			MMcf
			(MBbls)			(MBbls)			(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			(438.5	)		(4,685.6	)		(16,137.7	)		(46,882.3	)
	Purchases			1			0			0			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			NGLs			Natural Gas			MMcf
			(MBbls)			(MBbls)			(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			650.5			12,089.50			(1,413.6	)		75,026.40
	Improved Recovery			758.3			0			0			4,549.80
	Purchases			43.2			0			0			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
			2011
			Oil			NGLs			Natural Gas			MMcf
			(MBbls)			(MBbls)			(MMcf)			Equivalents
	Estimated Proved Reserves—Beginning of Period			8,142.80			4,200.00			127,621.90			201,678.70
	Extensions, Discoveries and Additions			156.5			2,640.40			139,067.70			155,849.10
	Revisions(a)			576.4			484.6			16,515.00			22,881.00
	Production(b)			(694.5	)		(190.2	)		(8,912.3	)		(14,220.5	)
	Estimated Proved Reserves—End of Period			8,181.20			7,134.80			274,292.30			366,188.30
	(a)	Revisions includes 120.9 MBbls and 725.4 MMcfe related to our successful ASP pilot in the Illinois Basin.
	(b)	Gas production excludes certain production associated with gas sales contracts for which we do not recognize reserves.
			Oil			NGLs			Natural Gas			Mcf
			(MBbls)			(MBbls)			(MMcf)			Equivalents
	Proved Developed Reserves
	December 31, 2013			7,742.50			16,322.50			212,061.40			356,451.40
	December 31, 2012			9,216.10			10,143.70			141,754.60			257,913.40
	December 31, 2011			8,181.20			2,218.40			110,853.30			173,250.90
	Proved Undeveloped Reserves
	December 31, 2013			877.1			29,808.20			309,221.40			493,333.20
	December 31, 2012			159.6			21,536.20			229,961.80			360,136.60
	December 31, 2011			0			4,916.40			163,439.00			192,937.40

Standardized_Measure_Of_Discou1

Standardized Measure Of Discounted Future Net Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013, 2012 and 2011 ($ in thousands):
			2013			2012			2011
	Future Cash Inflows		$	3,899,878	(a)	$	2,988,231	(b)	$	2,333,513	(c)
	Future Costs:
	Production			(1,619,629	)		(1,387,653	)		(880,077	)
	Abandonment			(95,183	)		(85,859	)		(65,560	)
	Development			(517,875	)		(324,873	)		(251,821	)
	Net Future Cash Inflow Before Income Taxes			1,667,191			1,189,846			1,136,055
	Future Income Tax Expense			(359,322	)		(245,078	)		(277,568	)
	Total Future Net Cash Flows Before 10.0% Discount			1,307,869			944,768			858,487
	Less: Effect of a 10.0% Discount Factor			(778,756	)		(548,645	)		(444,552	)
	Standardized Measure of Discounted Future Net Cash Flows		$	529,113		$	396,123		$	413,935
	(a)	Calculated using weighted average prices of $3.588 per Mcf, $94.28 per barrel of oil and $26.37 per barrel of NGLs
	(b)	Calculated using weighted average prices of $2.94 per Mcf, $90.92 per barrel of oil and $32.91 per barrel of NGLs
	(c)	Calculated using weighted average prices of $4.55 per Mcf, $92.45 per barrel of oil and $46.34 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:
			2013			2012			2011
	Standardized Measure—Beginning of Period		$	396,123		$	413,935		$	188,065
	Revisions of Previous Estimates:
	Changes in Prices and Production Costs			72,503			(198,433	)		29,223
	Revisions in Quantities			(51,289	)		91,462			40,525
	Changes in Future Development Costs			22,341			(3,885	)		(19,539	)
	Accretion of Discount and Timing of Future Cash Flows			47,571			52,093			25,218
	Net Change in Income Tax			31,433			27,405			(42,875	)
	Purchase (Sale) of Reserves in Place			0			1,188			0
	Plus Extensions, Discoveries, and Other Additions			170,846			88,749			159,047
	Development Costs Incurred			64,661			57,149			61,290
	Sales of Product—Net of Production Costs			(151,781	)		(86,936	)		(78,763	)
	Changes in Timing and Other			(73,295	)		(46,604	)		51,744
	Standardized Measure—End of Period		$	529,113		$	396,123		$	413,935

Results_Of_Operations_For_Oil_1

Results Of Operations For Oil And Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2013
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):
			2013			2012			2011
	Consolidated Entities (in thousands):
	Revenues
	Oil and Natural Gas Sales		$	213,919		$	134,574		$	111,879
	Expenses
	Production and Lease Operating Expense			62,138			47,638			33,116
	Impairment Expense			32,072			20,505			14,316
	Exploration Expense			11,408			4,782			2,507
	Depletion, Depreciation, Amortization and Accretion			62,386			44,955			27,670
	Total Costs			168,004			117,880			77,609
	Pre-Tax Operating Income (Loss)			45,915			16,694			34,270
	Income Tax Expense(a)			30,579			6,778			10,760
	Results of Operations for Oil and Gas Producing Activities		$	15,336		$	9,916		$	23,510
	Share of Equity Method Investments (in thousands):
	Expenses
	Depletion, Depreciation, Amortization and Accretion		$	752		$	1,082		$	1,568
	Total Costs			752			1,082			1,568
	Pre-Tax Operating Loss			(752	)		(1,082	)		(1,568	)
	Income Tax Benefit (a)			501			435			519
	Results of Operations for Oil and Gas Producing Activities		$	(251	)	$	(647	)	$	(1,049	)
	Total Consolidated and Equity Method Investees Results of Operations for Oil and Gas Producing Activities		$	15,085		$	9,269		$	22,461
	(a)	Computed using the effective rate for continuing operations for each period: 66.6% in 2013; 40.6% in 2012 and; 31.4% in 2011.

Selected_Quarterly_Financial_D1

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2013
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)
		2013
		March			June			September			December
	Revenues	$	47,470		$	55,360		$	62,974		$	72,127
	Costs and Expenses		49,810			41,919			61,142			85,401
	Net Income (Loss) From Continuing Operations		(2,340	)		13,441			1,832			(13,274	)
	Net Loss From Discontinued Operations		(61	)		520			0			(691	)
	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 Common Shareholders:
	Basic—Continuing Operations Attributable to Rex Energy	$	(0.05	)	$	0.25		$	0.03		$	(0.26	)
	Basic—Discontinued Operations		0			0.01			0			(0.01	)
	Basic—Net Income (Loss)	$	(0.05	)	$	0.26		$	0.03		$	(0.27	)
	Basic—Weighted Average Shares Outstanding		52,367			52,555			52,626			52,705
	Diluted—Continuing Operations Attributable to Rex Energy	$	(0.05	)	$	0.25		$	0.03		$	(0.26	)
	Diluted—Discontinued Operations		0			0.01			0			(0.01	)
	Diluted—Net Income (Loss)	$	(0.05	)	$	0.26		$	0.03		$	(0.27	)
	Diluted—Weighted Average Shares Outstanding		52,367			52,911			53,293			52,705
		2012
		March			June			September			December
	Revenues	$	33,834		$	30,257		$	38,929		$	45,119
	Costs and Expenses		30,006			(25,936	)		40,671			46,157
	Net Income (Loss) From Continuing Operations		3,828			56,193			(1,742	)		(1,038	)
	Net Loss From Discontinued Operations		(5,355	)		(3,050	)		(258	)		(2,280	)
	Net Income (Loss)		(1,527	)		53,143			(2,000	)		(3,318	)
	Net Income (Loss) Attributable to Noncontrolling Interests		101			222			193			303
	Net Income (Loss) Attributable to Rex Energy	$	(1,628	)	$	52,921		$	(2,193	)	$	(3,621	)
	Income (Loss) per Common Share Attributable to Rex Common Shareholders:
	Basic—Continuing Operations Attributable to Rex Energy	$	0.08		$	1.08		$	(0.04	)	$	(0.03	)
	Basic—Discontinued Operations		(0.11	)		(0.06	)		0			(0.04	)
	Basic—Net Income (Loss)	$	(0.03	)	$	1.02		$	(0.04	)	$	(0.07	)
	Basic—Weighted Average Shares Outstanding		48,744			52,009			52,036			52,278
	Diluted—Continuing Operations Attributable to Rex Energy	$	0.08		$	1.06		$	(0.04	)	$	(0.03	)
	Diluted—Discontinued Operations		(0.11	)		(0.06	)		0			(0.04	)
	Diluted—Net Income (Loss)	$	(0.03	)	$	1		$	(0.04	)	$	(0.07	)
	Diluted—Weighted Average Shares Outstanding		49,693			52,876			52,036			52,278

Condensed_Consolidating_Financ1

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2013
Condensed Consolidating Balance Sheets	'
	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-			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Guarantor			Corporation						Balance
					Subsidiaries			(Note Issuer)
	ASSETS
	Current Assets
	Cash and Cash Equivalents	$	1,386		$	509		$	5		$	0		$	1,900
	Accounts Receivable		32,283			9,882			0			(3,302	)		38,863
	Taxes Receivable		0			0			5,189			0			5,189
	Short-Term Derivative Instruments		5,180			0			488			0			5,668
	Current Deferred Tax Asset		0			0			3,451			0			3,451
	Inventory, Prepaid Expenses and Other		2,092			89			26			0			2,207
	Total Current Assets		40,941			10,480			9,159			(3,302	)		57,278
	Property and Equipment (Successful Efforts Method)
	Evaluated Oil and Gas Properties		752,781			0			0			(3,101	)		749,680
	Unevaluated Oil and Gas Properties		189,385			0			0			0			189,385
	Other Property and Equipment		57,409			12,706			0			0			70,115
	Wells and Facilities in Progress		70,759			6,576			0			(790	)		76,545
	Pipelines		7,678			0			0			0			7,678
	Total Property and Equipment		1,078,012			19,282			0			(3,891	)		1,093,403
	Less: Accumulated Depreciation, Depletion and Amortization		(188,699	)		(2,172	)		0			350			(190,521	)
	Net Property and Equipment		889,313			17,110			0			(3,541	)		902,882
	Deferred Financing Costs and Other Assets—Net		2,421			206			9,366			0			11,993
	Equity Method Investments		18,708			0			0			0			18,708
	Intercompany Receivables		0			0			628,517			(628,517	)		0
	Investment in Subsidiaries—Net		4,442			1,197			216,945			(222,584	)		0
	Long-Term Derivative Instruments		535			0			0			0			535
	Total Assets	$	956,360		$	28,993		$	863,987		$	(857,944	)	$	991,396
	LIABILITIES AND STOCKHOLDERS’ EQUITY
	Current Liabilities
	Accounts Payable	$	33,613		$	794		$	0		$	(3,304	)	$	31,103
	Current Maturities of Long-Term Debt		1,339			5,404			0			0			6,743
	Accrued Liabilities		45,196			6,287			2,967			0			54,450
	Short-Term Derivative Instruments		4,663			0			0			0			4,663
	Total Current Liabilities		84,811			12,485			2,967			(3,304	)		96,959
	8.875% Senior Notes Due 2020		0			0			350,000			0			350,000
	Premium (Discount) on Senior Notes		0			0			3,078			0			3,078
	Senior Secured Line of Credit and Long-Term Debt		137			3,054			59,000			0			62,191
	Long-Term Derivative Instruments		1,071			0			694			0			1,765
	Long-Term Deferred Tax Liability		0			0			29,446			0			29,446
	Other Deposits and Liabilities		4,992			0			0			0			4,992
	Future Abandonment Cost		26,027			13			0			0			26,040
	Intercompany Payables		554,329			74,188			0			(628,517	)		0
	Total Liabilities		671,367			89,740			445,185			(631,821	)		574,471
	Stockholders’ Equity
	Common Stock		0			0			54			0			54
	Additional Paid-In Capital		177,144			6,488			456,554			(183,632	)		456,554
	Accumulated 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		0			485			0			1,557			2,042
	Total Stockholders’ Equity		284,993			(60,747	)		418,802			(226,123	)		416,925
	Total Liabilities and Stockholders’ Equity	$	956,360		$	28,993		$	863,987		$	(857,944	)	$	991,396
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING BALANCE SHEETS
	FOR THE YEAR ENDED DECEMBER 31, 2012
	($ in Thousands, Except Share and Per Share Data)
		Guarantor			Non-			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Guarantor			Corporation						Balance
					Subsidiaries			(Note Issuer)
	ASSETS
Current Assets
Cash and Cash Equivalents	$	4,227		$	824		$	38,924		$	0		$	43,975
Accounts Receivable		26,490			3,367			0			(4,877	)		24,980
Taxes Receivable		0			0			6,429			0			6,429
Short-Term Derivative Instruments		12,005			0			0			0			12,005
Assets Held For Sale		0			2,279			0			0			2,279
Inventory, Prepaid Expenses and Other		1,277			13			26			0			1,316
Total Current Assets		43,999			6,483			45,379			(4,877	)		90,984
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		486,706			0			0			(1,258	)		485,448
Unevaluated Oil and Gas Properties		165,503			0			0			0			165,503
Other Property and Equipment		45,613			4,455			0			5			50,073
Wells and Facilities in Progress		88,204			4,780			0			(71	)		92,913
Pipelines		6,116			0			0			0			6,116
Total Property and Equipment		792,142			9,235			0			(1,324	)		800,053
Less: Accumulated Depreciation, Depletion and Amortization		(145,514	)		(674	)		0			150			(146,038	)
Net Property and Equipment		646,628			8,561			0			(1,174	)		654,015
Deferred Financing Costs and Other Assets—Net		2,427			199			7,403			0			10,029
Equity Method Investments		16,978			0			0			0			16,978
Intercompany Receivables		3,795			0			440,269			(444,064	)		0
Investment in Subsidiaries—Net		(227	)		(232	)		193,790			(193,331	)		0
Long-Term Derivative Instruments		704			0			0			0			704
Total Assets	$	714,304		$	15,011		$	686,841		$	(643,446	)	$	772,710
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	29,230		$	462		$	0		$	(244	)	$	29,448
Current Maturities of Long-Term Debt		588			1,098			0			0			1,686
Accrued Liabilities		20,489			1,036			1,494			0			23,019
Short-Term Derivative Instruments		1,389			0			0			0			1,389
Current Deferred Tax Liability		0			0			539			0			539
Liabilities Related to Assets Held For Sale		0			52			0			0			52
Total Current Liabilities		51,696			2,648			2,033			(244	)		56,133
8.875% Senior Notes Due 2020		0			0			250,000			0			250,000
Discount on Senior Notes		0			0			(1,742	)		0			(1,742	)
Senior Secured Line of Credit and Long-Term Debt		26			5,598			0			(4,633	)		991
Long-Term Derivative Instruments		1,510			0			0			0			1,510
Long-Term Deferred Tax Liability		0			0			23,625			0			23,625
Other Deposits and Liabilities		5,675			0			0			0			5,675
Future Abandonment Cost		24,224			0			0			0			24,224
Intercompany Payables		367,704			76,360			0			(444,064	)		0
Total Liabilities		450,835			84,606			273,916			(448,941	)		360,416
Stockholders’ Equity
Common Stock		0			0			52			0			52
Additional Paid-In Capital		177,143			(407	)		451,062			(176,736	)		451,062
Accumulated Deficit		86,326			(69,144	)		(38,189	)		(18,588	)		(39,595	)
Rex Energy Stockholders’ Equity		263,469			(69,551	)		412,925			(195,324	)		411,519
Noncontrolling Interests		0			(44	)		0			819			775
Total Stockholders’ Equity		263,469			(69,595	)		412,925			(194,505	)		412,294
Total Liabilities and Stockholders’ Equity	$	714,304		$	15,011		$	686,841		$	(643,446	)	$	772,710
Condensed Consolidating Statement of Operations	'
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
	FOR THE YEAR ENDED DECEMBER 31, 2013
	($ in Thousands)
		Guarantor			Non-			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Guarantor			Corporation						Balance
					Subsidiaries			(Note Issuer)
	OPERATING REVENUE
	Oil, Natural Gas and NGL Sales	$	213,919		$	0		$	0		$	0		$	213,919
	Field Services Revenue		0			32,583			0			(8,771	)		23,812
	Other Revenue		200			0			0			0			200
	TOTAL OPERATING REVENUE		214,119			32,583			0			(8,771	)		237,931
	OPERATING EXPENSES
	Production and Lease Operating Expense		62,138			0			0			0			62,138
	General and Administrative Expense		25,376			2,416			5,420			(86	)		33,126
	Loss on Disposal of Asset		1,601			46			0			0			1,647
	Impairment Expense		32,072			0			0			0			32,072
	Exploration Expense		11,395			13			0			0			11,408
	Depreciation, Depletion, Amortization and Accretion		62,540			1,604			0			(200	)		63,944
	Field Services Operating Expense		0			23,527			0			(6,197	)		17,330
	Other Operating Expense		592			0			0			0			592
	TOTAL OPERATING EXPENSES		195,714			27,606			5,420			(6,483	)		222,257
	INCOME (LOSS) FROM OPERATIONS		18,405			4,977			(5,420	)		(2,288	)		15,674
	OTHER INCOME (EXPENSE)
	Interest Expense		(64	)		(106	)		(22,612	)		0			(22,782	)
	Loss on Derivatives, Net		(2,703	)		0			(205	)		0			(2,908	)
	Other Income		6,739			0			0			(86	)		6,653
	Loss From Equity Method Investments		(763	)		0			0			0			(763	)
	Income (Loss) From Equity in Consolidated Subsidiaries		(33	)		33			5,703			(5,703	)		0
	TOTAL OTHER INCOME (LOSS)		3,176			(73	)		(17,114	)		(5,789	)		(19,800	)
	INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		21,581			4,904			(22,534	)		(8,077	)		(4,126	)
	Income Tax (Expense) Benefit		(14,409	)		(2,210	)		20,404			0			3,785
	INCOME (LOSS) FROM CONTINUING OPERATIONS		7,172			2,694			(2,130	)		(8,077	)		(341	)
	Loss From Discontinued Operations, Net of Income Taxes		0			(232	)		0			0			(232	)
	NET INCOME (LOSS)		7,172			2,462			(2,130	)		(8,077	)		(573	)
	Net Income Attributable to Noncontrolling Interests		0			1,557			0			0			1,557
	NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	7,172		$	905		$	(2,130	)	$	(8,077	)	$	(2,130	)
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
	FOR THE YEAR ENDED DECEMBER 31, 2012
	($ in Thousands)
		Guarantor			Non-			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Guarantor			Corporation						Balance
					Subsidiaries			(Note Issuer)
	OPERATING REVENUE
	Oil, Natural Gas and NGL Sales	$	134,574		$	0		$	0		$	0		$	134,574
	Field Services Revenue		0			15,637			0			(2,234	)		13,403
	Other Revenue		218			0			0			(56	)		162
	TOTAL OPERATING REVENUE		134,792			15,637			0			(2,290	)		148,139
	OPERATING EXPENSES
	Production and Lease Operating Expense		47,618			20			0			0			47,638
	General and Administrative Expense		19,283			1,007			3,159			(104	)		23,345
	Loss on Disposal of Asset		50			8			0			0			58
	Impairment Expense		20,505			80			0			0			20,585
	Exploration Expense		4,782			0			0			0			4,782
	Depreciation, Depletion, Amortization and Accretion		44,993			527			0			(83	)		45,437
	Field Services Operating Expense		0			9,859			0			(1,619	)		8,240
	Other Operating Expense		1,136			0			0			0			1,136
	TOTAL OPERATING EXPENSES		138,367			11,501			3,159			(1,806	)		151,221
	INCOME (LOSS) FROM OPERATIONS		(3,575	)		4,136			(3,159	)		(484	)		(3,082	)
	OTHER INCOME (EXPENSE)
	Interest Expense		(55	)		(26	)		(6,362	)		0			(6,443	)
	Gain on Derivatives, Net		10,687			0			0			0			10,687
Other Income (Expense)		99,575			0			(922	)		(104	)		98,549
Loss From Equity Method Investments		(3,921	)		0			0			0			(3,921	)
Income (Loss) From Equity in Consolidated Subsidiaries		(68	)		68			51,363			(51,363	)		0
TOTAL OTHER INCOME (LOSS)		106,218			42			44,079			(51,467	)		98,872
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		102,643			4,178			40,920			(51,951	)		95,790
Income Tax (Expense) Benefit		(41,772	)		(1,336	)		4,559			0			(38,549	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		60,871			2,842			45,479			(51,951	)		57,241
Loss From Discontinued Operations, Net of Income Taxes		0			(10,943	)		0			0			(10,943	)
NET INCOME (LOSS)		60,871			(8,101	)		45,479			(51,951	)		46,298
Net Income Attributable to Noncontrolling Interests		0			819			0			0			819
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	60,871		$	(8,920	)	$	45,479		$	(51,951	)	$	45,479
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2011
($ in Thousands)
	Guarantor			Non-			Rex Energy			Eliminations			Consolidated
	Subsidiaries			Guarantor			Corporation						Balance
				Subsidiaries			(Note Issuer)
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	111,879		$	0		$	0		$	0		$	111,879
Field Services Revenue		0			3,546			0			(1,028	)		2,518
Other Revenue		209			0			0			0			209
TOTAL OPERATING REVENUE		112,088			3,546			0			(1,028	)		114,606
OPERATING EXPENSES
Production and Lease Operating Expense		33,106			10			0			0			33,116
General and Administrative Expense		21,424			586			1,662			(36	)		23,636
Loss on Disposal of Asset		353			149			0			0			502
Impairment Expense		14,316			315			0			0			14,631
Exploration Expense		2,507			0			0			0			2,507
Depreciation, Depletion, Amortization and Accretion		27,672			231			0			(47	)		27,856
Field Services Operating Expense		0			2,470			0			(720	)		1,750
Other Operating Expense		819			0			0			0			819
TOTAL OPERATING EXPENSES		100,197			3,761			1,662			(803	)		104,817
INCOME (LOSS) FROM OPERATIONS		11,891			(215	)		(1,662	)		(225	)		9,789
OTHER INCOME (EXPENSE)
Interest Expense		(107	)		(2	)		(2,405	)		0			(2,514	)
Gain on Derivatives, Net		18,916			0			0			0			18,916
Other Income (Expense)		13			101			0			(35	)		79
Income From Equity Method Investments		81			0			0			0			81
Income (Loss) From Equity in Consolidated Subsidiaries		(53	)		53			(12,925	)		12,925			0
TOTAL OTHER INCOME (LOSS)		18,850			152			(15,330	)		12,890			16,562
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		30,741			(63	)		(16,992	)		12,665			26,351
Income Tax (Expense) Benefit		(9,927	)		33			1,624			0			(8,270	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		20,814			(30	)		(15,368	)		12,665			18,081
Loss From Discontinued Operations, Net of Income Taxes		0			(33,457	)		0			0			(33,457	)
NET INCOME (LOSS)		20,814			(33,487	)		(15,368	)		12,665			(15,376	)
Net Loss Attributable to Noncontrolling Interests		0			(7	)		0			0			(7	)
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	20,814		$	(33,480	)	$	(15,368	)	$	12,665		$	(15,369	)
Condensed Consolidated Statement of Cash Flows	'
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
	FOR THE YEAR ENDING DECEMBER 31, 2013
	($ in Thousands)
		Guarantor			Non-			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Guarantor			Corporation						Balance
					Subsidiaries			(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 From Equity Method Investments		763			0			0			0			763
	Non-Cash Expenses		(194	)		55			6,369			0			6,230
	Depreciation, Depletion, Amortization and Accretion		62,540			1,604			0			(200	)		63,944
	Deferred Income Tax Expense (Benefit)		14,409			2,210			(14,340	)		0			2,279
	Loss on Derivatives		2,703			0			205			0			2,908
	Cash Settlement of Derivatives		7,128			0			0			0			7,128
	Dry Hole Expense		2,993			0			0			0			2,993
	Gain on Sale of Assets and Equity Method Investments		(5,289	)		(922	)		0			0			(6,211	)
	Impairment Expense		32,072			0			0			0			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	)		0			0			(885	)
	Accounts Payable and Accrued Liabilities		8,554			874			1,481			1,982			12,891
	Other Assets and Liabilities		(2,272	)		(88	)		(137	)		0			(2,497	)
	NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		123,876			(379	)		(7,311	)		(7,870	)		108,316
	CASH FLOWS FROM INVESTING ACTIVITIES
	Intercompany loans to subsidiaries		186,089			1,619			(193,015	)		5,307			0
	Proceeds from Joint Venture Leasing Initiatives		458			0			0			0			458
	Contributions to Equity Method Investments		(2,493	)		0			0			0			(2,493	)
	Proceeds from the Sale of Assets and Equity Method Investments		8,071			3,234			0			0			11,305
	Acquisitions of Undeveloped Acreage		(41,782	)		(2	)		0			0			(41,784	)
	Capital Expenditures for Development of Oil and Gas Properties and Equipment		(275,697	)		(7,870	)		0			2,563			(281,004	)
	NET CASH USED IN INVESTING ACTIVITIES		(125,354	)		(3,019	)		(193,015	)		7,870			(313,518	)
	CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from Long-Term Debt and Lines of Credit		0			7,249			65,000			0			72,249
	Repayments of Long-Term Debt and Lines of Credit		0			(2,480	)		(6,000	)		0			(8,480	)
	Repayments of Loans and Other Notes Payable		(1,363	)		(642	)		0			0			(2,005	)
	Proceeds from 8.875% Senior Notes, net of Discount		0			0			105,000			0			105,000
	Debt Issuance Costs		0			(8	)		(3,126	)		0			(3,134	)
	Proceeds from the Exercise of Stock Options		0			0			533			0			533
	Capital Distributions by the Partners of Consolidated Joint Ventures		0			(886	)		0			0			(886	)
	Purchase of Noncontrolling Interests		0			(150	)		0			0			(150	)
	NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(1,363	)		3,083			161,407			0			163,127
	NET INCREASE (DECREASE) IN CASH		(2,841	)		(315	)		(38,919	)		0			(42,075	)
	CASH—BEGINNING		4,227			824			38,924			0			43,975
	CASH—ENDING	$	1,386		$	509		$	5		$	0		$	1,900
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
	FOR THE YEAR ENDING DECEMBER 31, 2012
	($ in Thousands)
		Guarantor			Non-			Rex Energy			Eliminations			Consolidated
		Subsidiaries			Guarantor			Corporation						Balance
					Subsidiaries			(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 From Equity Method Investments		3,921			0			0			0			3,921
	Non-Cash Expenses		33			14			3,144			0			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	)		0			23,665
	Gain on Derivatives		(10,687	)		0			0			0			(10,687	)
	Cash Settlement of Derivatives		16,219			0			0			0			16,219
	Dry Hole Expense		320			336			0			0			656
(Gain) Loss on Sale of Assets and Equity Method Investments		(99,355	)		(2,118	)		922			0			(100,551	)
Impairment Expense		20,505			19,850			0			0			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			0			(92	)
Accounts Payable and Accrued Liabilities		(8,875	)		(766	)		916			(107	)		(8,832	)
Other Assets and Liabilities		(1,146	)		(64	)		0			29			(1,181	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		91,600			(1,178	)		7,596			(52,313	)		45,705
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		2,915			1,931			(56,489	)		51,643			0
Proceeds from Joint Venture Leasing Initiatives		260			0			0			0			260
Contributions to Equity Method Investments		0			(4,087	)		0			0			(4,087	)
Proceeds from the Sale of Assets and Equity Method Investments		128,554			4,871			0			0			133,425
Acquisitions of Undeveloped Acreage		(51,783	)		(19	)		0			0			(51,802	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(177,892	)		(1,316	)		0			670			(178,538	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(97,946	)		1,380			(56,489	)		52,313			(100,742	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		0			730			126,000			0			126,730
Repayments of Long-Term Debt and Lines of Credit		0			0			(351,000	)		0			(351,000	)
Repayments of Loans and Other Notes Payable		(764	)		(198	)		0			0			(962	)
Proceeds from 8.875% Senior Notes, net of Discount		0			0			248,250			0			248,250
Debt Issuance Costs		0			0			(6,397	)		0			(6,397	)
Settlement of Tax Withholdings Related to Share-Based Compensation Awards		0			0			(234	)		0			(234	)
Proceeds from the Issuance of Common Stock, Net of Issuance Costs		0			0			70,583			0			70,583
Proceeds from the Exercise of Stock Options		0			0			565			0			565
Capital Distributions by the Partners of Consolidated Joint Ventures		0			(319	)		0			0			(319	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(764	)		213			87,767			0			87,216
NET INCREASE (DECREASE) IN CASH		(7,110	)		415			38,874			0			32,179
CASH—BEGINNING		11,337			409			50			0			11,796
CASH—ENDING	$	4,227		$	824		$	38,924		$	0		$	43,975
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDING DECEMBER 31, 2011
($ in Thousands)
	Guarantor			Non-			Rex Energy			Eliminations			Consolidated
	Subsidiaries			Guarantor			Corporation						Balance
				Subsidiaries			(Note Issuer)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	20,814		$	(33,487	)	$	(15,368	)	$	12,665		$	(15,376	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
(Gain) Loss From Equity Method Investments		(81	)		0			0			0			(81	)
Non-Cash Expenses		118			2			1,625			0			1,745
Depreciation, Depletion, Amortization and Accretion		27,672			316			505			(47	)		28,446
Deferred Income Tax Expense (Benefit)		(10,234	)		1,271			1,624			0			(7,339	)
(Gain) Loss on Derivatives		(18,916	)		0			0			0			(18,916	)
Cash Settlements of Derivatives		6,212			0			0			0			6,212
Dry Hole Expense		6			32,763			0			0			32,769
(Gain) Loss on Sale of Assets and Equity Method Investments		353			149			0			0			502
Impairment Expense		14,316			13,492			0			0			27.808
Changes in operating assets and liabilities
Accounts Receivable		188,899			29,099			(211,952	)		5,072			11,118
Inventory, Prepaid Expenses and Other Assets		157			(56	)		(15	)		0			86
Accounts Payable and Accrued Liabilities		859			(3,124	)		405			(136	)		(1,996	)
Other Assets and Liabilities		(1,473	)		961			0			41			(471	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		228,702			41,386			(223,176	)		17,595			64,507
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		(2,337	)		10,811			9,121			(17,595	)		0
Proceeds from Joint Venture Leasing Initiatives		3,209			0			0			0			3,209
Change in Restricted Cash		16,086			0			0			0			16,086
Contributions to Equity Method Investments		0			(23,204	)		0			0			(23,204	)
Proceeds from the Sale of Assets and Equity Method Investments		2,293			436			0			0			2,729
Acquisitions of Undeveloped Acreage		(76,698	)		(1,871	)		0			0			(78,569	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(169,689	)		(27,444	)		308			0			(196,825	)
NET CASH USED IN INVESTING ACTIVITIES		(227,136	)		(41,272	)		9,429			(17,595	)		(276,574	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		0			0			240,000			0			240,000
Repayments of Long-Term Debt and Lines of Credit		0			0			(25,000	)		0			(25,000	)
Repayments of Loans and Other Notes Payable		(831	)		(48	)		0			0			(879	)
Proceeds from 8.875% Senior Notes, net of Discount		0			0			0			0			0
Debt Issuance Costs		0			0			(2,615	)		0			(2,615	)
Proceeds from the Exercise of Stock Options		0			0			1,362			0			1,362
Capital Distributions by the Partners of Consolidated Joint Ventures		0			(20	)		0			0			(20	)
Capital Contributions by the Partners of Equity Method Investments and Consolidated Joint Ventures		7			0			0			0			7
NET CASH PROVIDED BY FINANCING ACTIVITIES		(824	)		(68	)		213,747			0			212,855
NET INCREASE IN CASH		742			46			0			0			788
CASH—BEGINNING		10,595			363			50			0			11,008
CASH—ENDING	$	11,337		$	409		$	50		$	0		$	11,796

Recovered_Sheet1

Basis of Presentation and Principles of Consolidation - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Organization Consolidation And Presentation Of Financial Statements [Line Items]	'		'		'
Unevaluated Oil and Gas Properties	$189,385		$165,503		'
Changes in accounts payable and accrued liabilities	12,891		-8,832		-1,996
Future Abandonment Costs	28,525	[1]	24,822	[1]	18,670
Accrued Expenses	'		'		'
Organization Consolidation And Presentation Of Financial Statements [Line Items]	'		'		'
Future Abandonment Costs	2,500		600		'
Reclassification from Wells and Facilities in Progress	'		'		'
Organization Consolidation And Presentation Of Financial Statements [Line Items]	'		'		'
Unevaluated Oil and Gas Properties	3,900		'		'
Reclassification from Changes in Other Assets and Liabilities	'		'		'
Organization Consolidation And Presentation Of Financial Statements [Line Items]	'		'		'
Changes in accounts payable and accrued liabilities	'		$2,100		$900
[1]	As of December 31, 2013 and 2012, approximately $2.5 million and $0.6 million, respectively of our Future Abandonment Costs were classified as short-term liabilities under the caption Accrued Expenses on our Consolidated Balance Sheets.

Recovered_Sheet2

Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011	Dec. 31, 2010
	Customer		Customer
Accounting Policies [Line Items]	'		'		'	'
Accounts Receivable	$38,863,000		$24,980,000		'	'
Number of major customers	4		4		'	'
Impairment Expense	32,072,000		20,585,000		14,631,000	'
Deferred financing costs and other assets	12,000,000		'		'	'
Amortization expense	1,300,000		1,200,000		800,000	'
Debt issuance costs	3,100,000		6,400,000		'	'
Debt issuance costs, accumulated amortization	3,031,000		1,866,000		'	'
Accretion expense	3,094,000		2,029,000		1,500,000	'
Increase in estimated present value of asset retirement obligations	1,311,000		3,953,000		'	'
Future Abandonment Costs	28,525,000	[1]	24,822,000	[1]	18,670,000	'
Income tax examination minimum likelihood of tax benefits being realized upon ultimate settlement	50.00%		'		'	'
Capitalized interest costs	7,500,000		3,000,000		1,200,000	'
Common Stock, shares outstanding	54,186,490		53,213,264		'	'
Options outstanding	449,087		502,253		698,327	826,511
Other than Options outstanding	2,172,639		'		'	'
Illinois and Appalachian Basin Operations | Field Vehicles	'		'		'	'
Accounting Policies [Line Items]	'		'		'	'
Capital leases	3,000,000		1,600,000		'	'
Remaining obligation to be paid on capital leases	2,200,000		'		'	'
Illinois and Appalachian Basin Operations | Field Vehicles | Long-term Debt	'		'		'	'
Accounting Policies [Line Items]	'		'		'	'
Remaining obligation to be paid on capital leases	1,400,000		'		'	'
Illinois and Appalachian Basin Operations | Field Vehicles | Current Maturities of Long-Term Debt	'		'		'	'
Accounting Policies [Line Items]	'		'		'	'
Remaining obligation to be paid on capital leases	800,000		'		'	'
Sumitomo Corporation	'		'		'	'
Accounting Policies [Line Items]	'		'		'	'
Receivable from related party	4,400,000		2,100,000		'	'
Stock Appreciation Rights (SARs)	'		'		'	'
Accounting Policies [Line Items]	'		'		'	'
Other than Options outstanding	20,500		'		'	'
Warrant	'		'		'	'
Accounting Policies [Line Items]	'		'		'	'
Share based compensation, warrants outstanding	0		'		'	'
Restricted Stock	'		'		'	'
Accounting Policies [Line Items]	'		'		'	'
Other than Options outstanding	2,172,639		1,431,573		1,229,826	814,965
Performance Shares	'		'		'	'
Accounting Policies [Line Items]	'		'		'	'
Other than Options outstanding	1,279,050		'		'	'
Accrued Expenses	'		'		'	'
Accounting Policies [Line Items]	'		'		'	'
Future Abandonment Costs	2,500,000		600,000		'	'
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	'3 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		'		'	'
Oil And Gas Production	'		'		'	'
Accounting Policies [Line Items]	'		'		'	'
Accounts Receivable	28,800,000		18,100,000		'	'
Oil And Gas Production | Major Customers	'		'		'	'
Accounting Policies [Line Items]	'		'		'	'
Accounts Receivable	$22,700,000		$16,300,000		'	'
[1]	As of December 31, 2013 and 2012, approximately $2.5 million and $0.6 million, respectively of our Future Abandonment Costs were classified as short-term liabilities under the caption Accrued Expenses on our Consolidated Balance Sheets.

Summary_of_Deferred_Financing_

Summary of Deferred Financing Costs (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Deferred Costs, Capitalized and Other Assets Disclosure [Line Items]	'	'
Deferred Financing Costs-Gross	$12,404	$9,270
Accumulated Amortization	-3,031	-1,866
Deferred Financing Costs-Net	$9,373	$7,404

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Asset Retirement Obligations [Line Items]	'		'		'
Beginning Balance	$24,822,000	[1]	$18,670,000		'
Asset Retirement Obligation Incurred	1,750,000		598,000		'
Asset Retirement Obligation Settled	-2,452,000		-428,000		'
Asset Retirement Obligation Cancelled or Sold Well Properties	0		0		'
Asset Retirement Obligation Revision of Estimated Obligation	1,311,000		3,953,000		'
Asset Retirement Obligation Accretion Expense	3,094,000		2,029,000		1,500,000
Total Future Abandonment Costs	$28,525,000	[1]	$24,822,000	[1]	$18,670,000
[1]	As of December 31, 2013 and 2012, approximately $2.5 million and $0.6 million, respectively of our Future Abandonment Costs were classified as short-term liabilities under the caption Accrued Expenses on our Consolidated Balance Sheets.

Asset_Retirement_Obligations_P

Asset Retirement Obligations (Parenthetical) (Detail) (USD $)	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
In Thousands, unless otherwise specified
Asset Retirement Obligations [Line Items]	'		'		'
Future Abandonment Costs	$28,525	[1]	$24,822	[1]	$18,670
Accrued Expenses	'		'		'
Asset Retirement Obligations [Line Items]	'		'		'
Future Abandonment Costs	$2,500		$600		'
[1]	As of December 31, 2013 and 2012, approximately $2.5 million and $0.6 million, respectively of our Future Abandonment Costs were classified as short-term liabilities under the caption Accrued Expenses on our Consolidated Balance Sheets.

Business_Segment_Information_A

Business Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013
	Segment
Segment Reporting Information [Line Items]	'
Principal reportable segments	2

Performance_of_Business_Segmen

Performance of Business Segments Based on Net Income (Loss) from Continuing Operations, before Income Taxes (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Segment Reporting Information [Line Items]	'		'		'
Revenues	$237,931		$148,139		$114,606
Depreciation, Depletion and Amortization	63,944		45,437		27,856
Impairment Expense	32,072		20,585		14,631
Other Operating Expense	126,241	[1]	85,199	[1]	62,330	[1]
Interest Expense	22,825		6,450		2,524
Other (Income) Expense	-3,025	[2]	-105,322	[2]	-19,086	[2]
Income (Loss) From Continuing Operations, Before Income Taxes	-4,126		95,790		26,351
Total Assets	991,396		772,710		601,551
Expenditures for Long-Lived Assets	322,788		230,340		275,394
Equity Method Investments	18,708		16,978		41,683
Operating Segments	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	237,931		148,139		114,606
Inter-Segment Revenues	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	0		0		0
Exploration and Production Equipment	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	214,119		134,736		112,088
Depreciation, Depletion and Amortization	62,585		44,955		27,670
Impairment Expense	32,072		20,505		14,316
Other Operating Expense	106,591	[1]	76,063	[1]	59,917	[1]
Interest Expense	22,719		6,424		2,523
Other (Income) Expense	-3,111	[2]	-105,426	[2]	-19,021	[2]
Income (Loss) From Continuing Operations, Before Income Taxes	-6,737		92,215		26,683
Total Assets	971,973		766,599		600,049
Expenditures for Long-Lived Assets	317,481		227,913		269,823
Equity Method Investments	18,708		16,978		41,683
Exploration and Production Equipment | Operating Segments	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	214,119		134,736		112,088
Exploration and Production Equipment | Inter-Segment Revenues	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	0		0		0
Field Services	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	23,812		13,403		2,518
Depreciation, Depletion and Amortization	1,559		482		186
Impairment Expense	0		80		315
Other Operating Expense	25,945	[1]	10,859	[1]	3,169	[1]
Interest Expense	106		26		1
Other (Income) Expense	0	[2]	0	[2]	-100	[2]
Income (Loss) From Continuing Operations, Before Income Taxes	-3,798		1,956		-1,053
Total Assets	26,266		12,166		7,143
Expenditures for Long-Lived Assets	7,870		3,134		5,571
Equity Method Investments	0		0		0
Field Services | Operating Segments	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	32,583		15,637		3,546
Field Services | Inter-Segment Revenues	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	-8,771		-2,234		-1,028
Eliminations	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	0		0		0
Depreciation, Depletion and Amortization	-200		0		0
Impairment Expense	0		0		0
Other Operating Expense	-6,295	[1]	-1,723	[1]	-756	[1]
Interest Expense	0		0		0
Other (Income) Expense	86	[2]	104	[2]	35	[2]
Income (Loss) From Continuing Operations, Before Income Taxes	6,409		1,619		721
Total Assets	-6,843		-6,055		-5,641
Expenditures for Long-Lived Assets	-2,563		-707		0
Equity Method Investments	0		0		0
Eliminations | Operating Segments	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	-8,771		-2,234		-1,028
Eliminations | Inter-Segment Revenues	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	$8,771		$2,234		$1,028
[1]	Includes the following expenses: production and lease operating expenses, general and administrative expenses, (gain) loss on disposal of assets, exploration expense, field services operating expenses and other operating expenses.
[2]	Includes the following expenses: interest income, gain (loss) on derivative, net, other income (expense) and gain (loss) on equity method investments.

Business_and_Oil_and_Gas_Prope1

Business and Oil and Gas Property Acquisitions and Dispositions - Additional Information (Detail) (Keystone Midstream Services, USD $)	0 Months Ended	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	29-May-12	Sep. 30, 2012	Dec. 31, 2013	Dec. 31, 2012
Keystone Midstream Services	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Base consideration for sale	$483.20	'	'	'
Proceeds from sale at closing	121.4	'	'	'
Transactional costs which we recorded as Gain (Loss) on Equity Method Investments	3.3	'	'	'
Post-closing settlement charges	'	0.5	'	'
Proceeds from sale at closing	'	120.9	'	'
Cash held in escrow and paid out over the next 12 months	14.3	'	'	'
Proceed from escrow amount	'	'	6.9	7.2
Funds by other sellers in transaction	'	'	3.8	'
Post-closing adjustment	0.5	'	'	'
Gain on sale of investment	$99.40	'	$6.90	'

Discontinued_Operations_Assets

Discontinued Operations/ Assets Held for Sale - Additional Information (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2013	Dec. 31, 2012
			Dj Basin	Dj Basin
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]	'	'	'	'
Sale of the remaining DJ Basin assets	'	'	$3,100,000	'
Gain on asset held for sale	'	'	1,000,000	'
Assets Held For Sale	0	2,279,000	'	2,300,000
Liabilities Related to Assets Held for Sale	$0	$52,000	'	$100,000

Summary_of_Financial_Informati

Summary of Financial Information for Discontinued Operations (Detail) (Discontinued Operations Assets Held For Sale, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues:	'	'	'
Oil and Gas Sales	$25	$97	$556
Total Operating Revenue	25	97	556
Costs and Expenses:	'	'	'
Production and Lease Operating Expense	104	353	493
General and Administrative Expense	23	660	1,745
Exploration Expense	97	867	33,812
Impairment Expense	0	19,770	13,177
Depreciation, Depletion, Amortization and Accretion	0	0	85
Other Operating Expense (Income)	-3	8	1
Gain on Disposal of Asset	-969	-2,126	0
Interest Expense	0	0	1
Other (Income) Expense	0	-3	1
Total Expenses (Income)	-748	19,529	49,315
Income (Loss) from Discontinued Operations Before Income Taxes	773	-19,432	-48,759
Income Tax (Expense) Benefit	-1,005	8,489	15,302
Loss from Discontinued Operations, Net of Income Taxes	($232)	($10,943)	($33,457)
Crude Oil (Bbls)	'	'	'
Production	'	'	'
Production Units	356	1,272	6,939

Consolidated_Subsidiaries_Addi

Consolidated Subsidiaries - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Variable Interest Entity [Line Items]	'	'
Line of credit facility, amount outstanding	$59	'
Field Services	'	'
Variable Interest Entity [Line Items]	'	'
Percentage of interest by consolidated subsidiaries	100.00%	'
Water Solutions Holding	'	'
Variable Interest Entity [Line Items]	'	'
Ownership percentage by parent	60.00%	'
Effective date of ownership percentage	1-Apr-13	'
Water Solutions Holding | Water Solutions Credit Facility	'	'
Variable Interest Entity [Line Items]	'	'
Line of credit facility, amount outstanding	4	0.7
Water Solutions Holding | Equipment Line of Credit	'	'
Variable Interest Entity [Line Items]	'	'
Line of credit facility, amount outstanding	1.5	'
NorthStar 3 LLC	'	'
Variable Interest Entity [Line Items]	'	'
Promissory note	'	4.6
Sand Hills Management | Water Solutions Holding	'	'
Variable Interest Entity [Line Items]	'	'
Date of Agreement	'2009-11	'
Membership interest	20.00%	'
Ownership percentage by subsidiary	40.00%	'
Rex	'	'
Variable Interest Entity [Line Items]	'	'
Membership interest	80.00%	'
R.E. Gas Development LLC | NorthStar 3 LLC	'	'
Variable Interest Entity [Line Items]	'	'
Date of Agreement	'2011-08	'
Membership interest	100.00%	51.00%
Ownership interst	$0.20	'
Northstar Water Management | NorthStar 3 LLC	'	'
Variable Interest Entity [Line Items]	'	'
Date of Agreement	'2011-08	'
Membership interest	'	49.00%

Schedule_of_Carrying_Amount_an

Schedule of Carrying Amount and Classification of Assets and Liabilities of Water Solutions as Consolidated (Detail) (USD $)	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified
Variable Interest Entity [Line Items]	'		'	'	'
Cash and Cash Equivalents	$1,900		$43,975	$11,796	$11,008
Accounts Receivable	38,863		24,980	'	'
Inventory, Prepaid Expenses and Other	2,207		1,316	'	'
Other Property and Equipment	70,115		50,073	'	'
Accumulated Depreciation, Depletion and Amortization	-190,521		-146,038	'	'
Deferred Financing Costs and Other Assets - Net	9,373		7,404	'	'
Total Assets	991,396		772,710	601,551	'
Accounts Payable	31,103		29,448	'	'
Current Maturities of Long-Term Debt	6,743		1,686	'	'
Accrued Liabilities	54,450		23,019	'	'
Senior Secured Line of Credit and Long-Term Debt	418,934	[1]	'	'	'
Total Liabilities	574,471		360,416	'	'
Variable Interest Entity, Primary Beneficiary | Water Solutions Holding	'		'	'	'
Variable Interest Entity [Line Items]	'		'	'	'
Cash and Cash Equivalents	593		741	'	'
Accounts Receivable	9,882		3,360	'	'
Inventory, Prepaid Expenses and Other	89		13	'	'
Other Property and Equipment	11,798		3,560	'	'
Wells and Facilities in Progress	1,031		221	'	'
Accumulated Depreciation, Depletion and Amortization	-1,954		-501	'	'
Deferred Financing Costs and Other Assets - Net	206		199	'	'
Total Assets	21,645		7,593	'	'
Accounts Payable	758		456	'	'
Current Maturities of Long-Term Debt	5,404		1,098	'	'
Accrued Liabilities	6,247		1,036	'	'
Senior Secured Line of Credit and Long-Term Debt	3,053		965	'	'
Total Liabilities	$15,462		$3,555	'	'
[1]	Does not include $3.1 million net premium on Senior Notes.

Schedule_of_Carrying_Amount_an1

Schedule of Carrying Amount and Classification of Assets and Liabilities as Consolidated (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified
Variable Interest Entity [Line Items]	'	'	'	'
Cash and Cash Equivalents	$1,900	$43,975	$11,796	$11,008
NorthStar 3 LLC	'	'	'	'
Variable Interest Entity [Line Items]	'	'	'	'
Cash and Cash Equivalents	'	14	'	'
Wells and Facilities in Progress	'	4,559	'	'
Total Assets	'	4,573	'	'
Accounts Payable	'	6	'	'
Note Payable	'	4,633	'	'
Total Liabilities	'	$4,639	'	'

Equity_Method_Investments_Addi

Equity Method Investments - Additional Information (Detail) (USD $)	12 Months Ended						0 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	29-May-12	Dec. 31, 2012	Dec. 31, 2011
				RW Gathering, LLC	RW Gathering, LLC	RW Gathering, LLC	Keystone Midstream Services	Keystone Midstream Services	Keystone Midstream Services
Schedule of Equity Method Investments [Line Items]	'	'	'	'	'	'	'	'	'
Ownership percentage	'	'	'	40.00%	'	'	28.00%	'	'
Equity investment	$18,708,000	$16,978,000	$41,683,000	$18,700,000	$17,000,000	'	$28,100,000	'	'
Equity investment, cash contribution	2,493,000	4,087,000	23,204,000	2,500,000	2,000,000	'	'	2,100,000	'
Income (Loss) on Equity Method Investments	-763,000	-3,921,000	81,000	1,900,000	1,700,000	400,000	-11,500,000	'	1,600,000
Income (Loss) on Equity Method Investments, net of tax	'	'	'	'	'	'	-3,200,000	'	500,000
Transaction expenses related to the sale of the entity	'	'	'	'	'	'	$12,000,000	'	'

Concentrations_of_Credit_Risk_

Concentrations of Credit Risk - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
	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	38,863,000	24,980,000
Number of major customers	4	4
Oil And Gas Production	'	'
Concentration Risk [Line Items]	'	'
Accounts Receivable	28,800,000	18,100,000
Oil And Gas Production | Major Customers	'	'
Concentration Risk [Line Items]	'	'
Accounts Receivable	$22,700,000	$16,300,000

Recovered_Sheet3

Commitments and Contingencies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	acre
Loss Contingencies [Line Items]	'	'	'
Letters of credit	$1,400,000	$800,000	'
Rent expense	800,000	300,000	400,000
Payment related to sale agreement	406,400,000	'	'
Transportation, processing and marketing expenses of oil natural gas and natural gas liquids	26,400,000	14,100,000	4,600,000
Working interest through acquisition	62.50%	'	'
Acres through acquisition	4,510	'	'
Percentage of working interest in 15% of MFC	100.00%	'	'
Working interest of MFC	15.00%	'	'
Commitment period for drilling wells	'November 15 of each year	'	'
Production and Lease Operating Expense	62,138,000	47,638,000	33,116,000
Drilling Rights	'	'	'
Loss Contingencies [Line Items]	'	'	'
Number of rigs to support Appalachian Basin operations	2	'	'
Drilling carry obligation	14,100,000	'	'
Drilling carry obligation balance	5,200,000	'	'
Drilling commitments	3	'	'
Drilling Rights | Minimum	'	'	'
Loss Contingencies [Line Items]	'	'	'
Estimated commitment for each well drilled and completed	8,000,000	'	'
Drilling Rights | Maximum	'	'	'
Loss Contingencies [Line Items]	'	'	'
Estimated commitment for each well drilled and completed	9,000,000	'	'
Drilling Rights | 2014	'	'	'
Loss Contingencies [Line Items]	'	'	'
Minimum cost to retain drilling rigs	4,900,000	'	'
Minimum cost to retain the completion services	9,800,000	'	'
Drilling Rights | 2015	'	'	'
Loss Contingencies [Line Items]	'	'	'
Minimum cost to retain drilling rigs	3,200,000	'	'
Drilling Rights | 2016	'	'	'
Loss Contingencies [Line Items]	'	'	'
Minimum cost to retain drilling rigs	1,500,000	'	'
Pennsylvania Impact Fee	'	'	'
Loss Contingencies [Line Items]	'	'	'
Rate in which unconventional wells are charged	20.00%	'	'
Production and Lease Operating Expense	3,200,000	5,400,000	'
Expenses related to wells spud	2,800,000	'	'
Capacity Reservation	'	'	'
Loss Contingencies [Line Items]	'	'	'
Estimated working interest	70.00%	'	'
Charges incurred for unused processing capacity	300,000	500,000	100,000
Capacity Reservation | 2014	'	'	'
Loss Contingencies [Line Items]	'	'	'
Obligation for the cryogenic gas processing plant if gas is not processed	10,400,000	'	'
Capacity Reservation | 2015	'	'	'
Loss Contingencies [Line Items]	'	'	'
Obligation for the cryogenic gas processing plant if gas is not processed	13,000,000	'	'
Capacity Reservation | 2016	'	'	'
Loss Contingencies [Line Items]	'	'	'
Obligation for the cryogenic gas processing plant if gas is not processed	14,600,000	'	'
Capacity Reservation | 2017	'	'	'
Loss Contingencies [Line Items]	'	'	'
Obligation for the cryogenic gas processing plant if gas is not processed	14,600,000	'	'
Capacity Reservation | Two Thousand Eighteen	'	'	'
Loss Contingencies [Line Items]	'	'	'
Obligation for the cryogenic gas processing plant if gas is not processed	14,600,000	'	'
Capacity Reservation | Thereafter	'	'	'
Loss Contingencies [Line Items]	'	'	'
Obligation for the cryogenic gas processing plant if gas is not processed	$100,700,000	'	'

Lease_Commitments_for_Each_of_

Lease Commitments for Each of Next Five Years (Detail) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Oil and Gas Delivery Commitments and Contracts [Line Items]	'
2014	$859
2015	807
2016	815
2017	823
2018	133
Thereafter	0
Total	$3,437

Minimum_Net_Obligations_under_

Minimum Net Obligations under Sales, Gathering and Transportation Agreements (Detail) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Oil and Gas Delivery Commitments and Contracts [Line Items]	'
2014	$7,463
2015	16,525
2016	23,654
2017	29,495
2018	31,724
Thereafter	294,571
Total	$403,432

Fee_for_Unconventional_Gas_Wel

Fee for Unconventional Gas Wells (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013
Less than $2.25	'
Unconventional Gas Wells [Line Items]	'
Year One	$40,000	[1]
Year Two	30,000	[1]
Year Three	25,000	[1]
Year 4-10	10,000	[1]
Year 11-15	5,000	[1]
$2.26 - $2.99	'
Unconventional Gas Wells [Line Items]	'
Year One	45,000	[1]
Year Two	35,000	[1]
Year Three	30,000	[1]
Year 4-10	15,000	[1]
Year 11-15	5,000	[1]
$3.00 - $4.99	'
Unconventional Gas Wells [Line Items]	'
Year One	50,000	[1]
Year Two	40,000	[1]
Year Three	30,000	[1]
Year 4-10	20,000	[1]
Year 11-15	10,000	[1]
$5.00 - $5.99	'
Unconventional Gas Wells [Line Items]	'
Year One	55,000	[1]
Year Two	45,000	[1]
Year Three	40,000	[1]
Year 4-10	20,000	[1]
Year 11-15	10,000	[1]
More than $5.99	'
Unconventional Gas Wells [Line Items]	'
Year One	60,000	[1]
Year Two	55,000	[1]
Year Three	50,000	[1]
Year 4-10	20,000	[1]
Year 11-15	$10,000	[1]
[1]	Pricing utilized for determining annual 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 12-month period ending December 31.

Related_Party_Transaction_Addi

Related Party Transaction - Additional Information (Detail) (USD $)

0 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

1 Months Ended

12 Months Ended

Jun. 27, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2013

Apr. 30, 2011

Sep. 30, 2010

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jun. 30, 2007

Jun. 30, 2007

Dec. 31, 2013

Dec. 31, 2012

Jun. 30, 2007

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Minimum

Maximum

Shaner Hotel Group Limited Partnership

Shaner Hotel Group Limited Partnership

Charlie Brown Air Corp

Charlie Brown Air Corp

Charlie Brown Air Corp

Charlie Brown Air Corp

Charlie Brown Air Corp

Charlie Brown Air Corp

Charlie Brown Air Two Llc

Charlie Brown Air Two Llc

Charlie Brown Air Two Llc

Charlie Brown Air Two Llc

Charlie Brown Air Two Llc

Charlie Brown Air Two Llc

Charlie Brown Air Two Llc

Charlie Brown Air Two Llc

Charlie Brown Air Two Llc

Charlie Brown Air Two Llc

RW Gathering, LLC

RW Gathering, LLC

RW Gathering, LLC

Keystone Midstream Services

Keystone Midstream Services

Water Solutions Holding

Water Solutions Holding

Water Solutions Holding

Aircraft

Minimum

Maximum

Related Party Debt

Related Party Debt

Related Party Debt

Related Party Debt

Shaner Hotel Group Limited Partnership

Unrelated Third Party

LIBOR

Related Party Transaction [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of aircrafts in related party transaction

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Ownership interest

'

'

'

'

'

'

'

'

50.00%

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aircraft use right, variable per hour flight rate

'

'

'

'

'

'

'

'

'

'

'

'

400

800

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aircraft use right, interest purchased

'

'

'

'

'

'

'

'

$600,000

$600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Payments for use of aircrafts

'

'

'

'

'

'

'

'

'

'

'

200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of membership interest

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25.00%

'

'

'

'

'

'

'

25.00%

50.00%

'

'

'

'

'

'

'

'

Bank loan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,500,000

1,200,000

1,300,000

'

'

'

'

'

'

'

'

'

'

'

Maturity period of bank loan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

21-Jun-17

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest rate on bank loan

'

'

'

'

1.75%

2.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.50%

'

'

'

'

'

'

'

'

'

'

Amortization period of bank loan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'180 months

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of loan guaranteed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of loan guaranteed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loan interest and retainer fees

'

'

'

'

'

'

'

'

'

'

'

'

'

'

200,000

200,000

200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Due to or from related party

'

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Monthly rental payments

35,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual CPI adjustment capped

2.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Lease term

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operating lease annual rent

'

'

'

'

'

'

'

400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Land acquired from related party

'

'

'

'

'

'

600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Production and Lease Operating Expense

'

62,138,000

47,638,000

33,116,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

800,000

800,000

800,000

2,400,000

4,600,000

'

'

'

Ownership interest

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

40.00%

'

'

'

'

'

'

'

Water transfer and water purification expenses

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,700,000

3,200,000

1,600,000

Water transfer and water purification expenses eliminated in consolidation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8,800,000

2,200,000

1,000,000

Due to related party

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$1,500,000

$200,000

'

LongTerm_Debt_Additional_Infor

Long-Term Debt - Additional Information (Detail) (USD $)

12 Months Ended

0 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

0 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Apr. 26, 2013

Dec. 12, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Mar. 27, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Mar. 27, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Oct. 18, 2013

Dec. 31, 2013

Oct. 18, 2013

Oct. 18, 2013

Oct. 18, 2013

Dec. 31, 2013

Oct. 18, 2013

Oct. 18, 2013

Oct. 18, 2013

8.875% Senior Notes

8.875% Senior Notes

8.875% Senior Notes

8.875% Senior Notes

8.875% Senior Notes

Crude Oil (Bbls)

Natural Gas

Minimum

Maximum

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Second Lien Credit Agreement

Abr Loans

Abr Loans

Defaulted Loans

Water Solutions Holding

Water Solutions Holding

Water Solutions Holding

Water Solutions Holding

Water Solutions Holding

Water Solutions Holding

Water Solutions Holding

Water Solutions Holding

Water Solutions Holding

Letter of Credit

Minimum

Minimum

Maximum

Minimum

Maximum

Demand Notes

Demand Notes

Demand Notes

Demand Notes

Equipment Line of Credit

Equipment Line of Credit

Equipment Line of Credit

Equipment Line of Credit

Equipment Line of Credit

LIBOR

Base Rate

Three Months LIBOR

Minimum

Maximum

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of purchase price of reserves for which interim borrowing base re-determinations may be requested

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit, maximum borrowing base

'

'

'

'

'

'

'

'

'

'

'

'

'

$325,000,000

'

'

'

'

'

'

'

'

'

$4,000,000

'

'

'

$6,000,000

'

'

'

'

Increase in revolving credit facility

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

500,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, current borrowing capacity

'

'

'

'

'

'

'

'

'

'

'

'

215,000,000

'

'

60,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility, amount outstanding

59,000,000

'

'

'

'

'

'

'

'

'

'

'

59,000,000

'

0

'

'

'

'

'

'

'

'

'

4,000,000

'

'

'

1,500,000

'

'

'

Debt instrument maturity date

'

'

'

'

1-Dec-20

'

'

'

'

'

'

'

27-Mar-18

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

LIBOR rate description

'

'

'

'

'

'

'

'

'

'

'

'

'The applicable per annum margin, in the case of loans bearing interest at the Adjusted LIBO Rate, ranges from 175 to 275 basis points, and the applicable per annum margin, in the case of loans bearing interest at the Alternate Base Rate, ranges from 50 to 150 basis points, in each case, determined based upon our borrowing utilization at such date of determination.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Effective rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.50%

'

'

'

'

'

'

'

'

'

'

'

'

Additional percentage with LIBOR

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

'

'

'

Margin rate

'

'

'

'

'

'

'

'

'

'

1.75%

2.75%

'

'

'

'

'

'

'

'

0.50%

1.50%

2.00%

'

'

2.75%

2.00%

'

'

3.00%

'

'

Percentage of reasonably anticipated projected production

85.00%

'

'

'

'

'

'

'

75.00%

75.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Duration of developed producing reserve

'5 years

'

'

'

'

'

'

'

'

'

'

'36 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Notional amounts of interest rate swap

20,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding principal amount of debt for borrowed money, percentage

75.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Liens covering the oil and gas properties, percentage

80.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Criteria Current ratio

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Current ratio

'

'

'

'

'

'

'

'

'

'

'

'

220.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Criteria Interest Coverage Ratio

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

300.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest coverage ratio

'

'

'

'

'

'

'

'

'

'

'

'

440.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Criteria Total debt to EBITAX"

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

425.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

Total debt to EBITAX

'

'

'

'

'

'

'

'

'

'

'

'

310.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

130.00%

'

'

225.00%

Debt issued aggregate principal amount

'

'

'

100,000,000

250,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Senior notes at an issue price

'

'

'

105.00%

99.30%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net proceeds of bond offering, after discounts and expenses

105,000,000

248,250,000

0

102,800,000

242,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Senior notes, issuance cost

3,134,000

6,397,000

2,615,000

'

6,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument interest rate

'

'

'

'

8.88%

8.88%

8.88%

8.88%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accrued interest

22,825,000

6,450,000

2,524,000

3,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt issuance costs

3,100,000

6,400,000

'

2,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Senior Notes

418,934,000

[1]

'

'

'

'

353,100,000

248,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Premium (Discount) on Senior Notes - Net

-3,078,000

1,742,000

'

'

'

3,100,000

-1,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amortization of net premium

'

'

'

'

'

200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of notes that can be redeemed

'

'

'

'

'

35.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Date at which Notes may be redeemed at borrower's option

'

'

'

'

'

1-Dec-16

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Latest date for equity proceeds to be applied to optional Note redemption

'

'

'

'

'

1-Dec-15

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of accounts receivable

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

80.00%

'

'

'

'

'

'

'

'

Accounts receivable, collection period

'

'

'

'

'

'

'

'

'

'

'30 days

'60 days

'

'

'

'

'

'

'

'

'

'

'

'90 days

'

'

'

'

'

'

'

'

Percentage of asset's cost funded by line of credit

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

80.00%

'

'

'

'

Line of credit, maturity period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'4 years

Line of credit, minimum required tangible net worth

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,500,000

'

'

'

'

Line of credit, minimum required tangible net worth, percentage of annual net income added

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

30.00%

'

'

'

'

Net worth

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$6,000,000

'

'

'

Fixed charge coverage ratio

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

240.00%

'

175.00%

'

[1]

Does not include $3.1 million net premium on Senior Notes.

Components_of_LongTerm_Debt_an

Components of Long-Term Debt and Lines of Credit (Detail) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Debt Instrument [Line Items]	'		'
8.875% Senior Notes	$350,000		$250,000
Premium (Discount) on Senior Notes	3,078		-1,742
Senior Lines of Credit	59,000	[1]	0	[1]
Capital Leases and Other Obligations	9,934	[1]	2,677	[1]
Total Debt	422,012		250,935
Less Current Portion of Long-Term Debt	-6,743		-1,686
Total Long-Term Debt	$415,269		$249,249
[1]	The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2013 and 2012 was approximately 1.9 % and 2.5%, respectively. The weighted average interest rate on borrowings under the Demand Note and the Equipment Note for the year ended December 31, 2013 was approximately 3.0%. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2013 and 2012 was approximately 5.3% and 4.5%, respectively.

Components_of_LongTerm_Debt_an1

Components of Long-Term Debt and Lines of Credit (Parenthetical) (Detail)	Dec. 31, 2013	Dec. 31, 2012	Dec. 12, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012
	8.875% Senior Notes	8.875% Senior Notes	8.875% Senior Notes	8.875% Senior Notes	Senior Credit Facility	Senior Credit Facility	Demand Notes	Equipment Line of Credit	Other Loans and Notes Payable	Other Loans and Notes Payable
Debt Instrument [Line Items]	'	'	'	'	'	'	'	'	'	'
Senior note, interest rate	8.88%	8.88%	8.88%	8.88%	'	'	'	'	'	'
Weighted average interest rate	'	'	'	'	1.90%	2.50%	3.00%	3.00%	5.30%	4.50%

Principal_Maturity_Schedule_fo

Principal Maturity Schedule for Debt Outstanding (Detail) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Debt Instrument [Line Items]	'
2014	$6,743
2015	1,467
2016	1,270
2017	292
2018	59,162
Thereafter	350,000
Total	$418,934	[1]
[1]	Does not include $3.1 million net premium on Senior Notes.

Principal_Maturity_Schedule_fo1

Principal Maturity Schedule for Debt Outstanding (Parenthetical) (Detail) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Debt Instrument [Line Items]	'
Senior notes, net premium	$3.10

Fair_Value_of_Financial_and_De

Fair Value of Financial and Derivative Instruments - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
		Contract
Derivatives, Fair Value [Line Items]	'	'	'
Cash Settlements of Derivatives	$7,128,000	$16,219,000	$6,212,000
Senior Credit Facility, amount outstanding	59,000,000	'	'
Senior Notes, amount outstanding	350,000,000	250,000,000	'
Fair value of interest rate swap, liability	200,000	'	'
Fair value of commodity derivative contracts	200,000	9,800,000	'
Unrealized loss on commodity derivative contracts	4,300,000	'	'
Outstanding commodity derivatives	'	0	'
Fixed to Floating Interest Rate Swap	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'
Derivative, amount of hedged item	25,000,000	'	'
Oil | Minimum	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'
Commodity hedged on annualized basis hedge through 2014	100.00%	'	'
Natural Gas	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'
Fair value of commodity derivative contracts	1,183,000	'	'
Natural Gas | Minimum	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'
Commodity hedged on annualized basis hedge through 2014	90.00%	'	'
Commodity hedged on annualized basis hedge through 2015	30.00%	'	'
Natural Gas Liquids	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'
Fair value of commodity derivative contracts	($912,000)	'	'
Natural Gas Liquids | Minimum	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'
Commodity hedged on annualized basis hedge through 2014	40.00%	'	'

Schedule_of_Location_and_Amoun

Schedule of Location and Amounts of Gains and Losses on Derivative Instruments (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss) on derivatives, net	($2,908)	$10,687	$18,916
Oil	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss) on derivatives, net	-2,798	1,579	-308
Natural Gas	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss) on derivatives, net	1,807	8,162	19,224
Natural Gas Liquids	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss) on derivatives, net	-1,711	946	0
Interest Rate Swap	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss) on derivatives, net	($206)	$0	$0

Asset_or_Liability_Financial_C

Asset or Liability Financial Commodity Derivative Instrument Positions (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
In Thousands, unless otherwise specified			Natural Gas Liquids	Natural Gas	Oil	2014- Swap	2014- Swap	2014- Swap	2014 - Sold Call	2014-3-Collar	2014-3-Collar	2014-Swaption	2014-Cap Swap	2014-Cap Swap	2014-Basis Swap	2014-Collar	2014-Collar	2015-Swap	2015-Cap Swap	2015-Three Way Collar	2015-Sold Call	2015-Basis Swap	2014-Deferred Put Spread
			bbl	Mcf	bbl	Natural Gas Liquids	Natural Gas	Oil	Natural Gas	Natural Gas	Oil	Natural Gas	Natural Gas	Oil	Natural Gas	Natural Gas	Oil	Natural Gas	Natural Gas	Natural Gas	Natural Gas	Natural Gas	Oil
						bbl	Mcf	bbl	Mcf	Mcf	bbl	Mcf	Mcf	bbl	Mcf	Mcf	bbl	Mcf	Mcf	Mcf	Mcf	Mcf	bbl
						OptionPlan	OptionPlan	OptionPlan	OptionPlan	OptionPlan	OptionPlan	OptionPlan	OptionPlan	OptionPlan	OptionPlan	OptionPlan	OptionPlan	OptionPlan	OptionPlan	OptionPlan	OptionPlan	OptionPlan	OptionPlan
Derivatives, Fair Value [Line Items]	'	'	'	'	'	'	'	'	'	'	'	'	'	'	'	'	'	'	'	'	'	'	'
Volume	'	'	357,000	38,430,000	990,000	357,000	4,830,000	30,000	1,800,000	7,800,000	372,000	2,400,000	3,600,000	360,000	7,200,000	1,800,000	60,000	1,200,000	2,400,000	2,400,000	2,400,000	600,000	168,000
Sold Put Option	'	'	'	'	'	0	0	0	0	3.32	76.61	0	3.3	80.83	0	0	0	0	3.28	3.4	0	0	75
Floor	'	'	'	'	'	0	0	0	0	4.08	87.6	0	0	0	0	3.51	90	0	0	4.16	0	0	90
Ceiling	'	'	'	'	'	0	0	0	5	4.59	103.85	0	0	0	0	4.43	97.65	0	0	4.63	4.4	0	0
Swap	'	'	'	'	'	48.49	3.97	93.75	0	0	0	4.45	4.09	97.72	0	0	0	4.18	4.1	0	0	0	0
Base Differential	'	'	'	'	'	0	0	0	0	0	0	0	0	0	-0.36	0	0	0	0	0	0	-0.35	0
Fair Market Value	$200	$9,800	($912)	$1,183	($291)	($912)	($1,064)	($119)	($150)	$393	$75	($717)	($491)	$380	$3,984	($235)	($42)	$18	($302)	$169	($761)	$339	($585)

Combined_Fair_Value_of_Derivat

Combined Fair Value of Derivatives (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]	'	'
Total Derivative Assets	$6,203	$12,709
Total Derivative Liabilities	-6,428	-2,899
Short Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	5,668	12,005
Long Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Long - Term Derivative Assets	535	704
Short Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-4,663	-1,389
Long-Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Long - Term Derivative Liabilities	-1,765	-1,510
Crude Oil-Cap Swaps | Short Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	380	90
Crude Oil - Three Way Collars | Short Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	104	0
Crude Oil - Three Way Collars | Short Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-29	-45
Crude Oil - Three Way Collars | Long-Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Long - Term Derivative Liabilities	0	-509
Natural Gas Liquids - Swaps | Short Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	83	535
Natural Gas Liquids - Swaps | Short Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-995	0
Natural Gas - Swaps | Short Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	106	2,416
Natural Gas - Swaps | Long Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Long - Term Derivative Assets	22	239
Natural Gas - Swaps | Short Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-1,170	-785
Natural Gas - Swaps | Long-Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Long - Term Derivative Liabilities	-4	-434
Natural Gas - Swaption | Short Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	0	354
Natural Gas - Swaption | Short Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-717	0
Natural Gas-Cap Swap | Short Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	5	0
Natural Gas-Cap Swap | Long Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Long - Term Derivative Assets	5	0
Natural Gas-Cap Swap | Short Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-496	0
Natural Gas-Cap Swap | Long-Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Long - Term Derivative Liabilities	-307	0
Natural Gas-Basis Swaps | Short Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	3,984	0
Natural Gas-Basis Swaps | Long Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Long - Term Derivative Assets	339	0
Natural Gas - Three Way Collars | Short Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	518	1,021
Natural Gas - Three Way Collars | Long Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Long - Term Derivative Assets	169	465
Natural Gas - Three Way Collars | Short Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-125	-35
Natural Gas - Three Way Collars | Long-Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Long - Term Derivative Liabilities	0	-35
Natural Gas - Collars | Short Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	0	4,211
Natural Gas - Collars | Long Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Long - Term Derivative Assets	0	0
Natural Gas - Collars | Short Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-235	0
Natural Gas - Collars | Long-Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Long - Term Derivative Liabilities	0	-166
Natural Gas - Puts | Short Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	0	3,378
Natural Gas - Puts | Long Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Long - Term Derivative Assets	0	0
Interest Rate Swap | Short Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	488	0
Interest Rate Swap | Long-Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Long - Term Derivative Liabilities	-693	0
Crude Oil - Collars | Long Term Derivative Assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Long - Term Derivative Assets	0	0
Crude Oil - Collars | Short Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-42	-307
Crude Oil Swaps | Short Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-119	-217
Crude Oil - Deferred Put Spread | Short Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-585	0
Natural Gas - Calls | Short Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-150	0
Natural Gas - Calls | Long-Term Derivative Liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Total Long - Term Derivative Liabilities	($761)	($366)

Significant_Unobservable_Input

Significant Unobservable Inputs Used in Fair Value Measurements of Natural Gas Basis Swaps (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
In Thousands, unless otherwise specified			Natural Gas Basis Differential Forward Curve	Natural Gas Basis Differential Forward Curve	Natural Gas Basis Differential Forward Curve
				Minimum	Maximum
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'	'	'	'
Range (price per Mcf)	'	'	'	-0.78	-1.08
Weighted Average (price per Mcf)	'	'	-0.91	'	'
Fair value of derivatives	$200	$9,800	$4,323	'	'

Fair_Value_Hierarchy_Table_for

Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivatives assets and liabilities	$200	$9,800
Parent Company | Commodity Derivatives	'	'
Derivatives assets and liabilities	-20	'
Parent Company | Interest Rate Swap	'	'
Derivatives assets and liabilities	-205	'
Quoted Prices in Active Markets for Identical Assets (Level 1) | Parent Company | Commodity Derivatives	'	'
Derivatives assets and liabilities	0	'
Quoted Prices in Active Markets for Identical Assets (Level 1) | Parent Company | Interest Rate Swap	'	'
Derivatives assets and liabilities	0	'
Significant Other Observable Inputs (Level 2) | Parent Company | Commodity Derivatives	'	'
Derivatives assets and liabilities	-4,343	'
Significant Other Observable Inputs (Level 2) | Parent Company | Interest Rate Swap	'	'
Derivatives assets and liabilities	-205	'
Significant Unobservable Inputs (Level 3) | Parent Company | Commodity Derivatives	'	'
Derivatives assets and liabilities	4,323	'
Significant Unobservable Inputs (Level 3) | Parent Company | Interest Rate Swap	'	'
Derivatives assets and liabilities	$0	'

Reconciliation_of_Commodity_De

Reconciliation of Commodity Derivative Contracts Measured at Fair Value on Recurring Basis Using Significant Unobservable Inputs (Level 3) (Detail) (Recurring Basis, Significant Unobservable Inputs (Level 3), USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Recurring Basis | Significant Unobservable Inputs (Level 3)	'	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'
Beginning Balance of Level 3	$0	$0
Changes in Fair Value	4,328	0
Purchases	0	0
Settlements Received	-5	0
Ending Balance of Level 3	$4,323	$0

Financial_Instruments_Not_Reco

Financial Instruments Not Recorded at Fair Value (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Carrying Amount	'	'
Derivatives, Fair Value [Line Items]	'	'
8.875% Senior Notes	$350,000	$250,000
Secured Lines of Credit	59,000	0
Capital Leases and Other Obligations	9,934	2,677
Total	418,934	252,677
Fair Value	'	'
Derivatives, Fair Value [Line Items]	'	'
8.875% Senior Notes	385,000	249,074
Secured Lines of Credit	59,000	0
Capital Leases and Other Obligations	9,731	2,524
Total	$453,731	$251,598

Financial_Instruments_Not_Reco1

Financial Instruments Not Recorded at Fair Value (Parenthetical) (Detail) (8.875% Senior Notes)	Dec. 31, 2013	Dec. 31, 2012	Dec. 12, 2012	Dec. 31, 2011
Derivatives, Fair Value [Line Items]	'	'	'	'
Senior Notes, interest rate	8.88%	8.88%	8.88%	8.88%
Carrying Amount	'	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'	'
Senior Notes, interest rate	8.88%	8.88%	'	'
Fair Value	'	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'	'
Senior Notes, interest rate	8.88%	8.88%	'	'

Income_Tax_Expense_benefit_fro

Income Tax Expense (benefit) from Continuing Operations (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current:	'	'	'
Federal	($1,916)	$2,329	$63
State	-4,104	5,825	244
Deferred:	'	'	'
Federal	808	28,216	8,524
State	1,427	2,179	-561
Income Tax Expense	($3,785)	$38,549	$8,270

Reconciliation_of_Income_Tax_E

Reconciliation of Income Tax Expense (Benefit) Using Statutory Rate Compared with Actual Income Tax Expense (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule Of Effective Tax Rates Line Items	'	'	'
Income before noncontrolling interests and income taxes	($5,683)	$94,971	$26,358
Statutory U.S. income tax rate	35.00%	35.00%	35.00%
Tax expense recognized using statutory U.S. income tax rate	-1,989	33,240	9,225
Change in estimated future state rate	-484	-7	612
Permanent differences	83	52	176
Change in valuation allowances	-160	-131	1,031
Other	-479	-493	-4,092
Adjusted federal income tax expense (benefit)	-3,029	32,661	6,952
State income tax expense (benefit)	-756	5,888	1,318
Income Tax Expense	($3,785)	$38,549	$8,270
Effective income tax rate	66.60%	40.60%	31.40%

Components_of_Deferred_Tax_Ass

Components of Deferred Tax Assets (Liabilities) (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Assets:	'	'
Asset retirement obligation	$997	$0
Future sale proceeds held in escrow	0	2,947
Non-cash compensation plans	2,593	714
Other	370	306
Total current deferred tax assets	3,960	3,967
Liabilities:	'	'
Unrealized gain on derivatives	-404	-4,365
Other	-105	-141
Total current deferred tax liabilities	-509	-4,506
Net total current deferred tax asset (liability)	3,451	-539
Assets:	'	'
Asset retirement obligation	10,445	10,211
Non-cash compensation plans	1,513	2,090
Net operating loss carryforward	48,703	4,384
Organization costs	602	689
Deferred revenue	1,338	1,487
AMT credits	292	1,380
Unrealized loss on derivatives	493	0
Other	232	593
Total long-term deferred tax assets	63,618	20,834
Liabilities:	'	'
Timing differences-tax partnerships	-7,474	-5,873
Valuation allowances	-1,965	-1,732
Book basis of oil and gas properties in excess of tax basis	-83,594	-36,805
Other	-31	-49
Total long-term deferred tax liabilities	-93,064	-44,459
Net total long-term deferred tax liability	($29,446)	($23,625)

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
In Millions, unless otherwise specified			Minimum	Maximum	Federal
Income Tax Disclosure [Line Items]	'	'	'	'	'
Valuation allowance for statutory depletion carryforwards and charitable contributions	$2	$1.70	'	'	'
Federal net operating loss carryforwards	'	'	'	'	121.1
Net operating loss carryforwards	$111	'	'	'	'
Federal net operating loss carryforwards, expiration year	'	'	'2023	'2033	'

Expirations_by_Year_for_Federa

Expirations by Year for Federal and State Net Operating Loss Carryforwards (Detail) (Federal and state, USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Operating Loss Carryforwards [Line Items]	'
Net Operating Loss Carryforwards	$48,703
Expiration Year, 2023	'
Operating Loss Carryforwards [Line Items]	'
Net Operating Loss Carryforwards	256
Expiration Year, 2024	'
Operating Loss Carryforwards [Line Items]	'
Net Operating Loss Carryforwards	53
Expiration Year, 2025	'
Operating Loss Carryforwards [Line Items]	'
Net Operating Loss Carryforwards	0
Expiration Year, 2026	'
Operating Loss Carryforwards [Line Items]	'
Net Operating Loss Carryforwards	898
Expiration Year, 2027	'
Operating Loss Carryforwards [Line Items]	'
Net Operating Loss Carryforwards	0
Expiration Year, 2028	'
Operating Loss Carryforwards [Line Items]	'
Net Operating Loss Carryforwards	4,179
Expiration Year, 2029	'
Operating Loss Carryforwards [Line Items]	'
Net Operating Loss Carryforwards	798
Expiration Year, 2030	'
Operating Loss Carryforwards [Line Items]	'
Net Operating Loss Carryforwards	803
Expiration Year, 2031	'
Operating Loss Carryforwards [Line Items]	'
Net Operating Loss Carryforwards	19,769
Expiration Year, 2032	'
Operating Loss Carryforwards [Line Items]	'
Net Operating Loss Carryforwards	60
Expiration Year, 2033	'
Operating Loss Carryforwards [Line Items]	'
Net Operating Loss Carryforwards	$21,887

Earnings_Per_Common_Share_Addi

Earnings Per Common Share - Additional Information (Detail)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Stock Options	'	'	'
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	0.6
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	1.3	1	0.8

Computation_of_Basic_and_Dilut

Computation of Basic and Diluted Earning Per Common Share (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Schedule Of Earnings Per Share Basic And Diluted [Line Items]	'	'	'	'	'	'	'	'	'		'		'
Net Income (Loss) From Continuing Operations, Less Noncontrolling Interests	($13,274)	$1,832	$13,441	($2,340)	($1,038)	($1,742)	$56,193	$3,828	($1,898)		$56,422		$18,088
Net Loss From Discontinued Operations	-691	0	520	-61	-2,280	-258	-3,050	-5,355	-232		-10,943		-33,457
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	($14,610)	$1,574	$13,740	($2,834)	($3,621)	($2,193)	$52,921	($1,628)	($2,130)		$45,479		($15,369)
Weighted Average Common Shares Outstanding-Basic	52,705	52,626	52,555	52,367	52,278	52,036	52,009	48,744	52,572		51,543		43,930
Effect of Dilutive Securities:	'	'	'	'	'	'	'	'	'		'		'
Employee Stock Options	'	'	'	'	'	'	'	'	0		69		95
Employee Performance-Based Restricted Stock Awards	'	'	'	'	'	'	'	'	0		413		451
Weighted Average Common Shares Outstanding-Diluted	52,705	53,293	52,911	52,367	52,278	52,036	52,876	49,693	52,572		52,025		44,476
Earnings per Common Share:	'	'	'	'	'	'	'	'	'		'		'
Basic-Net Income (Loss) From Continuing Operations	($0.26)	$0.03	$0.25	($0.05)	($0.03)	($0.04)	$1.08	$0.08	($0.04)	[1]	$1.09	[1]	$0.41	[1]
-Net Loss From Discontinued Operations	($0.01)	$0	$0.01	$0	($0.04)	$0	($0.06)	($0.11)	$0	[1]	($0.21)	[1]	($0.76)	[1]
-Net Income (Loss)	($0.27)	$0.03	$0.26	($0.05)	($0.07)	($0.04)	$1.02	($0.03)	($0.04)	[1]	$0.88	[1]	($0.35)	[1]
Diluted-Net Income (Loss) From Continuing Operations	($0.26)	$0.03	$0.25	($0.05)	($0.03)	($0.04)	$1.06	$0.08	($0.04)	[1]	$1.08	[1]	$0.41	[1]
-Net Loss From Discontinued Operations	($0.01)	$0	$0.01	$0	($0.04)	$0	($0.06)	($0.11)	$0	[1]	($0.21)	[1]	($0.76)	[1]
-Net Income (Loss)	($0.27)	$0.03	$0.26	($0.05)	($0.07)	($0.04)	$1	($0.03)	($0.04)	[1]	$0.87	[1]	($0.35)	[1]
[1]	All earnings per share amounts are attributable to Rex common shareholders.

Capital_Stock_Additional_Infor

Capital Stock - Additional Information (Detail) (USD $)	1 Months Ended	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Feb. 29, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Class of Stock [Line Items]	'	'	'	'
Authorized capital stock, common stock	'	100,000,000	100,000,000	'
Authorized capital stock, preferred stock	'	100,000	'	'
Common Stock, shares outstanding	'	54,186,490	53,213,264	'
Common stock issued under public offering	8,050,000	'	'	'
Common stock issued under public offering per price	$9.25	'	'	'
Net proceeds from offering after deducting underwriting discounts, commissions and estimated offering expenses	$70,600	$0	$70,583	$0

Major_Customers_Additional_Inf

Major Customers - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenue, Major Customer [Line Items]	'	'	'
Sales revenue	$237,931	$148,139	$114,606
Sales	'	'	'
Revenue, Major Customer [Line Items]	'	'	'
Sales revenue	179,500	128,300	103,600
Percentage of revenue from major customers	83.90%	95.30%	92.60%
Number of major customers	4	5	4
Sales | Customer 1	'	'	'
Revenue, Major Customer [Line Items]	'	'	'
Sales revenue	$73,800	$64,700	$62,900
Percentage of revenue from major customers	34.50%	48.10%	56.20%

Recovered_Sheet4

Employee Benefit and Equity Plans - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Employer contribution to the plan	$0.70	$0.50	$0.40
Intrinsic value of stock options exercised	0.4	0.1	0.3
Total tax benefit	0.2	'	'
Outstanding weighted average remaining term (in years)	'3 years 10 months 24 days	'	'
Aggregate intrinsic value of options outstanding	4.1	'	'
Weighted average remaining term of options exercisable (in years)	'4 years 1 month 6 days	'4 years 7 months 6 days	'
Aggregate intrinsic value of options exercisable	'	1.4	'
Common stock issued by compensation committee	981,544	425,209	'
Expected Dividend Yield	0.00%	0.00%	'
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	2,785,836	813,475	'
Stock Options	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Share-based compensation	0.2	0.2	0.7
Unrecognized compensation expense	0.1	'	'
Unrecognized compensation expense weighted average period, in years	'9 months 18 days	'	'
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	5.1	2.9	0.9
Unrecognized compensation expense	8.3	'	'
Unrecognized compensation expense weighted average period, in years	'2 years 3 months 18 days	'	'
Number of companies in peer group	15	13	'
Fair value of TSR awards of per share estimated on date of grant	$16.03	$11.59	$13.07
Expected Dividend Yield	0.00%	'	'
Total fair value of stock awards vested in period	$3	$0.70	'
Restricted Stock | TSR	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Fair value of TSR awards of per share estimated on date of grant	$12.59	$7.80	'

Summary_of_Stock_Option_Activi

Summary of Stock Option Activity (Detail) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Beginning Balance, Number of Shares	502,253	698,327	826,511
Granted, Number of Shares	0	0	90,074
Exercised, Number of Shares	-49,166	-52,287	-139,682
Cancelled/Forfeited, Number of Shares	-4,000	-143,787	-78,576
Ending Balance, Number of Shares	449,087	502,253	698,327
Beginning Balance, Weighted Average Exercise Price	$10.95	$12.94	$12.50
Options Exercisable December 31, 2013, Number of Shares	397,921	'	'
Granted, Weighted Average Exercise Price	$0	$0	$12.74
Exercised, Weighted Average Exercise Price	$10.85	$10.80	$9.75
Cancelled/Forfeited, Weighted Average Exercise Price	$23.28	$20.71	$13.75
Ending Balance, Weighted Average Exercise Price	$10.85	$10.95	$12.94
Options Exercisable December 31, 2013, Weighted Average Exercise Price	$10.55	'	'
Options Outstanding December 31, 2013, Weighted Average Remaining Term (in years)	'3 years 10 months 24 days	'	'
Options Exercisable December 31, 2013, Weighted Average Remaining Term (in years)	'4 years 1 month 6 days	'4 years 7 months 6 days	'
Options Outstanding December 31, 2013, Aggregate Intrinsic Value	$4,060	'	'
Options Exercisable December 31, 2013, Aggregate Intrinsic Value	$3,725	'	'

Summary_of_Issued_and_Outstand

Summary of Issued and Outstanding Stock Options (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'	'	'	'
Number Outstanding at 12/31/13	449,087	502,253	698,327	826,511
Weighted Average Remaining Contractual Life (Years), Outstanding	'3 years 10 months 24 days	'	'	'
Weighted Average Exercise Price, Outstanding	$10.85	'	'	'
Number Exercisable at 12/31/13	397,921	'	'	'
Weighted Average Exercise Price, Exercisable	$10.55	'	'	'
$5.04	'	'	'	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'	'	'	'
Exercise Price	$5.04	'	'	'
Number Outstanding at 12/31/13	46,041	'	'	'
Weighted Average Remaining Contractual Life (Years), Outstanding	'5 years 4 months 24 days	'	'	'
Weighted Average Exercise Price, Outstanding	$5.04	'	'	'
Number Exercisable at 12/31/13	46,041	'	'	'
Weighted Average Exercise Price, Exercisable	$5.04	'	'	'
$9.50	'	'	'	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'	'	'	'
Exercise Price	$9.50	'	'	'
Number Outstanding at 12/31/13	85,000	'	'	'
Weighted Average Remaining Contractual Life (Years), Outstanding	'3 years 10 months 24 days	'	'	'
Weighted Average Exercise Price, Outstanding	$9.50	'	'	'
Number Exercisable at 12/31/13	85,000	'	'	'
Weighted Average Exercise Price, Exercisable	$9.50	'	'	'
$9.99	'	'	'	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'	'	'	'
Exercise Price	$9.99	'	'	'
Number Outstanding at 12/31/13	167,333	'	'	'
Weighted Average Remaining Contractual Life (Years), Outstanding	'3 years 10 months 24 days	'	'	'
Weighted Average Exercise Price, Outstanding	$9.99	'	'	'
Number Exercisable at 12/31/13	167,333	'	'	'
Weighted Average Exercise Price, Exercisable	$9.99	'	'	'
$10.42	'	'	'	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'	'	'	'
Exercise Price	$10.42	'	'	'
Number Outstanding at 12/31/13	29,548	'	'	'
Weighted Average Remaining Contractual Life (Years), Outstanding	'6 years 6 months	'	'	'
Weighted Average Exercise Price, Outstanding	$10.42	'	'	'
Number Exercisable at 12/31/13	29,548	'	'	'
Weighted Average Exercise Price, Exercisable	$10.42	'	'	'
$11.87	'	'	'	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'	'	'	'
Exercise Price	$11.87	'	'	'
Number Outstanding at 12/31/13	3,500	'	'	'
Weighted Average Remaining Contractual Life (Years), Outstanding	'2 years 3 months 18 days	'	'	'
Weighted Average Exercise Price, Outstanding	$11.87	'	'	'
Number Exercisable at 12/31/13	2,333	'	'	'
Weighted Average Exercise Price, Exercisable	$11.87	'	'	'
$12.50	'	'	'	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'	'	'	'
Exercise Price	$12.50	'	'	'
Number Outstanding at 12/31/13	19,139	'	'	'
Weighted Average Remaining Contractual Life (Years), Outstanding	'1 year 10 months 24 days	'	'	'
Weighted Average Exercise Price, Outstanding	$12.50	'	'	'
Number Exercisable at 12/31/13	19,139	'	'	'
Weighted Average Exercise Price, Exercisable	$12.50	'	'	'
$13.01	'	'	'	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'	'	'	'
Exercise Price	$13.01	'	'	'
Number Outstanding at 12/31/13	18,526	'	'	'
Weighted Average Remaining Contractual Life (Years), Outstanding	'1 year 9 months 18 days	'	'	'
Weighted Average Exercise Price, Outstanding	$13.01	'	'	'
Number Exercisable at 12/31/13	18,526	'	'	'
Weighted Average Exercise Price, Exercisable	$13.01	'	'	'
$13.19	'	'	'	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'	'	'	'
Exercise Price	$13.19	'	'	'
Number Outstanding at 12/31/13	50,000	'	'	'
Weighted Average Remaining Contractual Life (Years), Outstanding	'2 years 9 months 18 days	'	'	'
Weighted Average Exercise Price, Outstanding	$13.19	'	'	'
Number Exercisable at 12/31/13	0	'	'	'
Weighted Average Exercise Price, Exercisable	$0	'	'	'
$22.34	'	'	'	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'	'	'	'
Exercise Price	$22.34	'	'	'
Number Outstanding at 12/31/13	30,000	'	'	'
Weighted Average Remaining Contractual Life (Years), Outstanding	'4 years 3 months 18 days	'	'	'
Weighted Average Exercise Price, Outstanding	$22.34	'	'	'
Number Exercisable at 12/31/13	30,000	'	'	'
Weighted Average Exercise Price, Exercisable	$22.34	'	'	'

Percentage_of_Awards_to_Vest_D

Percentage of Awards to Vest (Detail) (Restricted Stock)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
TSR Rank 1 - 3	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Percentage of Awards to Vest	100.00%	100.00%
TSR Rank 4 - 6	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Percentage of Awards to Vest	75.00%	'
TSR Rank 7 - 10	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Percentage of Awards to Vest	50.00%	'
TSR Rank 11 - 13	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Percentage of Awards to Vest	25.00%	'
TSR Rank 14 - 16	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Percentage of Awards to Vest	0.00%	'
TSR Rank 4 - 5	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Percentage of Awards to Vest	'	75.00%
TSR Rank 6 - 8	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Percentage of Awards to Vest	'	50.00%
TSR Rank 9 - 11	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Percentage of Awards to Vest	'	25.00%
TSR Rank 12 - 14	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Percentage of Awards to Vest	'	0.00%

Monte_Carlo_Simulation_Model_A

Monte Carlo Simulation Model Assumptions Used to Estimate Fair Value of Restricted Stock (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Expected Dividend Yield	0.00%	0.00%
Risk-Free Interest Rate	0.70%	0.30%
Expected Volatility-Rex Energy	50.50%	54.40%
Market Index	35.30%	37.00%
Expected Life	'3 years	'3 years
Minimum	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Expected Volatility-Peer Group	28.40%	31.20%
Maximum	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Expected Volatility-Peer Group	63.50%	58.60%

Summary_of_Nonvested_Stock_Act

Summary of Nonvested Stock Activity (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Stock awards, ending balance, Number of Shares	2,172,639	'	'
Stock awards, ending balance, Weighted Average Grant Date Fair Value	$14.16	'	'
Restricted Stock	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Stock awards, beginning balance, Number of Shares	1,431,573	1,229,826	814,965
Awards, Number of Shares	981,544	425,209	757,816
Vested, Number of Shares	-182,994	-70,750	'
Forfeitures, Number of Shares	-57,484	-152,712	-342,955
Stock awards, ending balance, Number of Shares	2,172,639	1,431,573	1,229,826
Stock awards, beginning balance, Weighted Average Grant Date Fair Value	$12.45	$12.11	$11.01
Awards, Weighted Average Grant Date Fair Value	$16.03	$11.59	$13.07
Vested, Weighted Average Grant Date Fair Value	$11.59	$2.05	'
Forfeitures, Weighted Average Grant Date Fair Value	$11.84	$12.13	$11.60
Stock awards, ending balance, Weighted Average Grant Date Fair Value	'	$12.45	$12.11

Impairment_Expense_Additional_

Impairment Expense - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Depreciation and Other Amortization Expenses [Line Items]	'	'	'
Impairment Expense	$32,072	$20,585	$14,631
Impairment Expense	32,072	40,355	27,808
Undeveloped Land	'	'	'
Depreciation and Other Amortization Expenses [Line Items]	'	'	'
Impairment Expense	5,800	'	1,400
Refrigeration Plant	'	'	'
Depreciation and Other Amortization Expenses [Line Items]	'	'	'
Impairment Expense	'	'	1,600
Appalachian Basin	'	'	'
Depreciation and Other Amortization Expenses [Line Items]	'	'	'
Impairment Expense	'	13,700	11,600
Illinois Basin	'	'	'
Depreciation and Other Amortization Expenses [Line Items]	'	'	'
Impairment Expense	$29,300	'	'

Net_Change_in_Capitalized_Expl

Net Change in Capitalized Exploratory Well Costs (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Project	Project	Project
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Beginning Balance at January 1,	$36,968	$11,756	$1,637
Additions to capitalized exploratory well costs pending the determination of estimated proved reserves	171,087	95,980	106,045
Divested wells	0	0	0
Reclassification of wells, facilities, and equipment based on the determination of estimated proved reserves	-202,323	-70,518	-95,926
Capitalized exploratory well costs charged to expense	-1	-250	0
Ending Balance at December 31,	5,731	36,968	11,756
Less exploratory well costs that have been capitalized for a period of one year or less	-3,597	-36,630	-11,756
Capitalized exploratory well costs for a period of greater than one year	$2,134	$338	$0
Number of projects that have exploratory well costs capitalized for a period of more than one year	3	2	0

Suspended_Exploratory_Well_Cos2

Suspended Exploratory Well Costs - Additional Information (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified
Oil and Gas In Process Activities [Line Items]	'	'	'	'
Capitalized Exploratory Well Costs	$5,731	$36,968	$11,756	$1,637
Appalachian Basin	'	'	'	'
Oil and Gas In Process Activities [Line Items]	'	'	'	'
Capitalized Exploratory Well Costs	$2,100	'	'	'
Capitalized Exploratory Number of Wells	3	'	'	'

Recovered_Sheet5

Costs Incurred in Oil and Natural Gas Property Acquisitions and Development (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Acquisition of Properties	'		'		'
Exploration Costs	$11,408		$4,782		$2,507
Development Costs	3,651		1,156		1,126
Subtotal	337,614		238,854		302,416
Asset Retirement Obligations	3,031		4,480		316
Total Costs Incurred	340,540		241,182		252,172
Consolidated Entities	'		'		'
Acquisition of Properties	'		'		'
Proved	2,445		1,474		9
Unproved	39,291		49,331		76,852
Exploration Costs	231,112	[1]	128,748	[1]	113,075	[1]
Development Costs	64,661	[1]	57,149	[1]	61,920	[1]
Subtotal	337,509		236,702		251,856
Asset Retirement Obligations	3,031		4,480		316
Total Costs Incurred	340,540		241,182		252,172
Equity Method Investee	'		'		'
Acquisition of Properties	'		'		'
Proved	0		0		0
Unproved	0		0		0
Exploration Costs	0		0		0
Development Costs	1,958	[1]	4,316	[1]	12,682	[1]
Subtotal	$1,958		$4,316		$12,682
[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, 2013		Dec. 31, 2012		Dec. 31, 2011
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Total Costs Incurred	$340,540		$241,182		$252,172
Contributions to Equity Method Investments	-2,493		-4,087		-23,204
DJ Basin Expenditures	2		3,146		24,029
Exploration Expense	-11,408		-4,782		-2,507
Asset Retirement Obligations	-3,031		-4,480		-316
Depreciation for Support Equipment and Facilities	-5,024		-4,187		-3,308
Corporate Expenditures	3,651		1,156		1,126
Other	10,391	[1]	2,732	[1]	8,016	[1]
Subtotal	$337,614		$238,854		$302,416
[1]	Represents corporate capital, 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, 2013	Dec. 31, 2012
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	$749,680	$485,448
Pipelines and Support Equipment	33,119	31,231
Field Operation Vehicles and Other Equipment	21,608	13,412
Wells and Facilities in Progress	69,886	87,800
Unproven Properties	189,385	165,503
Total	1,063,678	783,394
Less Accumulated Depreciation and Depletion	-184,836	-141,769
Total	878,842	641,625
Equity Method Investee	'	'
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'
Pipelines and Support Equipment	19,270	17,524
Field Operation Vehicles and Other Equipment	0	0
Wells and Facilities in Progress	238	26
Total	19,508	17,550
Less Accumulated Depreciation and Depletion	-1,818	-1,077
Total	$17,690	$16,473

Summary_of_Changes_in_Estimate

Summary of Changes in Estimated Reserves of Oil and Natural Gas Wells (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MMcfe	MMcfe	MMcfe
	Mcf	Mcf	Mcf
Reserve Quantities [Line Items]	'	'	'
Estimated Proved Reserves-End of Period	65,500,000	'	'
Estimated Proved Reserves-Beginning of Period	618,050	366,188.30	201,678.70
Extensions, Discoveries and Additions	312,461.10	196,583.60	155,849.10
Revisions	-46,882.30	75,026.40	22,881	[1]
Improved Recovery	'	4,549.80	'
Purchases	6	259.2	'
Production	-33,850.20	-24,557.30	-14,220.50	[2]
Estimated Proved Reserves-End of Period	849,784.60	618,050	366,188.30
Proved Developed Reserves Energy Equivalents	356,451.40	257,913.40	173,250.90
Proved Undeveloped Reserves Energy Equivalents	493,333.20	360,136.60	192,937.40
Oil	'	'	'
Reserve Quantities [Line Items]	'	'	'
Estimated Proved Reserves-Beginning of Period	9,375,700	8,181,200	8,142,800
Extensions, Discoveries and Additions	595,600	474,600	156,500
Revisions	-438,500	650,500	576,400	[1]
Improved Recovery	'	758,300	'
Purchases	1,000	43,200	'
Production	-914,200	-732,100	-694,500	[2]
Estimated Proved Reserves-End of Period	8,619,600	9,375,700	8,181,200
Proved Developed Reserves	7,742,500	9,216,100	8,181,200
Proved Undeveloped Reserves	877,100	159,600	0
Natural Gas Liquids	'	'	'
Reserve Quantities [Line Items]	'	'	'
Estimated Proved Reserves-Beginning of Period	31,679,900	7,134,800	4,200,000
Extensions, Discoveries and Additions	19,956,100	12,813,600	2,640,400
Revisions	-4,685,600	12,089,500	484,600	[1]
Improved Recovery	'	0	'
Purchases	0	0	'
Production	-819,700	-358,000	-190,200	[2]
Estimated Proved Reserves-End of Period	46,130,700	31,679,900	7,134,800
Proved Developed Reserves	16,322,500	10,143,700	2,218,400
Proved Undeveloped Reserves	29,808,200	21,536,200	4,916,400
Natural Gas	'	'	'
Reserve Quantities [Line Items]	'	'	'
Estimated Proved Reserves-Beginning of Period	371,716,400	274,292,300	127,621,900
Extensions, Discoveries and Additions	189,150,900	116,854,400	139,067,700
Revisions	-16,137,700	-1,413,600	16,515,000	[1]
Improved Recovery	'	0	'
Purchases	0	0	'
Production	-23,446,800	-18,016,700	-8,912,300	[2]
Estimated Proved Reserves-End of Period	521,282,800	371,716,400	274,292,300
Proved Developed Reserves	212,061,400	141,754,600	110,853,300
Proved Undeveloped Reserves	309,221,400	229,961,800	163,439,000
[1]	Revisions includes 120.9 MBbls and 725.4 MMcfe related to our successful ASP pilot in the Illinois Basin.
[2]	Gas production excludes certain production associated with gas sales contracts for which we do not recognize reserves.

Summary_of_Changes_in_Estimate1

Summary of Changes in Estimated Reserves of Oil and Natural Gas Wells (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MMcfe	MMcfe	MMcfe
Reserve Quantities [Line Items]	'	'	'
Revisions, Mcf Equivalents	-46,882.30	75,026.40	22,881	[1]
Illinois Basin	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions, Oil and NGLs	'	'	120,900
Revisions, Mcf Equivalents	'	'	725.4
[1]	Revisions includes 120.9 MBbls and 725.4 MMcfe related to our successful ASP pilot in the Illinois Basin.

Oil_and_Natural_Gas_Reserve_Qu2

Oil and Natural Gas Reserve Quantities - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
	Location
	Bcfe
	Mcf
Reserve Quantities [Line Items]	'	'	'	'
Estimated proved undeveloped reserves, gross	21	'	'	'
Estimated proved undeveloped reserves, net	15.7	'	'	'
Discount rate	10.00%	'	'	'
Net reserve volume associated with locations	65,500,000	'	'	'
Net reserve volume percentage of total estimated proved reserves	7.70%	'	'	'
Period of development of proved locations	'5 years	'	'	'
Oil price	'	'	92.45	76.03
Natural gas price	'	2.94	4.55	'
Extension, discoveries and other additions	27.3	'	'	'
Maximum	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Period of development of proved locations	'36 months	'	'	'
Appalachian Basin	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Estimated proved undeveloped reserves, gross	136	'	'	'
Oil	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Net reserve volume associated with locations	8,619,600	9,375,700	8,181,200	8,142,800
Extension, discoveries and other additions	0.6	0.5	0.2	'
Natural Gas Liquids	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Net reserve volume associated with locations	46,130,700	31,679,900	7,134,800	4,200,000
Extension, discoveries and other additions	20	12.8	2.6	'
Natural Gas	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Net reserve volume associated with locations	521,282,800	371,716,400	274,292,300	127,621,900
Extension, discoveries and other additions	189.1	116.9	139.1	'
Operated Areas | Minimum	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Average estimated ultimate recovery per well	'	'	4,400,000	'
Operated Areas | Maximum	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Average estimated ultimate recovery per well	'	'	5,300,000	'
Nonoperated Areas | Minimum	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Average estimated ultimate recovery per well	'	'	3,000,000	'
Nonoperated Areas | Maximum	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Average estimated ultimate recovery per well	'	'	4,200,000	'
Marcellus Shale	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Percentage of estimated proved reserves	'	'	84.00%	'

Recovered_Sheet6

Standardized Measure of Discounted Future Net Cash Flows - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'
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 (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'		'		'		'
Future Cash Inflows	$3,899,878	[1]	$2,988,231	[2]	$2,333,513	[3]	'
Production	-1,619,629		-1,387,653		-880,077		'
Abandonment	-95,183		-85,859		-65,560		'
Development	-517,875		-324,873		-251,821		'
Net Future Cash Inflow Before Income Taxes	1,667,191		1,189,846		1,136,055		'
Future Income Tax Expense	-359,322		-245,078		-277,568		'
Total Future Net Cash Flows Before 10.0% Discount	1,307,869		944,768		858,487		'
Less: Effect of a 10.0% Discount Factor	-778,756		-548,645		-444,552		'
Standardized Measure of Discounted Future Net Cash Flows	$529,113		$396,123		$413,935		$188,065
[1]	Calculated using weighted average prices of $3.588 per Mcf, $94.28 per barrel of oil and $26.37 per barrel of NGLs
[2]	Calculated using weighted average prices of $2.94 per Mcf, $90.92 per barrel of oil and $32.91 per barrel of NGLs
[3]	Calculated using weighted average prices of $4.55 per Mcf, $92.45 per barrel of oil and $46.34 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) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
weighted average prices	3.588	2.94	4.55
Oil	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
weighted average prices	94.28	90.92	92.45
Natural Gas Liquids	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
weighted average prices	26.37	32.91	46.34

Principal_Sources_of_Change_in

Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Standardized Measure-Beginning of Period	$396,123	$413,935	$188,065
Changes in Prices and Production Costs	72,503	-198,433	29,223
Revisions in Quantities	-51,289	91,462	40,525
Changes in Future Development Costs	22,341	-3,885	-19,539
Accretion of Discount and Timing of Future Cash Flows	47,571	52,093	25,218
Net Change in Income Tax	31,433	27,405	-42,875
Purchase (Sale) of Reserves in Place	0	1,188	0
Plus Extensions, Discoveries, and Other Additions	170,846	88,749	159,047
Development Costs Incurred	64,661	57,149	61,290
Sales of Product-Net of Production Costs	-151,781	-86,936	-78,763
Changes in Timing and Other	-73,295	-46,604	51,744
Standardized Measure-End of Period	$529,113	$396,123	$413,935

Results_of_Operations_Detail

Results of Operations (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Expenses	'		'		'
Results of Operations for Oil and Gas Producing Activities	$15,085		$9,269		$22,461
Consolidated Entities	'		'		'
Revenues	'		'		'
Oil and Natural Gas Sales	213,919		134,574		111,879
Expenses	'		'		'
Production and Lease Operating Expense	62,138		47,638		33,116
Impairment Expense	32,072		20,505		14,316
Exploration Expense	11,408		4,782		2,507
Depletion, Depreciation, Amortization and Accretion	62,386		44,955		27,670
Total Costs	168,004		117,880		77,609
Pre-Tax Operating Income (Loss)	45,915		16,694		34,270
Income Tax Benefit	30,579	[1]	6,778	[1]	10,760	[1]
Results of Operations for Oil and Gas Producing Activities	15,336		9,916		23,510
Equity Method Investee	'		'		'
Expenses	'		'		'
Depletion, Depreciation, Amortization and Accretion	752		1,082		1,568
Total Costs	752		1,082		1,568
Pre-Tax Operating Income (Loss)	-752		-1,082		-1,568
Income Tax Benefit	501	[1]	435	[1]	519	[1]
Results of Operations for Oil and Gas Producing Activities	($251)		($647)		($1,049)
[1]	Computed using the effective rate for continuing operations for each period: 66.6% in 2013; 40.6% in 2012 and; 31.4% in 2011.

Results_of_Operations_Parenthe

Results of Operations (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Effective tax rate	66.60%	40.60%	31.40%

Litigation_Additional_Informat

Litigation - Additional Information (Detail) (USD $)	1 Months Ended
	Jul. 31, 2011	Jul. 31, 2009
		Plaintiff
Litigation [Line Items]	'	'
Number of plaintiffs	'	5
Prepaid rental	$2,500	'
Rental agreement period	'5 years	'
Royalty payment	15.00%	'
Amount agreed to pay plantiff	30,000	'
Amount deposited for distribution to class members and for attorney's fees, costs and expenses	$2,500,000	'

Unaudited_Financial_Informatio

Unaudited Financial Information on Quarterly Basis (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Quarterly Results Of Operations [Line Items]	'	'	'	'	'	'	'	'	'		'		'
Revenues	$72,127	$62,974	$55,360	$47,470	$45,119	$38,929	$30,257	$33,834	$237,931		$148,139		$114,606
Costs and Expenses	85,401	61,142	41,919	49,810	46,157	40,671	-25,936	30,006	222,257		151,221		104,817
Net Income (Loss) From Continuing Operations	-13,274	1,832	13,441	-2,340	-1,038	-1,742	56,193	3,828	-1,898		56,422		18,088
Net Loss From Discontinued Operations	-691	0	520	-61	-2,280	-258	-3,050	-5,355	-232		-10,943		-33,457
NET INCOME (LOSS)	-13,965	1,832	13,961	-2,401	-3,318	-2,000	53,143	-1,527	-573		46,298		-15,376
Net Income (Loss) Attributable to Noncontrolling Interests	645	258	221	433	303	193	222	101	1,557		819		-7
Net Income (Loss) Attributable to Rex Energy	($14,610)	$1,574	$13,740	($2,834)	($3,621)	($2,193)	$52,921	($1,628)	($2,130)		$45,479		($15,369)
Income (Loss) per Common Share Attributable to Rex Common Shareholders:	'	'	'	'	'	'	'	'	'		'		'
Basic-Continuing Operations Attributable to Rex Energy	($0.26)	$0.03	$0.25	($0.05)	($0.03)	($0.04)	$1.08	$0.08	($0.04)	[1]	$1.09	[1]	$0.41	[1]
Basic-Discontinued Operations	($0.01)	$0	$0.01	$0	($0.04)	$0	($0.06)	($0.11)	$0	[1]	($0.21)	[1]	($0.76)	[1]
Basic-Net Income (Loss)	($0.27)	$0.03	$0.26	($0.05)	($0.07)	($0.04)	$1.02	($0.03)	($0.04)	[1]	$0.88	[1]	($0.35)	[1]
Basic-Weighted Average Shares Outstanding	52,705	52,626	52,555	52,367	52,278	52,036	52,009	48,744	52,572		51,543		43,930
Diluted-Continuing Operations Attributable to Rex Energy	($0.26)	$0.03	$0.25	($0.05)	($0.03)	($0.04)	$1.06	$0.08	($0.04)	[1]	$1.08	[1]	$0.41	[1]
Diluted-Discontinued Operations	($0.01)	$0	$0.01	$0	($0.04)	$0	($0.06)	($0.11)	$0	[1]	($0.21)	[1]	($0.76)	[1]
Diluted-Net Income (Loss)	($0.27)	$0.03	$0.26	($0.05)	($0.07)	($0.04)	$1	($0.03)	($0.04)	[1]	$0.87	[1]	($0.35)	[1]
Diluted-Weighted Average Shares Outstanding	52,705	53,293	52,911	52,367	52,278	52,036	52,876	49,693	52,572		52,025		44,476
[1]	All earnings per share amounts are attributable to Rex common shareholders.

Condensed_Consolidating_Financ2

Condensed Consolidating Financial Information - Additional Information (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Condensed Financial Statements, Captions [Line Items]	'	'
Senior Notes	$350,000	$250,000

Condensed_Consolidating_Balanc

Condensed Consolidating Balance Sheets (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified
Current Assets	'	'	'	'
Cash and Cash Equivalents	$1,900	$43,975	$11,796	$11,008
Accounts Receivable	38,863	24,980	'	'
Taxes Receivable	5,189	6,429	'	'
Short-Term Derivative Instruments	5,668	12,005	'	'
Assets Held For Sale	0	2,279	'	'
Current Deferred Tax Asset	3,451	0	'	'
Inventory, Prepaid Expenses and Other	2,207	1,316	'	'
Total Current Assets	57,278	90,984	'	'
Property and Equipment (Successful Efforts Method)	'	'	'	'
Evaluated Oil and Gas Properties	749,680	485,448	'	'
Unevaluated Oil and Gas Properties	189,385	165,503	'	'
Other Property and Equipment	70,115	50,073	'	'
Wells and Facilities in Progress	76,545	92,913	'	'
Pipelines	7,678	6,116	'	'
Total Property and Equipment	1,093,403	800,053	'	'
Less: Accumulated Depreciation, Depletion and Amortization	-190,521	-146,038	'	'
Net Property and Equipment	902,882	654,015	'	'
Deferred Financing Costs and Other Assets-Net	11,993	10,029	'	'
Equity Method Investments	18,708	16,978	41,683	'
Intercompany Receivables	0	0	'	'
Investment in Subsidiaries-Net	0	0	'	'
Long-Term Derivative Instruments	535	704	'	'
Total Assets	991,396	772,710	601,551	'
Current Liabilities	'	'	'	'
Accounts Payable	31,103	29,448	'	'
Current Maturities of Long-Term Debt	6,743	1,686	'	'
Accrued Liabilities	54,450	23,019	'	'
Short-Term Derivative Instruments	4,663	1,389	'	'
Current Deferred Tax Liability	0	539	'	'
Liabilities Related to Assets Held for Sale	0	52	'	'
Total Current Liabilities	96,959	56,133	'	'
8.875% Senior Notes Due 2020	350,000	250,000	'	'
Premium (Discount) on Senior Notes	3,078	-1,742	'	'
Senior Secured Line of Credit and Long-Term Debt	62,191	991	'	'
Long-Term Derivative Instruments	1,765	1,510	'	'
Long-Term Deferred Tax Liability	29,446	23,625	'	'
Other Deposits and Liabilities	4,992	5,675	'	'
Future Abandonment Cost	26,040	24,224	'	'
Intercompany Payables	0	0	'	'
Total Liabilities	574,471	360,416	'	'
Stockholders' Equity	'	'	'	'
Common Stock	54	52	'	'
Additional Paid-In Capital	456,554	451,062	'	'
Accumulated Deficit	-41,725	-39,595	'	'
Rex Energy Stockholders' Equity	414,883	411,519	'	'
Noncontrolling Interests	2,042	775	'	'
Total Stockholders' Equity	416,925	412,294	292,274	304,676
Total Liabilities and Stockholders' Equity	991,396	772,710	'	'
Guarantor Subsidiaries	'	'	'	'
Current Assets	'	'	'	'
Cash and Cash Equivalents	1,386	4,227	11,337	10,595
Accounts Receivable	32,283	26,490	'	'
Taxes Receivable	0	0	'	'
Short-Term Derivative Instruments	5,180	12,005	'	'
Assets Held For Sale	'	0	'	'
Current Deferred Tax Asset	0	'	'	'
Inventory, Prepaid Expenses and Other	2,092	1,277	'	'
Total Current Assets	40,941	43,999	'	'
Property and Equipment (Successful Efforts Method)	'	'	'	'
Evaluated Oil and Gas Properties	752,781	486,706	'	'
Unevaluated Oil and Gas Properties	189,385	165,503	'	'
Other Property and Equipment	57,409	45,613	'	'
Wells and Facilities in Progress	70,759	88,204	'	'
Pipelines	7,678	6,116	'	'
Total Property and Equipment	1,078,012	792,142	'	'
Less: Accumulated Depreciation, Depletion and Amortization	-188,699	-145,514	'	'
Net Property and Equipment	889,313	646,628	'	'
Deferred Financing Costs and Other Assets-Net	2,421	2,427	'	'
Equity Method Investments	18,708	16,978	'	'
Intercompany Receivables	0	3,795	'	'
Investment in Subsidiaries-Net	4,442	-227	'	'
Long-Term Derivative Instruments	535	704	'	'
Total Assets	956,360	714,304	'	'
Current Liabilities	'	'	'	'
Accounts Payable	33,613	29,230	'	'
Current Maturities of Long-Term Debt	1,339	588	'	'
Accrued Liabilities	45,196	20,489	'	'
Short-Term Derivative Instruments	4,663	1,389	'	'
Current Deferred Tax Liability	'	0	'	'
Liabilities Related to Assets Held for Sale	'	0	'	'
Total Current Liabilities	84,811	51,696	'	'
8.875% Senior Notes Due 2020	0	0	'	'
Premium (Discount) on Senior Notes	0	0	'	'
Senior Secured Line of Credit and Long-Term Debt	137	26	'	'
Long-Term Derivative Instruments	1,071	1,510	'	'
Long-Term Deferred Tax Liability	0	0	'	'
Other Deposits and Liabilities	4,992	5,675	'	'
Future Abandonment Cost	26,027	24,224	'	'
Intercompany Payables	554,329	367,704	'	'
Total Liabilities	671,367	450,835	'	'
Stockholders' Equity	'	'	'	'
Common Stock	0	0	'	'
Additional Paid-In Capital	177,144	177,143	'	'
Accumulated Deficit	107,849	86,326	'	'
Rex Energy Stockholders' Equity	284,993	263,469	'	'
Noncontrolling Interests	0	0	'	'
Total Stockholders' Equity	284,993	263,469	'	'
Total Liabilities and Stockholders' Equity	956,360	714,304	'	'
Non-Guarantor Subsidiaries	'	'	'	'
Current Assets	'	'	'	'
Cash and Cash Equivalents	509	824	409	363
Accounts Receivable	9,882	3,367	'	'
Taxes Receivable	0	0	'	'
Short-Term Derivative Instruments	0	0	'	'
Assets Held For Sale	'	2,279	'	'
Current Deferred Tax Asset	0	'	'	'
Inventory, Prepaid Expenses and Other	89	13	'	'
Total Current Assets	10,480	6,483	'	'
Property and Equipment (Successful Efforts Method)	'	'	'	'
Evaluated Oil and Gas Properties	0	0	'	'
Unevaluated Oil and Gas Properties	0	0	'	'
Other Property and Equipment	12,706	4,455	'	'
Wells and Facilities in Progress	6,576	4,780	'	'
Pipelines	0	0	'	'
Total Property and Equipment	19,282	9,235	'	'
Less: Accumulated Depreciation, Depletion and Amortization	-2,172	-674	'	'
Net Property and Equipment	17,110	8,561	'	'
Deferred Financing Costs and Other Assets-Net	206	199	'	'
Equity Method Investments	0	0	'	'
Intercompany Receivables	0	0	'	'
Investment in Subsidiaries-Net	1,197	-232	'	'
Long-Term Derivative Instruments	0	0	'	'
Total Assets	28,993	15,011	'	'
Current Liabilities	'	'	'	'
Accounts Payable	794	462	'	'
Current Maturities of Long-Term Debt	5,404	1,098	'	'
Accrued Liabilities	6,287	1,036	'	'
Short-Term Derivative Instruments	0	0	'	'
Current Deferred Tax Liability	'	0	'	'
Liabilities Related to Assets Held for Sale	'	52	'	'
Total Current Liabilities	12,485	2,648	'	'
8.875% Senior Notes Due 2020	0	0	'	'
Premium (Discount) on Senior Notes	0	0	'	'
Senior Secured Line of Credit and Long-Term Debt	3,054	5,598	'	'
Long-Term Derivative Instruments	0	0	'	'
Long-Term Deferred Tax Liability	0	0	'	'
Other Deposits and Liabilities	0	0	'	'
Future Abandonment Cost	13	0	'	'
Intercompany Payables	74,188	76,360	'	'
Total Liabilities	89,740	84,606	'	'
Stockholders' Equity	'	'	'	'
Common Stock	0	0	'	'
Additional Paid-In Capital	6,488	-407	'	'
Accumulated Deficit	-67,720	-69,144	'	'
Rex Energy Stockholders' Equity	-61,232	-69,551	'	'
Noncontrolling Interests	485	-44	'	'
Total Stockholders' Equity	-60,747	-69,595	'	'
Total Liabilities and Stockholders' Equity	28,993	15,011	'	'
Parent Company	'	'	'	'
Current Assets	'	'	'	'
Cash and Cash Equivalents	5	38,924	50	50
Accounts Receivable	0	0	'	'
Taxes Receivable	5,189	6,429	'	'
Short-Term Derivative Instruments	488	0	'	'
Assets Held For Sale	'	0	'	'
Current Deferred Tax Asset	3,451	'	'	'
Inventory, Prepaid Expenses and Other	26	26	'	'
Total Current Assets	9,159	45,379	'	'
Property and Equipment (Successful Efforts Method)	'	'	'	'
Evaluated Oil and Gas Properties	0	0	'	'
Unevaluated Oil and Gas Properties	0	0	'	'
Other Property and Equipment	0	0	'	'
Wells and Facilities in Progress	0	0	'	'
Pipelines	0	0	'	'
Total Property and Equipment	0	0	'	'
Less: Accumulated Depreciation, Depletion and Amortization	0	0	'	'
Net Property and Equipment	0	0	'	'
Deferred Financing Costs and Other Assets-Net	9,366	7,403	'	'
Equity Method Investments	0	0	'	'
Intercompany Receivables	628,517	440,269	'	'
Investment in Subsidiaries-Net	216,945	193,790	'	'
Long-Term Derivative Instruments	0	0	'	'
Total Assets	863,987	686,841	'	'
Current Liabilities	'	'	'	'
Accounts Payable	0	0	'	'
Current Maturities of Long-Term Debt	0	0	'	'
Accrued Liabilities	2,967	1,494	'	'
Short-Term Derivative Instruments	0	0	'	'
Current Deferred Tax Liability	'	539	'	'
Liabilities Related to Assets Held for Sale	'	0	'	'
Total Current Liabilities	2,967	2,033	'	'
8.875% Senior Notes Due 2020	350,000	250,000	'	'
Premium (Discount) on Senior Notes	3,078	-1,742	'	'
Senior Secured Line of Credit and Long-Term Debt	59,000	0	'	'
Long-Term Derivative Instruments	694	0	'	'
Long-Term Deferred Tax Liability	29,446	23,625	'	'
Other Deposits and Liabilities	0	0	'	'
Future Abandonment Cost	0	0	'	'
Intercompany Payables	0	0	'	'
Total Liabilities	445,185	273,916	'	'
Stockholders' Equity	'	'	'	'
Common Stock	54	52	'	'
Additional Paid-In Capital	456,554	451,062	'	'
Accumulated Deficit	-37,806	-38,189	'	'
Rex Energy Stockholders' Equity	418,802	412,925	'	'
Noncontrolling Interests	0	0	'	'
Total Stockholders' Equity	418,802	412,925	'	'
Total Liabilities and Stockholders' Equity	863,987	686,841	'	'
Eliminations	'	'	'	'
Current Assets	'	'	'	'
Cash and Cash Equivalents	0	0	0	0
Accounts Receivable	-3,302	-4,877	'	'
Taxes Receivable	0	0	'	'
Short-Term Derivative Instruments	0	0	'	'
Assets Held For Sale	'	0	'	'
Current Deferred Tax Asset	0	'	'	'
Inventory, Prepaid Expenses and Other	0	0	'	'
Total Current Assets	-3,302	-4,877	'	'
Property and Equipment (Successful Efforts Method)	'	'	'	'
Evaluated Oil and Gas Properties	-3,101	-1,258	'	'
Unevaluated Oil and Gas Properties	0	0	'	'
Other Property and Equipment	0	5	'	'
Wells and Facilities in Progress	-790	-71	'	'
Pipelines	0	0	'	'
Total Property and Equipment	-3,891	-1,324	'	'
Less: Accumulated Depreciation, Depletion and Amortization	350	150	'	'
Net Property and Equipment	-3,541	-1,174	'	'
Deferred Financing Costs and Other Assets-Net	0	0	'	'
Equity Method Investments	0	0	'	'
Intercompany Receivables	-628,517	-444,064	'	'
Investment in Subsidiaries-Net	-222,584	-193,331	'	'
Long-Term Derivative Instruments	0	0	'	'
Total Assets	-857,944	-643,446	'	'
Current Liabilities	'	'	'	'
Accounts Payable	-3,304	-244	'	'
Current Maturities of Long-Term Debt	0	0	'	'
Accrued Liabilities	0	0	'	'
Short-Term Derivative Instruments	0	0	'	'
Current Deferred Tax Liability	'	0	'	'
Liabilities Related to Assets Held for Sale	'	0	'	'
Total Current Liabilities	-3,304	-244	'	'
8.875% Senior Notes Due 2020	0	0	'	'
Premium (Discount) on Senior Notes	0	0	'	'
Senior Secured Line of Credit and Long-Term Debt	0	-4,633	'	'
Long-Term Derivative Instruments	0	0	'	'
Long-Term Deferred Tax Liability	0	0	'	'
Other Deposits and Liabilities	0	0	'	'
Future Abandonment Cost	0	0	'	'
Intercompany Payables	-628,517	-444,064	'	'
Total Liabilities	-631,821	-448,941	'	'
Stockholders' Equity	'	'	'	'
Common Stock	0	0	'	'
Additional Paid-In Capital	-183,632	-176,736	'	'
Accumulated Deficit	-44,048	-18,588	'	'
Rex Energy Stockholders' Equity	-227,680	-195,324	'	'
Noncontrolling Interests	1,557	819	'	'
Total Stockholders' Equity	-226,123	-194,505	'	'
Total Liabilities and Stockholders' Equity	($857,944)	($643,446)	'	'

Condensed_Consolidating_Balanc1

Condensed Consolidating Balance Sheets (Parenthetical) (Detail) (8.875% Senior Notes)	Dec. 31, 2013	Dec. 31, 2012	Dec. 12, 2012	Dec. 31, 2011
8.875% Senior Notes	'	'	'	'
Condensed Financial Statements, Captions [Line Items]	'	'	'	'
Interest rate	8.88%	8.88%	8.88%	8.88%
Due date	'2020	'2020	'	'

Condensed_Consolidating_Statem

Condensed Consolidating Statements of Operations (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
OPERATING REVENUE	'	'	'	'	'	'	'	'	'	'	'
Oil, Natural Gas and NGL Sales	'	'	'	'	'	'	'	'	$213,919	$134,574	$111,879
Field Services Revenue	'	'	'	'	'	'	'	'	23,812	13,403	2,518
Other Revenue	'	'	'	'	'	'	'	'	200	162	209
TOTAL OPERATING REVENUE	72,127	62,974	55,360	47,470	45,119	38,929	30,257	33,834	237,931	148,139	114,606
OPERATING EXPENSES	'	'	'	'	'	'	'	'	'	'	'
Production and Lease Operating Expense	'	'	'	'	'	'	'	'	62,138	47,638	33,116
General and Administrative Expense	'	'	'	'	'	'	'	'	33,126	23,345	23,636
Loss on Disposal of Asset	'	'	'	'	'	'	'	'	1,647	58	502
Impairment Expense	'	'	'	'	'	'	'	'	32,072	20,585	14,631
Exploration Expense	'	'	'	'	'	'	'	'	11,408	4,782	2,507
Depreciation, Depletion, Amortization and Accretion	'	'	'	'	'	'	'	'	63,944	45,437	27,856
Field Services Operating Expense	'	'	'	'	'	'	'	'	17,330	8,240	1,750
Other Operating Expense	'	'	'	'	'	'	'	'	592	1,136	819
TOTAL OPERATING EXPENSES	85,401	61,142	41,919	49,810	46,157	40,671	-25,936	30,006	222,257	151,221	104,817
INCOME (LOSS) FROM OPERATIONS	'	'	'	'	'	'	'	'	15,674	-3,082	9,789
OTHER INCOME (EXPENSE)	'	'	'	'	'	'	'	'	'	'	'
Interest Expense	'	'	'	'	'	'	'	'	-22,782	-6,443	-2,514
Gain (Loss) on Derivatives, Net	'	'	'	'	'	'	'	'	-2,908	10,687	18,916
Other Income	'	'	'	'	'	'	'	'	6,653	98,549	79
Income (Loss) from Equity Method Investments	'	'	'	'	'	'	'	'	-763	-3,921	81
Income (Loss) From Equity in Consolidated Subsidiaries	'	'	'	'	'	'	'	'	0	0	0
TOTAL OTHER INCOME (LOSS)	'	'	'	'	'	'	'	'	-19,800	98,872	16,562
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX	'	'	'	'	'	'	'	'	-4,126	95,790	26,351
Income Tax (Expense) Benefit	'	'	'	'	'	'	'	'	3,785	-38,549	-8,270
INCOME (LOSS) FROM CONTINUING OPERATIONS	'	'	'	'	'	'	'	'	-341	57,241	18,081
Loss From Discontinued Operations, Net of Income Taxes	-691	0	520	-61	-2,280	-258	-3,050	-5,355	-232	-10,943	-33,457
Net Income (Loss)	-13,965	1,832	13,961	-2,401	-3,318	-2,000	53,143	-1,527	-573	46,298	-15,376
Net Income Attributable to Noncontrolling Interests	645	258	221	433	303	193	222	101	1,557	819	-7
Net Income (Loss) Attributable to Rex Energy	-14,610	1,574	13,740	-2,834	-3,621	-2,193	52,921	-1,628	-2,130	45,479	-15,369
Guarantor Subsidiaries	'	'	'	'	'	'	'	'	'	'	'
OPERATING REVENUE	'	'	'	'	'	'	'	'	'	'	'
Oil, Natural Gas and NGL Sales	'	'	'	'	'	'	'	'	213,919	134,574	111,879
Field Services Revenue	'	'	'	'	'	'	'	'	0	0	0
Other Revenue	'	'	'	'	'	'	'	'	200	218	209
TOTAL OPERATING REVENUE	'	'	'	'	'	'	'	'	214,119	134,792	112,088
OPERATING EXPENSES	'	'	'	'	'	'	'	'	'	'	'
Production and Lease Operating Expense	'	'	'	'	'	'	'	'	62,138	47,618	33,106
General and Administrative Expense	'	'	'	'	'	'	'	'	25,376	19,283	21,424
Loss on Disposal of Asset	'	'	'	'	'	'	'	'	1,601	50	353
Impairment Expense	'	'	'	'	'	'	'	'	32,072	20,505	14,316
Exploration Expense	'	'	'	'	'	'	'	'	11,395	4,782	2,507
Depreciation, Depletion, Amortization and Accretion	'	'	'	'	'	'	'	'	62,540	44,993	27,672
Field Services Operating Expense	'	'	'	'	'	'	'	'	0	0	0
Other Operating Expense	'	'	'	'	'	'	'	'	592	1,136	819
TOTAL OPERATING EXPENSES	'	'	'	'	'	'	'	'	195,714	138,367	100,197
INCOME (LOSS) FROM OPERATIONS	'	'	'	'	'	'	'	'	18,405	-3,575	11,891
OTHER INCOME (EXPENSE)	'	'	'	'	'	'	'	'	'	'	'
Interest Expense	'	'	'	'	'	'	'	'	-64	-55	-107
Gain (Loss) on Derivatives, Net	'	'	'	'	'	'	'	'	-2,703	10,687	18,916
Other Income	'	'	'	'	'	'	'	'	6,739	99,575	13
Income (Loss) from Equity Method Investments	'	'	'	'	'	'	'	'	-763	-3,921	81
Income (Loss) From Equity in Consolidated Subsidiaries	'	'	'	'	'	'	'	'	-33	-68	-53
TOTAL OTHER INCOME (LOSS)	'	'	'	'	'	'	'	'	3,176	106,218	18,850
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX	'	'	'	'	'	'	'	'	21,581	102,643	30,741
Income Tax (Expense) Benefit	'	'	'	'	'	'	'	'	-14,409	-41,772	-9,927
INCOME (LOSS) FROM CONTINUING OPERATIONS	'	'	'	'	'	'	'	'	7,172	60,871	20,814
Loss From Discontinued Operations, Net of Income Taxes	'	'	'	'	'	'	'	'	0	0	0
Net Income (Loss)	'	'	'	'	'	'	'	'	7,172	60,871	20,814
Net Income Attributable to Noncontrolling Interests	'	'	'	'	'	'	'	'	0	0	0
Net Income (Loss) Attributable to Rex Energy	'	'	'	'	'	'	'	'	7,172	60,871	20,814
Non-Guarantor Subsidiaries	'	'	'	'	'	'	'	'	'	'	'
OPERATING REVENUE	'	'	'	'	'	'	'	'	'	'	'
Oil, Natural Gas and NGL Sales	'	'	'	'	'	'	'	'	0	0	0
Field Services Revenue	'	'	'	'	'	'	'	'	32,583	15,637	3,546
Other Revenue	'	'	'	'	'	'	'	'	0	0	0
TOTAL OPERATING REVENUE	'	'	'	'	'	'	'	'	32,583	15,637	3,546
OPERATING EXPENSES	'	'	'	'	'	'	'	'	'	'	'
Production and Lease Operating Expense	'	'	'	'	'	'	'	'	0	20	10
General and Administrative Expense	'	'	'	'	'	'	'	'	2,416	1,007	586
Loss on Disposal of Asset	'	'	'	'	'	'	'	'	46	8	149
Impairment Expense	'	'	'	'	'	'	'	'	0	80	315
Exploration Expense	'	'	'	'	'	'	'	'	13	0	0
Depreciation, Depletion, Amortization and Accretion	'	'	'	'	'	'	'	'	1,604	527	231
Field Services Operating Expense	'	'	'	'	'	'	'	'	23,527	9,859	2,470
Other Operating Expense	'	'	'	'	'	'	'	'	0	0	0
TOTAL OPERATING EXPENSES	'	'	'	'	'	'	'	'	27,606	11,501	3,761
INCOME (LOSS) FROM OPERATIONS	'	'	'	'	'	'	'	'	4,977	4,136	-215
OTHER INCOME (EXPENSE)	'	'	'	'	'	'	'	'	'	'	'
Interest Expense	'	'	'	'	'	'	'	'	-106	-26	-2
Gain (Loss) on Derivatives, Net	'	'	'	'	'	'	'	'	0	0	0
Other Income	'	'	'	'	'	'	'	'	0	0	101
Income (Loss) from Equity Method Investments	'	'	'	'	'	'	'	'	0	0	0
Income (Loss) From Equity in Consolidated Subsidiaries	'	'	'	'	'	'	'	'	33	68	53
TOTAL OTHER INCOME (LOSS)	'	'	'	'	'	'	'	'	-73	42	152
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX	'	'	'	'	'	'	'	'	4,904	4,178	-63
Income Tax (Expense) Benefit	'	'	'	'	'	'	'	'	-2,210	-1,336	33
INCOME (LOSS) FROM CONTINUING OPERATIONS	'	'	'	'	'	'	'	'	2,694	2,842	-30
Loss From Discontinued Operations, Net of Income Taxes	'	'	'	'	'	'	'	'	-232	-10,943	-33,457
Net Income (Loss)	'	'	'	'	'	'	'	'	2,462	-8,101	-33,487
Net Income Attributable to Noncontrolling Interests	'	'	'	'	'	'	'	'	1,557	819	-7
Net Income (Loss) Attributable to Rex Energy	'	'	'	'	'	'	'	'	905	-8,920	-33,480
Parent Company	'	'	'	'	'	'	'	'	'	'	'
OPERATING REVENUE	'	'	'	'	'	'	'	'	'	'	'
Oil, Natural Gas and NGL Sales	'	'	'	'	'	'	'	'	0	0	0
Field Services Revenue	'	'	'	'	'	'	'	'	0	0	0
Other Revenue	'	'	'	'	'	'	'	'	0	0	0
TOTAL OPERATING REVENUE	'	'	'	'	'	'	'	'	0	0	0
OPERATING EXPENSES	'	'	'	'	'	'	'	'	'	'	'
Production and Lease Operating Expense	'	'	'	'	'	'	'	'	0	0	0
General and Administrative Expense	'	'	'	'	'	'	'	'	5,420	3,159	1,662
Loss on Disposal of Asset	'	'	'	'	'	'	'	'	0	0	0
Impairment Expense	'	'	'	'	'	'	'	'	0	0	0
Exploration Expense	'	'	'	'	'	'	'	'	0	0	0
Depreciation, Depletion, Amortization and Accretion	'	'	'	'	'	'	'	'	0	0	0
Field Services Operating Expense	'	'	'	'	'	'	'	'	0	0	0
Other Operating Expense	'	'	'	'	'	'	'	'	0	0	0
TOTAL OPERATING EXPENSES	'	'	'	'	'	'	'	'	5,420	3,159	1,662
INCOME (LOSS) FROM OPERATIONS	'	'	'	'	'	'	'	'	-5,420	-3,159	-1,662
OTHER INCOME (EXPENSE)	'	'	'	'	'	'	'	'	'	'	'
Interest Expense	'	'	'	'	'	'	'	'	-22,612	-6,362	-2,405
Gain (Loss) on Derivatives, Net	'	'	'	'	'	'	'	'	-205	0	0
Other Income	'	'	'	'	'	'	'	'	0	-922	0
Income (Loss) from Equity Method Investments	'	'	'	'	'	'	'	'	0	0	0
Income (Loss) From Equity in Consolidated Subsidiaries	'	'	'	'	'	'	'	'	5,703	51,363	-12,925
TOTAL OTHER INCOME (LOSS)	'	'	'	'	'	'	'	'	-17,114	44,079	-15,330
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX	'	'	'	'	'	'	'	'	-22,534	40,920	-16,992
Income Tax (Expense) Benefit	'	'	'	'	'	'	'	'	20,404	4,559	1,624
INCOME (LOSS) FROM CONTINUING OPERATIONS	'	'	'	'	'	'	'	'	-2,130	45,479	-15,368
Loss From Discontinued Operations, Net of Income Taxes	'	'	'	'	'	'	'	'	0	0	0
Net Income (Loss)	'	'	'	'	'	'	'	'	-2,130	45,479	-15,368
Net Income Attributable to Noncontrolling Interests	'	'	'	'	'	'	'	'	0	0	0
Net Income (Loss) Attributable to Rex Energy	'	'	'	'	'	'	'	'	-2,130	45,479	-15,368
Eliminations	'	'	'	'	'	'	'	'	'	'	'
OPERATING REVENUE	'	'	'	'	'	'	'	'	'	'	'
Oil, Natural Gas and NGL Sales	'	'	'	'	'	'	'	'	0	0	0
Field Services Revenue	'	'	'	'	'	'	'	'	-8,771	-2,234	-1,028
Other Revenue	'	'	'	'	'	'	'	'	0	-56	0
TOTAL OPERATING REVENUE	'	'	'	'	'	'	'	'	-8,771	-2,290	-1,028
OPERATING EXPENSES	'	'	'	'	'	'	'	'	'	'	'
Production and Lease Operating Expense	'	'	'	'	'	'	'	'	0	0	0
General and Administrative Expense	'	'	'	'	'	'	'	'	-86	-104	-36
Loss on Disposal of Asset	'	'	'	'	'	'	'	'	0	0	0
Impairment Expense	'	'	'	'	'	'	'	'	0	0	0
Exploration Expense	'	'	'	'	'	'	'	'	0	0	0
Depreciation, Depletion, Amortization and Accretion	'	'	'	'	'	'	'	'	-200	-83	-47
Field Services Operating Expense	'	'	'	'	'	'	'	'	-6,197	-1,619	-720
Other Operating Expense	'	'	'	'	'	'	'	'	0	0	0
TOTAL OPERATING EXPENSES	'	'	'	'	'	'	'	'	-6,483	-1,806	-803
INCOME (LOSS) FROM OPERATIONS	'	'	'	'	'	'	'	'	-2,288	-484	-225
OTHER INCOME (EXPENSE)	'	'	'	'	'	'	'	'	'	'	'
Interest Expense	'	'	'	'	'	'	'	'	0	0	0
Gain (Loss) on Derivatives, Net	'	'	'	'	'	'	'	'	0	0	0
Other Income	'	'	'	'	'	'	'	'	-86	-104	-35
Income (Loss) from Equity Method Investments	'	'	'	'	'	'	'	'	0	0	0
Income (Loss) From Equity in Consolidated Subsidiaries	'	'	'	'	'	'	'	'	-5,703	-51,363	12,925
TOTAL OTHER INCOME (LOSS)	'	'	'	'	'	'	'	'	-5,789	-51,467	12,890
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX	'	'	'	'	'	'	'	'	-8,077	-51,951	12,665
Income Tax (Expense) Benefit	'	'	'	'	'	'	'	'	0	0	0
INCOME (LOSS) FROM CONTINUING OPERATIONS	'	'	'	'	'	'	'	'	-8,077	-51,951	12,665
Loss From Discontinued Operations, Net of Income Taxes	'	'	'	'	'	'	'	'	0	0	0
Net Income (Loss)	'	'	'	'	'	'	'	'	-8,077	-51,951	12,665
Net Income Attributable to Noncontrolling Interests	'	'	'	'	'	'	'	'	0	0	0
Net Income (Loss) Attributable to Rex Energy	'	'	'	'	'	'	'	'	($8,077)	($51,951)	$12,665

Condensed_Consolidating_Statem1

Condensed Consolidating Statements of Cash Flows (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES	'	'	'
Net Income (Loss)	($573)	$46,298	($15,376)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities	'	'	'
(Gain) Loss from Equity Method Investments	763	3,921	-81
Non-Cash Expenses	6,230	3,191	1,745
Depreciation, Depletion, Amortization and Accretion	63,944	46,441	28,446
Deferred Income Tax Expense (Benefit)	2,279	23,665	-7,339
(Gain) Loss on Derivatives	2,908	-10,687	-18,916
Cash Settlement of Derivatives	7,128	16,219	6,212
Dry Hole Expense	2,993	656	32,769
(Gain) Loss on Sale of Assets and Equity Method Investments	-6,211	-100,551	502
Impairment Expense	32,072	40,355	27,808
Changes in operating assets and liabilities	'	'	'
Accounts Receivable	-12,726	-13,698	11,118
Inventory, Prepaid Expenses and Other Assets	-885	-92	86
Accounts Payable and Accrued Liabilities	12,891	-8,832	-1,996
Other Assets and Liabilities	-2,497	-1,181	-471
NET CASH PROVIDED BY OPERATING ACTIVITIES	108,316	45,705	64,507
CASH FLOWS FROM INVESTING ACTIVITIES	'	'	'
Intercompany loans to subsidiaries	0	0	0
Proceeds from Joint Venture Leasing Initiatives	458	260	3,209
Change in Restricted Cash	0	0	16,086
Contributions to Equity Method Investments	-2,493	-4,087	-23,204
Proceeds from the Sale of Assets and Equity Method Investments	11,305	133,425	2,729
Proceeds from the Sale of Assets and Equity Method Investments	11,305	'	'
Acquisitions of Undeveloped Acreage	-41,784	-51,802	-78,569
Capital Expenditures for Development of Oil and Gas Properties and Equipment	-281,004	-178,538	-196,825
NET CASH USED IN INVESTING ACTIVITIES	-313,518	-100,742	-276,574
CASH FLOWS FROM FINANCING ACTIVITIES	'	'	'
Proceeds from Long-Term Debt and Lines of Credit	72,249	126,730	240,000
Repayments of Long-Term Debt and Lines of Credit	-8,480	-351,000	-25,000
Repayments of Loans and Other Notes Payable	-2,005	-962	-879
Proceeds from 8.875% Senior Notes, net of Discount	105,000	248,250	0
Debt Issuance Costs	-3,134	-6,397	-2,615
Settlement of Tax Withholdings Related to Share-Based Compensation Awards	0	-234	0
Proceeds from the Issuance of Common Stock, Net of Issuance Costs	0	70,583	0
Proceeds from the Exercise of Stock Options	533	565	1,362
Capital Distributions by the Partners of Consolidated Joint Ventures	-886	-319	-20
Capital Contributions by the Partners of Equity Method Investments and Consolidated Joint Ventures	0	0	7
Purchase of Noncontrolling Interests	-150	0	0
NET CASH PROVIDED BY FINANCING ACTIVITIES	163,127	87,216	212,855
NET INCREASE (DECREASE) IN CASH	-42,075	32,179	788
CASH-BEGINNING	43,975	11,796	11,008
CASH-ENDING	1,900	43,975	11,796
Guarantor Subsidiaries	'	'	'
CASH FLOWS FROM OPERATING ACTIVITIES	'	'	'
Net Income (Loss)	7,172	60,871	20,814
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities	'	'	'
(Gain) Loss from Equity Method Investments	763	3,921	-81
Non-Cash Expenses	-194	33	118
Depreciation, Depletion, Amortization and Accretion	62,540	44,993	27,672
Deferred Income Tax Expense (Benefit)	14,409	35,376	-10,234
(Gain) Loss on Derivatives	2,703	-10,687	-18,916
Cash Settlement of Derivatives	7,128	16,219	6,212
Dry Hole Expense	2,993	320	6
(Gain) Loss on Sale of Assets and Equity Method Investments	-5,289	-99,355	353
Impairment Expense	32,072	20,505	14,316
Changes in operating assets and liabilities	'	'	'
Accounts Receivable	-5,877	29,564	188,899
Inventory, Prepaid Expenses and Other Assets	-826	-139	157
Accounts Payable and Accrued Liabilities	8,554	-8,875	859
Other Assets and Liabilities	-2,272	-1,146	-1,473
NET CASH PROVIDED BY OPERATING ACTIVITIES	123,876	91,600	228,702
CASH FLOWS FROM INVESTING ACTIVITIES	'	'	'
Intercompany loans to subsidiaries	186,089	2,915	-2,337
Proceeds from Joint Venture Leasing Initiatives	458	260	3,209
Change in Restricted Cash	'	'	16,086
Contributions to Equity Method Investments	-2,493	0	0
Proceeds from the Sale of Assets and Equity Method Investments	'	128,554	2,293
Proceeds from the Sale of Assets and Equity Method Investments	8,071	'	'
Acquisitions of Undeveloped Acreage	-41,782	-51,783	-76,698
Capital Expenditures for Development of Oil and Gas Properties and Equipment	-275,697	-177,892	-169,689
NET CASH USED IN INVESTING ACTIVITIES	-125,354	-97,946	-227,136
CASH FLOWS FROM FINANCING ACTIVITIES	'	'	'
Proceeds from Long-Term Debt and Lines of Credit	0	0	0
Repayments of Long-Term Debt and Lines of Credit	0	0	0
Repayments of Loans and Other Notes Payable	-1,363	-764	-831
Proceeds from 8.875% Senior Notes, net of Discount	0	0	0
Debt Issuance Costs	0	0	0
Settlement of Tax Withholdings Related to Share-Based Compensation Awards	'	0	'
Proceeds from the Issuance of Common Stock, Net of Issuance Costs	'	0	'
Proceeds from the Exercise of Stock Options	0	0	0
Capital Distributions by the Partners of Consolidated Joint Ventures	0	0	0
Capital Contributions by the Partners of Equity Method Investments and Consolidated Joint Ventures	'	'	7
Purchase of Noncontrolling Interests	0	'	'
NET CASH PROVIDED BY FINANCING ACTIVITIES	-1,363	-764	-824
NET INCREASE (DECREASE) IN CASH	-2,841	-7,110	742
CASH-BEGINNING	4,227	11,337	10,595
CASH-ENDING	1,386	4,227	11,337
Non-Guarantor Subsidiaries	'	'	'
CASH FLOWS FROM OPERATING ACTIVITIES	'	'	'
Net Income (Loss)	2,462	-8,101	-33,487
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities	'	'	'
(Gain) Loss from Equity Method Investments	0	0	0
Non-Cash Expenses	55	14	2
Depreciation, Depletion, Amortization and Accretion	1,604	527	316
Deferred Income Tax Expense (Benefit)	2,210	-7,152	1,271
(Gain) Loss on Derivatives	0	0	0
Cash Settlement of Derivatives	0	0	0
Dry Hole Expense	0	336	32,763
(Gain) Loss on Sale of Assets and Equity Method Investments	-922	-2,118	149
Impairment Expense	0	19,850	13,492
Changes in operating assets and liabilities	'	'	'
Accounts Receivable	-6,515	-3,736	29,099
Inventory, Prepaid Expenses and Other Assets	-59	32	-56
Accounts Payable and Accrued Liabilities	874	-766	-3,124
Other Assets and Liabilities	-88	-64	961
NET CASH PROVIDED BY OPERATING ACTIVITIES	-379	-1,178	41,386
CASH FLOWS FROM INVESTING ACTIVITIES	'	'	'
Intercompany loans to subsidiaries	1,619	1,931	10,811
Proceeds from Joint Venture Leasing Initiatives	0	0	0
Change in Restricted Cash	'	'	0
Contributions to Equity Method Investments	0	-4,087	-23,204
Proceeds from the Sale of Assets and Equity Method Investments	'	4,871	436
Proceeds from the Sale of Assets and Equity Method Investments	3,234	'	'
Acquisitions of Undeveloped Acreage	-2	-19	-1,871
Capital Expenditures for Development of Oil and Gas Properties and Equipment	-7,870	-1,316	-27,444
NET CASH USED IN INVESTING ACTIVITIES	-3,019	1,380	-41,272
CASH FLOWS FROM FINANCING ACTIVITIES	'	'	'
Proceeds from Long-Term Debt and Lines of Credit	7,249	730	0
Repayments of Long-Term Debt and Lines of Credit	-2,480	0	0
Repayments of Loans and Other Notes Payable	-642	-198	-48
Proceeds from 8.875% Senior Notes, net of Discount	0	0	0
Debt Issuance Costs	-8	0	0
Settlement of Tax Withholdings Related to Share-Based Compensation Awards	'	0	'
Proceeds from the Issuance of Common Stock, Net of Issuance Costs	'	0	'
Proceeds from the Exercise of Stock Options	0	0	0
Capital Distributions by the Partners of Consolidated Joint Ventures	-886	-319	-20
Capital Contributions by the Partners of Equity Method Investments and Consolidated Joint Ventures	'	'	0
Purchase of Noncontrolling Interests	-150	'	'
NET CASH PROVIDED BY FINANCING ACTIVITIES	3,083	213	-68
NET INCREASE (DECREASE) IN CASH	-315	415	46
CASH-BEGINNING	824	409	363
CASH-ENDING	509	824	409
Parent Company	'	'	'
CASH FLOWS FROM OPERATING ACTIVITIES	'	'	'
Net Income (Loss)	-2,130	45,479	-15,368
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities	'	'	'
(Gain) Loss from Equity Method Investments	0	0	0
Non-Cash Expenses	6,369	3,144	1,625
Depreciation, Depletion, Amortization and Accretion	0	1,004	505
Deferred Income Tax Expense (Benefit)	-14,340	-4,559	1,624
(Gain) Loss on Derivatives	205	0	0
Cash Settlement of Derivatives	0	0	0
Dry Hole Expense	0	0	0
(Gain) Loss on Sale of Assets and Equity Method Investments	0	922	0
Impairment Expense	0	0	0
Changes in operating assets and liabilities	'	'	'
Accounts Receivable	1,241	-39,325	-211,952
Inventory, Prepaid Expenses and Other Assets	0	15	-15
Accounts Payable and Accrued Liabilities	1,481	916	405
Other Assets and Liabilities	-137	0	0
NET CASH PROVIDED BY OPERATING ACTIVITIES	-7,311	7,596	-223,176
CASH FLOWS FROM INVESTING ACTIVITIES	'	'	'
Intercompany loans to subsidiaries	-193,015	-56,489	9,121
Proceeds from Joint Venture Leasing Initiatives	0	0	0
Change in Restricted Cash	'	'	0
Contributions to Equity Method Investments	0	0	0
Proceeds from the Sale of Assets and Equity Method Investments	'	0	0
Proceeds from the Sale of Assets and Equity Method Investments	0	'	'
Acquisitions of Undeveloped Acreage	0	0	0
Capital Expenditures for Development of Oil and Gas Properties and Equipment	0	0	308
NET CASH USED IN INVESTING ACTIVITIES	-193,015	-56,489	9,429
CASH FLOWS FROM FINANCING ACTIVITIES	'	'	'
Proceeds from Long-Term Debt and Lines of Credit	65,000	126,000	240,000
Repayments of Long-Term Debt and Lines of Credit	-6,000	-351,000	-25,000
Repayments of Loans and Other Notes Payable	0	0	0
Proceeds from 8.875% Senior Notes, net of Discount	105,000	248,250	0
Debt Issuance Costs	-3,126	-6,397	-2,615
Settlement of Tax Withholdings Related to Share-Based Compensation Awards	'	-234	'
Proceeds from the Issuance of Common Stock, Net of Issuance Costs	'	70,583	'
Proceeds from the Exercise of Stock Options	533	565	1,362
Capital Distributions by the Partners of Consolidated Joint Ventures	0	0	0
Capital Contributions by the Partners of Equity Method Investments and Consolidated Joint Ventures	'	'	0
Purchase of Noncontrolling Interests	0	'	'
NET CASH PROVIDED BY FINANCING ACTIVITIES	161,407	87,767	213,747
NET INCREASE (DECREASE) IN CASH	-38,919	38,874	0
CASH-BEGINNING	38,924	50	50
CASH-ENDING	5	38,924	50
Eliminations	'	'	'
CASH FLOWS FROM OPERATING ACTIVITIES	'	'	'
Net Income (Loss)	-8,077	-51,951	12,665
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities	'	'	'
(Gain) Loss from Equity Method Investments	0	0	0
Non-Cash Expenses	0	0	0
Depreciation, Depletion, Amortization and Accretion	-200	-83	-47
Deferred Income Tax Expense (Benefit)	0	0	0
(Gain) Loss on Derivatives	0	0	0
Cash Settlement of Derivatives	0	0	0
Dry Hole Expense	0	0	0
(Gain) Loss on Sale of Assets and Equity Method Investments	0	0	0
Impairment Expense	0	0	0
Changes in operating assets and liabilities	'	'	'
Accounts Receivable	-1,575	-201	5,072
Inventory, Prepaid Expenses and Other Assets	0	0	0
Accounts Payable and Accrued Liabilities	1,982	-107	-136
Other Assets and Liabilities	0	29	41
NET CASH PROVIDED BY OPERATING ACTIVITIES	-7,870	-52,313	17,595
CASH FLOWS FROM INVESTING ACTIVITIES	'	'	'
Intercompany loans to subsidiaries	5,307	51,643	-17,595
Proceeds from Joint Venture Leasing Initiatives	0	0	0
Change in Restricted Cash	'	'	0
Contributions to Equity Method Investments	0	0	0
Proceeds from the Sale of Assets and Equity Method Investments	'	0	0
Proceeds from the Sale of Assets and Equity Method Investments	0	'	'
Acquisitions of Undeveloped Acreage	0	0	0
Capital Expenditures for Development of Oil and Gas Properties and Equipment	2,563	670	0
NET CASH USED IN INVESTING ACTIVITIES	7,870	52,313	-17,595
CASH FLOWS FROM FINANCING ACTIVITIES	'	'	'
Proceeds from Long-Term Debt and Lines of Credit	0	0	0
Repayments of Long-Term Debt and Lines of Credit	0	0	0
Repayments of Loans and Other Notes Payable	0	0	0
Proceeds from 8.875% Senior Notes, net of Discount	0	0	0
Debt Issuance Costs	0	0	0
Settlement of Tax Withholdings Related to Share-Based Compensation Awards	'	0	'
Proceeds from the Issuance of Common Stock, Net of Issuance Costs	'	0	'
Proceeds from the Exercise of Stock Options	0	0	0
Capital Distributions by the Partners of Consolidated Joint Ventures	0	0	0
Capital Contributions by the Partners of Equity Method Investments and Consolidated Joint Ventures	'	'	0
Purchase of Noncontrolling Interests	0	'	'
NET CASH PROVIDED BY FINANCING ACTIVITIES	0	0	0
NET INCREASE (DECREASE) IN CASH	0	0	0
CASH-BEGINNING	0	0	0
CASH-ENDING	$0	$0	$0

Condensed_Consolidating_Statem2

Condensed Consolidating Statements of Cash Flows (Parenthetical) (Detail) (8.875% Senior Notes)	Dec. 31, 2013	Dec. 31, 2012	Dec. 12, 2012	Dec. 31, 2011
8.875% Senior Notes	'	'	'	'
Condensed Cash Flow Statements, Captions [Line Items]	'	'	'	'
Interest rate	8.88%	8.88%	8.88%	8.88%