Rex Energy 10-Q 5 Aug 14 2014 Q2 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	6 Months Ended
	Jun. 30, 2014	Aug. 01, 2014
Document Information [Line Items]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Jun-14	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q2	'
Trading Symbol	'REXX	'
Entity Registrant Name	'REX ENERGY CORP	'
Entity Central Index Key	'0001397516	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	54,103,008

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current Assets	'	'
Cash and Cash Equivalents	$5,951	$1,900
Accounts Receivable	46,574	38,863
Taxes Receivable	1,767	5,189
Short-Term Derivative Instruments	4,181	5,668
Current Deferred Tax Asset	4,010	3,451
Inventory, Prepaid Expenses and Other	2,223	2,207
Total Current Assets	64,706	57,278
Property and Equipment (Successful Efforts Method)	'	'
Evaluated Oil and Gas Properties	880,725	749,680
Unevaluated Oil and Gas Properties	227,831	189,385
Other Property and Equipment	79,717	70,115
Wells and Facilities in Progress	114,670	76,545
Pipelines	15,577	7,678
Total Property and Equipment	1,318,520	1,093,403
Less: Accumulated Depreciation, Depletion and Amortization	-230,187	-190,521
Net Property and Equipment	1,088,333	902,882
Deferred Financing Costs and Other Assets – Net	11,604	11,993
Equity Method Investments	18,300	18,708
Long-Term Derivative Instruments	159	535
Total Assets	1,183,102	991,396
Current Liabilities	'	'
Accounts Payable	49,351	31,103
Current Maturities of Long-Term Debt	7,729	6,743
Accrued Liabilities	47,491	54,450
Short-Term Derivative Instruments	6,699	4,663
Total Current Liabilities	111,270	96,959
8.875% Senior Notes Due 2020	350,000	350,000
Premium on Senior Notes, Net	2,905	3,078
Senior Secured Line of Credit and Long-Term Debt	206,897	62,191
Long-Term Derivative Instruments	1,535	1,765
Long-Term Deferred Tax Liability	40,128	29,446
Other Deposits and Liabilities	4,528	4,992
Future Abandonment Cost	27,043	26,040
Total Liabilities	744,306	574,471
Commitments and Contingencies (See Note 13)	'	'
Stockholders’ Equity	'	'
Common Stock	54	54
Additional Paid-In Capital	459,754	456,554
Accumulated Deficit	-24,779	-41,725
Rex Energy Stockholders’ Equity	435,029	414,883
Noncontrolling Interests	3,767	2,042
Total Stockholders’ Equity	438,796	416,925
Total Liabilities and Stockholders’ Equity	$1,183,102	$991,396

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	6 Months Ended	12 Months Ended
	Jun. 30, 2014	Dec. 31, 2013
Common Stock, par value	0.001	0.001
Authorized capital stock, common stock	100,000,000	100,000,000
Common Stock, shares issued	54,089,782	54,186,490
Common Stock, shares outstanding	54,089,782	54,186,490
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		6 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
OPERATING REVENUE	'	'	'	'
Oil, Natural Gas and NGL Sales	$72,903	$51,444	$154,202	$92,384
Field Services Revenue	13,087	3,840	28,391	10,345
Other Revenue	30	76	74	100
TOTAL OPERATING REVENUE	86,020	55,360	182,667	102,829
OPERATING EXPENSES	'	'	'	'
Production and Lease Operating Expense	21,620	13,092	41,646	26,492
General and Administrative Expense	9,239	7,782	19,630	15,578
Loss on Disposal of Asset	230	1,502	301	1,493
Impairment Expense	16	105	41	170
Exploration Expense	1,367	2,225	3,427	4,269
Depreciation, Depletion, Amortization and Accretion	21,226	12,943	41,650	24,101
Field Service Operating Expense	9,569	2,648	21,365	6,703
Other Operating Expense (Income)	-56	447	27	891
TOTAL OPERATING EXPENSES	63,211	40,744	128,087	79,697
INCOME FROM OPERATIONS	22,809	14,616	54,580	23,132
OTHER EXPENSE	'	'	'	'
Interest Expense	-7,503	-5,826	-14,638	-9,831
Gain (Loss) on Derivatives, Net	-251	11,741	-10,001	3,201
Other Income (Expense)	40	2,213	-17	2,073
Loss on Equity Method Investments	-208	-183	-408	-361
TOTAL OTHER INCOME (EXPENSE)	-7,922	7,945	-25,064	-4,918
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX	14,887	22,561	29,516	18,214
Income Tax Expense	-5,932	-9,120	-10,124	-7,115
INCOME FROM CONTINUING OPERATIONS	8,955	13,441	19,392	11,099
Income From Discontinued Operations, Net of Income Taxes	0	520	0	460
NET INCOME	8,955	13,961	19,392	11,559
Net Income Attributable to Noncontrolling Interests	877	221	2,446	654
NET INCOME ATTRIBUTABLE TO REX ENERGY	$8,078	$13,740	$16,946	$10,905
Earnings per common share:	'	'	'	'
Basic – Net Income From Continuing Operations Attributable to Rex Energy Common Shareholders	$0.15	$0.25	$0.32	$0.20
Basic – Net Income From Discontinued Operations Attributable to Rex Energy Common Shareholders	$0	$0.01	$0	$0.01
Basic – Net Income Attributable to Rex Energy Common Shareholders	$0.15	$0.26	$0.32	$0.21
Basic – Weighted Average Shares of Common Stock Outstanding	53,164	52,555	53,075	52,527
Diluted – Net Income From Continuing Operations Attributable to Rex Energy Common Shareholders	$0.15	$0.25	$0.32	$0.20
Diluted – Net Income From Discontinued Operations Attributable to Rex Energy Common Shareholders	$0	$0.01	$0	$0.01
Diluted – Net Income Attributable to Rex Energy Common Shareholders	$0.15	$0.26	$0.32	$0.21
Diluted – Weighted Average Shares of Common Stock Outstanding	53,509	52,911	53,511	52,901

Consolidated_Statements_of_Cha

Consolidated Statements of Changes in Noncontrolling Interests and Stockholders' Equity (USD $)	Total	Common Stock	Additional Paid-in Capital	Retained Earnings	Stockholders' Equity, Total	Noncontrolling Interest
In Thousands, except Share data
Balance at Dec. 31, 2013	$416,925	$54	$456,554	($41,725)	$414,883	$2,042
Balance (in shares) at Dec. 31, 2013	'	54,186,490	'	'	'	'
Non-Cash Compensation	2,779	'	2,779	'	2,779	'
Issuance of Restricted Stock, Net of Forfeitures	'	0	'	'	'	'
Issuance of Restricted Stock, Net of Forfeitures (in shares)	'	-96,000	'	'	'	'
Stock Option Exercise	421	'	421	'	421	'
Capital Distributions	-721	'	'	'	'	-721
Net Income	19,392	'	'	16,946	16,946	2,446
Balance at Jun. 30, 2014	$438,796	$54	$459,754	($24,779)	$435,029	$3,767
Balance (in shares) at Jun. 30, 2014	'	54,089,782	'	'	'	'

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
CASH FLOWS FROM OPERATING ACTIVITIES	'	'
Net Income	$19,392	$11,559
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities	'	'
Loss from Equity Method Investments	408	361
Non-cash Expenses	3,336	3,027
Depreciation, Depletion, Amortization and Accretion	41,650	24,101
(Gain) Loss on Derivatives	10,001	-3,201
Cash Settlements of Derivatives	-6,333	4,798
Dry Hole Expense	86	485
Deferred Income Tax Expense	10,124	7,372
Impairment Expense	41	170
Loss on Sale of Asset	301	524
Changes in operating assets and liabilities	'	'
Accounts Receivable	-4,302	1,974
Inventory, Prepaid Expenses and Other Assets	-16	37
Accounts Payable and Accrued Liabilities	12,875	10,353
Other Assets and Liabilities	-992	-562
NET CASH PROVIDED BY OPERATING ACTIVITIES	86,571	60,998
CASH FLOWS FROM INVESTING ACTIVITIES	'	'
Proceeds from Joint Venture Acreage Management	146	107
Contributions to Equity Method Investments	'	-2,207
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	139	3,732
Acquisitions of Undeveloped Acreage	-40,139	-15,706
Capital Expenditures for Development of Oil & Gas Properties and Equipment	-185,577	-123,609
NET CASH USED IN INVESTING ACTIVITIES	-225,431	-137,683
CASH FLOWS FROM FINANCING ACTIVITIES	'	'
Repayments of Long-Term Debt and Line of Credit	-17,753	-876
Proceeds from Long-Term Debt and Line of Credit	162,409	1,750
Repayments of Loans and Other Notes Payable	-1,168	-786
Proceeds from Senior Notes, Net of Discounts and Premiums	'	105,000
Debt Issuance Costs	-277	-2,894
Proceeds from the Exercise of Stock Options	421	266
Distributions by the Partners of Consolidated Joint Ventures	-721	-406
Purchase of Noncontrolling Interests	'	-150
NET CASH PROVIDED BY FINANCING ACTIVITIES	142,911	101,904
NET INCREASE IN CASH	4,051	25,219
CASH – BEGINNING	1,900	43,975
CASH – ENDING	5,951	69,194
SUPPLEMENTAL DISCLOSURES	'	'
Interest Paid	17,454	15,337
Cash Paid (Received) for Income Taxes	-3,388	57
NON-CASH ACTIVITIES	'	'
Increase (Decrease) in Accrued Liabilities	($208)	$13,399

Basis_of_Presentation_and_Prin

Basis of Presentation and Principles of Consolidation	6 Months Ended
	Jun. 30, 2014
Basis of Presentation and Principles of Consolidation	'
	1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION
	Rex Energy Corporation, together with our subsidiaries (the “Company”), is an independent oil, natural gas liquid (“NGL”) and natural gas company with operations currently focused in the Appalachian and Illinois Basins. In the Appalachian Basin, we are focused on our Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and exploration activities. In the Illinois Basin, we are focused on developmental oil drilling and the implementation of enhanced oil recovery (“EOR”) on our properties. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties. In addition to our drilling and exploration activities, we are also engaged in oil and gas field services, where we provide water sourcing, water disposal and water transfer capabilities for completion operations.
	The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of all of our wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries together. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies.
	The interim Consolidated Financial Statements of the Company are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented. Actual results may differ from those estimates and results for interim periods are not necessarily indicative of results to be expected for a full year or for previously reported periods due in part, but not limited to, the volatility in prices for crude oil, NGLs and natural gas, future commodity prices for financial derivative instruments, interest rates, estimates of reserves, drilling risks, geological risks, transportation restrictions, the timing of acquisitions, product demand, market consumption, interruption in production, our ability to obtain additional capital, and the success of oil, NGL and natural gas recovery techniques.
	Certain amounts and disclosures have been condensed or omitted from these Consolidated Financial Statements pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Therefore, these interim financial statements should be read in conjunction with the audited Consolidated Financial Statements and related notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2013.
	Discontinued Operations
	During December 2011, our board of directors approved a formal plan to sell our DJ Basin assets located in the states of Wyoming and Colorado, for which the final sale was completed in 2013. Pursuant to the rules for discontinued operations, the results of operations are reflected as Discontinued Operations in our Consolidated Statements of Operations. Unless otherwise noted, all disclosures and tables reflect the results of continuing operations and exclude any assets, liabilities or results from our discontinued operations. For additional information see Note 4, Discontinued Operations/Assets Held for Sale, to our Consolidated Financial Statements.

Business_Segment_Information

Business Segment Information	6 Months Ended
	Jun. 30, 2014
Business Segment Information	'
	2. BUSINESS SEGMENT INFORMATION
	We have two principal reportable segments, which are segregated based on the products and services that each provides: (a) exploration and production, and (b) field services. Our exploration and production segment engages in the exploration, acquisition, development and production of oil, NGLs and natural gas. We have a single, company-wide management team that oversees all properties as a whole rather than isolating operating segments; however, we do track basic operational data by area. Our financial performance is measured as a single enterprise and not by individual area. Our field services segment operates and manages water sourcing, water transfer, equipment rental and water disposal services, primarily in the Appalachian Basin. Our field services segment is comprised of operations that have economic characteristics that are distinct from those of our exploration and production segment and is managed by its own unique management team.
	We evaluate the performance of our business segments based on net income (loss) from continuing operations, before income taxes. All intercompany transactions, including those between consolidated business segments, are eliminated in consolidation. Summarized financial information concerning our segments is shown in the following table for the three and six months ended June 30, 2014 and 2013 (in thousands):
		Exploration and Production		Field Services			Intercompany Eliminations			Consolidated Total
	Three Months Ended June 30, 2014
	Revenues	$	72,933	$	15,974		$	(2,887	)	$	86,020
	Inter-Segment Revenues		—		(2,887	)		2,887			—
	Total Revenues		72,933		13,087			—			86,020
	Income (Loss) From Continuing Operations, Before Income Taxes	$	13,146	$	2,192		$	(451	)	$	14,887
	Three Months Ended June 30, 2013
	Revenues	$	51,520	$	5,072		$	(1,232	)	$	55,360
	Inter-Segment Revenues		—		(1,232	)		1,232			—
	Total Revenues		51,520		3,840			—			55,360
	Income (Loss) From Continuing Operations, Before Income Taxes	$	22,339	$	552		$	(330	)	$	22,561
	Six Months Ended June 30, 2014
	Revenues	$	154,276	$	38,597		$	(10,206	)	$	182,667
	Inter-Segment Revenues				(10,206	)		10,206			—
	Total Revenues		154,276		28,391			—			182,667
	Income (Loss) From Continuing Operations, Before Income Taxes	$	25,900	$	6,113		$	(2,497	)	$	29,516
	Six Months Ended June, 2013
	Revenues	$	92,484	$	13,124		$	(2,779	)	$	102,829
	Inter-Segment Revenues		—		(2,779	)		2,779			—
	Total Revenues		92,484		10,345			—			102,829
	Income (Loss) From Continuing Operations, Before Income Taxes	$	16,272	$	2,715		$	(773	)	$	18,214
	As of June 30, 2014
	Total Assets	$	1,162,747	$	28,798		$	(8,443	)	$	1,183,102
	As of December  31, 2013
	Total Assets	$	971,973	$	26,266		$	(6,843	)	$	991,396

Future_Abandonment_Cost

Future Abandonment Cost	6 Months Ended
	Jun. 30, 2014
Future Abandonment Cost	'
	3. FUTURE ABANDONMENT COST
	Future abandonment costs are recognized as obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed. If the fair value of a recorded future abandonment cost changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost.
	Accretion expense totaled approximately $0.9 million and $1.6 million for the three and six months ended June 30, 2014, respectively, and $0.5 million and $1.1 million for the three and six months ended June 30, 2013, respectively. These amounts are recorded as depreciation, depletion, amortization and accretion (“DD&A”) expense on our Consolidated Statements of Operations. We account for future abandonment costs that relate to wells that are drilled jointly based on our working interest in those wells.
	$ in Thousands	30-Jun-14
	Beginning Balance	$	28,525
	Future Abandonment Obligation Incurred		590
	Future Abandonment Obligation Settled		(841	)
	Future Abandonment Obligation Revision of Estimated Obligation		14
	Future Abandonment Obligation Accretion Expense		1,630
	Total Future Abandonment Cost1	$	29,918
	1 Includes approximately $2.9 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

Discontinued_OperationsAssets_

Discontinued Operations/Assets Held For Sale	6 Months Ended
	Jun. 30, 2014
Discontinued Operations/Assets Held For Sale	'
	4. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE
	During December 2011, our board of directors approved a formal plan to sell our DJ Basin assets located in the states of Wyoming and Colorado. During 2012, we sold various parcels of acreage throughout our DJ Basin holdings at varying prices, much of which was lower than the existing carrying value of similar remaining acreage at the time of sale. During the first quarter of 2013, we entered an agreement to sell our remaining DJ Basin assets for $3.1 million. This transaction closed during the second quarter of 2013 and resulted in a gain of approximately $1.0 million. Since that time, we have had no assets or liabilities related to the DJ Basin or continuing cash flows from this region.
	Summarized financial information for Discontinued Operations is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support.
		Three Months Ended June 30,					Six Months Ended June 30,
	($ in Thousands)	2014		2013			2014		2013
	Revenues:
	Oil, Natural Gas and NGL Sales	$	—	$	16		$	—	$	25
	Total Operating Revenue		—		16			—		25
	Costs and Expenses:
	Production and Lease Operating Expense		—		59			—		104
	General and Administrative Expense		—		11			—		23
	Exploration Expense		—		44			—		97
	Other Income Expense		—		—			—		(3	)
	Gain on Sale of Asset		—		(973	)		—		(969	)
	Total Costs and Expenses		—		(859	)		—		(748	)
	Income from Discontinued Operations Before Income Taxes		—		875			—		773
	Income Tax Expense		—		(355	)		—		(313	)
	Income from Discontinued Operations, net of taxes	$	—	$	520		$	—	$	460
	Production:
	Crude Oil (Bbls)		—		209			—		356
	Total (Mcfe)		—		1,254			—		2,136

Business_and_Oil_and_Gas_Prope

Business and Oil and Gas Property Acquisitions and Dispositions	6 Months Ended
	Jun. 30, 2014
Business and Oil and Gas Property Acquisitions and Dispositions	'
	5. BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS AND DISPOSITIONS
	There were no significant asset acquisitions or dispositions during the three and six-month periods ended June 30, 2014.

Recently_Issued_Accounting_Pro

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

Concentrations_of_Credit_Risk

Concentrations of Credit Risk	6 Months Ended
	Jun. 30, 2014
Concentrations of Credit Risk	'
	7. CONCENTRATIONS OF CREDIT RISK
	By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparties to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties. Our counterparties are investment grade financial institutions and lenders in our Senior Credit Facility (see Note 8, Long-term Debt, to our Consolidated Financial Statements). We have a master netting agreement in place with our counterparties that provides for the offsetting of payables against receivables from separate derivative contracts. None of our derivative contracts have a collateral provision that would require funding prior to the scheduled cash settlement date. For additional information, see Note 9, Fair Value of Financial and Derivative Instruments, to our Consolidated Financial Statements.
	We also depend on a relatively small number of purchasers for a substantial portion of our revenue. For the six months ended June 30, 2014, approximately 95.7% of our commodity sales came from five purchasers, with the largest single purchaser accounting for 35.9% of commodity sales. We believe the continued growth in our Appalachian Basin operations will help us to minimize our future risks by diversifying our ratio of oil, NGLs and natural gas sales as well as the quantity of purchasers.

Long_Term_Debt

Long Term Debt	6 Months Ended
	Jun. 30, 2014
Long Term Debt	'
	8. LONG-TERM DEBT
	Senior Credit Facility
	We maintain a revolving credit facility evidenced by a credit agreement, dated March 27, 2013 (the “Senior Credit Facility”) As of June 30, 2014, the borrowing base under the Senior Credit Facility was $375.0 million; however, the Senior Credit Facility may be increased to up to $500.0 million upon re-determinations of the borrowing base, consent of the lenders and other conditions prescribed by the agreement. Within the Senior Credit Facility, a letter of credit subfacility exists 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. Subsequent to our offering of 6.25% senior notes in July 2014, our borrowing base was immediately reduced to approximately $293.8 million. For additional information on our offering of 6.25% senior notes, see Note 20, Subsequent Events, to our Consolidated Financial Statements. As of June 30, 2014, 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 June 30, 2014 and December 31, 2013, we had approximately $200.0 million and $59.0 million, respectively, of outstanding borrowings under the Senior Credit Facility.
	At our election, borrowings under the Senior Credit Facility bear interest at a rate per annum equal to the “Adjusted LIBO Rate” or the “Alternate Base Rate” (each as defined below), plus, in each case, an applicable per annum margin. The “Adjusted LIBO Rate” is equal to the product of: (i) the London Interbank Offered Rate for deposits with a maturity comparable to the borrowings (the “LIBO Rate”) multiplied by (ii) the statutory reserve rate. The Alternative Base Rate is equal to the greater of: (i) 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 150 to 250 basis points, and the applicable per annum margin, in the case of loans bearing interest at the Alternate Base Rate, ranges from 50 to 150 basis points, in each case, determined based upon our borrowing utilization at such date of determination. Upon the occurrence and continuance of an event of default, all outstanding loans shall bear interest at a rate equal to 200 basis points per annum plus the then effective rate of interest. Interest is payable on the last day of the relevant interest period (or at least every three months), in the case of loans bearing interest at the Adjusted LIBO Rate, and quarterly, in the case of loans bearing interest at the Alternate Base Rate.
	Under the Senior Credit Facility, we may enter into commodity swap agreements with counterparties approved by the lenders, provided that the notional volumes for such agreements, when aggregated with other commodity swap agreements then in effect (other than basis differential swaps on volumes already hedged pursuant to other swap agreements), do not exceed, as of the date the swap agreement is executed, 85% of the reasonably anticipated projected production from our proved developed producing reserves for the 36 months following the date such agreement is entered into, and 75% thereafter, for each of crude oil and natural gas, calculated separately. We may also enter into interest rate swap agreements with counterparties approved by the lenders that convert interest rates from floating to fixed provided that the notional amounts of those agreements, when aggregated with all other similar interest rate swap agreements then in effect, do not exceed the greater of $20 million and 75% of the then outstanding principal amount of our debt for borrowed money which bears interest at a floating rate. As of June 30, 2014, we were in compliance with all of these metrics, and there were no existing defaults or events of default under our Senior Credit Facility.
	The Senior Credit Facility contains covenants that restrict our ability to, among other things, materially change our business; approve and distribute dividends; enter into transactions with affiliates; create or acquire additional subsidiaries; incur indebtedness; sell assets; make loans to others; make investments; enter into mergers; incur liens; and enter into agreements regarding swap and other derivative transactions (for further information, see Note 7, Concentrations of Credit Risk, and Note 9, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements). Borrowings under the Senior Credit Facility have been used to finance our working capital needs and for general corporate purposes in the ordinary course of business, including the exploration, acquisition and development of oil and gas properties. Obligations under the Senior Credit Facility are secured by mortgages on the oil and gas properties of our subsidiaries located in Pennsylvania, Ohio, Illinois and Indiana. We are required to maintain liens covering our oil and gas properties representing at least 80% of our total value of all oil and gas properties.
	The Senior Credit Facility also requires we meet, on a quarterly basis, minimum financial requirements of consolidated current ratio, EBITDAX to interest expense and total debt to EBITDAX. EBITDAX is a non-GAAP financial measure used by our management team and by other users of our financial statements, such as our commercial bank lenders, which adds to or subtracts from net income the following expenses or income for a given period to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, depletion, amortization, unrealized gains and losses from derivatives, exploration expense and other similar non-cash activity. The Senior Credit Facility requires that as of the last day of any fiscal quarter, our ratio of consolidated current assets, which includes the unused portion of our borrowing base, as of such day to consolidated current liabilities as of such day, known as our current ratio, must not be less than 1.0 to 1.0. Our current ratio as of June 30, 2014 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 June 30, 2014 was approximately 4.8 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 June 30, 2014 was approximately 3.4 to 1.0.
	Senior Notes
	As of June 30, 2014 and December 31, 2013, we had recorded on our Consolidated Balance Sheet approximately $352.9 million and $353.1 million of 8.875% senior notes due 2020 (the “Senior Notes”), which is inclusive of a net premium of $2.9 million and $3.1 million, respectively. The amortization of our net premium during the first six months of 2014, 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. Bond issuance costs of $8.4 million were recorded as Deferred Financing Costs and Other Assets-Net on our Consolidated Balance Sheet and are being amortized over the term of the Senior Notes as Interest Expense on our Consolidated Statements of Operations using the effective interest method.
	The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries. In addition, there are no significant restrictions on our ability, or the ability of any subsidiary guarantor, to receive funds from our subsidiaries through dividends, loans, advances or otherwise. For additional information on our guarantor and non-guarantor subsidiaries, see Note 19, Condensed Consolidating Financial Information, to our Consolidated Financial Statements.
	In addition to the Senior Credit Facility and the Senior Notes, we may, from time to time in the normal course of business finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and other obligations consisted of the following at June 30, 2014 and December 31, 2013:
	($ in Thousands)	June 30, 2014 (Unaudited)			31-Dec-13
	8.875% Senior Notes Due 2020	$	350,000		$	350,000
	Premium on Senior Notes		2,905			3,078
	Senior Line of Credit(a)		200,000			59,000
	Capital Leases and Other Obligations(a)		14,626			9,934
	Total Debt		567,531			422,012
	Less Current Portion of Long-Term Debt		(7,729	)		(6,743	)
	Total Long-Term Debt	$	559,802		$	415,269
	(a)	The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement.      The weighted average interest rate on borrowings under our Senior Credit Facility for the three and six months ended June 30, 2014 and the year ended December 31, 2013, was approximately 2.0%, 2.0% and 1.9%, respectively. The average interest rate on our capital leases and other obligations for the three and six months ended June 30, 2014 and the year ended December 31, 2013, was approximately 4.0%, 4.0% and 5.3%, respectively.
	Water Solutions
	On October 18, 2013, Water Solutions Holdings entered into agreements with M&T Bank (“M&T”) to obtain a revolving line of credit (“Demand Note”) and an equipment line of credit (“Equipment Term Note”).
	The borrowing base for the Demand Note is the lesser of (a) $8.0 million, increased from $4.0 million at December 31, 2013, or (b) 80% of Water Solutions’ Accounts Receivable which are less than 90 days old. Borrowings under the Demand Note are to be used for working capital and general corporate purposes. At Water Solutions’ election, borrowings under the Demand Note bear interest per annum equal to an adjusted LIBOR rate or an adjusted base rate, as defined below. The adjusted LIBOR rate is equal 2.75 percentage points above the greater of (a) one-month LIBOR, adjusting daily, or (b) one-day LIBOR. The adjusted base rate is equal to 2.0 percentage points above the rate of interest announced by M&T as its prime rate. All interest that is accrued through the last day of any calendar month will be due and payable by the tenth day of the next calendar month. While there is no stated maturity date for amounts outstanding under the Demand Note, in certain circumstances, Water Solutions may be required to repay amounts outstanding on demand from M&T. As of June 30, 2014, there was approximately $3.9 million outstanding under the Demand Note.
	The Demand Note agreement does not contain any collateral requirements on behalf of Water Solutions, nor does it contain any financial covenant requirements.
	Maximum borrowings under the Equipment Term Note are equal to $6.0 million and are to be used for purposes of making equipment or vehicle acquisitions up to a maximum of 80% of the costs of such assets. Borrowings under the Equipment Term Note bear interest per annum equal to the three month LIBOR plus 3.0 percentage points. All interest is due and payable on the first day of each fiscal quarter. Maturity dates will vary with each borrowing, but will generally be three to four years from the date of borrowing. In certain circumstances, Water Solutions may be required to prepay any loans that are outstanding. As of June 30, 2014, there was approximately $3.9 million outstanding under the Equipment Term Note.
	The Equipment Term Note contains covenants that restrict Water Solutions’ ability to, among other things, materially change their business; incur indebtedness; make loans to others; incur liens; make investments; or become a guarantor. Borrowings under the Equipment Term Note are collateralized with liens covering 80% of the value of assets purchased with associated loans under the Equipment Term Note. The Equipment Term Note also requires that Water Solutions meet certain financial covenants regarding tangible net worth, fixed charge coverage ratio and a debt to EBITDA ratio (as defined in the Equipment Term Note). EBITDA is a non-GAAP financial measure used by the management of Water Solutions and by other users of Water Solutions’ financial statements, such as commercial bank lenders, which adds to or subtracts from net income the following expenses or income for a given period to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, amortization and other similar non-cash activity. The Equipment Term Note requires that tangible net worth (i) not be less than $2.5 million measured annually, and (ii) not be less than $2.5 million plus 30% of annual net income commencing with the fiscal year ended December 31, 2013 and each fiscal year thereafter. As of December 31, 2013, Water Solutions’ net worth was approximately $9.2 million. Also, Water Solutions’ fixed charge coverage ratio for four consecutive fiscal quarters ending at the end of each fiscal quarter shall not be less than 1.75 to 1.0. As of June 30, 2014, Water Solutions’ fixed charge coverage ratio was approximately 2.1 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 June 30, 2014, Water Solutions’ debt to EBITDA ratio was approximately 1.1 to 1.0.
	The following is the principal maturity schedule for debt outstanding as of June 30, 2014:
	2014	$	5,992
	2015		3,089
	2016		2,749
	2017		1,428
	2018		200,588
	Thereafter		350,780
	Total(a)	$	564,626
	(a)	Excludes $2.9 million net premium on Senior Notes.

Fair_Value_Of_Financial_And_De

Fair Value Of Financial And Derivative Instruments	6 Months Ended
	Jun. 30, 2014
Fair Value Of Financial And Derivative Instruments	'
	9. FAIR VALUE OF FINANCIAL AND DERIVATIVE INSTRUMENTS
	Our results of operations and operating cash flows are impacted by changes in market prices for oil, natural gas and NGLs. To mitigate a portion of the exposure to adverse market changes, we enter into oil, natural gas and NGL commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels that are less than our average price floor, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling, we make payments to our counterparties. We do not enter into these arrangements for speculative trading purposes. As of June 30, 2014 and December 31, 2013, 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.
	Swap contracts provide a fixed price for a notional amount of sales volumes. Collars contain a fixed floor price (“put”) and ceiling price (“call”). The put options are purchased from the counterparty by our payment of a cash premium. If the put strike price is greater than the market price for a settlement period, then the counterparty pays us an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty, for which we receive a cash premium. If the market price is greater than the call strike price for a settlement period, then we pay the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price. A three-way collar is a combination of options, a sold call, a purchased put and a sold put. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the settlement price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price we will receive for the volumes under contract. Deferred put spread contracts are similar to three-way collars except that there is no maximum price ceiling established. Swaption agreements provide options to counterparties to extend swaps into subsequent years. Similar to a deferred put spread and a three-way collar, a cap swap provides a sold put in combination with a swap. Should prices fall below the sold put, we would receive the settlement price plus the differential between the sold put and the swap. Basis swaps are arrangements that guarantee a price differential from a specified delivery point. Currently, our basis swaps provide basis protection between Henry Hub and Dominion Appalachia pricing.
	We enter into the majority of our derivative arrangements with five counterparties and have a netting agreement in place with these counterparties. We do not obtain collateral to support the agreements, but we believe our credit risk is currently minimal on these transactions. For additional information on the credit risk regarding our counterparties, see Note 7, Concentrations of Credit Risk, to our Consolidated Financial Statements.
	None of our commodity derivatives are designated for hedge accounting but are, to a degree, an economic offset to our commodity price exposure. We utilize the mark-to-market accounting method to account for these contracts. We recognize all gains and losses related to these contracts in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Expense. We paid net cash settlements of $2.0 million and $7.2 million in relation to our commodity derivatives during the three and six months ended June 30, 2014, respectively, and received net cash settlements of $1.1 million and $4.8 million in relation to our commodity derivatives for the three and six months ended June 30, 2013, respectively.
	As of June 30, 2014, we had over 90.0% of our annualized 2014 oil production hedged through the remainder of 2014, over 80.0% and 40.0% of our annualized 2014 natural gas production hedged through the remainder of 2014 and 2015, respectively, and over 70.0% of our annualized 2014 NGL production hedged through the remainder of 2014. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future and completion or the natural decline of our oil and gas production.
	Interest Rate Derivatives
	We are exposed to interest rate risk on our long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in the market interest rates which are lower than our current fixed rate. Variable rate debt, where the interest rate fluctuates, exposes us to changes in market interest rates, which may increase over time. As of June 30, 2014 and December 31, 2013, we had approximately $200.0 million and $59.0 million outstanding under our Senior Credit Facility, respectively, which is subject to variable rates of interest and $350.0 million of Senior Notes outstanding subject to a fixed interest rate. See Note 8, Long-Term Debt, to our Consolidated Financial Statements for additional information on our Senior Credit Facility and Senior Notes.
	As of December 31, 2013, we had a $25.0 million notional fixed-to-variable interest rate swap to manage our interest rate exposure related to the Senior Notes. Prior to 2013, we did not have any interest rate swap agreements. During the three months ended June 30, 2014, we terminated our interest rate swap for net proceeds of approximately $0.6 million. We utilized the mark-to-market accounting method to account for our interest rate swap. We recognized all gains and losses related to this contract in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Expense. During 2013, there were no cash settlements related to our interest rate swap agreement. During the three and six months ended June 30, 2014, we received cash payments of approximately $0.5 million and $0.9 million, respectively, related to our interest rate swaps. The fair value of our interest rate swap as December 31, 2013, was a liability of approximately $0.2 million.
	The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three and six months ended June 30, 2014 and 2013:
			For the Three Months Ended June 30,								For the Six Months Ended June 30,
	In thousands		2014				2013				2014				2013
	Oil		$	(2,482	)		$	9,121			$	(3,650	)		$	8,137
	Natural Gas			2,147				1,445				(6,781	)			(6,127	)
	NGLs			(310	)			1,175				(653	)			1,191
	Interest Rate			394				—				1,083				—
	Gain (Loss) on Derivatives, Net		$	(251	)		$	11,741			$	(10,001	)		$	3,201
	Our derivative instruments are recorded on the balance sheet as either an asset or a liability, in either case measured at fair value. The fair value associated with our derivative instruments was a net liability of approximately $3.9 million and $0.2 million at June 30, 2014 and December 31, 2013, respectively.
	Our open asset/(liability) financial commodity derivative instrument positions at June 30, 2014 consisted of:
	Period		Volume		Put Option				Floor				Ceiling				Swap			Long Call		Fair Market Value ($ in Thousands)
	Oil
	2014—Collar		30,000 Bbls		$	—			$	90			$	97.65			$	—		$	—	$	(189	)
	2014—Cap Swap		190,000 Bbls			81.32				—				—				97.84			—		(1,038	)
	2014—Three Way Collar		180,000 Bbls			77.92				88.98				103.39				—			—		(440	)
	2014—Deferred Put Spread		84,000 Bbls			75				90				—				—			—		(441	)
	2015—Three Way Collar		120,000 Bbls			78.75				89.06				100.44				—			—		(358	)
	2015—Call Protected Swap		30,000 Bbls			—				—				—				95.76			110		(48	)
			634,000 Bbls																			$	(2,514	)
	Natural Gas
	2014—Call		900,000 Mcf		$	—			$	—			$	5			$	—		$	—	$	(68	)
	2014—Three Way Collar		6,750,000 Mcf			3.53				4.19				4.7				—			—		(231	)
	2014—Swap		2,220,000 Mcf			—				—				—				3.96			—		(1,017	)
	2014—Collar		1,500,000 Mcf			—				3.81				4.54				—			—		(133	)
	2014—Swaption		1,200,000 Mcf			—				—				—				4.45			—		(578	)
	2014—Basis Swap		3,000,000 Mcf			—				—				—				(0.37	)		—		2,834
	2014—Cap Swap		1,800,000 Mcf			3.3				—				—				4.09			—		(518	)
	2015—Three Way Collar		6,900,000 Mcf			3.63				4.2				4.68				—			—		(89	)
	2015—Swap		1,200,000 Mcf			—				—				—				4.18			—		(137	)
	2015—Cap Swap		2,400,000 Mcf			3.28				—				—				4.1			—		(569	)
	2015—Call		2,400,000 Mcf			—				—				4.4				—			—		(717	)
	2015—Collar		1,200,000 Mcf			—				4.25				4.7				—			—		139
	2015—Swaption		0 Mcf			—				—				—				4.4			—		(667	)
	2015—Basis Swap		600,000 Mcf			—				—				—				(0.35	)		—		494
			32,070,000 Mcf																			$	(1,257	)
	NGLs
	2014—Swap		474,000 Bbls		$	—			$	—			$	—			$	57.9		$	—	$	(158	)
	2015—Swap		42,000 Bbls			—				—				—				45.99			—	$	35
			516,000 Bbls																			$	(123	)
	The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013 is summarized below
		June 30,				December 31,
	($ in Thousands)	2014				2013
	Short-Term Derivative Assets:
	Crude Oil—Collars	$	—			$	380
	Crude Oil—Three-Way Collars		—				104
	NGL—Swaps		372				83
	Natural Gas—Swaps		—				106
	Natural Gas—Cap Swaps		—				5
	Natural Gas—Basis Swaps		3,328				3,984
	Natural Gas—Three-Way Collars		342				518
	Natural Gas—Collars		139				—
	Interest Rate—Swap		—				488
	Total Short-Term Derivative Assets	$	4,181			$	5,668
	Long-Term Derivative Assets:
Natural Gas—Cap Swap	$	—			$	5
Natural Gas—Swaps		—				22
Natural Gas—Basis Swaps		—				339
Natural Gas—Collars		69				—
Natural Gas—Three-Way Collars		90				169
Total Long-Term Derivative Assets	$	159			$	535
Total Derivative Assets	$	4,340			$	6,203
Short-Term Derivative Liabilities:
Crude Oil—Collars	$	(189	)		$	(42	)
Crude Oil—Swaps		—				(119	)
Crude Oil—Call Protected Swap		(48	)			—
Crude Oil—Cap Swap		(1,038	)			—
Crude Oil—Three-Way Collars		(798	)			(29	)
Crude Oil—Deferred Put Spread		(441	)			(585	)
NGL—Swaps		(495	)			(995	)
Natural Gas—Three-Way Collars		(594	)			(125	)
Natural Gas—Collars		(202	)			(235	)
Natural Gas—Call		(426	)			(150	)
Natural Gas—Cap Swaps		(804	)			(496	)
Natural Gas—Swaption		(578	)			(717	)
Natural Gas—Swaps		(1,086	)			(1,170	)
Total Short - Term Derivative Liabilities	$	(6,699	)		$	(4,663	)
Long-Term Derivative Liabilities:
Natural Gas—Swaps	$	(68	)		$	(4	)
Natural Gas—Cap Swaps		(283	)			(307	)
Natural Gas—Three-Way Collars		(158	)			—
Natural Gas—Swaption		(667	)			—
Natural Gas—Call		(359	)			(761	)
Interest Rate—Swap		—				(693	)
Total Long-Term Derivative Liabilities	$	(1,535	)		$	(1,765	)
Total Derivative Liabilities	$	(8,234	)		$	(6,428	)
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. We utilize a fair value hierarchy that gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:
Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.
Level 2—Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.
Our Level 2 fair value measurements are comprised of our derivative contracts, excluding our basis swap derivatives, and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, interest rates and discount rates, or can be confirmed from other active markets. The fair values recorded as of June 30, 2014 and December 31, 2013, were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party.
Our Level 3 fair value measurements are comprised of our natural gas basis swap contracts. The fair values recorded as of June 30, 2014 were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party. The significant unobservable input used in the fair value measurement of our natural gas basis swaps was the estimate of future natural gas basis differentials. Significant variations in price differentials could result in a significantly different fair value measurement.
The significant unobservable inputs and the range and weighted average of these inputs used in the fair value measurements of our natural gas basis swaps as of June 30, 2014 are included in the table below.
	Range		Weighted Average				Fair Value
	(price per Mcf)		(price per Mcf)				(in thousands)
Natural Gas Basis Differential Forward Curve	($ 0.85) - ($ 1.63)		$	(1.28	)		$	3,328
During the three and six months ended June 30, 2014, there were no transfers into or out of Level 1 or Level 2 measurements.
The following table presents the fair value hierarchy table for assets and liabilities measured at fair value ($ in thousands):
					Fair Value Measurements at June 30, 2014 Using:
	Total Carrying Value as of June 30, 2014				Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	(3,894	)		$	—			$	(7,222	)		$	3,328
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 June 30, 2014 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil and (iii) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our gas derivatives are comprised of puts, swaps, swaptions, collars, three way collars, basis swaps, cap swaps, and deferred put spreads contracts for notional volumes of gas contracted at NYMEX Henry Hub (“HH”). The fair values attributable to our gas derivative contracts as of June 30, 2014 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our NGL derivatives are comprised of swaps for notional volumes of NGLs contracted at NYMEX Mont Belvieu. The fair values attributable to our NGL derivative contracts as of June 30, 2014 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for Mont Belvieu, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. We classify our derivatives as Level 2 if the inputs used in the valuation models are directly observable for substantially the full term of the instrument; however, if the significant inputs were not observable for substantially the full term of the instrument, we would classify those derivatives as Level 3. We categorize our measurements as Level 2 because the valuation of our derivative instruments are based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instruments.
The table below sets forth a reconciliation of our commodity derivative contracts at fair value on a recurring basis using significant unobservable inputs (Level 3) during the six months ended June 30, 2014 and 2013:
	Six Months Ended June 30,
($ in Thousands)	2014				2013
Beginning Balance of Level 3	$	4,323			$	—
Changes in Fair Value		(2,007	)			—
Purchases		—				—
Settlements Received		1,012				—
Ending Balance of Level 3	$	3,328			$	—
Changes in fair value on our Level 3 commodity derivative contracts outstanding for the six months ended June 30, 2014, resulted in a loss of approximately $2.0 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 June 30, 2013.
Future Abandonment Cost
We report the fair value of future abandonment costs on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of future abandonment costs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; estimated probabilities, amounts and timing of settlements; estimated plugging costs; the credit-adjusted risk-free rate to be used; and inflation rates. The most significant inputs used in the determination of future abandonment costs are the estimated costs to plug and abandon our wells. Significant changes in the estimated cost to plug and abandon our wells can cause significant changes in the fair value measurement of our future abandonment costs due to the large number of wells that we operate. These inputs are unobservable, and thus result in a Level 3 classification. Refer to Note 3, Future Abandonment Cost, of our Consolidated Financial Statements for further information on future abandonment costs, which include a reconciliation of the beginning and ending balances.
Financial Instruments Not Recorded at Fair Value
The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements:
	30-Jun-14								31-Dec-13
$ in Thousands	Carrying Amount				Fair Value				Carrying Amount				Fair Value
8.875% Senior Notes due 2020	$	350,000			$	388,500			$	350,000			$	385,000
Secured Lines of Credit		200,000				200,000				59,000				59,000
Capital Leases and Other Obligations		14,626				14,280				9,934				9,731
Total	$	564,626			$	602,780			$	418,934			$	453,731
The fair value of the secured lines of credit approximates carrying value based on borrowing rates available to us for bank loans with similar terms and maturities and would be classified as Level 2 in the fair value hierarchy.
The fair value of the Senior Notes uses pricing that is readily available in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 1 in the fair value hierarchy. The fair value of our capital leases and other obligations are determined using a discounted cash flow approach based on the interest rate and payment terms of the obligations and assumed discount rate. The fair values of the obligations could be significantly influenced by the discount rate assumptions, which is unobservable. Accordingly, the fair value of the capital leases and other obligations would be classified as Level 3 in the fair value hierarchy.
The carrying values of all classes of cash and cash equivalents, accounts receivables and accounts payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.

Income_Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2014
Income Taxes	'
	10. INCOME TAXES
	We recognize deferred income taxes for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value.
	Income tax included in continuing operations was as follows:
		Three Months Ended June 30,						Six Months Ended June 30,
	($ in Thousands)	2014			2013			2014			2013
	Income Expense	$	(5,932	)	$	(9,120	)	$	(10,124	)	$	(7,115	)
	Effective Tax Rate		42.3	%		40.8	%		37.4	%		40.5	%
	For the six months ended June 30, 2014, our overall effective tax rate on pre-tax income from continuing operations was different than the statutory rate of 35% due primarily to decreases in state taxes, partially offset by section 162(m) limitations. For the six months ended June 30, 2013, our overall effective tax rate on pretax losses from continuing operations was different than the statutory rate of 35% due primarily to state taxes.
	Income tax payments made during the three and six months ended June 30, 2014 and 2013 were negligible. We received tax refunds during the three and six months ended June 30, 2014 of approximately $3.4 million as compared to $5.0 million for the three and six months ended June 30, 2013.

Capital_Stock

Capital Stock	6 Months Ended
	Jun. 30, 2014
Capital Stock	'
	11. CAPITAL STOCK
	We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of June 30, 2014 and December 31, 2013, we had 54,089,782 and 54,186,490 shares of common stock outstanding, respectively. There were no shares of preferred stock outstanding as of June 30, 2014 and December 31, 2013.

Employee_Benefit_and_Equity_Pl

Employee Benefit and Equity Plans	6 Months Ended
	Jun. 30, 2014
Employee Benefit and Equity Plans	'
	12. EMPLOYEE BENEFIT AND EQUITY PLANS
	Equity Plans
	We recognize all share-based payments to employees, including grants of employee stock options, in our Consolidated Statements of Operations based on their grant-date fair values, using prescribed option-pricing models where applicable. The fair value is expensed over the requisite service period of the individual grantees, which generally equals one vesting period. We report any benefits of income tax deductions in excess of recognized financial accounting compensation as cash flows from financing activities, rather than as cash flows from operating activities.
	2007 Long-Term Incentive Plan
	We have granted stock options, stock appreciation rights and restricted stock awards to various employees, non-employee contractors and non-employee directors under the terms of our 2007 Long-Term Incentive Plan, as amended (the “Plan”). The Plan is administered by the Compensation Committee of our Board of Directors (the “Compensation Committee”). Among the Compensation Committee’s responsibilities are: selecting participants to receive awards; determining the form, amount and other terms and conditions of awards; interpreting the provisions of the Plan or any award agreement; and adopting such rules, forms, instruments and guidelines for administering the Plan as it deems necessary or proper. All actions, interpretations and determinations by the Compensation Committee are final and binding. The composition of the Compensation Committee is intended to permit the awards under the Plan to qualify for exemption under Rule 16b-3 of the Exchange Act. In addition, awards under the Plan, including annual incentive awards paid to executive officers subject to section 162(m) of the Internal Revenue Code or covered employees, are intended to satisfy the requirements of section 162(m) to permit the deduction by us of the associated expenses for federal income tax purposes.
	All awards granted under the Plan have been issued at the closing price of our common stock on the NASDAQ Global Select Market on the date of the grant. All outstanding stock options have been awarded with five or ten year expiration dates at an exercise price equal to our closing price on the NASDAQ Global Select Market on the day the award was granted. A forfeiture rate based on a blended average of individual participant terminations and number of awards cancelled is used to estimate forfeitures prospectively.
	Stock Options
	Stock options represent the right to purchase shares of common stock in the future at the fair market value of the stock on the date of grant. In the event that any outstanding award expires, is forfeited, cancelled or otherwise terminated without the issuance of shares of our common stock or is otherwise settled in cash, shares of our common stock allocable to such award, including the unexercised portion of such award, shall again be available for the purposes of the Plan. If any award is exercised by tendering shares of our common stock to us, either as full or partial payment, in connection with the exercise of such award under the Plan or to satisfy our withholding obligation with respect to an award, only the number of shares of our common stock issued net of such shares tendered will be deemed delivered for purposes of determining the maximum number of shares of our common stock then available for delivery under the Plan. During the three and six months ended June 30, 2014 and 2013, we did not issue options to purchase shares of our common stock.
	Stock-based compensation expense relating to stock options outstanding for the three and six months ended June 30, 2014 and 2013 was negligible. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative Expense. The intrinsic value of stock options exercised for the six months ended June 30, 2014 and 2013, was approximately $0.3 million and $0.2 million, respectively.  The total tax benefit was approximately $0.1 million for each of the six-month periods ended June 30, 2014 and 2013, respectively.
	A summary of the status of our issued and outstanding stock options as of June 30, 2014 is as follows:
					Outstanding						Exercisable
	Exercise Price				Number Outstanding At 6/30/14				Weighted-Average Exercise Price		Number Exercisable At 6/30/14		Weighted-Average Exercise Price
	$	5.04				46,041			$	5.04		46,041	$	5.04
	$	9.5				85,000			$	9.5		85,000	$	9.5
	$	9.99				149,333			$	9.99		149,333	$	9.99
	$	10.42				29,548			$	10.42		29,548	$	10.42
	$	11.87				3,500			$	11.87		3,500	$	11.87
	$	12.5				19,139			$	12.5		19,139	$	12.5
	$	13.19				50,000			$	13.19		—	$	-
	$	22.34				30,000			$	22.34		30,000	$	22.34
						412,561			$	10.79		362,561	$	10.45
	The weighted average remaining contractual term and the aggregate intrinsic value for options outstanding at June 30, 2014 were 3.4 years and $3.0 million, respectively. The weighted average remaining contractual term and the aggregate intrinsic value for options exercisable at June 30, 2014 were 3.5 years and $2.8 million, respectively. As of June 30, 2014, unrecognized compensation expense related to stock options was negligible.
	Restricted Stock Awards
	During the six-month period ended June 30, 2014, the Compensation Committee approved the issuance of an aggregate of 17,643 shares of restricted common stock to 12 employees. During the six-month period ended June 30, 2013, the Compensation Committee approved the issuance of an aggregate of 383,384 shares of restricted stock to 40 employees and three non-employees. The shares granted are subject to time vesting and, in some cases, performance-based vesting. The shares will vest on the date on which the Compensation Committee certifies that the performance goals have been satisfied, provided that the recipient has been in continuous employment with us from the grant date through the date upon which the shares are released. Restrictions on the transfer associated with vesting schedules were determined by the Compensation Committee on an individual award basis. The restricted shares of common stock are valued at the closing price of our common stock on the NASDAQ Global Select Market on the date of grant. Upon a “change in control” of us, as such term is defined in the Plan, restrictions on time vesting and performance-based vesting restricted stock will lapse to varying degrees as outlined in each award agreement. Compensation expense associated with the restricted stock awards is recognized on a straight-line basis over the vesting period.
	Certain of our outstanding restricted stock awards granted in 2014, 2013 and 2012 are subject to market-based vesting through a calculation of total shareholder return (“TSR”) of our common stock relative to a pre-defined peer group over a three-year period.
	The number of shares ultimately awarded will correspond with the final TSR rank amongst the peer group in accordance with the following schedule:
	TSR Rank		Percentage of 2013 Awards to Vest
	3-Jan			100	%
	6-Apr			75	%
	10-Jul			50	%
	13-Nov			25	%
	14-16			0	%
	TSR Rank		Percentage of 2012 Awards to Vest
	3-Jan			100	%
	5-Apr			75	%
	8-Jun			50	%
	11-Sep			25	%
	14-Dec			0	%
	The weighted average fair value of the TSR awards granted as of June 30, 2014 and December 31, 2013 were $10.15 and $12.59 per share, respectively. Average fair values were estimated on the date of each grant using a Monte Carlo Simulation model that estimates the most likely outcome based on the terms of the award and used the following assumptions:
		Six Months Ended June 30, 2014				Year Ended December 31, 2013
	Expected Dividend Yield		0	%			0	%
	Risk-Free Interest Rate		0.8	%			0.7	%
	Expected Volatility – Rex Energy		50.4	%			50.5	%
	Expected Volatility – Peer Group	28.4%-65.7%				28.4%-63.5%
	Market Index		35.3	%			35.3	%
	Expected Life	Three Years				Three Years
	The dividend yield of zero reflects the fact that we have never paid cash dividends on our common stock and have no present intentions of doing so. The risk-free interest rate reflects the U.S. Treasury Constant Maturity rates as of the measurement date, converted into an implied “spot rate” yield. Our expected volatility estimates are based on observed historical volatility of daily stock returns for the three-year period preceding the grant date. Market index is an equal-weight index of the companies in the peer group. Expected life is measured as the grant date through the end of the performance period. Performance and market shares will vest on the date on which the Compensation Committee certifies that the performance goals have been satisfied, provided that the recipient has been in continuous employment with us from the grant date through the third anniversary of the grant date. Compensation expense for the TSR awards is recognized on a straight-line basis over the vesting period.
	Compensation expense associated with restricted stock awards totaled $1.1 million and $2.7 million for the three and six-month periods ended June 30, 2014, respectively, and $1.1 million and $2.2 million for the three and six-month periods ended June 30, 2013, respectively. As of June 30, 2014, total unrecognized compensation cost related to restricted common stock grants was approximately $6.8 million, which will be recognized over a weighted average period of 2.0 years.
	A summary of the restricted stock activity for the six months ended June 30, 2014 is as follows:
		Number of Shares				Weighted-Average Grant Date Fair Value
	Restricted stock awards, as of December 31, 2013		2,172,639			$	14.16
	Awards		17,643				15.64
	Forfeitures		(150,877	)			14.6
	Vested		(294,358	)			12.62
	Restricted stock awards, as of June 30, 2014		1,745,047			$	14.39

Commitments_and_Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2014
Commitments and Contingencies	'
	13. COMMITMENTS AND CONTINGENCIES
	Legal Reserves
	We are involved in various legal proceedings that arise in the ordinary course of our business. Although we cannot predict the outcome of these proceedings with certainty, we do not currently expect these matters to have a material adverse effect on our consolidated financial position or results of operations.
	The accrual of reserves for legal matters is included in Accrued Liabilities on our Consolidated Balance Sheets. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and the subjective judgment of management. While we believe that these reserves are adequate, there are uncertainties associated with legal proceedings and we can give no assurance that our estimate of any related liability will not increase or decrease in the future. The reserved and unreserved exposures for our legal proceedings could change based upon developments in those proceedings or changes in the facts and circumstances. It is possible that we could incur losses in excess of the amounts currently accrued. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed our current accruals by an amount that would have a material adverse effect on our consolidated financial position, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.
	There have been no significant changes with respect to the legal matters disclosed in our Annual Report on Form 10-K for the year ended December 31, 2013.
	Environmental
	Due to the nature of the oil and natural gas business, we are exposed to possible environmental risks. We have implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. We conduct periodic reviews of our policies and properties to identify changes in the environmental risk profile. In these reviews we evaluate whether there is a probable liability, its amount and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any remediation effort.
	We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. As of June 30, 2014, we know of no significant probable or possible environmental contingent liabilities.
	Letters of Credit
	At June 30, 2014, we had posted $2.0 million in various letters of credit to secure our drilling and related operations.
	Lease Commitments
	As of June 30, 2014, we have lease commitments for various real estate leases. Rent expense is recognized on a straight-line basis and has been recorded in General and Administrative expense on our Consolidated Statements of Operations. Rent expense for the three and six months ended June 30, 2014 and 2013 was $0.2 million and $0.5 million in 2014, respectively, and $0.2 million and $0.3 million in 2013, respectively. Lease commitments by year for each of the next five years are presented in the table below ($ in thousands):
	2014		$	516
	2015			1,011
	2016			950
	2017			923
	2018			234
	Thereafter			26
	Total		$	3,660
	Capacity Reservation
	We have a capacity reservation arrangement with a subsidiary of MarkWest Energy Partners, L.P. (“MarkWest”) to ensure sufficient capacity at the cryogenic gas processing plants owned by MarkWest in Butler County, Pennsylvania to process our produced natural gas. In the event that we do not process any gas through the cryogenic gas processing plants, we may be obligated to pay approximately $5.8 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 average working interest in the region of approximately 70%. Charges incurred for processing capacity with MarkWest were negligible during the three and six-month periods ended June 30, 2014 and 2013.
	Operational Commitments
	We have contracted drilling rig services on three rigs to support our Appalachian Basin operations. The minimum cost to retain these rigs would require payments of approximately $3.9 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 also have agreements for contracted completion services in the Appalachian Basin. The minimum cost to retain the completion services is approximately $2.6 million in 2014 and $5.1 million in 2015, which is consistent with our estimated working interest in this project area.
	Natural Gas Gathering, Processing and Sales Agreements
	During the normal course of business, we have entered into certain agreements to ensure the gathering, transportation, processing and sales of specified quantities of our oil, natural gas and NGLs. In some instances, we are obligated to pay shortfall fees, whereby we would pay a fee for any difference between actual volumes provided as compared to volumes that have been committed. In other instances, we are obligated to pay a fee on all volumes that are subject to the related agreement. In connection with our entry into certain of these agreements, we concurrently entered into a guaranty whereby we have guaranteed the payment of obligations under the specified agreements up to a maximum of $406.2 million, which is larger than our estimated minimum obligations due to certain contracts which have minimum commitment volumes and other contracts which contain provisions that require payment on all volumes delivered.
	For the three months ended June 30, 2014 and 2013, we incurred expenses related to the transportation, processing and marketing of our oil, natural gas and NGLs of approximately $11.1 million and $5.1 million, respectively. For the six months ended June 30, 2014 and 2013, we incurred expenses related to the transportation, processing and marketing of our oil, natural gas and NGLs of approximately $20.5 million and $10.0 million, respectively. Expense related to these agreements makes up a substantial portion of our Lease Operating Expense, which we expect to continue as existing agreements commence and new transportation, processing and marketing agreements are entered that will enable us to sell our product. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows ($ in thousands):
			Total
	2014		$	5,589
	2015			16,234
	2016			29,001
	2017			48,314
	2018			50,432
	Thereafter			726,512
	Total		$	876,082
	Drilling Commitments
	In 2012, we entered into a drill-to-earn agreement with MFC Drilling, Inc. (“MFC”). Under the terms and conditions of the agreement, we will acquire a minimum, through a drill-to-earn structure, a 62.5% working interest in approximately 4,510 acres in Belmont, Guernsey and Noble Counties, Ohio. The agreement provides that in order for us to earn the 62.5% working interest, we will bear the cost for our 62.5% working interest and 100% of the 15% working interest of MFC until such time that we have met the $14.1 million drilling carry obligation. As of June 30, 2014, the remaining drilling carry obligation balance was approximately $4.8 million. Our 2014 capital budget includes additional development in this area.
	In addition to the drilling carry obligation, we are required to meet drilling commitments. Amounts incurred toward the attainment of the drilling commitments are credited towards the drilling carry obligation. Our drilling commitments require us to commence the drilling of at least three Utica Shale wells by November 15 of each year until the carry obligation has been satisfied, with credits given to additional wells drilled beyond the annual commitment. We currently estimate the commitment for each well drilled and completed for our working interest and that of MFC to be approximately $8.0 million to $9.0 million. Should we not comply with the drilling commitments or terminate the agreement, we would be responsible for payment of any remaining drilling carry obligation at that time.
	Pennsylvania Impact Fee
	In 2012, Pennsylvania state legislators instituted a natural gas impact fee on producers of unconventional natural gas. The fee will be imposed on every producer of unconventional gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. The fee for each unconventional gas well is determined using the following matrix, with vertical unconventional gas wells being charged 20% of the applicable rates:
		<$2.25(a)			$2.26 - $2.99(a)		$3.00 - $4.99(a)		$5.00 - $5.99(a)		>$5.99(a)
	Year One	$	40,000		$	45,000	$	50,000	$	55,000	$	60,000
	Year Two	$	30,000		$	35,000	$	40,000	$	45,000	$	55,000
	Year Three	$	25,000		$	30,000	$	30,000	$	40,000	$	50,000
	Year 4 – 10	$	10,000		$	15,000	$	20,000	$	20,000	$	20,000
	Year 11 – 15	$	5,000		$	5,000	$	10,000	$	10,000	$	10,000
	(a) Pricing utilized for determining annual fee is based on the arithmetic mean of the NYMEX settled price for the near-month contract as reported by the Wall Street Journal for the last trading day of each month of a calendar year for the 12-month period ending December 31.
	All fees owed will be due on April 1 of each year. For each of the three-month periods ended June 30, 2014 and 2013, we recorded expense of approximately $0.7 million, and $1.3 million for each of the six month periods ended June 30, 2014 and 2013. We record expenses related to the impact fees as Production and Lease Operating Expense.
	Other
	In addition to the Asset Retirement Obligation discussed in Note 3, Future Abandonment Costs, to our Consolidated Financial Statements, we have withheld from distributions to certain other working interest owners amounts to be applied towards their share of those retirement costs. These amounts totaled $0.1 million and $0.3 million at June 30, 2014 and December 31, 2013, respectively, and are included in Other Liabilities on our Consolidated Balance Sheets.

Earnings_Loss_Per_Common_Share

Earnings (Loss) Per Common Share	6 Months Ended
	Jun. 30, 2014
Earnings (Loss) Per Common Share	'
	14. EARNINGS (LOSS) PER COMMON SHARE
	Basic income per common share is calculated based on the weighted average number of common shares outstanding at the end of the period, excluding restricted stock with performance-based vesting criteria. Diluted income per common share includes the assumed exercise of stock options and performance-based restricted stock which contain conditions that are not earnings or market based, given that the hypothetical effect is not anti-dilutive. For each of the three and six-month periods ending June 30, 2014, stock options to purchase 0.3 million shares of common stock were outstanding but not included in the computation of diluted net income per share primarily due to the estimate of shares that would be repurchased using the treasury method. Performance-based restricted stock awards of 0.8 million shares of common stock for each of the three and six-month periods ended June 30, 2014, were outstanding but not included in the computations of diluted net income per share calculations due to performance metrics that have not yet been attained. For each of the three and six-month periods ending June 30, 2013, stock options to purchase 0.3 million shares of common stock were outstanding but not included in the computation of diluted net income per share primarily due to the estimate of shares that would be repurchased using the treasury stock method. Performance-based restricted stock awards of 0.5 million shares and 0.6 million shares of common stock for the three and six months ended June 30, 2013, respectively, were outstanding but not included in the computations of diluted net income per share due to due to performance metrics that have not yet been attained. The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share amounts):
		Three Months Ended June 30,				Six Months Ended June 31,
	Numerator:	2014		2013		2014		2013
	Net Income From Continuing Operations, Less Noncontrolling Interests	$	8,078	$	13,220	$	16,946	$	10,445
	Net Income From Discontinued Operations		-		520		-		460
	Net Income	$	8,078	$	13,740	$	16,946	$	10,905
	Denominator:
	Weighted Average Common Shares Outstanding - Basic		53,164		52,555		53,075		52,527
	Effect of Dilutive Securities:
	Employee Stock Options		151		142		142		131
	Employee Performance-Based Restricted Stock Awards		194		214		294		243
	Weighted Average Common Shares Outstanding - Diluted		53,509		52,911		53,511		52,901
	Earnings per Common Share:
	Basic — Net Income From Continuing Operations	$	0.15	$	0.25	$	0.32	$	0.2
	— Net Income From Discontinued Operations		-		0.01		-		0.01
	— Net Income	$	0.15	$	0.26	$	0.32	$	0.21
	Diluted — Net Income From Continuing Operations	$	0.15	$	0.25	$	0.32	$	0.2
	— Net Income From Discontinued Operations		-		0.01		-		0.01
	— Net Income	$	0.15	$	0.26	$	0.32	$	0.21

Consolidated_Subsidiaries

Consolidated Subsidiaries	6 Months Ended
	Jun. 30, 2014
Consolidated Subsidiaries	'
	15. CONSOLIDATED SUBSIDIARIES
	Water Solutions Holdings
	In November 2009, we entered into a limited liability agreement with Sand Hills Management, LLC (“Sand Hills”) to form Water Solutions Holdings, LLC (“Water Solutions”) for the purpose of acquiring, managing and operating water treatment, disposal and transportation facilities that are designed to treat, dispose or transport brine and fresh waters used and produced in oil and gas well development activities. As the result of a change in membership interest that occurred on April 1, 2013, Rex Energy Corporation owns a 60% membership interest in Water Solutions and Sand Hills owns a 40% membership interest and serves as the operator of the entity. The change in ownership interests occurred in accordance with the original operating agreement which stipulated that the change would occur upon the return of our initial capital investments. The change in ownership transaction, in which we retained our controlling financial interest, was accounted for as an equity transaction, with no impact to our Consolidated Statements of Operations. Prior to the change in membership interests, the entity was owned 80% by us and 20% by Sand Hills.
	We fully consolidate the accounts of Water Solutions in our financial statements and accounted for the 40% equity interest owned by Sand Hills as a noncontrolling interest. Water Solutions is financed through cash contributions from its members and a credit facility upon which $7.8 million was drawn as of June 30, 2014. As of June 30, 2014, Water Solutions maintained capital leases of approximately $5.5 million. Capital contributions to Water Solutions during the first six months of 2014 and 2013 were negligible. The table below sets forth the carrying amount and classifications of Water Solutions’ assets and liabilities as of June 30, 2014 and December 31, 2013, with no restrictions or obligations to use certain assets to settle associated liabilities:
	($ in Thousands)	As of June 30, 2014			As of December 31, 2013
	Assets
	Cash and Cash Equivalents	$	528		$	593
	Accounts Receivable		13,541			9,882
	Inventory, Prepaid Expenses and Other		250			89
	Other Property and Equipment		17,478			11,798
	Wells and Facilities in Progress		298			1,031
	Accumulated Depreciation, Depletion and Amortization		(3,467	)		(1,954	)
	Deferred Financing Costs and Other Assets—Net		170			206
	Total Assets	$	28,798		$	21,645
	Liabilities
	Accounts Payable	$	267		$	758
	Current Maturities of Long-Term Debt		6,554			5,404
	Accrued Liabilities		4,746			6,247
	Senior Secured Line of Credit and Long-Term Debt		6,738			3,053
	Total Liabilities	$	18,305		$	15,462

Equity_Method_Investments

Equity Method Investments	6 Months Ended
	Jun. 30, 2014
Equity Method Investments	'
	16. EQUITY METHOD INVESTMENTS
	RW Gathering, LLC
	We own a 40% non-operated interest in RW Gathering, LLC (“RW Gathering”), which owns gas-gathering assets to facilitate development in our Appalachian Basin operations. We recorded our investment in RW Gathering of approximately $18.3 million and $18.7 million as of June 30, 2014 and December 31, 2013, respectively, on our Consolidated Balance Sheets as Equity Method Investments. We did not make any capital contributions to RW Gathering during the first six months of 2014 as compared to contributions of $2.2 million in cash to support gathering line construction during first six months of 2013.  RW Gathering recorded net losses from continuing operations of $0.5 million and $1.0 million for each of the three and six months ended June 30, 2014, respectively, as compared to losses of $0.5 million and $0.9 million for each of the three and six months ended June 30, 2013, respectively. The losses incurred were due to insurance fees, bank fees, rent expenses and depreciation expense. Our share of the net loss is recorded on the Statements of Operations as Loss on Equity Method Investments.
	During the three and six-month periods ended June 30, 2014, we incurred approximately $0.2 million and $0.4 million for 2014, respectively, as compared to $0.2 million and $0.4 million for 2013, respectively, in compression expenses that were charged to us from Williams Production Appalachia, LLC. These costs are in relation to compression costs incurred by RW Gathering and are recorded as Production and Lease Operating Expense on our Consolidated Statement of Operations. As of June 30, 2014 and December 31, 2013, there were no receivables due from RW Gathering to us.

Impairment_Expense

Impairment Expense	6 Months Ended
	Jun. 30, 2014
Impairment Expense	'
	17. IMPAIRMENT EXPENSE
	For the three and six months ended June 30, 2014 and 2013, impairment expenses incurred were negligible.   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. As of June 30, 2014, we continued to carry the costs of undeveloped properties of approximately $227.8 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale in the Appalachian Basin and for which we have development, trade or lease extension plans.

Exploration_Expense

Exploration Expense	6 Months Ended
	Jun. 30, 2014
Exploration Expense	'
	18. EXPLORATION EXPENSE
	For the three and six months ended June 30, 2014, we incurred approximately $1.4 million and $3.4 million in exploration expenses, respectively, as compared to $2.2 million and $4.4 million in exploration expenses for the same periods ended June 30, 2013, respectively. Approximately $2.4 million of the expense incurred in 2014 was due to geological and geophysical type expenditures. An additional $0.8 million of expense was incurred through the payment of delay rentals, predominately in the Appalachian Basin. Approximately $3.8 million of the expense incurred in 2013 was due to geological and geophysical type expenditures. An additional $0.5 million of expense was incurred through the payment of delay rentals, predominately in the Appalachian Basin.

Condensed_Consolidating_Financ

Condensed Consolidating Financial Information	6 Months Ended
	Jun. 30, 2014
Condensed Consolidating Financial Information	'
	19. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
	As of June 30, 2014, we had $350.0 million of outstanding Senior Notes due 2020, as shown in Note 8, Long-Term Debt, to our Consolidated Financial Statements. The Senior Notes are guaranteed by certain of our wholly-owned subsidiaries, or guarantor subsidiaries. Unless otherwise noted below, each of the following guarantor subsidiaries are wholly-owned by Rex Energy Corporation and have provided guarantees of the Senior Notes that are joint and several and full and unconditional as of June 30, 2014:
	—	Rex Energy I, LLC
	—	Rex Energy Operating Corporation
	—	Rex Energy IV, LLC
	—	PennTex Resources Illinois, Inc.
	—	R.E. Gas Development, LLC
	The non-guarantor subsidiaries include certain consolidated subsidiaries, including Water Solutions, R.E. Disposal, LLC, Rex Energy Marketing, LLC and R.E. Ventures Holdings, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of June 30, 2014, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries.
	The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the notes, (ii) the combined Guarantors, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of June 30, 2014 and December 31, 2013, the condensed consolidating statements of operations for each of the three and six-month periods ended June 30, 2014 and 2013, and the condensed consolidating statements of cash flows for each of the six-month periods ended June 30, 2014 and 2013.
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING BALANCE SHEETS
	AS OF JUNE 30, 2014
	($ in Thousands, Except Share and Per Share Data)
		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
	ASSETS
	Current Assets
	Cash and Cash Equivalents	$	5,431		$	515		$	5		$	—		$	5,951
	Accounts Receivable		35,441			13,538			—			(2,405	)		46,574
	Taxes Receivable		—			—			1,767			—			1,767
	Short-Term Derivative Instruments		4,181			—			—			—			4,181
	Current Deferred Tax Asset		—			—			4,010			—			4,010
	Inventory, Prepaid Expenses and Other		1,586			250			387			—			2,223
	Total Current Assets		46,639			14,303			6,169			(2,405	)		64,706
	Property and Equipment (Successful Efforts Method)
	Evaluated Oil and Gas Properties		884,639			213			—			(4,127	)		880,725
	Unevaluated Oil and Gas Properties		227,179			652			—			—			227,831
	Other Property and Equipment		61,331			18,386			—			—			79,717
	Wells and Facilities in Progress		108,802			6,576			—			(708	)		114,670
	Pipelines		17,399			—			—			(1,822	)		15,577
	Total Property and Equipment		1,299,350			25,827			—			(6,657	)		1,318,520
	Less: Accumulated Depreciation, Depletion and Amortization		(227,050	)		(3,755	)		—			618			(230,187	)
	Net Property and Equipment		1,072,300			22,072			—			(6,039	)		1,088,333
	Deferred Financing Costs and Other Assets—Net		2,421			170			9,013			—			11,604
	Equity Method Investments		18,300			—			—			—			18,300
	Intercompany Receivables		—			—			688,577			(688,577	)		—
	Investment in Subsidiaries – Net		4,156			4,361			332,163			(340,680	)		—
	Long-Term Derivative Instruments		159			—			—			—			159
	Total Assets	$	1,143,975		$	40,906		$	1,035,922		$	(1,037,701	)	$	1,183,102
	LIABILITIES AND STOCKHOLDERS’ EQUITY
	Current Liabilities
	Accounts Payable	$	51,431		$	324		$	—		$	(2,404	)	$	49,351
	Current Maturities of Long-Term Debt		1,175			6,554			—			—			7,729
	Accrued Liabilities		39,247			5,327			2,917			—			47,491
	Short-Term Derivative Instruments		6,699			—			—			—			6,699
	Total Current Liabilities		98,552			12,205			2,917			(2,404	)		111,270
	8.875% Senior Notes Due 2020		—			—			350,000			—			350,000
	Premium on Senior Notes – Net		—			—			2,905			—			2,905
	Senior Secured Line of Credit and Other Long-Term Debt		159			6,738			200,000			—			206,897
	Long-Term Derivative Instruments		1,535			—			—			—			1,535
	Long-Term Deferred Tax Liability		—			—			40,128			—			40,128
	Other Deposits and Liabilities		4,528			—			—			—			4,528
	Future Abandonment Cost		27,024			19			—			—			27,043
	Intercompany Payables		685,517			3,060			—			(688,577	)		—
	Total Liabilities		817,315			22,022			595,950			(690,981	)		744,306
	Stockholders’ Equity
	Common Stock		—			—			54			—			54
	Additional Paid-In Capital		177,143			84,241			459,754			(261,384	)		459,754
	Accumulated Earnings (Deficit)		149,517			(66,679	)		(19,836	)		(87,781	)		(24,779	)
	Rex Energy Stockholders’ Equity		326,660			17,562			439,972			(349,165	)		435,029
	Noncontrolling Interests		—			1,322			—			2,445			3,767
	Total Stockholders’ Equity		326,660			18,884			439,972			(346,720	)		438,796
	Total Liabilities and Stockholders’ Equity	$	1,143,975		$	40,906		$	1,035,922		$	(1,037,701	)	$	1,183,102
	REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE THREE MONTHS ENDED JUNE 30, 2014
($ in Thousands)
	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	72,903		$	—		$	—		$	—		$	72,903
Field Services Revenue		—			15,974			—			(2,887	)		13,087
Other Revenue		30			—			—			—			30
TOTAL OPERATING REVENUE		72,933			15,974			—			(2,887	)		86,020
OPERATING EXPENSES
Production and Lease Operating Expense		21,630			3			—			(13	)		21,620
General and Administrative Expense		7,221			950			1,083			(15	)		9,239
Loss on Disposal of Asset		223			7			—			—			230
Impairment Expense		16			—			—			—			16
Exploration Expense		1,364			3			—			—			1,367
Depreciation, Depletion, Amortization and Accretion		20,454			931			—			(159	)		21,226
Field Services Operating Expense		—			11,832			—			(2,263	)		9,569
Other Operating (Income) Expense		(56	)		—			—			—			(56	)
TOTAL OPERATING EXPENSES		50,852			13,726			1,083			(2,450	)		63,211
INCOME (LOSS) FROM OPERATIONS		22,081			2,248			(1,083	)		(437	)		22,809
OTHER INCOME (EXPENSE)
Interest Expense		(17	)		(145	)		(7,341	)		—			(7,503	)
Gain (Loss) on Derivatives, Net		(645	)		—			394			—			(251	)
Other Expense		55			—			—			(15	)		40
Loss From Equity Method Investments		(208	)		—			—			—			(208	)
Income (Loss) From Equity in Consolidated Subsidiaries		(56	)		56			12,409			(12,409	)		—
TOTAL OTHER INCOME (EXPENSE)		(871	)		(89	)		5,462			(12,424	)		(7,922	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		21,210			2,159			4,379			(12,861	)		14,887
Income Tax (Expense) Benefit		(9,051	)		(580	)		3,699			—			(5,932	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		12,159			1,579			8,078			(12,861	)		8,955
Net Income Attributable to Noncontrolling Interests		—			877			—			—			877
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	12,159		$	702		$	8,078		$	(12,861	)	$	8,078
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE SIX MONTHS ENDED JUNE 30, 2014
($ in Thousands)
	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	154,202		$	—		$	—		$	—		$	154,202
Field Services Revenue		—			38,597			—			(10,206	)		28,391
Other Revenue		74			—			—			—			74
TOTAL OPERATING REVENUE		154,276			38,597			—			(10,206	)		182,667
OPERATING EXPENSES
Production and Lease Operating Expense		41,660			6			—			(20	)		41,646
General and Administrative Expense		15,101			1,822			2,742			(35	)		19,630
Loss on Disposal of Asset		294			7			—			—			301
Impairment Expense		41			—			—			—			41
Exploration Expense		3,424			3			—			—			3,427
Depreciation, Depletion, Amortization and Accretion		40,277			1,643			—			(270	)		41,650
Field Services Operating Expense		—			28,782			—			(7,417	)		21,365
Other Operating Expense		27			—			—			—			27
TOTAL OPERATING EXPENSES		100,824			32,263			2,742			(7,742	)		128,087
INCOME (LOSS) FROM OPERATIONS		53,452			6,334			(2,742	)		(2,464	)		54,580
OTHER INCOME (EXPENSE)
Interest Expense		(31	)		(347	)		(14,260	)		—			(14,638	)
Gain (Loss) on Derivatives, Net		(11,084	)		—			1,083			—			(10,001	)
Other Income (Expense)		18			—			—			(35	)		(17	)
Loss From Equity Method Investments		(408	)		—			—			—			(408	)
Income (Loss) From Equity in Consolidated Subsidiaries		(81	)		81			25,977			(25,977	)		—
TOTAL OTHER INCOME (EXPENSE)		(11,586	)		(266	)		12,800			(26,012	)		(25,064	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		41,866			6,068			10,058			(28,476	)		29,516
Income Tax (Expense) Benefit		(15,689	)		(1,323	)		6,888			—			(10,124	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		26,177			4,745			16,946			(28,476	)		19,392
Net Income Attributable to Noncontrolling Interests		—			2,446			—			—			2,446
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	26,177		$	2,299		$	16,946		$	(28,476	)	$	16,946
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE SIX MONTHS ENDING JUNE 30, 2014
($ in Thousands)
	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	26,177		$	4,745		$	16,946		$	(28,476	)	$	19,392
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss From Equity Method Investments		408			—			—			—			408
Non-Cash Expenses (Income)		(133	)		186			3,283			—			3,336
Depreciation, Depletion, Amortization and Accretion		40,277			1,643			—			(270	)		41,650
Deferred Income Tax Expense (Benefit)		15,689			1,323			(6,888	)		—			10,124
(Gain) Loss on Derivatives		11,084			—			(1,083	)		—			10,001
Cash Settlements of Derivatives		(7,211	)		—			878			—			(6,333	)
Dry Hole Expense		86			—			—			—			86
Loss on Sale of Asset		294			7			—			—			301
Impairment Expense		41			—			—			—			41
Changes in operating assets and liabilities
Accounts Receivable		(3,163	)		(3,664	)		3,423			(898	)		(4,302	)
Inventory, Prepaid Expenses and Other Assets		505			(161	)		(360	)		—			(16	)
Accounts Payable and Accrued Liabilities		13,404			(1,432	)		5			898			12,875
Other Assets and Liabilities		(970	)		(22	)		—			—			(992	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		96,488			2,625			16,204			(28,746	)		86,571
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		131,376			(4	)		(157,352	)		25,980			—
Proceeds from Joint Venture Acreage Management		146			—			—			—			146
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		139			—			—			—			139
Acquisitions of Undeveloped Acreage		(39,484	)		(655	)		—			—			(40,139	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(183,765	)		(4,578	)		—			2,766			(185,577	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(91,588	)		(5,237	)		(157,352	)		28,746			(225,431	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			9,409			153,000			—			162,409
Repayments of Long-Term Debt and Lines of Credit		—			(5,753	)		(12,000	)		—			(17,753	)
Repayments of Loans and Other Long-Term Debt		(855	)		(313	)		—			—			(1,168	)
Debt Issuance Costs		—			(4	)		(273	)		—			(277	)
Proceeds from Exercise of Stock Options		—			—			421			—			421
Distributions by the Partners of Consolidated Subsidiaries		—			(721	)		—			—			(721	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(855	)		2,618			141,148			—			142,911
NET INCREASE IN CASH		4,045			6			—			—			4,051
CASH – BEGINNING		1,386			509			5			—			1,900
CASH - ENDING	$	5,431		$	515		$	5		$	—		$	5,951
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
AS OF DECEMBER 31, 2013
($ in Thousands, Except Share and Per Share Data)
	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,386		$	509		$	5		$	—		$	1,900
Accounts Receivable		32,283			9,882			—			(3,302	)		38,863
Taxes Receivable		—			—			5,189			—			5,189
Short-Term Derivative Instruments		5,180			—			488			—			5,668
Current Deferred Tax Asset		—			—			3,451			—			3,451
Inventory, Prepaid Expenses and Other		2,092			89			26			—			2,207
Total Current Assets		40,941			10,480			9,159			(3,302	)		57,278
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		752,781			—			—			(3,101	)		749,680
Unevaluated Oil and Gas Properties		189,385			—			—			—			189,385
Other Property and Equipment		57,409			12,706			—			—			70,115
Wells and Facilities in Progress		70,759			6,576			—			(790	)		76,545
Pipelines		7,678			—			—			—			7,678
Total Property and Equipment		1,078,012			19,282			—			(3,891	)		1,093,403
Less: Accumulated Depreciation, Depletion and Amortization		(188,699	)		(2,172	)		—			350			(190,521	)
Net Property and Equipment		889,313			17,110			—			(3,541	)		902,882
Deferred Financing Costs and Other Assets—Net		2,421			206			9,366			—			11,993
Equity Method Investments		18,708			—			—			—			18,708
Intercompany Receivables		—			—			628,517			(628,517	)		—
Investment in Subsidiaries – Net		4,442			1,197			216,945			(222,584	)		—
Long-Term Derivative Instruments		535			—			—			—			535
Total Assets	$	956,360		$	28,993		$	863,987		$	(857,944	)	$	991,396
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	33,613		$	794		$	—		$	(3,304	)	$	31,103
Current Maturities of Long-Term Debt		1,339			5,404			—			—			6,743
Accrued Liabilities		45,196			6,287			2,967			—			54,450
Short-Term Derivative Instruments		4,663			—			—			—			4,663
Total Current Liabilities		84,811			12,485			2,967			(3,304	)		96,959
8.875% Senior Notes Due 2020		—			—			350,000			—			350,000
Premium (Discount) on Senior Notes – Net		—			—			3,078			—			3,078
Senior Secured Line of Credit and Other Long-Term Debt		137			3,054			59,000			—			62,191
Long-Term Derivative Instruments		1,071			—			694			—			1,765
Long-Term Deferred Tax Liability		—			—			29,446			—			29,446
Other Deposits and Liabilities		4,992			—			—			—			4,992
Future Abandonment Cost		26,027			13			—			—			26,040
Intercompany Payables		554,329			74,188			—			(628,517	)		—
Total Liabilities		671,367			89,740			445,185			(631,821	)		574,471
Stockholders’ Equity
Common Stock		—			—			54			—			54
Additional Paid-In Capital		177,144			6,488			456,554			(183,632	)		456,554
Accumulated Earnings (Deficit)		107,849			(67,720	)		(37,806	)		(44,048	)		(41,725	)
Rex Energy Stockholders’ Equity		284,993			(61,232	)		418,802			(227,680	)		414,883
Noncontrolling Interests		—			485			—			1,557			2,042
Total Stockholders’ Equity		284,993			(60,747	)		418,802			(226,123	)		416,925
Total Liabilities and Stockholders’ Equity	$	956,360		$	28,993		$	863,987		$	(857,944	)	$	991,396
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE THREE MONTHS ENDED JUNE 30, 2013
($ in Thousands)
	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	51,444		$	—		$	—		$	—		$	51,444
Field Services Revenue		—			5,072			—			(1,232	)		3,840
Other Revenue		76			—			—			—			76
TOTAL OPERATING REVENUE		51,520			5,072			—			(1,232	)		55,360
OPERATING EXPENSES
Production and Lease Operating Expense		13,090			2			—			—			13,092
General and Administrative Expense		5,970			659			1,153			—			7,782
Loss on Disposal of Asset		1,502			—			—			—			1,502
Impairment Expense		105			—			—			—			105
Exploration Expense		2,225			—			—			—			2,225
Depreciation, Depletion, Amortization and Accretion		12,645			336			—			(38	)		12,943
Field Services Operating Expense		—			3,510			—			(862	)		2,648
Other Operating Expense		447			—			—			—			447
TOTAL OPERATING EXPENSES		35,984			4,507			1,153			(900	)		40,744
INCOME (LOSS) FROM OPERATIONS		15,536			565			(1,153	)		(332	)		14,616
OTHER INCOME (EXPENSE)
Interest Expense		(22	)		(28	)		(5,776	)		—			(5,826	)
Gain on Derivatives, Net		11,741			—			—			—			11,741
Other Income (Expense)		2,235			—			—			(22	)		2,213
Loss From Equity Method Investments		(183	)		—			—			—			(183	)
Income (Loss) From Equity in Consolidated Subsidiaries		(11	)		11			17,697			(17,697	)		—
TOTAL OTHER INCOME (EXPENSE)		13,760			(17	)		11,921			(17,719	)		7,945
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		29,296			548			10,768			(18,051	)		22,561
Income Tax (Expense) Benefit		(11,964	)		(128	)		2,972			—			(9,120	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		17,332			420			13,740			(18,051	)		13,441
Income From Discontinued Operations, Net of Income Taxes		—			520			—			—			520
NET INCOME (LOSS)		17,332			940			13,740			(18,051	)		13,961
Net Income Attributable to Noncontrolling Interests		—			221			—			—			221
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	17,332		$	719		$	13,740		$	(18,051	)	$	13,740
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE SIX MONTHS ENDING JUNE 30, 2013
($ in Thousands)
	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	92,384		$	—		$	—		$	—		$	92,384
Field Services Revenue		—			13,124			—			(2,779	)		10,345
Other Revenue		100			—			—			—			100
TOTAL OPERATING REVENUE		92,484			13,124			—			(2,779	)		102,829
OPERATING EXPENSES
Production and Lease Operating Expense		26,487			5			—			—			26,492
General and Administrative Expense		12,033			1,148			2,453			(56	)		15,578
Loss on Disposal of Asset		1,493			—			—			—			1,493
Impairment Expense		170			—			—			—			170
Exploration Expense		4,269			—			—			—			4,269
Depreciation, Depletion, Amortization and Accretion		23,559			603			—			(61	)		24,101
Field Services Operating Expense		—			8,648			—			(1,945	)		6,703
Other Operating Expense		891			—			—			—			891
TOTAL OPERATING EXPENSES		68,902			10,404			2,453			(2,062	)		79,697
INCOME (LOSS) FROM OPERATIONS		23,582			2,720			(2,453	)		(717	)		23,132
OTHER INCOME (EXPENSE)
Interest Expense		(31	)		(40	)		(9,760	)		—			(9,831	)
Gain on Derivatives, Net		3,201			—			—			—			3,201
Other Income (Expense)		2,129			—			—			(56	)		2,073
Loss From Equity Method Investments		(361	)		—			—			—			(361	)
Income (Loss) From Equity in Consolidated Subsidiaries		(22	)		22			17,856			(17,856	)		—
TOTAL OTHER INCOME (EXPENSE)		4,916			(18	)		8,096			(17,912	)		(4,918	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		28,498			2,702			5,643			(18,629	)		18,214
Income Tax (Expense) Benefit		(11,555	)		(822	)		5,262			—			(7,115	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		16,943			1,880			10,905			(18,629	)		11,099
Income From Discontinued Operations, Net of Income Taxes		—			460			—			—			460
NET INCOME (LOSS)		16,943			2,340			10,905			(18,629	)		11,559
Net Income Attributable to Noncontrolling Interests		—			654			—			—			654
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	16,943		$	1,686		$	10,905		$	(18,629	)	$	10,905
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE SIX MONTHS ENDING JUNE 30, 2013
($ in Thousands)
	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	16,943		$	2,340		$	10,905		$	(18,629	)	$	11,559
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss From Equity Method Investments		361			—			—			—			361
Non-Cash Expenses		3			50			2,974			—			3,027
Depreciation, Depletion, Amortization and Accretion		23,559			603			—			(61	)		24,101
Deferred Income Tax Expense (Benefit)		11,499			1,135			(5,262	)		—			7,372
Gain on Derivatives		(3,201	)		—			—			—			(3,201	)
Cash Settlements of Derivatives		4,798			—			—			—			4,798
Dry Hole Expense		485			—			—			—			485
(Gain) Loss on Sale of Asset		1,493			(969	)		—			—			524
Impairment Expense		170			—			—			—			170
Changes in operating assets and liabilities
Accounts Receivable		85,176			(3,089	)		(76,104	)		(4,009	)		1,974
Inventory, Prepaid Expenses and Other Assets		25			(6	)		18			—			37
Accounts Payable and Accrued Liabilities		8,503			805			1,480			(435	)		10,353
Other Assets and Liabilities		(557	)		(5	)		—			—			(562	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		149,257			864			(65,989	)		(23,134	)		60,998
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		(6,704	)		1,083			(16,679	)		22,300			—
Proceeds from Joint Venture Acreage Management		107			—			—			—			107
Contributions to Equity Method Investments		—			(2,207	)		—			—			(2,207	)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		498			3,234			—			—			3,732
Acquisitions of Undeveloped Acreage		(15,704	)		(2	)		—			—			(15,706	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(122,834	)		(1,609	)		—			834			(123,609	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(144,637	)		499			(16,679	)		23,134			(137,683	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			1,750			—			—			1,750
Repayments of Long-Term Debt and Lines of Credit		—			(876	)		—			—			(876	)
Repayments of Loans and Other Notes Payable		(543	)		(243	)		—			—			(786	)
Proceeds from Senior Notes, net of Discounts and Premiums		—			—			105,000			—			105,000
Debt Issuance Costs		—			—			(2,894	)		—			(2,894	)
Proceeds from the Exercise of Stock Options		—			—			266			—			266
Purchase of Non-Controlling Interests		—			(150	)		—			—			(150	)
Distributions by the Partners of Consolidated Subsidiaries		—			(406	)		—			—			(406	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(543	)		75			102,372			—			101,904
NET INCREASE IN CASH		4,077			1,438			19,704			—			25,219
CASH – BEGINNING		4,227			824			38,924			—			43,975
CASH - ENDING	$	8,304		$	2,262		$	58,628		$	—		$	69,194

Subsequent_Events

Subsequent Events	6 Months Ended
	Jun. 30, 2014
Subsequent Events	'
	20. SUBSEQUENT EVENTS
	Senior Notes
	On July 14, 2014, we issued $325.0 million in aggregate principal amount of 6.25% senior notes in an offering at an issue price of 100.0% of the aggregate principal amount of senior notes, due to mature on August 1, 2022. We received net proceeds in the offering of approximately $318.8 million, after discounts and offering expenses. Interest is payable semi-annually at a rate of 6.25% per annum on February 1 and August 1 of each year, with the first interest payment to be made on February 1, 2015. We used the proceeds of the offering to repay all of the borrowings outstanding under our Senior Credit Facility, which was $218.0 million at the time of the payment, and expect to use the remaining proceeds for general corporate purposes.

Recently_Issued_Accounting_Pro1

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

Business_Segment_Information_T

Business Segment Information (Tables)	6 Months Ended
	Jun. 30, 2014
Performance of Business Segments Based on Net Income (Loss) from Continuing Operations, before Income Taxes	'
	We evaluate the performance of our business segments based on net income (loss) from continuing operations, before income taxes. All intercompany transactions, including those between consolidated business segments, are eliminated in consolidation. Summarized financial information concerning our segments is shown in the following table for the three and six months ended June 30, 2014 and 2013 (in thousands):
		Exploration and Production		Field Services			Intercompany Eliminations			Consolidated Total
	Three Months Ended June 30, 2014
	Revenues	$	72,933	$	15,974		$	(2,887	)	$	86,020
	Inter-Segment Revenues		—		(2,887	)		2,887			—
	Total Revenues		72,933		13,087			—			86,020
	Income (Loss) From Continuing Operations, Before Income Taxes	$	13,146	$	2,192		$	(451	)	$	14,887
	Three Months Ended June 30, 2013
	Revenues	$	51,520	$	5,072		$	(1,232	)	$	55,360
	Inter-Segment Revenues		—		(1,232	)		1,232			—
	Total Revenues		51,520		3,840			—			55,360
	Income (Loss) From Continuing Operations, Before Income Taxes	$	22,339	$	552		$	(330	)	$	22,561
	Six Months Ended June 30, 2014
	Revenues	$	154,276	$	38,597		$	(10,206	)	$	182,667
	Inter-Segment Revenues				(10,206	)		10,206			—
	Total Revenues		154,276		28,391			—			182,667
	Income (Loss) From Continuing Operations, Before Income Taxes	$	25,900	$	6,113		$	(2,497	)	$	29,516
	Six Months Ended June, 2013
	Revenues	$	92,484	$	13,124		$	(2,779	)	$	102,829
	Inter-Segment Revenues		—		(2,779	)		2,779			—
	Total Revenues		92,484		10,345			—			102,829
	Income (Loss) From Continuing Operations, Before Income Taxes	$	16,272	$	2,715		$	(773	)	$	18,214
	As of June 30, 2014
	Total Assets	$	1,162,747	$	28,798		$	(8,443	)	$	1,183,102
	As of December  31, 2013
	Total Assets	$	971,973	$	26,266		$	(6,843	)	$	991,396

Future_Abandonment_Cost_Tables

Future Abandonment Cost (Tables)	6 Months Ended
	Jun. 30, 2014
Future Abandonment Costs	'
	$ in Thousands	30-Jun-14
	Beginning Balance	$	28,525
	Future Abandonment Obligation Incurred		590
	Future Abandonment Obligation Settled		(841	)
	Future Abandonment Obligation Revision of Estimated Obligation		14
	Future Abandonment Obligation Accretion Expense		1,630
	Total Future Abandonment Cost1	$	29,918
	1 Includes approximately $2.9 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

Discontinued_OperationsAssets_1

Discontinued Operations/Assets Held For Sale (Tables)	6 Months Ended
	Jun. 30, 2014
Summary of Financial Information for Discontinued Operations	'
	Summarized financial information for Discontinued Operations is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support.
		Three Months Ended June 30,					Six Months Ended June 30,
	($ in Thousands)	2014		2013			2014		2013
	Revenues:
	Oil, Natural Gas and NGL Sales	$	—	$	16		$	—	$	25
	Total Operating Revenue		—		16			—		25
	Costs and Expenses:
	Production and Lease Operating Expense		—		59			—		104
	General and Administrative Expense		—		11			—		23
	Exploration Expense		—		44			—		97
	Other Income Expense		—		—			—		(3	)
	Gain on Sale of Asset		—		(973	)		—		(969	)
	Total Costs and Expenses		—		(859	)		—		(748	)
	Income from Discontinued Operations Before Income Taxes		—		875			—		773
	Income Tax Expense		—		(355	)		—		(313	)
	Income from Discontinued Operations, net of taxes	$	—	$	520		$	—	$	460
	Production:
	Crude Oil (Bbls)		—		209			—		356
	Total (Mcfe)		—		1,254			—		2,136

Long_Term_Debt_Tables

Long Term Debt (Tables)	6 Months Ended
	Jun. 30, 2014
Components of Long-Term Debt and Lines of Credit	'
	In addition to the Senior Credit Facility and the Senior Notes, we may, from time to time in the normal course of business finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and other obligations consisted of the following at June 30, 2014 and December 31, 2013:
	($ in Thousands)	June 30, 2014 (Unaudited)			31-Dec-13
	8.875% Senior Notes Due 2020	$	350,000		$	350,000
	Premium on Senior Notes		2,905			3,078
	Senior Line of Credit(a)		200,000			59,000
	Capital Leases and Other Obligations(a)		14,626			9,934
	Total Debt		567,531			422,012
	Less Current Portion of Long-Term Debt		(7,729	)		(6,743	)
	Total Long-Term Debt	$	559,802		$	415,269
	(a)	The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement.      The weighted average interest rate on borrowings under our Senior Credit Facility for the three and six months ended June 30, 2014 and the year ended December 31, 2013, was approximately 2.0%, 2.0% and 1.9%, respectively. The average interest rate on our capital leases and other obligations for the three and six months ended June 30, 2014 and the year ended December 31, 2013, was approximately 4.0%, 4.0% and 5.3%, respectively.
Principal Maturity Schedule for Debt Outstanding	'
	The following is the principal maturity schedule for debt outstanding as of June 30, 2014:
	2014	$	5,992
	2015		3,089
	2016		2,749
	2017		1,428
	2018		200,588
	Thereafter		350,780
	Total(a)	$	564,626
	—	Excludes $2.9 million net premium on Senior Notes.

Fair_Value_Of_Financial_And_De1

Fair Value Of Financial And Derivative Instruments (Tables)	6 Months Ended
	Jun. 30, 2014
Schedule of Location and Amounts of Gains and Losses on Derivative Instruments	'
	The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three and six months ended June 30, 2014 and 2013:
			For the Three Months Ended June 30,								For the Six Months Ended June 30,
	In thousands		2014				2013				2014				2013
	Oil		$	(2,482	)		$	9,121			$	(3,650	)		$	8,137
	Natural Gas			2,147				1,445				(6,781	)			(6,127	)
	NGLs			(310	)			1,175				(653	)			1,191
	Interest Rate			394				—				1,083				—
	Gain (Loss) on Derivatives, Net		$	(251	)		$	11,741			$	(10,001	)		$	3,201
Asset or Liability Financial Commodity Derivative Instrument Positions	'
	Our open asset/(liability) financial commodity derivative instrument positions at June 30, 2014 consisted of:
	Period		Volume		Put Option				Floor				Ceiling				Swap			Long Call		Fair Market Value ($ in Thousands)
	Oil
	2014—Collar		30,000 Bbls		$	—			$	90			$	97.65			$	—		$	—	$	(189	)
	2014—Cap Swap		190,000 Bbls			81.32				—				—				97.84			—		(1,038	)
	2014—Three Way Collar		180,000 Bbls			77.92				88.98				103.39				—			—		(440	)
	2014—Deferred Put Spread		84,000 Bbls			75				90				—				—			—		(441	)
	2015—Three Way Collar		120,000 Bbls			78.75				89.06				100.44				—			—		(358	)
	2015—Call Protected Swap		30,000 Bbls			—				—				—				95.76			110		(48	)
			634,000 Bbls																			$	(2,514	)
	Natural Gas
	2014—Call		900,000 Mcf		$	—			$	—			$	5			$	—		$	—	$	(68	)
	2014—Three Way Collar		6,750,000 Mcf			3.53				4.19				4.7				—			—		(231	)
	2014—Swap		2,220,000 Mcf			—				—				—				3.96			—		(1,017	)
	2014—Collar		1,500,000 Mcf			—				3.81				4.54				—			—		(133	)
	2014—Swaption		1,200,000 Mcf			—				—				—				4.45			—		(578	)
	2014—Basis Swap		3,000,000 Mcf			—				—				—				(0.37	)		—		2,834
	2014—Cap Swap		1,800,000 Mcf			3.3				—				—				4.09			—		(518	)
	2015—Three Way Collar		6,900,000 Mcf			3.63				4.2				4.68				—			—		(89	)
	2015—Swap		1,200,000 Mcf			—				—				—				4.18			—		(137	)
	2015—Cap Swap		2,400,000 Mcf			3.28				—				—				4.1			—		(569	)
	2015—Call		2,400,000 Mcf			—				—				4.4				—			—		(717	)
	2015—Collar		1,200,000 Mcf			—				4.25				4.7				—			—		139
	2015—Swaption		0 Mcf			—				—				—				4.4			—		(667	)
	2015—Basis Swap		600,000 Mcf			—				—				—				(0.35	)		—		494
			32,070,000 Mcf																			$	(1,257	)
	NGLs
	2014—Swap		474,000 Bbls		$	—			$	—			$	—			$	57.9		$	—	$	(158	)
	2015—Swap		42,000 Bbls			—				—				—				45.99			—	$	35
			516,000 Bbls																			$	(123	)
Combined Fair Value of Derivatives	'
	The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013 is summarized below
		June 30,				December 31,
	($ in Thousands)	2014				2013
	Short-Term Derivative Assets:
	Crude Oil—Collars	$	—			$	380
	Crude Oil—Three-Way Collars		—				104
	NGL—Swaps		372				83
	Natural Gas—Swaps		—				106
	Natural Gas—Cap Swaps		—				5
	Natural Gas—Basis Swaps		3,328				3,984
	Natural Gas—Three-Way Collars		342				518
	Natural Gas—Collars		139				—
	Interest Rate—Swap		—				488
	Total Short-Term Derivative Assets	$	4,181			$	5,668
	Long-Term Derivative Assets:
	Natural Gas—Cap Swap	$	—			$	5
	Natural Gas—Swaps		—				22
	Natural Gas—Basis Swaps		—				339
	Natural Gas—Collars		69				—
	Natural Gas—Three-Way Collars		90				169
	Total Long-Term Derivative Assets	$	159			$	535
	Total Derivative Assets	$	4,340			$	6,203
	Short-Term Derivative Liabilities:
	Crude Oil—Collars	$	(189	)		$	(42	)
	Crude Oil—Swaps		—				(119	)
	Crude Oil—Call Protected Swap		(48	)			—
	Crude Oil—Cap Swap		(1,038	)			—
	Crude Oil—Three-Way Collars		(798	)			(29	)
	Crude Oil—Deferred Put Spread		(441	)			(585	)
	NGL—Swaps		(495	)			(995	)
	Natural Gas—Three-Way Collars		(594	)			(125	)
	Natural Gas—Collars		(202	)			(235	)
	Natural Gas—Call		(426	)			(150	)
	Natural Gas—Cap Swaps		(804	)			(496	)
	Natural Gas—Swaption		(578	)			(717	)
	Natural Gas—Swaps		(1,086	)			(1,170	)
	Total Short - Term Derivative Liabilities	$	(6,699	)		$	(4,663	)
	Long-Term Derivative Liabilities:
	Natural Gas—Swaps	$	(68	)		$	(4	)
	Natural Gas—Cap Swaps		(283	)			(307	)
	Natural Gas—Three-Way Collars		(158	)			—
	Natural Gas—Swaption		(667	)			—
	Natural Gas—Call		(359	)			(761	)
	Interest Rate—Swap		—				(693	)
	Total Long-Term Derivative Liabilities	$	(1,535	)		$	(1,765	)
	Total Derivative Liabilities	$	(8,234	)		$	(6,428	)
Significant Unobservable Inputs Used in Fair Value Measurements of Natural Gas Basis Swaps	'
	The significant unobservable inputs and the range and weighted average of these inputs used in the fair value measurements of our natural gas basis swaps as of June 30, 2014 are included in the table below.
		Range		Weighted Average				Fair Value
		(price per Mcf)		(price per Mcf)				(in thousands)
	Natural Gas Basis Differential Forward Curve	($ 0.85) - ($ 1.63)		$	(1.28	)		$	3,328
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):
Reconciliation of Commodity Derivative Contracts Measured at Fair Value on Recurring Basis Using Significant Unobservable Inputs (Level 3)	'
	The table below sets forth a reconciliation of our commodity derivative contracts at fair value on a recurring basis using significant unobservable inputs (Level 3) during the six months ended June 30, 2014 and 2013:
		Six Months Ended June 30,
	($ in Thousands)	2014				2013
	Beginning Balance of Level 3	$	4,323			$	—
	Changes in Fair Value		(2,007	)			—
	Purchases		—				—
	Settlements Received		1,012				—
	Ending Balance of Level 3	$	3,328			$	—
Financial Instruments Not Recorded at Fair Value	'
	The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements:
		30-Jun-14								31-Dec-13
	$ in Thousands	Carrying Amount				Fair Value				Carrying Amount				Fair Value
	8.875% Senior Notes due 2020	$	350,000			$	388,500			$	350,000			$	385,000
	Secured Lines of Credit		200,000				200,000				59,000				59,000
	Capital Leases and Other Obligations		14,626				14,280				9,934				9,731
	Total	$	564,626			$	602,780			$	418,934			$	453,731

Income_Taxes_Tables

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2014
Schedule of Income Tax Included in Continuing Operations	'
	Income tax included in continuing operations was as follows:
		Three Months Ended June 30,						Six Months Ended June 30,
	($ in Thousands)	2014			2013			2014			2013
	Income Expense	$	(5,932	)	$	(9,120	)	$	(10,124	)	$	(7,115	)
	Effective Tax Rate		42.3	%		40.8	%		37.4	%		40.5	%

Employee_Benefit_and_Equity_Pl1

Employee Benefit and Equity Plans (Tables)	6 Months Ended
	Jun. 30, 2014
Summary of Issued and Outstanding Stock Options	'
	A summary of the status of our issued and outstanding stock options as of June 30, 2014 is as follows:
					Outstanding						Exercisable
	Exercise Price				Number Outstanding At 6/30/14				Weighted-Average Exercise Price		Number Exercisable At 6/30/14		Weighted-Average Exercise Price
	$	5.04				46,041			$	5.04		46,041	$	5.04
	$	9.5				85,000			$	9.5		85,000	$	9.5
	$	9.99				149,333			$	9.99		149,333	$	9.99
	$	10.42				29,548			$	10.42		29,548	$	10.42
	$	11.87				3,500			$	11.87		3,500	$	11.87
	$	12.5				19,139			$	12.5		19,139	$	12.5
	$	13.19				50,000			$	13.19		—	$	-
	$	22.34				30,000			$	22.34		30,000	$	22.34
						412,561			$	10.79		362,561	$	10.45
Percentage of Awards to Vest	'
	The number of shares ultimately awarded will correspond with the final TSR rank amongst the peer group in accordance with the following schedule:
	TSR Rank		Percentage of 2013 Awards to Vest
	3-Jan			100	%
	6-Apr			75	%
	10-Jul			50	%
	13-Nov			25	%
	14-16			0	%
	TSR Rank		Percentage of 2012 Awards to Vest
	3-Jan			100	%
	5-Apr			75	%
	8-Jun			50	%
	11-Sep			25	%
	14-Dec			0	%
Monte Carlo Simulation Model Assumptions Used to Estimate Fair Value of Restricted Stock	'
	The weighted average fair value of the TSR awards granted as of June 30, 2014 and December 31, 2013 were $10.15 and $12.59 per share, respectively. Average fair values were estimated on the date of each grant using a Monte Carlo Simulation model that estimates the most likely outcome based on the terms of the award and used the following assumptions:
		Six Months Ended June 30, 2014				Year Ended December 31, 2013
	Expected Dividend Yield		0	%			0	%
	Risk-Free Interest Rate		0.8	%			0.7	%
	Expected Volatility – Rex Energy		50.4	%			50.5	%
	Expected Volatility – Peer Group	28.4%-65.7%				28.4%-63.5%
	Market Index		35.3	%			35.3	%
	Expected Life	Three Years				Three Years
Summary of Nonvested Restricted Stock Activity	'
	A summary of the restricted stock activity for the six months ended June 30, 2014 is as follows:
		Number of Shares				Weighted-Average Grant Date Fair Value
	Restricted stock awards, as of December 31, 2013		2,172,639			$	14.16
	Awards		17,643				15.64
	Forfeitures		(150,877	)			14.6
	Vested		(294,358	)			12.62
	Restricted stock awards, as of June 30, 2014		1,745,047			$	14.39

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	6 Months Ended
	Jun. 30, 2014
Lease Commitments for Each of Next Five Years	'
	As of June 30, 2014, we have lease commitments for various real estate leases. Rent expense is recognized on a straight-line basis and has been recorded in General and Administrative expense on our Consolidated Statements of Operations. Rent expense for the three and six months ended June 30, 2014 and 2013 was $0.2 million and $0.5 million in 2014, respectively, and $0.2 million and $0.3 million in 2013, respectively. Lease commitments by year for each of the next five years are presented in the table below ($ in thousands):
	2014		$	516
	2015			1,011
	2016			950
	2017			923
	2018			234
	Thereafter			26
	Total		$	3,660
Minimum Net Obligations under Sales, Gathering and Transportation Agreements	'
	For the three months ended June 30, 2014 and 2013, we incurred expenses related to the transportation, processing and marketing of our oil, natural gas and NGLs of approximately $11.1 million and $5.1 million, respectively. For the six months ended June 30, 2014 and 2013, we incurred expenses related to the transportation, processing and marketing of our oil, natural gas and NGLs of approximately $20.5 million and $10.0 million, respectively. Expense related to these agreements makes up a substantial portion of our Lease Operating Expense, which we expect to continue as existing agreements commence and new transportation, processing and marketing agreements are entered that will enable us to sell our product. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows ($ in thousands):
			Total
	2014		$	5,589
	2015			16,234
	2016			29,001
	2017			48,314
	2018			50,432
	Thereafter			726,512
	Total		$	876,082
Fee for Unconventional Gas Wells	'
	In 2012, Pennsylvania state legislators instituted a natural gas impact fee on producers of unconventional natural gas. The fee will be imposed on every producer of unconventional gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. The fee for each unconventional gas well is determined using the following matrix, with vertical unconventional gas wells being charged 20% of the applicable rates:
		<$2.25(a)			$2.26 - $2.99(a)		$3.00 - $4.99(a)		$5.00 - $5.99(a)		>$5.99(a)
	Year One	$	40,000		$	45,000	$	50,000	$	55,000	$	60,000
	Year Two	$	30,000		$	35,000	$	40,000	$	45,000	$	55,000
	Year Three	$	25,000		$	30,000	$	30,000	$	40,000	$	50,000
	Year 4 – 10	$	10,000		$	15,000	$	20,000	$	20,000	$	20,000
	Year 11 – 15	$	5,000		$	5,000	$	10,000	$	10,000	$	10,000
	(a) Pricing utilized for determining annual fee is based on the arithmetic mean of the NYMEX settled price for the near-month contract as reported by the Wall Street Journal for the last trading day of each month of a calendar year for the 12-month period ending December 31.

Earnings_Loss_Per_Common_Share1

Earnings (Loss) Per Common Share (Tables)	6 Months Ended
	Jun. 30, 2014
Computation of Basic and Diluted Earning (Loss) Per Common Share	'
	The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share amounts):
		Three Months Ended June 30,				Six Months Ended June 31,
	Numerator:	2014		2013		2014		2013
	Net Income From Continuing Operations, Less Noncontrolling Interests	$	8,078	$	13,220	$	16,946	$	10,445
	Net Income From Discontinued Operations		-		520		-		460
	Net Income	$	8,078	$	13,740	$	16,946	$	10,905
	Denominator:
	Weighted Average Common Shares Outstanding - Basic		53,164		52,555		53,075		52,527
	Effect of Dilutive Securities:
	Employee Stock Options		151		142		142		131
	Employee Performance-Based Restricted Stock Awards		194		214		294		243
	Weighted Average Common Shares Outstanding - Diluted		53,509		52,911		53,511		52,901
	Earnings per Common Share:
	Basic — Net Income From Continuing Operations	$	0.15	$	0.25	$	0.32	$	0.2
	— Net Income From Discontinued Operations		-		0.01		-		0.01
	— Net Income	$	0.15	$	0.26	$	0.32	$	0.21
	Diluted — Net Income From Continuing Operations	$	0.15	$	0.25	$	0.32	$	0.2
	— Net Income From Discontinued Operations		-		0.01		-		0.01
	— Net Income	$	0.15	$	0.26	$	0.32	$	0.21

Consolidated_Subsidiaries_Tabl

Consolidated Subsidiaries (Tables) (Water Solutions)	6 Months Ended
	Jun. 30, 2014
Water Solutions	'
Schedule of Carrying Amount and Classification of Assets and Liabilities as Consolidated	'
	We fully consolidate the accounts of Water Solutions in our financial statements and accounted for the 40% equity interest owned by Sand Hills as a noncontrolling interest. Water Solutions is financed through cash contributions from its members and a credit facility upon which $7.8 million was drawn as of June 30, 2014. As of June 30, 2014, Water Solutions maintained capital leases of approximately $5.5 million. Capital contributions to Water Solutions during the first six months of 2014 and 2013 were negligible. The table below sets forth the carrying amount and classifications of Water Solutions’ assets and liabilities as of June 30, 2014 and December 31, 2013, with no restrictions or obligations to use certain assets to settle associated liabilities:
	($ in Thousands)	As of June 30, 2014			As of December 31, 2013
	Assets
	Cash and Cash Equivalents	$	528		$	593
	Accounts Receivable		13,541			9,882
	Inventory, Prepaid Expenses and Other		250			89
	Other Property and Equipment		17,478			11,798
	Wells and Facilities in Progress		298			1,031
	Accumulated Depreciation, Depletion and Amortization		(3,467	)		(1,954	)
	Deferred Financing Costs and Other Assets—Net		170			206
	Total Assets	$	28,798		$	21,645
	Liabilities
	Accounts Payable	$	267		$	758
	Current Maturities of Long-Term Debt		6,554			5,404
	Accrued Liabilities		4,746			6,247
	Senior Secured Line of Credit and Long-Term Debt		6,738			3,053
	Total Liabilities	$	18,305		$	15,462

Condensed_Consolidating_Financ1

Condensed Consolidating Financial Information (Tables)	6 Months Ended
	Jun. 30, 2014
Condensed Consolidating Balance Sheets	'
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING BALANCE SHEETS
	AS OF JUNE 30, 2014
	($ in Thousands, Except Share and Per Share Data)
		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
	ASSETS
	Current Assets
	Cash and Cash Equivalents	$	5,431		$	515		$	5		$	—		$	5,951
	Accounts Receivable		35,441			13,538			—			(2,405	)		46,574
	Taxes Receivable		—			—			1,767			—			1,767
	Short-Term Derivative Instruments		4,181			—			—			—			4,181
	Current Deferred Tax Asset		—			—			4,010			—			4,010
	Inventory, Prepaid Expenses and Other		1,586			250			387			—			2,223
	Total Current Assets		46,639			14,303			6,169			(2,405	)		64,706
	Property and Equipment (Successful Efforts Method)
	Evaluated Oil and Gas Properties		884,639			213			—			(4,127	)		880,725
	Unevaluated Oil and Gas Properties		227,179			652			—			—			227,831
	Other Property and Equipment		61,331			18,386			—			—			79,717
	Wells and Facilities in Progress		108,802			6,576			—			(708	)		114,670
	Pipelines		17,399			—			—			(1,822	)		15,577
	Total Property and Equipment		1,299,350			25,827			—			(6,657	)		1,318,520
	Less: Accumulated Depreciation, Depletion and Amortization		(227,050	)		(3,755	)		—			618			(230,187	)
	Net Property and Equipment		1,072,300			22,072			—			(6,039	)		1,088,333
	Deferred Financing Costs and Other Assets—Net		2,421			170			9,013			—			11,604
	Equity Method Investments		18,300			—			—			—			18,300
	Intercompany Receivables		—			—			688,577			(688,577	)		—
	Investment in Subsidiaries – Net		4,156			4,361			332,163			(340,680	)		—
	Long-Term Derivative Instruments		159			—			—			—			159
	Total Assets	$	1,143,975		$	40,906		$	1,035,922		$	(1,037,701	)	$	1,183,102
	LIABILITIES AND STOCKHOLDERS’ EQUITY
	Current Liabilities
	Accounts Payable	$	51,431		$	324		$	—		$	(2,404	)	$	49,351
	Current Maturities of Long-Term Debt		1,175			6,554			—			—			7,729
	Accrued Liabilities		39,247			5,327			2,917			—			47,491
	Short-Term Derivative Instruments		6,699			—			—			—			6,699
	Total Current Liabilities		98,552			12,205			2,917			(2,404	)		111,270
	8.875% Senior Notes Due 2020		—			—			350,000			—			350,000
	Premium on Senior Notes – Net		—			—			2,905			—			2,905
	Senior Secured Line of Credit and Other Long-Term Debt		159			6,738			200,000			—			206,897
	Long-Term Derivative Instruments		1,535			—			—			—			1,535
	Long-Term Deferred Tax Liability		—			—			40,128			—			40,128
	Other Deposits and Liabilities		4,528			—			—			—			4,528
	Future Abandonment Cost		27,024			19			—			—			27,043
	Intercompany Payables		685,517			3,060			—			(688,577	)		—
	Total Liabilities		817,315			22,022			595,950			(690,981	)		744,306
	Stockholders’ Equity
	Common Stock		—			—			54			—			54
	Additional Paid-In Capital		177,143			84,241			459,754			(261,384	)		459,754
	Accumulated Earnings (Deficit)		149,517			(66,679	)		(19,836	)		(87,781	)		(24,779	)
	Rex Energy Stockholders’ Equity		326,660			17,562			439,972			(349,165	)		435,029
	Noncontrolling Interests		—			1,322			—			2,445			3,767
	Total Stockholders’ Equity		326,660			18,884			439,972			(346,720	)		438,796
	Total Liabilities and Stockholders’ Equity	$	1,143,975		$	40,906		$	1,035,922		$	(1,037,701	)	$	1,183,102
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING BALANCE SHEETS
	AS OF DECEMBER 31, 2013
	($ in Thousands, Except Share and Per Share Data)
		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
	ASSETS
	Current Assets
	Cash and Cash Equivalents	$	1,386		$	509		$	5		$	—		$	1,900
	Accounts Receivable		32,283			9,882			—			(3,302	)		38,863
	Taxes Receivable		—			—			5,189			—			5,189
Short-Term Derivative Instruments		5,180			—			488			—			5,668
Current Deferred Tax Asset		—			—			3,451			—			3,451
Inventory, Prepaid Expenses and Other		2,092			89			26			—			2,207
Total Current Assets		40,941			10,480			9,159			(3,302	)		57,278
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		752,781			—			—			(3,101	)		749,680
Unevaluated Oil and Gas Properties		189,385			—			—			—			189,385
Other Property and Equipment		57,409			12,706			—			—			70,115
Wells and Facilities in Progress		70,759			6,576			—			(790	)		76,545
Pipelines		7,678			—			—			—			7,678
Total Property and Equipment		1,078,012			19,282			—			(3,891	)		1,093,403
Less: Accumulated Depreciation, Depletion and Amortization		(188,699	)		(2,172	)		—			350			(190,521	)
Net Property and Equipment		889,313			17,110			—			(3,541	)		902,882
Deferred Financing Costs and Other Assets—Net		2,421			206			9,366			—			11,993
Equity Method Investments		18,708			—			—			—			18,708
Intercompany Receivables		—			—			628,517			(628,517	)		—
Investment in Subsidiaries – Net		4,442			1,197			216,945			(222,584	)		—
Long-Term Derivative Instruments		535			—			—			—			535
Total Assets	$	956,360		$	28,993		$	863,987		$	(857,944	)	$	991,396
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	33,613		$	794		$	—		$	(3,304	)	$	31,103
Current Maturities of Long-Term Debt		1,339			5,404			—			—			6,743
Accrued Liabilities		45,196			6,287			2,967			—			54,450
Short-Term Derivative Instruments		4,663			—			—			—			4,663
Total Current Liabilities		84,811			12,485			2,967			(3,304	)		96,959
8.875% Senior Notes Due 2020		—			—			350,000			—			350,000
Premium (Discount) on Senior Notes – Net		—			—			3,078			—			3,078
Senior Secured Line of Credit and Other Long-Term Debt		137			3,054			59,000			—			62,191
Long-Term Derivative Instruments		1,071			—			694			—			1,765
Long-Term Deferred Tax Liability		—			—			29,446			—			29,446
Other Deposits and Liabilities		4,992			—			—			—			4,992
Future Abandonment Cost		26,027			13			—			—			26,040
Intercompany Payables		554,329			74,188			—			(628,517	)		—
Total Liabilities		671,367			89,740			445,185			(631,821	)		574,471
Stockholders’ Equity
Common Stock		—			—			54			—			54
Additional Paid-In Capital		177,144			6,488			456,554			(183,632	)		456,554
Accumulated Earnings (Deficit)		107,849			(67,720	)		(37,806	)		(44,048	)		(41,725	)
Rex Energy Stockholders’ Equity		284,993			(61,232	)		418,802			(227,680	)		414,883
Noncontrolling Interests		—			485			—			1,557			2,042
Total Stockholders’ Equity		284,993			(60,747	)		418,802			(226,123	)		416,925
Total Liabilities and Stockholders’ Equity	$	956,360		$	28,993		$	863,987		$	(857,944	)	$	991,396
Condensed Consolidating Statements of Operations	'
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
	FOR THE THREE MONTHS ENDED JUNE 30, 2014
	($ in Thousands)
		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
	OPERATING REVENUE
	Oil, Natural Gas and NGL Sales	$	72,903		$	—		$	—		$	—		$	72,903
	Field Services Revenue		—			15,974			—			(2,887	)		13,087
	Other Revenue		30			—			—			—			30
	TOTAL OPERATING REVENUE		72,933			15,974			—			(2,887	)		86,020
	OPERATING EXPENSES
	Production and Lease Operating Expense		21,630			3			—			(13	)		21,620
	General and Administrative Expense		7,221			950			1,083			(15	)		9,239
	Loss on Disposal of Asset		223			7			—			—			230
	Impairment Expense		16			—			—			—			16
	Exploration Expense		1,364			3			—			—			1,367
	Depreciation, Depletion, Amortization and Accretion		20,454			931			—			(159	)		21,226
	Field Services Operating Expense		—			11,832			—			(2,263	)		9,569
	Other Operating (Income) Expense		(56	)		—			—			—			(56	)
	TOTAL OPERATING EXPENSES		50,852			13,726			1,083			(2,450	)		63,211
	INCOME (LOSS) FROM OPERATIONS		22,081			2,248			(1,083	)		(437	)		22,809
	OTHER INCOME (EXPENSE)
	Interest Expense		(17	)		(145	)		(7,341	)		—			(7,503	)
	Gain (Loss) on Derivatives, Net		(645	)		—			394			—			(251	)
	Other Expense		55			—			—			(15	)		40
	Loss From Equity Method Investments		(208	)		—			—			—			(208	)
	Income (Loss) From Equity in Consolidated Subsidiaries		(56	)		56			12,409			(12,409	)		—
	TOTAL OTHER INCOME (EXPENSE)		(871	)		(89	)		5,462			(12,424	)		(7,922	)
	INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		21,210			2,159			4,379			(12,861	)		14,887
	Income Tax (Expense) Benefit		(9,051	)		(580	)		3,699			—			(5,932	)
	INCOME (LOSS) FROM CONTINUING OPERATIONS		12,159			1,579			8,078			(12,861	)		8,955
	Net Income Attributable to Noncontrolling Interests		—			877			—			—			877
	NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	12,159		$	702		$	8,078		$	(12,861	)	$	8,078
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
	FOR THE SIX MONTHS ENDED JUNE 30, 2014
	($ in Thousands)
		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
	OPERATING REVENUE
	Oil, Natural Gas and NGL Sales	$	154,202		$	—		$	—		$	—		$	154,202
	Field Services Revenue		—			38,597			—			(10,206	)		28,391
	Other Revenue		74			—			—			—			74
	TOTAL OPERATING REVENUE		154,276			38,597			—			(10,206	)		182,667
	OPERATING EXPENSES
	Production and Lease Operating Expense		41,660			6			—			(20	)		41,646
	General and Administrative Expense		15,101			1,822			2,742			(35	)		19,630
	Loss on Disposal of Asset		294			7			—			—			301
	Impairment Expense		41			—			—			—			41
	Exploration Expense		3,424			3			—			—			3,427
	Depreciation, Depletion, Amortization and Accretion		40,277			1,643			—			(270	)		41,650
	Field Services Operating Expense		—			28,782			—			(7,417	)		21,365
	Other Operating Expense		27			—			—			—			27
	TOTAL OPERATING EXPENSES		100,824			32,263			2,742			(7,742	)		128,087
	INCOME (LOSS) FROM OPERATIONS		53,452			6,334			(2,742	)		(2,464	)		54,580
	OTHER INCOME (EXPENSE)
	Interest Expense		(31	)		(347	)		(14,260	)		—			(14,638	)
	Gain (Loss) on Derivatives, Net		(11,084	)		—			1,083			—			(10,001	)
	Other Income (Expense)		18			—			—			(35	)		(17	)
	Loss From Equity Method Investments		(408	)		—			—			—			(408	)
	Income (Loss) From Equity in Consolidated Subsidiaries		(81	)		81			25,977			(25,977	)		—
	TOTAL OTHER INCOME (EXPENSE)		(11,586	)		(266	)		12,800			(26,012	)		(25,064	)
	INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		41,866			6,068			10,058			(28,476	)		29,516
	Income Tax (Expense) Benefit		(15,689	)		(1,323	)		6,888			—			(10,124	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		26,177			4,745			16,946			(28,476	)		19,392
Net Income Attributable to Noncontrolling Interests		—			2,446			—			—			2,446
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	26,177		$	2,299		$	16,946		$	(28,476	)	$	16,946
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE THREE MONTHS ENDED JUNE 30, 2013
($ in Thousands)
	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	51,444		$	—		$	—		$	—		$	51,444
Field Services Revenue		—			5,072			—			(1,232	)		3,840
Other Revenue		76			—			—			—			76
TOTAL OPERATING REVENUE		51,520			5,072			—			(1,232	)		55,360
OPERATING EXPENSES
Production and Lease Operating Expense		13,090			2			—			—			13,092
General and Administrative Expense		5,970			659			1,153			—			7,782
Loss on Disposal of Asset		1,502			—			—			—			1,502
Impairment Expense		105			—			—			—			105
Exploration Expense		2,225			—			—			—			2,225
Depreciation, Depletion, Amortization and Accretion		12,645			336			—			(38	)		12,943
Field Services Operating Expense		—			3,510			—			(862	)		2,648
Other Operating Expense		447			—			—			—			447
TOTAL OPERATING EXPENSES		35,984			4,507			1,153			(900	)		40,744
INCOME (LOSS) FROM OPERATIONS		15,536			565			(1,153	)		(332	)		14,616
OTHER INCOME (EXPENSE)
Interest Expense		(22	)		(28	)		(5,776	)		—			(5,826	)
Gain on Derivatives, Net		11,741			—			—			—			11,741
Other Income (Expense)		2,235			—			—			(22	)		2,213
Loss From Equity Method Investments		(183	)		—			—			—			(183	)
Income (Loss) From Equity in Consolidated Subsidiaries		(11	)		11			17,697			(17,697	)		—
TOTAL OTHER INCOME (EXPENSE)		13,760			(17	)		11,921			(17,719	)		7,945
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		29,296			548			10,768			(18,051	)		22,561
Income Tax (Expense) Benefit		(11,964	)		(128	)		2,972			—			(9,120	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		17,332			420			13,740			(18,051	)		13,441
Income From Discontinued Operations, Net of Income Taxes		—			520			—			—			520
NET INCOME (LOSS)		17,332			940			13,740			(18,051	)		13,961
Net Income Attributable to Noncontrolling Interests		—			221			—			—			221
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	17,332		$	719		$	13,740		$	(18,051	)	$	13,740
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE SIX MONTHS ENDING JUNE 30, 2013
($ in Thousands)
	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	92,384		$	—		$	—		$	—		$	92,384
Field Services Revenue		—			13,124			—			(2,779	)		10,345
Other Revenue		100			—			—			—			100
TOTAL OPERATING REVENUE		92,484			13,124			—			(2,779	)		102,829
OPERATING EXPENSES
Production and Lease Operating Expense		26,487			5			—			—			26,492
General and Administrative Expense		12,033			1,148			2,453			(56	)		15,578
Loss on Disposal of Asset		1,493			—			—			—			1,493
Impairment Expense		170			—			—			—			170
Exploration Expense		4,269			—			—			—			4,269
Depreciation, Depletion, Amortization and Accretion		23,559			603			—			(61	)		24,101
Field Services Operating Expense		—			8,648			—			(1,945	)		6,703
Other Operating Expense		891			—			—			—			891
TOTAL OPERATING EXPENSES		68,902			10,404			2,453			(2,062	)		79,697
INCOME (LOSS) FROM OPERATIONS		23,582			2,720			(2,453	)		(717	)		23,132
OTHER INCOME (EXPENSE)
Interest Expense		(31	)		(40	)		(9,760	)		—			(9,831	)
Gain on Derivatives, Net		3,201			—			—			—			3,201
Other Income (Expense)		2,129			—			—			(56	)		2,073
Loss From Equity Method Investments		(361	)		—			—			—			(361	)
Income (Loss) From Equity in Consolidated Subsidiaries		(22	)		22			17,856			(17,856	)		—
TOTAL OTHER INCOME (EXPENSE)		4,916			(18	)		8,096			(17,912	)		(4,918	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		28,498			2,702			5,643			(18,629	)		18,214
Income Tax (Expense) Benefit		(11,555	)		(822	)		5,262			—			(7,115	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		16,943			1,880			10,905			(18,629	)		11,099
Income From Discontinued Operations, Net of Income Taxes		—			460			—			—			460
NET INCOME (LOSS)		16,943			2,340			10,905			(18,629	)		11,559
Net Income Attributable to Noncontrolling Interests		—			654			—			—			654
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	16,943		$	1,686		$	10,905		$	(18,629	)	$	10,905
Condensed Consolidating Statements of Cash Flows	'
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
	FOR THE SIX MONTHS ENDING JUNE 30, 2014
	($ in Thousands)
		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
	CASH FLOWS FROM OPERATING ACTIVITIES
	Net Income (Loss)	$	26,177		$	4,745		$	16,946		$	(28,476	)	$	19,392
	Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
	Loss From Equity Method Investments		408			—			—			—			408
	Non-Cash Expenses (Income)		(133	)		186			3,283			—			3,336
	Depreciation, Depletion, Amortization and Accretion		40,277			1,643			—			(270	)		41,650
	Deferred Income Tax Expense (Benefit)		15,689			1,323			(6,888	)		—			10,124
	(Gain) Loss on Derivatives		11,084			—			(1,083	)		—			10,001
	Cash Settlements of Derivatives		(7,211	)		—			878			—			(6,333	)
	Dry Hole Expense		86			—			—			—			86
	Loss on Sale of Asset		294			7			—			—			301
	Impairment Expense		41			—			—			—			41
	Changes in operating assets and liabilities
	Accounts Receivable		(3,163	)		(3,664	)		3,423			(898	)		(4,302	)
	Inventory, Prepaid Expenses and Other Assets		505			(161	)		(360	)		—			(16	)
	Accounts Payable and Accrued Liabilities		13,404			(1,432	)		5			898			12,875
	Other Assets and Liabilities		(970	)		(22	)		—			—			(992	)
	NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		96,488			2,625			16,204			(28,746	)		86,571
	CASH FLOWS FROM INVESTING ACTIVITIES
	Intercompany loans to subsidiaries		131,376			(4	)		(157,352	)		25,980			—
	Proceeds from Joint Venture Acreage Management		146			—			—			—			146
	Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		139			—			—			—			139
	Acquisitions of Undeveloped Acreage		(39,484	)		(655	)		—			—			(40,139	)
	Capital Expenditures for Development of Oil and Gas Properties and Equipment		(183,765	)		(4,578	)		—			2,766			(185,577	)
	NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(91,588	)		(5,237	)		(157,352	)		28,746			(225,431	)
	CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from Long-Term Debt and Lines of Credit		—			9,409			153,000			—			162,409
	Repayments of Long-Term Debt and Lines of Credit		—			(5,753	)		(12,000	)		—			(17,753	)
	Repayments of Loans and Other Long-Term Debt		(855	)		(313	)		—			—			(1,168	)
	Debt Issuance Costs		—			(4	)		(273	)		—			(277	)
	Proceeds from Exercise of Stock Options		—			—			421			—			421
	Distributions by the Partners of Consolidated Subsidiaries		—			(721	)		—			—			(721	)
	NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(855	)		2,618			141,148			—			142,911
	NET INCREASE IN CASH		4,045			6			—			—			4,051
	CASH – BEGINNING		1,386			509			5			—			1,900
	CASH - ENDING	$	5,431		$	515		$	5		$	—		$	5,951
	REX ENERGY CORPORATION AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
	FOR THE SIX MONTHS ENDING JUNE 30, 2013
	($ in Thousands)
		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
	CASH FLOWS FROM OPERATING ACTIVITIES
	Net Income (Loss)	$	16,943		$	2,340		$	10,905		$	(18,629	)	$	11,559
	Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
	Loss From Equity Method Investments		361			—			—			—			361
	Non-Cash Expenses		3			50			2,974			—			3,027
	Depreciation, Depletion, Amortization and Accretion		23,559			603			—			(61	)		24,101
	Deferred Income Tax Expense (Benefit)		11,499			1,135			(5,262	)		—			7,372
	Gain on Derivatives		(3,201	)		—			—			—			(3,201	)
	Cash Settlements of Derivatives		4,798			—			—			—			4,798
	Dry Hole Expense		485			—			—			—			485
	(Gain) Loss on Sale of Asset		1,493			(969	)		—			—			524
	Impairment Expense		170			—			—			—			170
	Changes in operating assets and liabilities
	Accounts Receivable		85,176			(3,089	)		(76,104	)		(4,009	)		1,974
	Inventory, Prepaid Expenses and Other Assets		25			(6	)		18			—			37
	Accounts Payable and Accrued Liabilities		8,503			805			1,480			(435	)		10,353
	Other Assets and Liabilities		(557	)		(5	)		—			—			(562	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		149,257			864			(65,989	)		(23,134	)		60,998
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		(6,704	)		1,083			(16,679	)		22,300			—
Proceeds from Joint Venture Acreage Management		107			—			—			—			107
Contributions to Equity Method Investments		—			(2,207	)		—			—			(2,207	)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		498			3,234			—			—			3,732
Acquisitions of Undeveloped Acreage		(15,704	)		(2	)		—			—			(15,706	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(122,834	)		(1,609	)		—			834			(123,609	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(144,637	)		499			(16,679	)		23,134			(137,683	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			1,750			—			—			1,750
Repayments of Long-Term Debt and Lines of Credit		—			(876	)		—			—			(876	)
Repayments of Loans and Other Notes Payable		(543	)		(243	)		—			—			(786	)
Proceeds from Senior Notes, net of Discounts and Premiums		—			—			105,000			—			105,000
Debt Issuance Costs		—			—			(2,894	)		—			(2,894	)
Proceeds from the Exercise of Stock Options		—			—			266			—			266
Purchase of Non-Controlling Interests		—			(150	)		—			—			(150	)
Distributions by the Partners of Consolidated Subsidiaries		—			(406	)		—			—			(406	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(543	)		75			102,372			—			101,904
NET INCREASE IN CASH		4,077			1,438			19,704			—			25,219
CASH – BEGINNING		4,227			824			38,924			—			43,975
CASH - ENDING	$	8,304		$	2,262		$	58,628		$	—		$	69,194

Business_Segment_Information_A

Business Segment Information - Additional Information (Details)	6 Months Ended
	Jun. 30, 2014
	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 (Details) (USD $)	3 Months Ended		6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	$86,020	$55,360	$182,667	$102,829	'
Income (Loss) From Continuing Operations, Before Income Taxes	14,887	22,561	29,516	18,214	'
Total Assets	1,183,102	'	1,183,102	'	991,396
Exploration and Production	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	72,933	51,520	154,276	92,484	'
Field Services	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	13,087	3,840	28,391	10,345	'
Operating Segments | Exploration and Production	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	72,933	51,520	154,276	92,484	'
Income (Loss) From Continuing Operations, Before Income Taxes	13,146	22,339	25,900	16,272	'
Total Assets	1,162,747	'	1,162,747	'	971,973
Operating Segments | Field Services	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	15,974	5,072	38,597	13,124	'
Income (Loss) From Continuing Operations, Before Income Taxes	2,192	552	6,113	2,715	'
Total Assets	28,798	'	28,798	'	26,266
Intercompany Eliminations	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	-2,887	-1,232	-10,206	-2,779	'
Income (Loss) From Continuing Operations, Before Income Taxes	-451	-330	-2,497	-773	'
Total Assets	-8,443	'	-8,443	'	-6,843
Intercompany Eliminations | Field Services	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	-2,887	-1,232	-10,206	-2,779	'
Eliminations	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	2,887	1,232	10,206	2,779	'
Income (Loss) From Continuing Operations, Before Income Taxes	-12,861	-18,051	-28,476	-18,629	'
Total Assets	($1,037,701)	'	($1,037,701)	'	($857,944)

Future_Abandonment_Cost_Additi

Future Abandonment Cost - Additional Information (Details) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Asset Retirement Obligations [Line Items]	'	'	'	'
Accretion expense	$0.90	$0.50	$1.60	$1.10

Future_Abandonment_Cost_Detail

Future Abandonment Cost (Details) (USD $)	6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014
Asset Retirement Obligations [Line Items]	'
Beginning Balance	$28,525
Future Abandonment Obligation Incurred	590
Future Abandonment Obligation Settled	-841
Future Abandonment Obligation Revision of Estimated Obligation	14
Future Abandonment Obligation Accretion Expense	1,630
Total Future Abandonment Cost	$29,918

Future_Abandonment_Cost_Parent

Future Abandonment Cost (Parenthetical) (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Asset Retirement Obligations [Line Items]	'	'
Accrued Liabilities	$47,491	$54,450
Remediation Property for Sale, Abandonment or Disposal	'	'
Asset Retirement Obligations [Line Items]	'	'
Accrued Liabilities	$2,900	'

Discontinued_Operations_Assets

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

Summary_of_Financial_Informati

Summary of Financial Information for Discontinued Operations (Details) (USD $)	3 Months Ended		6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Costs and Expenses:	'	'	'	'
Income from Discontinued Operations, net of taxes	$0	$520	$0	$460
Discontinued Operations Assets Held For Sale	'	'	'	'
Revenues:	'	'	'	'
Oil, Natural Gas and NGL Sales	'	16	'	25
Total Operating Revenue	'	16	'	25
Costs and Expenses:	'	'	'	'
Production and Lease Operating Expense	'	59	'	104
General and Administrative Expense	'	11	'	23
Exploration Expense	'	44	'	97
Other Income Expense	'	'	'	-3
Gain on Sale of Asset	'	-973	'	-969
Total Costs and Expenses	'	-859	'	-748
Income from Discontinued Operations Before Income Taxes	'	875	'	773
Income Tax Expense	'	-355	'	-313
Income from Discontinued Operations, net of taxes	'	$520	'	$460
Crude Oil (Bbls) | Discontinued Operations Assets Held For Sale	'	'	'	'
Production:	'	'	'	'
Production Units	'	209	'	356
Total (Mcfe) | Discontinued Operations Assets Held For Sale	'	'	'	'
Production:	'	'	'	'
Production Units	'	1,254	'	2,136

Concentrations_of_Credit_Risk_

Concentrations of Credit Risk - Additional Information (Details) (Sales, Customer Concentration Risk)	6 Months Ended
	Jun. 30, 2014
	Customer
Five purchaser	'
Concentration Risk [Line Items]	'
Percentage of revenue from major customers	95.70%
Number of major customers	5
Largest single purchaser	'
Concentration Risk [Line Items]	'
Percentage of revenue from major customers	35.90%

Long_Term_Debt_Senior_Credit_F

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

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jul. 31, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

In Millions, unless otherwise specified

Adjusted LIBO Rate

Alternate Base Rate

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Senior Credit Facility

Maximum

Maximum

Crude Oil

Natural Gas

Minimum

Maximum

Maximum

Adjusted LIBO Rate

Alternate Base Rate

Subsequent Event

Letter of Credit

Revolving Credit Facility

Defaulted Loans

Interest Rate Swap

Minimum

Minimum

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility, current borrowing capacity

'

'

'

'

$375

$375

'

'

'

'

'

'

'

'

$293.80

'

'

'

Line of credit facility, maximum borrowing capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

60

500

'

Line of credit facility, amount outstanding

200

[1]

59

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility, maturity date

'

'

'

'

27-Mar-18

27-Mar-18

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

'

'

'

'

'

'

'

'

'

'

'

'

Effective rate

'

'

'

'

'

0.50%

'

'

'

'

'

'

'

'

'

'

'

'

Additional percentage with LIBOR

'

'

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

'

'

'

Margin rate

'

'

0.25%

0.15%

'

'

'

'

'

'

'

'

1.50%

0.50%

'

'

'

2.00%

Percentage of reasonably anticipated projected production

'

'

'

'

'

85.00%

'

75.00%

75.00%

'

'

'

'

'

'

'

'

'

Duration of developed producing reserve

'

'

'

'

'

'

'

'

'

'

'36 months

'

'

'

'

'

'

'

Notional amounts of interest rate swap

'

'

'

'

'

'

'

'

'

'

'

$20

'

'

'

'

'

'

Outstanding principal amount of debt for borrowed money, percentage

'

'

'

'

'

'

'

'

'

'

75.00%

'

'

'

'

'

'

'

Liens covering the oil and gas properties, percentage

'

'

'

'

80.00%

80.00%

'

'

'

'

'

'

'

'

'

'

'

'

Criteria Current ratio

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

Current ratio

'

'

'

'

2.2

2.2

'

'

'

'

'

'

'

'

'

'

'

'

Criteria Interest Coverage Ratio

'

'

'

'

'

'

'

'

'

3

'

'

'

'

'

'

'

'

Interest coverage ratio

'

'

'

'

4.8

4.8

'

'

'

'

'

'

'

'

'

'

'

'

Criteria Total debt to EBITAX"

'

'

'

'

'

'

'

'

'

'

4.25

'

'

'

'

'

'

'

Total debt to EBITAX

'

'

'

'

3.4

3.4

'

'

'

'

'

'

'

'

'

'

'

'

[1]

The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. The weighted average interest rate on borrowings under our Senior Credit Facility for the three and six months ended June 30, 2014 and the year ended December 31, 2013, was approximately 2.0%, 2.0% and 1.9%, respectively. The average interest rate on our capital leases and other obligations for the three and six months ended June 30, 2014 and the year ended December 31, 2013, was approximately 4.0%, 4.0% and 5.3%, respectively

Long_Term_Debt_Senior_Notes_Du

Long Term Debt - Senior Notes Due Twenty Twenty - Additional Information (Details) (USD $)	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2014	Dec. 31, 2013
Debt Instrument [Line Items]	'	'	'
Premium (Discount) on senior notes - net	($2,905,000)	($2,905,000)	($3,078,000)
8.875% Senior Notes	'	'	'
Debt Instrument [Line Items]	'	'	'
Senior notes	352,900,000	352,900,000	353,100,000
Interest rate	8.88%	8.88%	8.88%
Debt instrument maturity date	1-Dec-20	1-Dec-20	1-Dec-20
Premium (Discount) on senior notes - net	-2,905,000	-2,905,000	-3,078,000
Amortization of net premium	'	-200,000	'
Deferred financing costs	$8,400,000	$8,400,000	'

Components_of_LongTerm_Debt_an

Components of Long-Term Debt and Lines of Credit (Details) (USD $)	Jun. 30, 2014		Dec. 31, 2013
Debt Instrument [Line Items]	'		'
8.875% Senior Notes Due 2020	$350,000,000		$350,000,000
Premium on Senior Notes, Net	2,905,000		3,078,000
Senior Lines of Credit	200,000,000	[1]	59,000,000	[1]
Capital Leases and Other Obligations	14,626,000		9,934,000
Total Debt	567,531,000		422,012,000
Less Current Portion of Long-Term Debt	-7,729,000		-6,743,000
Total Long-Term Debt	$559,802,000		$415,269,000
[1]	The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. The weighted average interest rate on borrowings under our Senior Credit Facility for the three and six months ended June 30, 2014 and the year ended December 31, 2013, was approximately 2.0%, 2.0% and 1.9%, respectively. The average interest rate on our capital leases and other obligations for the three and six months ended June 30, 2014 and the year ended December 31, 2013, was approximately 4.0%, 4.0% and 5.3%, respectively

Components_of_LongTerm_Debt_an1

Components of Long-Term Debt and Lines of Credit (Parenthetical) (Details)	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2014	Dec. 31, 2013
8.875% Senior Notes	'	'	'
Debt Instrument [Line Items]	'	'	'
Interest rate	8.88%	8.88%	8.88%
Debt instrument maturity date	1-Dec-20	1-Dec-20	1-Dec-20
Senior Credit Facility	'	'	'
Debt Instrument [Line Items]	'	'	'
Line of credit facility, maturity date	27-Mar-18	27-Mar-18	27-Mar-18
Average interest rate	2.00%	2.00%	1.90%
Other Loans and Notes Payable	'	'	'
Debt Instrument [Line Items]	'	'	'
Average interest rate	4.00%	4.00%	5.30%

Long_Term_Debt_Water_Solutions

Long Term Debt - Water Solutions - Additional Information (Details) (USD $)	1 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Oct. 18, 2013	Dec. 31, 2013		Jun. 30, 2014
Debt Instrument [Line Items]	'	'		'
Line of credit facility, amount outstanding	'	$59	[1]	$200	[1]
Water Solutions Holding | Demand Notes	'	'		'
Debt Instrument [Line Items]	'	'		'
Percentage of accounts receivable	80.00%	'		'
Accounts receivable, collection period	'90 days	'		'
Line of credit facility, amount outstanding	'	'		3.9
Line of credit facility, current borrowing capacity	8	'		'
Line of credit facility, increase current borrowing capacity	'	4		'
Water Solutions Holding | Demand Notes | LIBOR	'	'		'
Debt Instrument [Line Items]	'	'		'
Margin rate	2.75%	'		'
Water Solutions Holding | Demand Notes | Base Rate	'	'		'
Debt Instrument [Line Items]	'	'		'
Margin rate	2.00%	'		'
Water Solutions Holding | Equipment Term Note	'	'		'
Debt Instrument [Line Items]	'	'		'
Line of credit facility, amount outstanding	'	'		3.9
Line of credit facility, maximum borrowing capacity	6	'		'
Percentage of asset's cost funded by line of credit	80.00%	'		'
Line of credit, minimum required tangible net worth	2.5	'		'
Line of credit, minimum required tangible net worth, percentage of annual net income added	30.00%	'		'
Net worth	'	$9.20		'
Fixed charge coverage ratio	'	'		2.1
Total debt to EBITAX	'	'		1.1
Water Solutions Holding | Equipment Term Note | Minimum	'	'		'
Debt Instrument [Line Items]	'	'		'
Line of credit facility, maturity period	'3 years	'		'
Criteria fixed charge coverage ratio	1.75	'		'
Water Solutions Holding | Equipment Term Note | Maximum	'	'		'
Debt Instrument [Line Items]	'	'		'
Line of credit facility, maturity period	'4 years	'		'
Criteria Total debt to EBITAX"	2.25	'		'
Water Solutions Holding | Equipment Term Note | Three Months LIBOR	'	'		'
Debt Instrument [Line Items]	'	'		'
Margin rate	3.00%	'		'
[1]	The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. The weighted average interest rate on borrowings under our Senior Credit Facility for the three and six months ended June 30, 2014 and the year ended December 31, 2013, was approximately 2.0%, 2.0% and 1.9%, respectively. The average interest rate on our capital leases and other obligations for the three and six months ended June 30, 2014 and the year ended December 31, 2013, was approximately 4.0%, 4.0% and 5.3%, respectively

Principal_Maturity_Schedule_fo

Principal Maturity Schedule for Debt Outstanding (Details) (USD $)	Jun. 30, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Debt Instrument [Line Items]	'		'
2014	$5,992		'
2015	3,089		'
2016	2,749		'
2017	1,428		'
2018	200,588		'
Thereafter	350,780		'
Total	$564,626	[1]	$418,934
[1]	Excludes $2.9 million net premium on Senior Notes.

Principal_Maturity_Schedule_fo1

Principal Maturity Schedule for Debt Outstanding (Parenthetical) (Details) (USD $)	Jun. 30, 2014
In Millions, unless otherwise specified
Debt Instrument [Line Items]	'
Senior notes, net premium	$2.90

Recovered_Sheet1

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

6 Months Ended

3 Months Ended

6 Months Ended

3 Months Ended

6 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Dec. 31, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2014

Dec. 31, 2013

Contract

Crude Oil

Crude Oil

Natural Gas

Natural Gas

Natural Gas Liquids

Natural Gas Liquids

Commodity derivatives

Commodity derivatives

Commodity derivatives

Commodity derivatives

Interest Rate Swap

Interest Rate Swap

Fixed To Floating Interest Rate Swap

Minimum

Minimum

Minimum

Derivatives Fair Value [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash Settlements of Derivatives

$6,333,000

($4,798,000)

'

'

'

'

'

'

'

$2,000,000

($1,100,000)

$7,200,000

($4,800,000)

($500,000)

($900,000)

'

Commodity hedged on annualized basis hedge through 2014

'

'

'

'

90.00%

'

80.00%

'

70.00%

'

'

'

'

'

'

'

Commodity hedged on annualized basis hedge through 2015

'

'

'

'

'

'

40.00%

'

'

'

'

'

'

'

'

'

Senior Lines of Credit

200,000,000

[1]

'

59,000,000

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

8.875% Senior Notes Due 2020

350,000,000

'

350,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative, amount of hedged item

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25,000,000

Proceeds from interest rate swaps

'

'

'

'

'

'

'

'

'

'

'

'

'

600,000

'

'

Fair value of interest rate swap, liability

'

'

200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivatives asset (liability)

-3,900,000

'

-200,000

-2,514,000

'

-1,257,000

'

-123,000

'

-3,894,000

'

-3,894,000

'

'

'

'

Unrealized gain (loss) on commodity derivative contracts

($2,000,000)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding commodity derivatives

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

[1]

The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. The weighted average interest rate on borrowings under our Senior Credit Facility for the three and six months ended June 30, 2014 and the year ended December 31, 2013, was approximately 2.0%, 2.0% and 1.9%, respectively. The average interest rate on our capital leases and other obligations for the three and six months ended June 30, 2014 and the year ended December 31, 2013, was approximately 4.0%, 4.0% and 5.3%, respectively

Schedule_of_Location_and_Amoun

Schedule of Location and Amounts of Gains and Losses on Derivative Instruments (Details) (USD $)	3 Months Ended		6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Derivative Instruments Gain Loss [Line Items]	'	'	'	'
Gain (loss) on derivatives, net	($251)	$11,741	($10,001)	$3,201
Crude Oil	'	'	'	'
Derivative Instruments Gain Loss [Line Items]	'	'	'	'
Gain (loss) on derivatives, net	-2,482	9,121	-3,650	8,137
Natural Gas	'	'	'	'
Derivative Instruments Gain Loss [Line Items]	'	'	'	'
Gain (loss) on derivatives, net	2,147	1,445	-6,781	-6,127
Natural Gas Liquids	'	'	'	'
Derivative Instruments Gain Loss [Line Items]	'	'	'	'
Gain (loss) on derivatives, net	-310	1,175	-653	1,191
Interest Rate Swap	'	'	'	'
Derivative Instruments Gain Loss [Line Items]	'	'	'	'
Gain (loss) on derivatives, net	$394	'	$1,083	'

Asset_or_Liability_Financial_C

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

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

In Thousands, unless otherwise specified

Crude Oil

Crude Oil

Crude Oil

Crude Oil

Crude Oil

Crude Oil

Crude Oil

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas Liquids

Natural Gas Liquids

Natural Gas Liquids

bbl

2014

2014

2014

2014

2015

2015

Mcf

2014

2014

2014

2014

2014

2014

2014

2015

2015

2015

2015

2015

2015

2015

bbl

2014

2015

Collars

Cap Swap

Three Way Collars

Deferred Put Spread

Three Way Collars

Call Protected Swap

Collars

Cap Swap

Three Way Collars

Call Option

Swap

Swaption

Basis Swap

Collars

Cap Swap

Three Way Collars

Call Option

Swap

Swaption

Basis Swap

Swap

Swap

bbl

bbl

bbl

bbl

bbl

bbl

Mcf

Mcf

Mcf

Mcf

Mcf

Mcf

Mcf

Mcf

Mcf

Mcf

Mcf

Mcf

Mcf

Mcf

bbl

bbl

Derivatives Fair Value [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Volume

'

'

634,000

30,000

190,000

180,000

84,000

120,000

30,000

31,570,000

1,500,000

1,800,000

6,750,000

900,000

2,220,000

600,000

3,000,000

1,200,000

2,400,000

6,900,000

2,400,000

1,200,000

100,000

600,000

516,000

474,000

42,000

Put Option

'

'

'

'

81.32

77.92

75

78.75

'

'

'

3.3

3.53

'

'

'

'

'

3.28

3.63

'

'

'

'

'

'

'

Floor

'

'

'

90

'

88.98

90

89.06

'

'

3.81

'

4.19

'

'

'

'

4.25

'

4.2

'

'

'

'

'

'

'

Ceiling

'

'

'

97.65

'

103

'

100

'

'

4.54

'

4.7

5

'

'

'

4.7

'

4.68

4.4

'

'

'

'

'

'

Swap

'

'

'

'

97.84

'

'

'

95.76

'

'

4.09

'

'

3.96

4.45

-0.37

'

4.1

'

'

4.18

4.4

-0.35

'

57.9

45.99

Long Call

'

'

'

'

'

'

'

'

110

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivatives asset (liability)

($3,900)

($200)

($2,514)

($189)

($1,038)

($440)

($441)

($358)

($48)

($1,257)

($133)

($518)

($231)

($68)

($1,017)

($578)

$2,834

$139

($569)

($89)

($717)

($137)

($667)

$494

($123)

($158)

$35

Combined_Fair_Value_of_Derivat

Combined Fair Value of Derivatives (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivatives Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	$4,181	$5,668
Total Long - Term Derivative Assets	159	535
Total Derivative Assets	4,340	6,203
Total Short - Term Derivative Liabilities	-6,699	-4,663
Total Long-Term Derivative Liabilities	-1,535	-1,765
Total Derivative Liabilities	-8,234	-6,428
Natural Gas | Swaption	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	372	83
Natural Gas Liquids	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-495	-995
Short Term Derivative Assets	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	4,181	5,668
Short Term Derivative Assets | Three Way Collars	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	342	518
Short Term Derivative Assets | Cap Swap	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	'	5
Short Term Derivative Assets | Natural Gas - Collars	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	139	'
Short Term Derivative Assets | Interest Rate Swap	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	'	488
Short Term Derivative Assets | Crude Oil | Collars	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	'	380
Short Term Derivative Assets | Crude Oil | Three Way Collars	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	'	104
Short Term Derivative Assets | Natural Gas | Swap	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	'	106
Short Term Derivative Assets | Natural Gas | Basis Swap	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short -Term Derivative Assets	3,328	3,984
Long Term Derivative Assets	'	'
Derivatives Fair Value [Line Items]	'	'
Total Long - Term Derivative Assets	159	535
Long Term Derivative Assets | Natural Gas - Collars	'	'
Derivatives Fair Value [Line Items]	'	'
Total Long - Term Derivative Assets	69	'
Long Term Derivative Assets | Natural Gas Cap Swap	'	'
Derivatives Fair Value [Line Items]	'	'
Total Long - Term Derivative Assets	'	5
Long Term Derivative Assets | Natural Gas-Basis Swaps	'	'
Derivatives Fair Value [Line Items]	'	'
Total Long - Term Derivative Assets	'	339
Long Term Derivative Assets | Natural Gas - Three Way Collars	'	'
Derivatives Fair Value [Line Items]	'	'
Total Long - Term Derivative Assets	90	169
Long Term Derivative Assets | Natural Gas | Swap	'	'
Derivatives Fair Value [Line Items]	'	'
Total Long - Term Derivative Assets	'	22
Short Term Derivative Liabilities | Natural Gas Cap Swap	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-804	-496
Short Term Derivative Liabilities | Natural Gas - Three Way Collars	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-594	-125
Short Term Derivative Liabilities | Crude Oil - Collars	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-189	-42
Short Term Derivative Liabilities | Crude Oil Call Protected Swaps	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-48	'
Short Term Derivative Liabilities | Crude Oil - Three Way Collars	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-798	-29
Short Term Derivative Liabilities | Natural Gas - Swaps	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-1,086	-1,170
Short Term Derivative Liabilities | Crude Oil | Swap	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	'	-119
Short Term Derivative Liabilities | Crude Oil | Cap Swap	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-1,038	'
Short Term Derivative Liabilities | Crude Oil | Crude Oil Deferred Put Spread	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-441	-585
Short Term Derivative Liabilities | Natural Gas | Collars	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-202	-235
Short Term Derivative Liabilities | Natural Gas | Swaption	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-578	-717
Short Term Derivative Liabilities | Natural Gas | Call Option	'	'
Derivatives Fair Value [Line Items]	'	'
Total Short - Term Derivative Liabilities	-426	-150
Long Term Derivative Liabilities	'	'
Derivatives Fair Value [Line Items]	'	'
Total Long-Term Derivative Liabilities	-1,535	-1,765
Long Term Derivative Liabilities | Interest Rate Swap	'	'
Derivatives Fair Value [Line Items]	'	'
Total Long-Term Derivative Liabilities	'	-693
Long Term Derivative Liabilities | Natural Gas Cap Swap	'	'
Derivatives Fair Value [Line Items]	'	'
Total Long-Term Derivative Liabilities	-283	-307
Long Term Derivative Liabilities | Natural Gas - Three Way Collars	'	'
Derivatives Fair Value [Line Items]	'	'
Total Long-Term Derivative Liabilities	-158	'
Long Term Derivative Liabilities | Natural Gas - Swaps	'	'
Derivatives Fair Value [Line Items]	'	'
Total Long-Term Derivative Liabilities	-68	-4
Long Term Derivative Liabilities | Natural Gas Swaption	'	'
Derivatives Fair Value [Line Items]	'	'
Total Long-Term Derivative Liabilities	-667	'
Long Term Derivative Liabilities | Natural Gas - Calls	'	'
Derivatives Fair Value [Line Items]	'	'
Total Long-Term Derivative Liabilities	($359)	($761)

Significant_Unobservable_Input

Significant Unobservable Inputs Used in Fair Value Measurements of Natural Gas Basis Swaps (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2014
In Thousands, unless otherwise specified			Natural Gas	Natural Gas	Natural Gas	Natural Gas
				Basis Swap	Basis Swap	Basis Swap
					Minimum	Maximum
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]	'	'	'	'	'	'
Range (price per Mcf)	'	'	'	'	-0.85	-1.63
Weighted Average (price per Mcf)	'	'	'	-1.28	'	'
Derivatives asset (liability)	($3,900)	($200)	($1,257)	$3,328	'	'

Fair_Value_Hierarchy_Table_for

Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivatives asset (liability)	($3,900)	($200)
Commodity Swaps	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivatives asset (liability)	-3,894	'
Commodity Swaps | Significant Other Observable Inputs (Level 2)	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivatives asset (liability)	-7,222	'
Commodity Swaps | Significant Unobservable Inputs (Level 3)	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivatives asset (liability)	$3,328	'

Reconciliation_of_Commodity_De

Reconciliation of Commodity Derivative Contracts Measured at Fair Value on Recurring Basis Using Significant Unobservable Inputs (Level 3) (Details) (Commodity derivatives, USD $)	6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
Commodity derivatives	'	'
Fair Value Net Derivative Asset Liability Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]	'	'
Beginning Balance of Level 3	$4,323	'
Changes in Fair Value	-2,007	'
Purchases	0	'
Settlements Received	1,012	'
Ending Balance of Level 3	$3,328	'

Financial_Instruments_Not_Reco

Financial Instruments Not Recorded at Fair Value (Details) (USD $)	Jun. 30, 2014		Dec. 31, 2013
Derivatives Fair Value [Line Items]	'		'
8.875% Senior Notes Due 2020	$350,000,000		$350,000,000
Senior Lines of Credit	200,000,000	[1]	59,000,000	[1]
Capital Leases and Other Obligations	14,626,000		9,934,000
Total	564,626,000	[2]	418,934,000
Fair Value	'		'
Derivatives Fair Value [Line Items]	'		'
8.875% Senior Notes due 2020	388,500,000		385,000,000
Secured Lines of Credit	200,000,000		59,000,000
Capital Leases and Other Obligations	14,280,000		9,731,000
Total	$602,780,000		$453,731,000
[1]	The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. The weighted average interest rate on borrowings under our Senior Credit Facility for the three and six months ended June 30, 2014 and the year ended December 31, 2013, was approximately 2.0%, 2.0% and 1.9%, respectively. The average interest rate on our capital leases and other obligations for the three and six months ended June 30, 2014 and the year ended December 31, 2013, was approximately 4.0%, 4.0% and 5.3%, respectively
[2]	Excludes $2.9 million net premium on Senior Notes.

Financial_Instruments_Not_Reco1

Financial Instruments Not Recorded at Fair Value (Parenthetical) (Details) (8.875% Senior Notes)	Jun. 30, 2014	Dec. 31, 2013
8.875% Senior Notes	'	'
Derivatives Fair Value [Line Items]	'	'
Interest rate	8.88%	8.88%

Schedule_of_Income_Tax_Include

Schedule of Income Tax Included in Continuing Operations (Details) (USD $)	3 Months Ended		6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Income Tax Disclosure [Line Items]	'	'	'	'
Income Tax Expense	($5,932)	($9,120)	($10,124)	($7,115)
Effective Tax Rate	42.30%	40.80%	37.40%	40.50%

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Details) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Income Tax Disclosure [Line Items]	'	'	'	'
Statutory rate	'	'	35.00%	35.00%
Income tax refunds	$3.40	$5	$3.40	$5

Capital_Stock_Additional_Infor

Capital Stock - Additional Information (Details)	Jun. 30, 2014	Dec. 31, 2013
Schedule Of Capitalization Equity [Line Items]	'	'
Authorized capital stock, common stock	100,000,000	100,000,000
Authorized capital stock, preferred stock	100,000	100,000
Common stock, shares outstanding	54,089,782	54,186,490
Preferred stock, shares outstanding	0	0

Employee_Benefit_and_Equity_Pl2

Employee Benefit and Equity Plans - Additional Information (Details) (USD $)	6 Months Ended		12 Months Ended	6 Months Ended		3 Months Ended		6 Months Ended			12 Months Ended
In Millions, except Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Dec. 31, 2013
		Person		Stock Options	Stock Options	Restricted Stock	Restricted Stock	Restricted Stock	Restricted Stock	Restricted Stock	Restricted Stock
				Minimum	Maximum			Person	Person	TSR	TSR
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Expiration period for outstanding stock options	'	'	'	'5 years	'10 years	'	'	'	'	'	'
Intrinsic value of stock options exercised	$0.30	$0.20	'	'	'	'	'	'	'	'	'
Total tax benefit	0.1	0.1	'	'	'	'	'	'	'	'	'
Outstanding weighted average remaining term (in years)	'3 years 4 months 24 days	'	'	'	'	'	'	'	'	'	'
Aggregate intrinsic value of options outstanding	3	'	'	'	'	'	'	'	'	'	'
Weighted average remaining term of options exercisable (in years)	'3 years 6 months	'	'	'	'	'	'	'	'	'	'
Aggregate intrinsic value of options exercisable	2.8	'	'	'	'	'	'	'	'	'	'
Common stock issued by compensation committee	'	'	'	'	'	'	'	17,643	383,384	'	'
Number of employees subjected to issuance of common stock	'	'	'	'	'	'	'	12	40	'	'
Number of non-employees subject to issuance of common stock	'	3	'	'	'	'	'	'	'	'	'
Fair value of TSR awards of per share estimated on date of grant	'	'	'	'	'	'	'	$15.64	'	$10.15	$12.59
Expected dividend yield	0.00%	'	0.00%	'	'	0.00%	'	'	'	'	'
Share-based compensation	'	'	'	'	'	1.1	1.1	2.7	2.2	'	'
Unrecognized compensation expense	'	'	'	'	'	$6.80	'	$6.80	'	'	'
Unrecognized compensation expense weighted average period, in years	'	'	'	'	'	'	'	'2 years	'	'	'

Summary_of_Issued_and_Outstand

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

Percentage_of_Awards_to_Vest_D

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

Monte_Carlo_Simulation_Model_A

Monte Carlo Simulation Model Assumptions Used to Estimate Fair Value of Restricted Stock (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Expected Dividend Yield	0.00%	0.00%
Risk-Free Interest Rate	0.80%	0.70%
Expected Volatility	50.40%	50.50%
Market Index	35.30%	35.30%
Expected Life	'3 years	'3 years
Peer Group | Minimum	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Expected Volatility	28.40%	28.40%
Peer Group | Maximum	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Expected Volatility	65.70%	63.50%

Summary_of_Nonvested_Stock_Act

Summary of Nonvested Stock Activity (Details) (Restricted Stock, USD $)	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Restricted Stock	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Stock awards, beginning balance, Number of Shares	2,172,639	'
Awards, Number of Shares	17,643	383,384
Forfeitures, Number of Shares	-150,877	'
Vested, Number of Shares	-294,358	'
Stock awards, ending balance, Number of Shares	1,745,047	'
Stock awards, beginning balance, Weighted Average Grant Date Fair Value	$14.16	'
Awards, Weighted Average Grant Date Fair Value	$15.64	'
Forfeitures, Weighted Average Grant Date Fair Value	$14.60	'
Vested, Weighted Average Grant Date Fair Value	$12.62	'
Stock awards, ending balance, Weighted Average Grant Date Fair Value	$14.39	'

Commitments_and_Contingencies_1

Commitments and Contingencies - Additional Information (Details) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2012	Dec. 31, 2013
					acre
Loss Contingencies [Line Items]	'	'	'	'	'	'
Letters of credit	$2,000,000	'	$2,000,000	'	'	'
Rent expense	200,000	200,000	500,000	300,000	'	'
Maximum guarantee of payment of obligations	406,200,000	'	406,200,000	'	'	'
Transportation, processing and marketing expenses of oil natural gas and natural gas liquids	11,100,000	5,100,000	20,500,000	10,000,000	'	'
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	21,620,000	13,092,000	41,646,000	26,492,000	'	'
Other Liabilities	4,528,000	'	4,528,000	'	'	4,992,000
Working Interest Owners	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Other Liabilities	100,000	'	100,000	'	'	300,000
Capacity Reservation	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Estimated working interest	70.00%	'	70.00%	'	'	'
Capacity Reservation | 2014	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Obligation for the cryogenic gas processing plant if gas is not processed	'	'	5,800,000	'	'	'
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 | 2018	'	'	'	'	'	'
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	'	'	'
Drilling Commitments	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Number of rigs to support Appalachian Basin operations	3	'	3	'	'	'
Drilling carry obligation balance	4,800,000	'	4,800,000	'	14,100,000	'
Drilling commitments	3	'	3	'	'	'
Drilling Commitments | Minimum	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Estimated commitment for each well drilled and completed	'	'	8,000,000	'	'	'
Drilling Commitments | Maximum	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Estimated commitment for each well drilled and completed	'	'	9,000,000	'	'	'
Drilling Commitments | 2014	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Minimum cost to retain drilling rigs	'	'	3,900,000	'	'	'
Minimum cost to retain the completion services	'	'	2,600,000	'	'	'
Drilling Commitments | 2015	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Minimum cost to retain drilling rigs	'	'	3,200,000	'	'	'
Minimum cost to retain the completion services	'	'	5,100,000	'	'	'
Drilling Commitments | 2016	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Minimum cost to retain drilling rigs	'	'	1,500,000	'	'	'
Pennsylvania Impact Fee	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Rate in which unconventional wells are charged	'	'	20.00%	'	'	'
Production and Lease Operating Expense	$700,000	$700,000	$1,300,000	$1,300,000	'	'

Lease_Commitments_for_Each_of_

Lease Commitments for Each of Next Five Years (Details) (USD $)	Jun. 30, 2014
In Thousands, unless otherwise specified
Oil And Gas Delivery Commitments And Contracts [Line Items]	'
2014	$516
2015	1,011
2016	950
2017	923
2018	234
Thereafter	26
Total	$3,660

Minimum_Net_Obligations_under_

Minimum Net Obligations under Sales, Gathering and Transportation Agreements (Details) (USD $)	Jun. 30, 2014
In Thousands, unless otherwise specified
Oil And Gas Delivery Commitments And Contracts [Line Items]	'
2014	$5,589
2015	16,234
2016	29,001
2017	48,314
2018	50,432
Thereafter	726,512
Total	$876,082

Fee_for_Unconventional_Gas_Wel

Fee for Unconventional Gas Wells (Details) (USD $)	6 Months Ended
	Jun. 30, 2014
Less than $2.25	'
Unconventional Gas Wells [Line Items]	'
Year One	$40,000	[1]
Year Two	30,000	[1]
Year Three	25,000	[1]
Year 4 – 10	10,000	[1]
Year 11 – 15	5,000	[1]
$2.26 - $2.99	'
Unconventional Gas Wells [Line Items]	'
Year One	45,000	[1]
Year Two	35,000	[1]
Year Three	30,000	[1]
Year 4 – 10	15,000	[1]
Year 11 – 15	5,000	[1]
$3.00 - $4.99	'
Unconventional Gas Wells [Line Items]	'
Year One	50,000	[1]
Year Two	40,000	[1]
Year Three	30,000	[1]
Year 4 – 10	20,000	[1]
Year 11 – 15	10,000	[1]
$5.00 - $5.99	'
Unconventional Gas Wells [Line Items]	'
Year One	55,000	[1]
Year Two	45,000	[1]
Year Three	40,000	[1]
Year 4 – 10	20,000	[1]
Year 11 – 15	10,000	[1]
More than $5.99	'
Unconventional Gas Wells [Line Items]	'
Year One	60,000	[1]
Year Two	55,000	[1]
Year Three	50,000	[1]
Year 4 – 10	20,000	[1]
Year 11 – 15	$10,000	[1]
[1]	Pricing utilized for determining annual fee is based on the arithmetic mean of the NYMEX settled price for the near-month contract as reported by the Wall Street Journal for the last trading day of each month of a calendar year for the 12-month period ending December 31.

Earnings_Loss_Per_Common_Share2

Earnings (Loss) Per Common Share - Additional Information (Details)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Employee Stock Option	'	'	'	'
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]	'	'	'	'
Anti-dilutive securities excluded from computation of earnings per share	0.3	0.3	0.3	0.3
Performance Based Restricted Stock Awards	'	'	'	'
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]	'	'	'	'
Anti-dilutive securities excluded from computation of earnings per share	0.8	0.5	0.6	0.6

Earnings_Loss_Per_Share_Comput

Earnings (Loss) Per Share - Computation of Basic and Diluted Earning (Loss) Per Common Share (Details) (USD $)	3 Months Ended		6 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Numerator:	'	'	'	'
Net Income From Continuing Operations, Less Noncontrolling Interests	$8,078	$13,220	$16,946	$10,445
Net Income From Discontinued Operations	'	520	'	460
NET INCOME ATTRIBUTABLE TO REX ENERGY	$8,078	$13,740	$16,946	$10,905
Denominator:	'	'	'	'
Weighted Average Common Shares Outstanding - Basic	53,164	52,555	53,075	52,527
Effect of Dilutive Securities:	'	'	'	'
Employee Stock Options	151	142	142	131
Employee Performance-Based Restricted Stock Awards	194	214	294	243
Weighted Average Common Shares Outstanding - Diluted	53,509	52,911	53,511	52,901
Earnings per Common Share:	'	'	'	'
Basic — Net Income From Continuing Operations	$0.15	$0.25	$0.32	$0.20
Basic— Net Loss From Discontinued Operations	'	$0.01	'	$0.01
Basic – Net Income Attributable to Rex Energy Common Shareholders	$0.15	$0.26	$0.32	$0.21
Diluted — Net Income From Continuing Operations	$0.15	$0.25	$0.32	$0.20
Diluted— Net Loss From Discontinued Operations	'	$0.01	'	$0.01
Diluted – Net Income Attributable to Rex Energy Common Shareholders	$0.15	$0.26	$0.32	$0.21

Consolidated_Subsidiaries_Addi

Consolidated Subsidiaries - Additional Information (Details) (USD $)	Jun. 30, 2014		Dec. 31, 2013		Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2014
					Water Solutions Holding	Rex	Sand Hills Management
						Water Solutions Holding	Water Solutions Holding
Variable Interest Entity [Line Items]	'		'		'	'	'
Date of Agreement	'		'		'	'	'2009-11
Membership interest	'		'		'	80.00%	20.00%
Ownership percentage by parent	'		'		60.00%	'	'
Ownership percentage by subsidiary	'		'		'	'	40.00%
Effective date of ownership percentage	'		'		1-Apr-13	'	'
Line of credit facility, amount outstanding	$200,000,000	[1]	$59,000,000	[1]	$7,800,000	'	'
Capital Leases and Other Obligations	$14,626,000		$9,934,000		$5,500,000	'	'
[1]	The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. The weighted average interest rate on borrowings under our Senior Credit Facility for the three and six months ended June 30, 2014 and the year ended December 31, 2013, was approximately 2.0%, 2.0% and 1.9%, respectively. The average interest rate on our capital leases and other obligations for the three and six months ended June 30, 2014 and the year ended December 31, 2013, was approximately 4.0%, 4.0% and 5.3%, respectively

Schedule_of_Carrying_Amount_an

Schedule of Carrying Amount and Classification of Assets and Liabilities of Water Solutions as Consolidated (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Variable Interest Entity [Line Items]	'	'	'	'
Cash and Cash Equivalents	$5,951	$1,900	$69,194	$43,975
Accounts Receivable	46,574	38,863	'	'
Inventory, Prepaid Expenses and Other	2,223	2,207	'	'
Other Property and Equipment	79,717	70,115	'	'
Wells and Facilities in Progress	114,670	76,545	'	'
Less: Accumulated Depreciation, Depletion and Amortization	-230,187	-190,521	'	'
Deferred Financing Costs and Other Assets – Net	11,604	11,993	'	'
Total Assets	1,183,102	991,396	'	'
Accounts Payable	49,351	31,103	'	'
Current Maturities of Long-Term Debt	7,729	6,743	'	'
Accrued Liabilities	47,491	54,450	'	'
Senior Secured Line of Credit and Long-Term Debt	206,897	62,191	'	'
Total Liabilities	744,306	574,471	'	'
Water Solutions Holding | Variable Interest Entity, Primary Beneficiary	'	'	'	'
Variable Interest Entity [Line Items]	'	'	'	'
Cash and Cash Equivalents	528	593	'	'
Accounts Receivable	13,541	9,882	'	'
Inventory, Prepaid Expenses and Other	250	89	'	'
Other Property and Equipment	17,478	11,798	'	'
Wells and Facilities in Progress	298	1,031	'	'
Less: Accumulated Depreciation, Depletion and Amortization	-3,467	-1,954	'	'
Deferred Financing Costs and Other Assets – Net	170	206	'	'
Total Assets	28,798	21,645	'	'
Accounts Payable	267	758	'	'
Current Maturities of Long-Term Debt	6,554	5,404	'	'
Accrued Liabilities	4,746	6,247	'	'
Senior Secured Line of Credit and Long-Term Debt	6,738	3,053	'	'
Total Liabilities	$18,305	$15,462	'	'

Equity_Method_Investments_Addi

Equity Method Investments - Additional Information (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013
Schedule Of Equity Method Investments [Line Items]	'	'	'	'	'
Equity investment	$18,300,000	'	$18,300,000	'	$18,708,000
Contributions to Equity Method Investments	'	'	'	2,207,000	'
Income (Loss) on Equity Method Investments	-208,000	-183,000	-408,000	-361,000	'
Production and Lease Operating Expense	21,620,000	13,092,000	41,646,000	26,492,000	'
RW Gathering, LLC	'	'	'	'	'
Schedule Of Equity Method Investments [Line Items]	'	'	'	'	'
Ownership percentage	40.00%	'	40.00%	'	'
Contributions to Equity Method Investments	'	'	'	2,207,000	'
Income (Loss) on Equity Method Investments	500,000	500,000	1,000,000	900,000	'
Production and Lease Operating Expense	200,000	200,000	400,000	400,000	'
Receivables	$0	'	$0	'	$0

Impairment_Expense_Additional_

Impairment Expense - Additional Information (Details) (USD $)	Jun. 30, 2014
In Millions, unless otherwise specified
Depreciation And Other Amortization Expenses [Line Items]	'
Undeveloped properties, cost	$227.80

Exploration_Expense_Additional

Exploration Expense - Additional Information (Details) (USD $)	3 Months Ended		6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Exploration Expense [Line Items]	'	'	'	'
Exploration Expense	$1,367	$2,225	$3,427	$4,269
Geological and Geophysical Type Expenditures	'	'	'	'
Exploration Expense [Line Items]	'	'	'	'
Exploration Expense	'	'	2,400	3,800
Payment of Delay Rentals | Appalachian Basin	'	'	'	'
Exploration Expense [Line Items]	'	'	'	'
Exploration Expense	'	'	$800	$500

Condensed_Consolidating_Financ2

Condensed Consolidating Financial Information - Additional Information (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Condensed Financial Statements Captions [Line Items]	'	'
8.875% Senior Notes Due 2020	$350,000	$350,000

Condensed_Consolidating_Balanc

Condensed Consolidating Balance Sheets (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current Assets	'	'	'	'
Cash and Cash Equivalents	$5,951	$1,900	$69,194	$43,975
Accounts Receivable	46,574	38,863	'	'
Taxes Receivable	1,767	5,189	'	'
Short-Term Derivative Instruments	4,181	5,668	'	'
Current Deferred Tax Asset	4,010	3,451	'	'
Inventory, Prepaid Expenses and Other	2,223	2,207	'	'
Total Current Assets	64,706	57,278	'	'
Property and Equipment (Successful Efforts Method)	'	'	'	'
Evaluated Oil and Gas Properties	880,725	749,680	'	'
Unevaluated Oil and Gas Properties	227,831	189,385	'	'
Other Property and Equipment	79,717	70,115	'	'
Wells and Facilities in Progress	114,670	76,545	'	'
Pipelines	15,577	7,678	'	'
Total Property and Equipment	1,318,520	1,093,403	'	'
Less: Accumulated Depreciation, Depletion and Amortization	-230,187	-190,521	'	'
Net Property and Equipment	1,088,333	902,882	'	'
Deferred Financing Costs and Other Assets – Net	11,604	11,993	'	'
Equity Method Investments	18,300	18,708	'	'
Long-Term Derivative Instruments	159	535	'	'
Total Assets	1,183,102	991,396	'	'
Current Liabilities	'	'	'	'
Accounts Payable	49,351	31,103	'	'
Current Maturities of Long-Term Debt	7,729	6,743	'	'
Accrued Liabilities	47,491	54,450	'	'
Short-Term Derivative Instruments	6,699	4,663	'	'
Total Current Liabilities	111,270	96,959	'	'
8.875% Senior Notes Due 2020	350,000	350,000	'	'
Premium on Senior Notes, Net	2,905	3,078	'	'
Senior Secured Line of Credit and Other Long-Term Debt	206,897	62,191	'	'
Long-Term Derivative Instruments	1,535	1,765	'	'
Long-Term Deferred Tax Liability	40,128	29,446	'	'
Other Deposits and Liabilities	4,528	4,992	'	'
Future Abandonment Cost	27,043	26,040	'	'
Total Liabilities	744,306	574,471	'	'
Stockholders’ Equity	'	'	'	'
Common Stock	54	54	'	'
Additional Paid-In Capital	459,754	456,554	'	'
Accumulated Earnings (Deficit)	-24,779	-41,725	'	'
Rex Energy Stockholders’ Equity	435,029	414,883	'	'
Noncontrolling Interests	3,767	2,042	'	'
Total Stockholders’ Equity	438,796	416,925	'	'
Total Liabilities and Stockholders’ Equity	1,183,102	991,396	'	'
Premium (Discount) on Senior Notes – Net	2,905	3,078	'	'
Senior Secured Line of Credit and Long-Term Debt	206,897	62,191	'	'
Eliminations	'	'	'	'
Current Assets	'	'	'	'
Accounts Receivable	-2,405	-3,302	'	'
Total Current Assets	-2,405	-3,302	'	'
Property and Equipment (Successful Efforts Method)	'	'	'	'
Evaluated Oil and Gas Properties	-4,127	-3,101	'	'
Wells and Facilities in Progress	-708	-790	'	'
Pipelines	-1,822	'	'	'
Total Property and Equipment	-6,657	-3,891	'	'
Less: Accumulated Depreciation, Depletion and Amortization	618	350	'	'
Net Property and Equipment	-6,039	-3,541	'	'
Intercompany Receivables	-688,577	-628,517	'	'
Investment in Subsidiaries – Net	-340,680	-222,584	'	'
Total Assets	-1,037,701	-857,944	'	'
Current Liabilities	'	'	'	'
Accounts Payable	-2,404	-3,304	'	'
Total Current Liabilities	-2,404	-3,304	'	'
Intercompany Payables	-688,577	-628,517	'	'
Total Liabilities	-690,981	-631,821	'	'
Stockholders’ Equity	'	'	'	'
Additional Paid-In Capital	-261,384	-183,632	'	'
Accumulated Earnings (Deficit)	-87,781	-44,048	'	'
Rex Energy Stockholders’ Equity	-349,165	-227,680	'	'
Noncontrolling Interests	2,445	1,557	'	'
Total Stockholders’ Equity	-346,720	-226,123	'	'
Total Liabilities and Stockholders’ Equity	-1,037,701	-857,944	'	'
Guarantor Subsidiaries	'	'	'	'
Current Assets	'	'	'	'
Cash and Cash Equivalents	5,431	1,386	8,304	4,227
Accounts Receivable	35,441	32,283	'	'
Short-Term Derivative Instruments	4,181	5,180	'	'
Inventory, Prepaid Expenses and Other	1,586	2,092	'	'
Total Current Assets	46,639	40,941	'	'
Property and Equipment (Successful Efforts Method)	'	'	'	'
Evaluated Oil and Gas Properties	884,639	752,781	'	'
Unevaluated Oil and Gas Properties	227,179	189,385	'	'
Other Property and Equipment	61,331	57,409	'	'
Wells and Facilities in Progress	108,802	70,759	'	'
Pipelines	17,399	7,678	'	'
Total Property and Equipment	1,299,350	1,078,012	'	'
Less: Accumulated Depreciation, Depletion and Amortization	-227,050	-188,699	'	'
Net Property and Equipment	1,072,300	889,313	'	'
Deferred Financing Costs and Other Assets – Net	2,421	2,421	'	'
Equity Method Investments	18,300	18,708	'	'
Investment in Subsidiaries – Net	4,156	4,442	'	'
Long-Term Derivative Instruments	159	535	'	'
Total Assets	1,143,975	956,360	'	'
Current Liabilities	'	'	'	'
Accounts Payable	51,431	33,613	'	'
Current Maturities of Long-Term Debt	1,175	1,339	'	'
Accrued Liabilities	39,247	45,196	'	'
Short-Term Derivative Instruments	6,699	4,663	'	'
Total Current Liabilities	98,552	84,811	'	'
Senior Secured Line of Credit and Other Long-Term Debt	159	137	'	'
Long-Term Derivative Instruments	1,535	1,071	'	'
Other Deposits and Liabilities	4,528	4,992	'	'
Future Abandonment Cost	27,024	26,027	'	'
Intercompany Payables	685,517	554,329	'	'
Total Liabilities	817,315	671,367	'	'
Stockholders’ Equity	'	'	'	'
Additional Paid-In Capital	177,143	177,144	'	'
Accumulated Earnings (Deficit)	149,517	107,849	'	'
Rex Energy Stockholders’ Equity	326,660	284,993	'	'
Total Stockholders’ Equity	326,660	284,993	'	'
Total Liabilities and Stockholders’ Equity	1,143,975	956,360	'	'
Senior Secured Line of Credit and Long-Term Debt	159	137	'	'
Non-Guarantor Subsidiaries	'	'	'	'
Current Assets	'	'	'	'
Cash and Cash Equivalents	515	509	2,262	824
Accounts Receivable	13,538	9,882	'	'
Inventory, Prepaid Expenses and Other	250	89	'	'
Total Current Assets	14,303	10,480	'	'
Property and Equipment (Successful Efforts Method)	'	'	'	'
Evaluated Oil and Gas Properties	213	'	'	'
Unevaluated Oil and Gas Properties	652	'	'	'
Other Property and Equipment	18,386	12,706	'	'
Wells and Facilities in Progress	6,576	6,576	'	'
Total Property and Equipment	25,827	19,282	'	'
Less: Accumulated Depreciation, Depletion and Amortization	-3,755	-2,172	'	'
Net Property and Equipment	22,072	17,110	'	'
Deferred Financing Costs and Other Assets – Net	170	206	'	'
Investment in Subsidiaries – Net	4,361	1,197	'	'
Total Assets	40,906	28,993	'	'
Current Liabilities	'	'	'	'
Accounts Payable	324	794	'	'
Current Maturities of Long-Term Debt	6,554	5,404	'	'
Accrued Liabilities	5,327	6,287	'	'
Total Current Liabilities	12,205	12,485	'	'
Senior Secured Line of Credit and Other Long-Term Debt	6,738	3,054	'	'
Future Abandonment Cost	19	13	'	'
Intercompany Payables	3,060	74,188	'	'
Total Liabilities	22,022	89,740	'	'
Stockholders’ Equity	'	'	'	'
Additional Paid-In Capital	84,241	6,488	'	'
Accumulated Earnings (Deficit)	-66,679	-67,720	'	'
Rex Energy Stockholders’ Equity	17,562	-61,232	'	'
Noncontrolling Interests	1,322	485	'	'
Total Stockholders’ Equity	18,884	-60,747	'	'
Total Liabilities and Stockholders’ Equity	40,906	28,993	'	'
Senior Secured Line of Credit and Long-Term Debt	6,738	3,054	'	'
Parent Company	'	'	'	'
Current Assets	'	'	'	'
Cash and Cash Equivalents	5	5	58,628	38,924
Taxes Receivable	1,767	5,189	'	'
Short-Term Derivative Instruments	'	488	'	'
Current Deferred Tax Asset	4,010	3,451	'	'
Inventory, Prepaid Expenses and Other	387	26	'	'
Total Current Assets	6,169	9,159	'	'
Property and Equipment (Successful Efforts Method)	'	'	'	'
Deferred Financing Costs and Other Assets – Net	9,013	9,366	'	'
Intercompany Receivables	688,577	628,517	'	'
Investment in Subsidiaries – Net	332,163	216,945	'	'
Total Assets	1,035,922	863,987	'	'
Current Liabilities	'	'	'	'
Accrued Liabilities	2,917	2,967	'	'
Total Current Liabilities	2,917	2,967	'	'
8.875% Senior Notes Due 2020	350,000	350,000	'	'
Premium on Senior Notes, Net	2,905	3,078	'	'
Senior Secured Line of Credit and Other Long-Term Debt	200,000	59,000	'	'
Long-Term Derivative Instruments	'	694	'	'
Long-Term Deferred Tax Liability	40,128	29,446	'	'
Total Liabilities	595,950	445,185	'	'
Stockholders’ Equity	'	'	'	'
Common Stock	54	54	'	'
Additional Paid-In Capital	459,754	456,554	'	'
Accumulated Earnings (Deficit)	-19,836	-37,806	'	'
Rex Energy Stockholders’ Equity	439,972	418,802	'	'
Total Stockholders’ Equity	439,972	418,802	'	'
Total Liabilities and Stockholders’ Equity	1,035,922	863,987	'	'
Premium (Discount) on Senior Notes – Net	2,905	3,078	'	'
Senior Secured Line of Credit and Long-Term Debt	$200,000	$59,000	'	'

Condensed_Consolidating_Balanc1

Condensed Consolidating Balance Sheets (Parenthetical) (Details) (8.875% Senior Notes)	6 Months Ended	12 Months Ended
	Jun. 30, 2014	Dec. 31, 2013
8.875% Senior Notes	'	'
Condensed Balance Sheet Statements Captions [Line Items]	'	'
Interest rate	8.88%	8.88%
Due date	'2020	'2020

Condensed_Consolidating_Statem

Condensed Consolidating Statements of Operations (Details) (USD $)	3 Months Ended		6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
OPERATING REVENUE	'	'	'	'
Oil, Natural Gas and NGL Sales	$72,903	$51,444	$154,202	$92,384
Field Services Revenue	13,087	3,840	28,391	10,345
Other Revenue	30	76	74	100
TOTAL OPERATING REVENUE	86,020	55,360	182,667	102,829
OPERATING EXPENSES	'	'	'	'
Production and Lease Operating Expense	21,620	13,092	41,646	26,492
General and Administrative Expense	9,239	7,782	19,630	15,578
Loss on Disposal of Asset	230	1,502	301	1,493
Impairment Expense	16	105	41	170
Exploration Expense	1,367	2,225	3,427	4,269
Depreciation, Depletion, Amortization and Accretion	21,226	12,943	41,650	24,101
Field Services Operating Expense	9,569	2,648	21,365	6,703
Other Operating Expense (Income)	-56	447	27	891
TOTAL OPERATING EXPENSES	63,211	40,744	128,087	79,697
INCOME (LOSS) FROM OPERATIONS	22,809	14,616	54,580	23,132
OTHER INCOME (EXPENSE)	'	'	'	'
Interest Expense	-7,503	-5,826	-14,638	-9,831
Gain (Loss) on Derivatives, Net	-251	11,741	-10,001	3,201
Other Income (Expense)	40	2,213	-17	2,073
Loss on Equity Method Investments	-208	-183	-408	-361
TOTAL OTHER INCOME (EXPENSE)	-7,922	7,945	-25,064	-4,918
Income (Loss) From Continuing Operations, Before Income Taxes	14,887	22,561	29,516	18,214
Income Tax Expense	-5,932	-9,120	-10,124	-7,115
INCOME (LOSS) FROM CONTINUING OPERATIONS	8,955	13,441	19,392	11,099
Net Income Attributable to Noncontrolling Interests	877	221	2,446	654
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	8,078	13,740	16,946	10,905
Income From Discontinued Operations, Net of Income Taxes	0	520	0	460
Net Income	8,955	13,961	19,392	11,559
Eliminations	'	'	'	'
OPERATING REVENUE	'	'	'	'
Field Services Revenue	-2,887	-1,232	-10,206	-2,779
TOTAL OPERATING REVENUE	-2,887	-1,232	-10,206	-2,779
OPERATING EXPENSES	'	'	'	'
Production and Lease Operating Expense	-13	'	-20	'
General and Administrative Expense	-15	'	-35	-56
Depreciation, Depletion, Amortization and Accretion	-159	-38	-270	-61
Field Services Operating Expense	-2,263	-862	-7,417	-1,945
TOTAL OPERATING EXPENSES	-2,450	-900	-7,742	-2,062
INCOME (LOSS) FROM OPERATIONS	-437	-332	-2,464	-717
OTHER INCOME (EXPENSE)	'	'	'	'
Other Income (Expense)	-15	-22	-35	-56
Income (Loss) From Equity in Consolidated Subsidiaries	-12,409	-17,697	-25,977	-17,856
TOTAL OTHER INCOME (EXPENSE)	-12,424	-17,719	-26,012	-17,912
Income (Loss) From Continuing Operations, Before Income Taxes	-12,861	-18,051	-28,476	-18,629
INCOME (LOSS) FROM CONTINUING OPERATIONS	-12,861	-18,051	-28,476	-18,629
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	-12,861	-18,051	-28,476	-18,629
Net Income	'	-18,051	-28,476	-18,629
Guarantor Subsidiaries	'	'	'	'
OPERATING REVENUE	'	'	'	'
Oil, Natural Gas and NGL Sales	72,903	51,444	154,202	92,384
Other Revenue	30	76	74	100
TOTAL OPERATING REVENUE	72,933	51,520	154,276	92,484
OPERATING EXPENSES	'	'	'	'
Production and Lease Operating Expense	21,630	13,090	41,660	26,487
General and Administrative Expense	7,221	5,970	15,101	12,033
Loss on Disposal of Asset	223	1,502	294	1,493
Impairment Expense	16	105	41	170
Exploration Expense	1,364	2,225	3,424	4,269
Depreciation, Depletion, Amortization and Accretion	20,454	12,645	40,277	23,559
Other Operating Expense (Income)	-56	447	27	891
TOTAL OPERATING EXPENSES	50,852	35,984	100,824	68,902
INCOME (LOSS) FROM OPERATIONS	22,081	15,536	53,452	23,582
OTHER INCOME (EXPENSE)	'	'	'	'
Interest Expense	-17	-22	-31	-31
Gain (Loss) on Derivatives, Net	-645	11,741	-11,084	3,201
Other Income (Expense)	55	2,235	18	2,129
Loss on Equity Method Investments	-208	-183	-408	-361
Income (Loss) From Equity in Consolidated Subsidiaries	-56	-11	-81	-22
TOTAL OTHER INCOME (EXPENSE)	-871	13,760	-11,586	4,916
Income (Loss) From Continuing Operations, Before Income Taxes	21,210	29,296	41,866	28,498
Income Tax Expense	-9,051	-11,964	-15,689	-11,555
INCOME (LOSS) FROM CONTINUING OPERATIONS	12,159	17,332	26,177	16,943
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	12,159	17,332	26,177	16,943
Net Income	'	17,332	26,177	16,943
Non-Guarantor Subsidiaries	'	'	'	'
OPERATING REVENUE	'	'	'	'
Field Services Revenue	15,974	5,072	38,597	13,124
TOTAL OPERATING REVENUE	15,974	5,072	38,597	13,124
OPERATING EXPENSES	'	'	'	'
Production and Lease Operating Expense	3	2	6	5
General and Administrative Expense	950	659	1,822	1,148
Loss on Disposal of Asset	7	'	7	'
Exploration Expense	3	'	3	'
Depreciation, Depletion, Amortization and Accretion	931	336	1,643	603
Field Services Operating Expense	11,832	3,510	28,782	8,648
TOTAL OPERATING EXPENSES	13,726	4,507	32,263	10,404
INCOME (LOSS) FROM OPERATIONS	2,248	565	6,334	2,720
OTHER INCOME (EXPENSE)	'	'	'	'
Interest Expense	-145	-28	-347	-40
Income (Loss) From Equity in Consolidated Subsidiaries	56	11	81	22
TOTAL OTHER INCOME (EXPENSE)	-89	-17	-266	-18
Income (Loss) From Continuing Operations, Before Income Taxes	2,159	548	6,068	2,702
Income Tax Expense	-580	-128	-1,323	-822
INCOME (LOSS) FROM CONTINUING OPERATIONS	1,579	420	4,745	1,880
Net Income Attributable to Noncontrolling Interests	877	221	2,446	654
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	702	719	2,299	1,686
Income From Discontinued Operations, Net of Income Taxes	'	520	'	460
Net Income	'	940	4,745	2,340
Parent Company	'	'	'	'
OPERATING EXPENSES	'	'	'	'
General and Administrative Expense	1,083	1,153	2,742	2,453
TOTAL OPERATING EXPENSES	1,083	1,153	2,742	2,453
INCOME (LOSS) FROM OPERATIONS	-1,083	-1,153	-2,742	-2,453
OTHER INCOME (EXPENSE)	'	'	'	'
Interest Expense	-7,341	-5,776	-14,260	-9,760
Gain (Loss) on Derivatives, Net	394	'	1,083	'
Income (Loss) From Equity in Consolidated Subsidiaries	12,409	17,697	25,977	17,856
TOTAL OTHER INCOME (EXPENSE)	5,462	11,921	12,800	8,096
Income (Loss) From Continuing Operations, Before Income Taxes	4,379	10,768	10,058	5,643
Income Tax Expense	3,699	2,972	6,888	5,262
INCOME (LOSS) FROM CONTINUING OPERATIONS	8,078	13,740	16,946	10,905
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	8,078	13,740	16,946	10,905
Net Income	'	$13,740	$16,946	$10,905

Condensed_Consolidating_Statem1

Condensed Consolidating Statements of Cash Flows (Details) (USD $)	6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
CASH FLOWS FROM OPERATING ACTIVITIES	'	'
Net Income	$19,392	$11,559
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities	'	'
Loss from Equity Method Investments	408	361
Non-cash Expenses	3,336	3,027
Depreciation, Depletion, Amortization and Accretion	41,650	24,101
Deferred Income Tax Expense (Benefit)	10,124	7,372
(Gain) Loss on Derivatives	10,001	-3,201
Cash Settlements of Derivatives	-6,333	4,798
Dry Hole Expense	86	485
Loss on Sale of Asset	301	524
Impairment Expense	41	170
Changes in operating assets and liabilities	'	'
Accounts Receivable	-4,302	1,974
Inventory, Prepaid Expenses and Other Assets	-16	37
Accounts Payable and Accrued Liabilities	12,875	10,353
Other Assets and Liabilities	-992	-562
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	86,571	60,998
CASH FLOWS FROM INVESTING ACTIVITIES	'	'
Proceeds from Joint Venture Acreage Management	146	107
Contributions to Equity Method Investments	'	-2,207
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	139	3,732
Acquisitions of Undeveloped Acreage	-40,139	-15,706
Capital Expenditures for Development of Oil & Gas Properties and Equipment	-185,577	-123,609
NET CASH USED IN INVESTING ACTIVITIES	-225,431	-137,683
CASH FLOWS FROM FINANCING ACTIVITIES	'	'
Proceeds from Long-Term Debt and Line of Credit	162,409	1,750
Repayments of Long-Term Debt and Line of Credit	-17,753	-876
Repayments of Loans and Other Notes Payable	-1,168	-786
Debt Issuance Costs	-277	-2,894
Proceeds from the Exercise of Stock Options	421	266
Distributions by the Partners of Consolidated Joint Ventures	-721	-406
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	142,911	101,904
Proceeds from Senior Notes, Net of Discounts and Premiums	'	105,000
Purchase of Noncontrolling Interests	'	-150
NET INCREASE IN CASH	4,051	25,219
CASH – BEGINNING	1,900	43,975
CASH – ENDING	5,951	69,194
Eliminations	'	'
CASH FLOWS FROM OPERATING ACTIVITIES	'	'
Net Income	-28,476	-18,629
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities	'	'
Depreciation, Depletion, Amortization and Accretion	-270	-61
Changes in operating assets and liabilities	'	'
Accounts Receivable	-898	-4,009
Accounts Payable and Accrued Liabilities	898	-435
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	-28,746	-23,134
CASH FLOWS FROM INVESTING ACTIVITIES	'	'
Intercompany loans to subsidiaries	25,980	22,300
Capital Expenditures for Development of Oil & Gas Properties and Equipment	2,766	834
NET CASH USED IN INVESTING ACTIVITIES	28,746	23,134
Guarantor Subsidiaries	'	'
CASH FLOWS FROM OPERATING ACTIVITIES	'	'
Net Income	26,177	16,943
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities	'	'
Loss from Equity Method Investments	408	361
Non-cash Expenses	-133	3
Depreciation, Depletion, Amortization and Accretion	40,277	23,559
Deferred Income Tax Expense (Benefit)	15,689	11,499
(Gain) Loss on Derivatives	11,084	-3,201
Cash Settlements of Derivatives	-7,211	4,798
Dry Hole Expense	86	485
Loss on Sale of Asset	294	1,493
Impairment Expense	41	170
Changes in operating assets and liabilities	'	'
Accounts Receivable	-3,163	85,176
Inventory, Prepaid Expenses and Other Assets	505	25
Accounts Payable and Accrued Liabilities	13,404	8,503
Other Assets and Liabilities	-970	-557
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	96,488	149,257
CASH FLOWS FROM INVESTING ACTIVITIES	'	'
Intercompany loans to subsidiaries	131,376	-6,704
Proceeds from Joint Venture Acreage Management	146	107
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	139	498
Acquisitions of Undeveloped Acreage	-39,484	-15,704
Capital Expenditures for Development of Oil & Gas Properties and Equipment	-183,765	-122,834
NET CASH USED IN INVESTING ACTIVITIES	-91,588	-144,637
CASH FLOWS FROM FINANCING ACTIVITIES	'	'
Repayments of Loans and Other Notes Payable	-855	-543
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	-855	-543
NET INCREASE IN CASH	4,045	4,077
CASH – BEGINNING	1,386	4,227
CASH – ENDING	5,431	8,304
Non-Guarantor Subsidiaries	'	'
CASH FLOWS FROM OPERATING ACTIVITIES	'	'
Net Income	4,745	2,340
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities	'	'
Non-cash Expenses	186	50
Depreciation, Depletion, Amortization and Accretion	1,643	603
Deferred Income Tax Expense (Benefit)	1,323	1,135
Loss on Sale of Asset	7	-969
Changes in operating assets and liabilities	'	'
Accounts Receivable	-3,664	-3,089
Inventory, Prepaid Expenses and Other Assets	-161	-6
Accounts Payable and Accrued Liabilities	-1,432	805
Other Assets and Liabilities	-22	-5
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	2,625	864
CASH FLOWS FROM INVESTING ACTIVITIES	'	'
Intercompany loans to subsidiaries	-4	1,083
Contributions to Equity Method Investments	'	-2,207
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets	'	3,234
Acquisitions of Undeveloped Acreage	-655	-2
Capital Expenditures for Development of Oil & Gas Properties and Equipment	-4,578	-1,609
NET CASH USED IN INVESTING ACTIVITIES	-5,237	499
CASH FLOWS FROM FINANCING ACTIVITIES	'	'
Proceeds from Long-Term Debt and Line of Credit	9,409	1,750
Repayments of Long-Term Debt and Line of Credit	-5,753	-876
Repayments of Loans and Other Notes Payable	-313	-243
Debt Issuance Costs	-4	'
Distributions by the Partners of Consolidated Joint Ventures	-721	-406
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	2,618	75
Purchase of Noncontrolling Interests	'	-150
NET INCREASE IN CASH	6	1,438
CASH – BEGINNING	509	824
CASH – ENDING	515	2,262
Parent Company	'	'
CASH FLOWS FROM OPERATING ACTIVITIES	'	'
Net Income	16,946	10,905
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities	'	'
Non-cash Expenses	3,283	2,974
Deferred Income Tax Expense (Benefit)	-6,888	-5,262
(Gain) Loss on Derivatives	-1,083	'
Cash Settlements of Derivatives	878	'
Changes in operating assets and liabilities	'	'
Accounts Receivable	3,423	-76,104
Inventory, Prepaid Expenses and Other Assets	-360	18
Accounts Payable and Accrued Liabilities	5	1,480
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	16,204	-65,989
CASH FLOWS FROM INVESTING ACTIVITIES	'	'
Intercompany loans to subsidiaries	-157,352	-16,679
NET CASH USED IN INVESTING ACTIVITIES	-157,352	-16,679
CASH FLOWS FROM FINANCING ACTIVITIES	'	'
Proceeds from Long-Term Debt and Line of Credit	153,000	'
Repayments of Long-Term Debt and Line of Credit	-12,000	'
Debt Issuance Costs	-273	-2,894
Proceeds from the Exercise of Stock Options	421	266
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	141,148	102,372
Proceeds from Senior Notes, Net of Discounts and Premiums	'	105,000
NET INCREASE IN CASH	'	19,704
CASH – BEGINNING	5	38,924
CASH – ENDING	$5	$58,628

Subsequent_Events_Additional_I

Subsequent Events - Additional Information (Details) (USD $)	6 Months Ended						0 Months Ended
	Jun. 30, 2013	Jun. 30, 2014		Dec. 31, 2013		Jul. 14, 2014	Jul. 14, 2014
						Subsequent Event	Subsequent Event
						Senior Credit Facility	6.25% Senior Notes
Subsequent Event [Line Items]	'	'		'		'	'
Debt issued aggregate principal amount	'	'		'		'	$325,000,000
Interest rate	'	'		'		'	6.25%
Offering price as percentage of issue price	'	'		'		'	100.00%
Debt instrument maturity date	'	'		'		'	1-Aug-22
Proceeds from Senior Notes, Net of Discounts and Premiums	105,000,000	'		'		'	318,800,000
Line of credit facility, amount outstanding	'	$200,000,000	[1]	$59,000,000	[1]	$218,000,000	'
[1]	The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. The weighted average interest rate on borrowings under our Senior Credit Facility for the three and six months ended June 30, 2014 and the year ended December 31, 2013, was approximately 2.0%, 2.0% and 1.9%, respectively. The average interest rate on our capital leases and other obligations for the three and six months ended June 30, 2014 and the year ended December 31, 2013, was approximately 4.0%, 4.0% and 5.3%, respectively