Grizzly Energy (GRZZP) 10-Q 31 Oct 13 2013 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Oct. 30, 2013
Document and Entity Information [Abstract]	'	'
Entity Registrant Name	'Vanguard Natural Resources, LLC	'
Entity Central Index Key	'0001384072	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	77,500,753
Document Fiscal Year Focus	'2013	'
Document Period End Date	30-Sep-13	'
Document Fiscal Period Focus	'Q3	'
Document Type	'10-Q	'
Amendment Flag	'false	'

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Revenues:	'	'	'	'
Oil, natural gas and NGLs sales	$121,510	$78,871	$334,929	$228,029
Realized gain (loss) on commodity derivative contracts	-5,359	318	-2,175	-756
Unrealized gain (loss) on commodity derivative contracts	-12,355	-51,332	13,781	9,243
Total revenues	103,796	27,857	346,535	236,516
Production:	'	'	'	'
Lease operating expenses	25,339	19,514	76,021	54,754
Production and other taxes	11,097	7,053	30,404	21,164
Depreciation, depletion, amortization and accretion	41,750	31,245	123,354	73,897
Impairment of Oil and Gas Properties	0	18,029	0	18,029
Selling, general and administrative expenses	5,730	5,499	19,179	15,298
Total costs and expenses	83,916	81,340	248,958	183,142
Income from operations	19,880	-53,483	97,577	53,374
Other income (expense):	'	'	'	'
Interest expense	-14,832	-12,389	-46,233	-27,548
Realized loss on interest rate derivative contracts	-987	-468	-2,896	-1,610
Unrealized gain (loss) on interest rate derivative contracts	-742	-2,463	3,294	-5,507
Gain (loss) on acquisition of oil and natural gas properties, net	-236	0	5,591	13,796
Other	38	76	66	191
Total other expense	-16,759	-15,244	-40,178	-20,678
Net income (loss)	3,121	-68,727	57,399	32,696
Distributions to Preferred unitholders	-1,240	0	-1,392	0
Net income available to Common and Class B unitholders	$1,881	($68,727)	$56,007	$32,696
Earnings Per Share, Basic and Diluted	$0.02	($1.29)	$0.78	$0.62
Common Units	'	'	'	'
Other income (expense):	'	'	'	'
Weighted Average Number of Shares Outstanding, Basic	77,483	52,719	70,931	52,135
Weighted Average Number of Shares Outstanding, Diluted	77,748	52,719	71,361	52,188
Class B Units [Member]	'	'	'	'
Other income (expense):	'	'	'	'
Weighted Average Number of Shares Outstanding, Basic and Diluted	420	420	420	420

CONSOLIDATED_BALANCE_SHEETS_Un

CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets	'	'
Cash and cash equivalents	$7,426	$11,563
Trade accounts receivable, net	75,050	51,880
Derivative assets	30,733	46,690
Other currents assets	4,051	3,858
Total current assets	117,260	113,991
Oil and natural gas properties, at cost	2,492,082	2,126,268
Accumulated depletion, amortization and impairment	-670,413	-550,032
Oil and natural gas properties evaluated, net - full cost method	1,821,669	1,576,236
Other assets	'	'
Goodwill	420,955	420,955
Derivative assets	62,849	53,240
Other assets	33,262	35,712
Total assets	2,455,995	2,200,134
Accounts payable:	'	'
Trade	9,638	8,417
Affiliates	163	32
Accrued liabilities:	'	'
Lease operating	9,421	7,884
Developmental capital	8,231	4,754
Interest	22,693	11,573
Production and other taxes	19,393	12,852
Derivative liabilities	11,638	5,366
Oil and natural gas revenue payable	19,333	8,226
Distribution payable	16,339	11,919
Other	10,819	8,479
Total current liabilities	127,668	79,502
Long-term debt	957,815	1,247,631
Derivative liabilities	5,337	11,996
Asset retirement obligations, net of current portion	70,059	60,096
Other long-term liabilities	1,345	3,445
Total liabilities	1,162,224	1,402,670
Commitments and contingencies (Note 8)	'	'
Members' equity	'	'
Members' equity	1,293,771	797,464
Total liabilities and members' equity	2,455,995	2,200,134
Preferred units	'	'
Members' equity	'	'
Members' equity	60,635	0
Common Units	'	'
Members' equity	'	'
Members' equity	1,230,871	794,426
Class B Units [Member]	'	'
Members' equity	'	'
Members' equity	$2,265	$3,038

CONSOLIDATED_BALANCE_SHEETS_Un1

CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical)	Sep. 30, 2013	Dec. 31, 2012
Members' equity	'	'
Preferred units, issued	2,520,000	'
Preferred units, outstanding	2,520,000	'
Common Units	'	'
Members' equity	'	'
Common units, issued	77,498,386	58,706,282
Common units, outstanding	77,498,386	58,706,282
Class B Units [Member]	'	'
Members' equity	'	'
Common units, issued	420,000	420,000
Common units, outstanding	420,000	420,000

CONSOLIDATED_STATEMENTS_OF_MEM

CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY (Unaudited) (USD $)	Total	Preferred units	Common Units	Class B Units [Member]
In Thousands, unless otherwise specified
Balance at Dec. 31, 2011	$843,921	$0	$839,714	$4,207
Balance (in units) at Dec. 31, 2011	'	0	48,320	420
Increase (Decrease) in Members' Equity [Roll Forward]	'	'	'	'
Distributions to Common and Class B unitholders	-152,190	'	-151,021	-1,169
Issuance of units, net of offering costs	'	'	321,900	'
Issuance of units, net of offering costs (in units)	'	'	12,149	'
Common units received in exchange for Appalachian Basin properties	-52,480	'	-52,480	'
Common units received in exchange for Appalachian Basin properties (in units)	'	'	-1,900	'
Unit-based compensation	4,178	'	4,178	'
Unit-based compensation (in units)	'	'	87	'
Options exercised	950	'	950	'
Options exercised (in units)	'	'	50	'
Net income (loss)	-168,815	'	-168,815	'
Balance at Dec. 31, 2012	797,464	0	794,426	3,038
Balance (in units) at Dec. 31, 2012	'	0	58,706	420
Increase (Decrease) in Members' Equity [Roll Forward]	'	'	'	'
Issuance of Common units for the acquisition of oil and natural gas properties	29,992	'	29,992	'
Issuance of Common units for the acquisition of oil and natural gas properties (in units)	'	'	1,075	'
Distributions to Preferred unitholders	-1,392	'	-1,392	'
Distributions to Common and Class B unitholders	-132,870	'	-132,097	-773
Issuance of units, net of offering costs	'	60,635	477,279	'
Issuance of units, net of offering costs (in units)	'	2,520	17,628	'
Common units received in exchange for Appalachian Basin properties (in units)	-1,900	'	'	'
Unit-based compensation	5,264	'	5,264	'
Unit-based compensation (in units)	'	'	89	'
Net income (loss)	57,399	'	57,399	'
Balance at Sep. 30, 2013	$1,293,771	$60,635	$1,230,871	$2,265
Balance (in units) at Sep. 30, 2013	'	2,520	77,498	420

CONSOLIDATED_STATEMENTS_OF_MEM1

CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY (Unaudited) (Parenthetical) (USD $)	9 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Common Units	'	'
Issuance of common units, offering costs	$325	$1,109
Preferred units	'	'
Issuance of common units, offering costs	$380	'

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Operating activities	'	'
Net income	$57,399	$32,696
Adjustments to reconcile net income to net cash provided by operating activities:	'	'
Depreciation, depletion, amortization and accretion	123,354	73,897
Impairment of Oil and Gas Properties	0	18,029
Amortization of deferred financing costs	2,811	2,086
Amortization of debt discount	184	113
Deferred taxes	-563	-139
Compensation related items	4,445	3,258
Amortization of premiums paid on derivative contracts	165	10,516
Amortization of value on derivative contracts acquired	22,872	14,096
Unrealized gains on commodity and interest rate derivative contracts, net	-17,075	-3,736
Gain on acquisition of oil and natural gas properties, net	-5,591	-13,796
Changes in operating assets and liabilities:	'	'
Trade accounts receivable	-27,006	-985
Payables to affiliates	131	-1,362
Other current assets	-1,093	388
Price risk management activities, net	-147	-8,176
Accounts payable and oil and natural gas revenue payable	12,328	8,741
Accrued expenses and other current liabilities	26,488	23,113
Other assets	431	422
Net cash provided by operating activities	199,133	159,161
Investing activities	'	'
Additions to property and equipment	-1,735	-392
Additions to oil and natural gas properties	-42,192	-40,285
Acquisitions of oil and natural gas properties and derivative contracts	-270,097	-452,114
Deposits and prepayments of oil and natural gas properties	-5,262	-4,761
Proceeds from the sale of oil and natural gas properties	0	5,522
Net cash used in investing activities	-319,286	-492,030
Financing activities	'	'
Proceeds from long-term debt	435,500	896,459
Repayment of long-term debt	-725,500	-750,000
Proceeds from preferred unit offerings, net	60,635	0
Proceeds from issuance of common units, net	477,279	322,021
Distributions to Preferred unitholders	-1,185	0
Distributions to Common and Class B unitholders	-128,657	-104,508
Financing fees	-2,056	-10,484
Proceeds from Stock Options Exercised	0	950
Net cash provided by financing activities	116,016	354,438
Net increase (decrease) in cash and cash equivalents	-4,137	21,569
Cash and cash equivalents, beginning of period	11,563	2,851
Cash and cash equivalents, end of period	7,426	24,420
Supplemental cash flow information:	'	'
Cash paid for interest	32,344	11,480
Non-cash financing and investing activities:	'	'
Asset retirement obligations	9,138	8,797
Common units issued for the acquisition of oil and gas properties	29,992	0
Common units received in exchange for Appalachian Basin properties	$0	$52,478

Description_of_the_Business

Description of the Business	9 Months Ended
	Sep. 30, 2013
Accounting Policies [Abstract]	'
Description of Business	'
	Description of the Business:
	We are a publicly traded limited liability company focused on the acquisition and development of mature, long-lived oil and natural gas properties in the United States. Our primary business objective is to generate stable cash flows allowing us to make monthly cash distributions to our unitholders and, over time, increase our monthly cash distributions through the acquisition of additional mature, long-lived oil and natural gas properties. Through our operating subsidiaries, we own properties and oil and natural gas reserves primarily located in nine operating areas:
	•	the Arkoma Basin in Arkansas and Oklahoma;
	•	the Permian Basin in West Texas and New Mexico;
	•	the Big Horn Basin in Wyoming and Montana;
	•	the Piceance Basin in Colorado;
	•	South Texas;
	•	the Williston Basin in North Dakota and Montana;
	•	the Wind River Basin in Wyoming;
	•	the Powder River Basin in Wyoming; and
	•	Mississippi.
	We were formed in October 2006 and completed our initial public offering in October 2007. Our common units are listed on the NASDAQ Global Select Market (“NASDAQ”) under the symbol "VNR."

Summary_of_Significant_Account

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Summary of Significant Accounting Policies	'
	Summary of Significant Accounting Policies
	The accompanying consolidated financial statements are unaudited and were prepared from our records. We derived the Consolidated Balance Sheet as of December 31, 2012, from the audited financial statements contained in our 2012 Annual Report.  Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by generally accepted accounting principles in the United States (“GAAP”). You should read this Quarterly Report on Form 10-Q along with our 2012 Annual Report, which contains a summary of our significant accounting policies and other disclosures. In our opinion, we have made all adjustments which are of a normal, recurring nature to fairly present our interim period results. Information for interim periods may not be indicative of our operating results for the entire year.
	As of September 30, 2013, our significant accounting policies are consistent with those discussed in Note 1 of our consolidated financial statements contained in our 2012 Annual Report.
	(a)	Basis of Presentation and Principles of Consolidation:
	The consolidated financial statements as of September 30, 2013 and December 31, 2012 and for the three and nine months ended September 30, 2013 and 2012 include our accounts and those of our subsidiaries.  We present our financial statements in accordance with GAAP.  All intercompany transactions and balances have been eliminated upon consolidation.
	(b)	Oil and Natural Gas Properties:
	The full cost method of accounting is used to account for oil and natural gas properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil, natural gas and NGLs reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and subject to ceiling test limitations as discussed below.
	Capitalized costs associated with proved reserves are amortized over the life of the reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated, which occurs on a quarterly basis. Specifically, costs are transferred to the amortizable base when properties are determined to have proved reserves. In addition, we transfer unproved property costs to the amortizable base when unproved properties are evaluated as being impaired and as exploratory wells are determined to be unsuccessful. Additionally, the amortizable base includes estimated future development costs, dismantlement, restoration and abandonment costs net of estimated salvage values.
	Capitalized costs are limited to a ceiling based on the present value of future net revenues, computed using the 12-month unweighted average of first-day-of-the-month historical price (the “12-month average price”), discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is less than the total capitalized costs, we are required to write-down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write-downs are included in the Consolidated Statements of Operations as an impairment charge. No ceiling test impairment was required during the nine months ended September 30, 2013. We recorded a non-cash ceiling test impairment of oil and natural gas properties for the quarter ended September 30, 2012 of $18.0 million. The impairment was a result of a decline in natural gas prices at the measurement date, September 30, 2012. This impairment was calculated using the 12-month average price of $2.77 per MMBtu for natural gas and $95.26 per barrel of crude oil.
	When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties.
	(c)	Use of Estimates:
	The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related cash flow estimates used in impairment tests of oil and natural gas properties and goodwill, the acquisition of oil and natural gas properties, the fair value of derivative contracts and asset retirement obligations, accrued oil, natural gas and NGLs revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ from those estimates.

Acquisitions

Acquisitions	9 Months Ended
	Sep. 30, 2013
Business Combinations [Abstract]	'
Acquisitions	'
	Acquisitions
	Our acquisitions are accounted for under the acquisition method of accounting in accordance with ASC Topic 805, “Business Combinations” (“ASC Topic 805”). An acquisition may result in the recognition of a gain or goodwill based on the measurement of the fair value of the assets acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. Any such gain or any loss resulting from the impairment of goodwill is recognized in current period earnings and classified in other income and expense in the accompanying Consolidated Statements of Operations. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of the properties acquired in our acquisitions have been included in the consolidated financial statements since the closing dates of the acquisitions.
	During the nine months ended September 30, 2013, we completed certain acquisitions of oil and natural gas properties located in our various operating regions. The total consideration transferred for the purchase of these properties amounted to $297.3 million, in the aggregate, including cash consideration of $267.3 million and $30.0 million paid in common equity by issuing 1,075,000 VNR common units, at an agreed price of $27.65 per common unit, valued at the closing price of $27.90 at the closing date of the acquisition. During the three months ended September 30, 2013, we completed an acquisition that resulted in goodwill of $0.2 million, which was immediately impaired and recorded as a loss. During the nine months ended September 30, 2013, our acquisitions resulted in a gain of $7.3 million and in goodwill of $1.7 million, which was immediately impaired and recorded as a loss, resulting in a net gain of $5.6 million for the period.
	On December 31, 2012, we completed the acquisition of natural gas and liquids properties in the Piceance Basin in Colorado and Powder River and Wind River Basins in Wyoming, with an effective date of October 1, 2012. We completed this acquisition for an adjusted purchase price of $324.7 million. We refer to this acquisition as the "Rockies Acquisition."
	On June 29, 2012, we completed the acquisition of natural gas and liquids properties in the Woodford Shale in Oklahoma and Fayetteville Shale in Arkansas of the Arkoma Basin, with an effective date of April 1, 2012. Additionally, upon closing of this acquisition, we assumed natural gas swaps. We completed this acquisition for an adjusted purchase price of $428.5 million. We refer to this acquisition as the "Arkoma Basin Acquisition."
	During 2012, we completed other smaller acquisitions of oil and natural gas properties located in various operating regions. We paid, in the aggregate, approximately $24.8 million in total consideration for these properties.
	During the nine months ended September 30, 2012, our acquisitions resulted in a gain of $14.1 million and in goodwill of $0.3 million, which was immediately impaired and recorded as a loss, resulting in a net gain of $13.8 million for the period. For a complete description of our 2012 acquisitions, please refer to footnote 2 of our consolidated financial statements contained in our 2012 Annual Report.
	In accordance with ASC Topic 805, presented below are unaudited pro forma results for the three and nine months ended September 30, 2013 and 2012 to show the effect on our consolidated results of operations as if our acquisitions completed in 2013 had occurred on January 1, 2012, and as if the Arkoma Basin Acquisition, the Rockies Acquisition and our other smaller acquisitions completed during 2012 had occurred on January 1, 2011.
	The pro forma results reflect the results of combining our statement of operations with the results of operations from the oil and natural gas properties acquired during 2013 and 2012, adjusted for (1) the assumption of asset retirement obligations and accretion expense for the properties acquired, (2) depletion expense applied to the adjusted basis of the properties acquired, (3) interest expense on additional borrowings necessary to finance the acquisitions, and (4) interest expense on the Senior Notes (defined in Note 3. Long-Term Debt), including the amortization of discount on bonds payable. The impact of the issuance of 1,075,000 VNR common units as consideration for one of our 2013 acquisitions is also reflected in the pro forma results. As discussed in Note 3 of our consolidated financial statements, we used a portion of the net proceeds from the Senior Notes offering to repay all indebtedness outstanding under a second lien term loan and applied the balance of the net proceeds to outstanding borrowings under our Reserve-Based Credit Facility. The repayment therefore resulted in an increase in the amount available for borrowing under our Reserve-Based Credit Facility. The pro forma results assume that the increase in borrowing capacity provided us available funding for the Arkoma Basin Acquisition. The unaudited pro forma results also reflect the impact of the Unit Exchange, including the elimination of the results of operations from the properties we previously owned in the Appalachian Basin and the receipt of the 1.9 million common units received as consideration for the exchange, as if it had occurred on January 1, 2011. The net gain and loss on acquisitions of oil and natural gas properties was excluded from the pro forma results for the three and nine months ended September 30, 2013 and 2012. The pro forma information is based upon these assumptions and is not necessarily indicative of future results of operations:
		Pro forma
		(in thousands, except per unit data)
		Three Months Ended September 30,						Nine Months Ended September 30,
		2013			2012			2013		2012
	Total revenues	$	103,796		$	65,635		$	362,510	$	407,845
	Net income (loss)	$	2,117		$	(68,987	)	$	52,972	$	31,670
	Net income (loss) per unit:
	Common & Class B units – basic and diluted	$	0.03		$	(1.27	)	$	0.73	$	0.6
	The amount of revenues and excess of revenues over direct operating expenses that were eliminated to reflect the impact of the Unit Exchange in the pro forma results for the nine months ended September 30, 2012 presented above are as follows:
		(in thousands)
	Revenues	$	3,267
	Excess of revenues over direct operating expenses	$	(400	)
	The amount of revenues and excess of revenues over direct operating expenses included in the accompanying Consolidated Statements of Operations for all of our acquisitions are shown in the table that follows. Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes.
		Three Months Ended September 30,						Nine Months Ended September 30,
		2013			2012			2013		2012
		(in thousands)
	Arkoma Basin Acquisition
	Revenues	$	14,473		$	12,048		$	42,754	$	12,048
	Excess of revenues over direct operating expenses	$	11,894		$	9,953		$	35,186	$	9,953
	Rockies Acquisition
	Revenues	$	14,820		$	—		$	47,231	$	—
	Excess of revenues over direct operating expenses	$	8,827		$	—		$	31,215	$	—
	All other acquisitions
	Revenues	$	15,903		$	551		$	32,288	$	1,047
	Excess of revenues over direct operating expenses	$	11,285		$	400		$	21,983	$	782

LongTerm_Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2013
Debt Disclosure [Abstract]	'
Debt	'
	Long-Term Debt
	Our financing arrangements consisted of the following as of the date indicated:
							Amount Outstanding
	Description		Interest Rate		Maturity Date		September 30, 2013				December 31, 2012
							(in thousands)
	Senior Secured Reserve-Based		Variable (1)		April 16, 2018		$	410,000			$	700,000
	Credit Facility
	Senior Notes		7.875% (2)		April 1, 2020		550,000				550,000
							$	960,000			$	1,250,000
	Unamortized discount on Senior Notes						(2,185		)		(2,369		)
	Total long-term debt						$	957,815			$	1,247,631
	-1	Variable interest rate was 1.93% and 2.22% at September 30, 2013 and December 31, 2012, respectively.
	-2	Effective interest rate was 8.0%.
	Senior Secured Reserve-Based Credit Facility
	The Company's Third Amended and Restated Credit Agreement (the “Credit Agreement”) provides a maximum credit facility of $1.5 billion and an initial borrowing base of $1.3 billion (the “Reserve-Based Credit Facility”). As of September 30, 2013, there were $410.0 million of outstanding borrowings and $888.3 million of borrowing capacity under the Reserve-Based Credit Facility, after consideration of a $1.7 million reduction in availability for letters of credit (discussed below).
	On April 17, 2013, we entered into the Fourth Amendment to the Credit Agreement, which provided for, among others, (a) the extension of the maturity date to April 16, 2018, (b) the increase of our borrowing base from $1.2 billion to $1.3 billion and (c) increased hedging flexibility. However, under the amended Credit Agreement, we are only committed to and paying for a borrowing utilization of $1.2 billion, but we have the flexibility to request the additional $100.0 million of availability if needed in the future.
	Interest rates under the Reserve-Based Credit Facility are based on Euro-Dollars (LIBOR) or ABR (Prime) indications, plus a margin. Interest is generally payable quarterly for ABR loans and at the applicable maturity date for LIBOR loans. At September 30, 2013, the applicable margin and other fees increase as the utilization of the borrowing base increases as follows:
	Borrowing Base Utilization Grid
	Borrowing Base Utilization Percentage		<25%			>25% <50%			>50% <75%			>75% <90%		>90%
	Eurodollar Loans Margin		1.5	%		1.75	%		2	%		2.25	%	2.5	%
	ABR Loans Margin		0.5	%		0.75	%		1	%		1.25	%	1.5	%
	Commitment Fee Rate		0.5	%		0.5	%		0.375	%		0.375	%	0.375	%
	Letter of Credit Fee		0.5	%		0.75	%		1	%		1.25	%	1.5	%
	Our Reserve-Based Credit Facility contains a number of customary covenants that require us to maintain certain financial ratios, limit our ability to incur indebtedness, enter into commodity and interest rate derivatives, grant certain liens, make certain loans, acquisitions, capital expenditures and investments, merge or consolidate, or engage in certain asset dispositions, including a sale of all or substantially all of our assets. At September 30, 2013, we were in compliance with all of our debt covenants.
	Our Reserve-Based Credit Facility allows us to enter into commodity price hedge positions establishing certain minimum fixed prices for anticipated future production. See Note 4. Price and Interest Rate Risk Management Activities for further discussion.
	Letters of Credit
	At September 30, 2013, we have unused irrevocable standby letters of credit of approximately $1.7 million. The letters of credit have an initial term that ends on December 31, 2013 with subsequent twelve month term extensions automatically commencing each year thereafter. The letters are being maintained as security for performance on long-term transportation contracts. Borrowing availability for the letters of credit is provided under our Reserve-Based Credit Facility. The fair value of these letters of credit approximates contract values based on the nature of the fee arrangements with the issuing banks.
	Senior Notes
	On April 4, 2012, we completed a public offering of $350.0 million aggregate principal amount of 7.875% senior unsecured notes due 2020 (the “Senior Notes”), at a public offering price of 99.274%, resulting in aggregate net proceeds of $338.7 million, after deducting original issue and underwriting discounts of $10.4 million and offering costs of $0.9 million. The discount and financing fees will be amortized over the life of the Senior Notes. Such amortization is recorded in interest expense on the Consolidated Statements of Operations. We used a portion of the net proceeds from this offering to repay all remaining indebtedness outstanding under a second lien term loan and applied the balance of the net proceeds to repay outstanding borrowings under our Reserve-Based Credit Facility.
	On October 9, 2012, we completed a public offering of an additional $200.0 million aggregate principal amount of 7.875% senior unsecured notes due 2020 (the “Additional Senior Notes”). We received net proceeds of approximately $196.4 million from this offering, after deducting underwriting discounts of $3.5 million and offering costs of $0.1 million. The Additional Senior Notes have identical terms, other than the issue date, and constitute part of the same series as and are fungible with the Senior Notes. We used the net proceeds from this offering to repay indebtedness outstanding under our Reserve-Based Credit Facility.
	The issuers of the Senior Notes and Additional Senior Notes are VNR and our 100% owned finance subsidiary, VNRF. VNR has no independent assets or operations. Under the indenture governing the Senior Notes (the “Indenture”), all of our existing subsidiaries (other than VNRF), all of which are 100% owned, and certain of our future subsidiaries (the “Subsidiary Guarantors”) have unconditionally guaranteed, jointly and severally, on an unsecured basis, the Senior Notes, subject to certain customary release provisions, including: (i) upon the sale or other disposition of all or substantially all of the subsidiary's properties or assets; (ii) upon the sale or other disposition of our equity interests in the subsidiary; (iii) upon designation of the subsidiary as an unrestricted subsidiary in accordance with the terms of the Indenture; (iv) upon legal defeasance or covenant defeasance or the discharge of the Indenture; (v) upon the liquidation or dissolution of the subsidiary; (vi) upon the subsidiary ceasing to guarantee any other of our indebtedness and to be an obligor under any of our credit facilities; or (vii) upon such subsidiary dissolving or ceasing to exist after consolidating with, merging into or transferring all of its properties or assets to us.
	The Indenture also contains covenants that will limit our ability to (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) make distributions on, purchase or redeem our common units or purchase or redeem subordinated indebtedness; (iv) make investments; (v) restrict dividends, loans or other asset transfers from our restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of our properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; (viii) enter into transactions with affiliates; or (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the Senior Notes achieve an investment grade rating from each of Standard & Poor's Rating Services and Moody's Investors Services, Inc. and no default under the Indenture exists, many of the foregoing covenants will terminate. At September 30, 2013, based on the most restrictive covenants of the Indenture, the Company’s cash balance and the borrowings available under the Reserve-Based Credit Facility, $389.4 million of members’ equity is available for distributions to unitholders, while the remainder is restricted.
	Interest on the Senior Notes is payable on April 1 and October 1 of each year, beginning on October 1, 2012. We may redeem some or all of the Senior Notes at any time on or after April 1, 2016 at redemption prices of 103.93750% of the aggregate principal amount of the Senior Notes as of April 1, 2016, declining to 100% on April 1, 2018 and thereafter.  We may also redeem some or all of the Senior Notes at any time prior to April 1, 2016 at a redemption price equal to 100% of the aggregate principal amount of the Senior Notes thereof, plus a "make-whole" premium. In addition, before April 1, 2015, we may redeem up to 35% of the aggregate principal amount of the Senior Notes at a redemption price equal to 107.875% of the aggregate principal amount of the Senior Notes thereof, with the proceeds of certain equity offerings, provided that 65% of the aggregate principal amount of the Senior Notes remain outstanding immediately after any such redemption and the redemption occurs within 180 days of such equity offering. If we sell certain of our assets or experience certain changes of control, we may be required to repurchase all or a portion of the Senior Notes at a price equal to 100% and 101% of the aggregate principal amount of the Senior Notes, respectively.

Price_and_Interest_Rate_Risk_M

Price and Interest Rate Risk Management Activities	9 Months Ended
	Sep. 30, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Price and Interest Rate Risk Management Activities	'
	Price and Interest Rate Risk Management Activities
	We have entered into derivative contracts with counterparties that are lenders under our Reserve-Based Credit Facility to hedge price risk associated with a portion of our oil, natural gas and NGLs production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated which has, and could, result in overhedged volumes. Pricing for these derivative contracts are based on certain market indexes and prices at our primary sales points. During the first nine months of 2013, our derivative transactions included the following:
	•	Fixed-price swaps - where we will receive a fixed-price for our production and pay a variable market price to the contract counterparty.
	•	Basis swap contracts - which guarantee a price differential between the NYMEX prices and our physical pricing points. We receive a payment from the counterparty or make a payment to the counterparty for the difference between the settled price differential and amounts stated under the terms of the contract.
	•	Collars - where we pay the counterparty if the market price is above the ceiling price (short call) and the counterparty pays us if the market price is below the floor (long put) on a notional quantity.
	•	Three-way collar contracts - which combine a long put, a short put and a short call. The use of the long put combined with the short put allows us to sell a call at a higher price thus establishing a higher ceiling and limiting our exposure to future settlement payments while also restricting our downside risk to the difference between the long put and the short put if the price drops below the price of the short put. This allows us to settle for market plus the spread between the short put and the long put in a case where the market price has fallen below the short put fixed price.
	•	Swaption agreements - where we provide options to counterparties to extend swap contracts into subsequent years.
	•	Call options sold - a structure that may be combined with an existing swap to raise the strike price, putting us in either a higher asset position, or a lower liability position. In general, selling a call option is used to enhance an existing position or a position that we intend to enter into simultaneously.
	•	Put spread options - created when we purchase a long put and sell a short put simultaneously.
	•	Put options sold - a structure that may be combined with an existing swap to raise the strike price, putting us in either a higher asset position or a lower liability position. In general, selling a put option is used to enhance an existing position or a position that we intend to enter into simultaneously.
	•	Range bonus accumulators - a structure that allows us to receive a cash payment when the daily average settlement price remains within a predefined range on each expiry date. Depending on the terms of the contract, if the settlement price is below the floor or above the ceiling on any expiry date, we may have to sell at that level. Range bonus accumulators are used to enhance an existing position or a position that we intend to enter into simultaneously.
	We also enter into fixed LIBOR interest rate swap agreements with certain counterparties that are lenders under our Reserve-Based Credit Facility, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates.
	Any premiums paid on derivative contracts and the fair value of derivative contracts acquired in connection with our acquisitions are capitalized as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid or the contracts are assumed. Premium payments are reflected in cash flows from operating activities in our Consolidated Statements of Cash Flows. When the consideration for an acquisition is cash, the fair value of any derivative contracts acquired in the acquisition is reflected in cash flows from investing activities. Over time, as the derivative contracts settle, the differences between the cash received and the premiums paid or amortization of fair value of contracts acquired are recognized as a realized gain or loss on commodity or interest rate derivate contracts, and the cash received or paid is reflected in cash flows from operating activities in our Consolidated Statements of Cash Flows.
	Under ASC Topic 815 “Derivatives and Hedging” (“ASC Topic 815”), all derivative instruments are recorded on the Consolidated Balance Sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date.  We have elected not to designate our current portfolio of derivative contracts as hedges.  Therefore, changes in fair value of these derivative instruments are recognized in earnings and included as unrealized gains (losses) on commodity derivative contracts or gains (losses) on interest rate derivative contracts in the accompanying Consolidated Statements of Operations. We net derivative assets and liabilities for counterparties where we have a legal right of offset.
	As of September 30, 2013, we had open commodity derivative contracts covering our anticipated future production as follows:
	Fixed-Price Swaps
			Gas							Oil							NGLs
	Contract Period		MMBtu			Weighted Average				Bbls			Weighted Average				Bbls	Weighted Average
						Fixed Price							WTI Price					Fixed Price
	October 1, 2013 – December 31, 2013		12,024,400			$	4.63			538,200			$	90.47			46,001	$	40.3
	January 1, 2014 – December 31, 2014		39,750,225			$	4.55			1,669,875			$	90.07			273,750	$	40.87
	January 1, 2015 – December 31, 2015		38,507,500			$	4.58			619,000			$	91.26			91,250	$	42
	January 1, 2016 – December 31, 2016		34,953,000			$	4.67			73,200			$	92.25			—	$	—
	January 1, 2017 – December 31, 2017		7,602,000			$	4.75			—			$	—			—	$	—
	Swaptions and Call Options Sold
	Calls were sold or options were provided to counterparties under swaption agreements to extend the swap into subsequent years as follows:
			Gas							Oil
	Contract Period		MMBtu			Weighted Average				Bbls			Weighted Average
						Fixed Price							Fixed Price
	October 1, 2013 – December 31, 2013		—			$	—			46,000			$	99.5
	January 1, 2014 – December 31, 2014		1,642,500			$	5.69			492,750			$	117.22
	January 1, 2015 – December 31, 2015		—			$	—			508,445			$	105.98
	January 1, 2016 – December 31, 2016		—			$	—			622,200			$	125
	Basis Swaps
			Gas
	Contract Period		MMBtu			Weighted Avg. Basis				Pricing Index
						Differential
	October 1, 2013 – December 31, 2013		230,000			$	(0.32	)		Rocky Mountain CIG and NYMEX Henry Hub Basis Differential
	January 1, 2014 – December 31, 2014		452,500			$	(0.32	)		Rocky Mountain CIG and NYMEX Henry Hub Basis Differential
			Oil
	Contract Period		Bbls			Weighted Avg. Basis				Pricing Index
						Differential ($/Bbl)
	October 1, 2013 – December 31, 2013		147,200			$	(0.84	)		WTI Midland and WTI Cushing Basis Differential
			82,800			$	(1.05	)		West Texas Sour and WTI Cushing Basis Differential
			21,000			$	9.6			Light Louisiana Sweet Crude and WTI Basis Differential
	January 1, 2014 – December 31, 2014		584,000			$	(0.84	)		WTI Midland and WTI Cushing Basis Differential
			328,500			$	(1.05	)		West Texas Sour and WTI Cushing Basis Differential
			182,500			$	(3.95	)		Light Louisiana Sweet Crude and Brent Basis Differential
	January 1, 2015 – December 31, 2015		365,000			$	(0.90	)		WTI Midland and WTI Cushing Basis Differential
	Collars
			Oil
	Contract Period		Bbls			Floor				Ceiling
	October 1, 2013 – December 31, 2013		20,700			$	88.89			$	102.36
	January 1, 2014 – December 31, 2014		12,000			$	100			$	116.2
	Three-Way Collars
			Oil
	Contract Period		Bbls			Floor				Ceiling				Put Sold
	October 1, 2013 – December 31, 2013		299,000			$	93.85			$	101.67			$	72.19
	January 1, 2014 – December 31, 2014		1,313,850			$	93.47			$	101.26			$	72.57
	January 1, 2015 – December 31, 2015		924,055			$	92.1			$	101.55			$	72.04
	January 1, 2016 – December 31, 2016		549,000			$	90			$	95			$	70
	Put Options Sold
			Oil
Contract Period		Bbls			Put Sold ($/Bbl)
October 1, 2013 – December 31, 2013		202,400			$	65.34
January 1, 2015 – December 31, 2015		619,000			$	72.05
January 1, 2016 – December 31, 2016		73,200			$	75
Put Spread Options
		Oil
Contract Period		Bbls			Floor				Put Sold
January 1, 2015 – December 31, 2015		255,500			$	100			$	75
Range Bonus Accumulators
		Oil
Contract Period		Bbls			Bonus				Range Ceiling				Range Floor
October 1, 2013 – December 31, 2013		184,000			$	3.88			$	104.15			$	72.63
January 1, 2014 – December 31, 2014		912,500			$	4.94			$	103.2			$	70.5
Interest Rate Swaps
As of September 30, 2013, we had open interest rate derivative contracts as follows (in thousands):
Period		Notional Amount				Fixed Libor Rates
October 1, 2013 to December 10, 2016		$	20,000			2.17	%
October 1, 2013 to October 31, 2016		$	40,000			1.65	%
October 1, 2013 to August 5, 2015 (1)		$	30,000			2.25	%
October 1, 2013 to August 6, 2016		$	25,000			1.8	%
October 1, 2013 to October 31, 2016		$	20,000			1.78	%
October 1, 2013 to September 23, 2016		$	75,000			1.15	%
October 1, 2013 to March 7, 2016		$	75,000			1.08	%
October 1, 2013 to September 7, 2016		$	25,000			1.25	%
October 1, 2013 to December 10, 2015 (2)		$	50,000			0.21	%
Total		$	360,000
-1	The counterparty has the option to extend the termination date of this contract at 2.25% to August 5, 2018.
-2	The counterparty has the option to require Vanguard to pay a fixed rate of 0.91% from December 10, 2015 to December 10, 2017.
Balance Sheet Presentation
Our commodity derivatives and interest rate swap derivatives are presented on a net basis in “derivative assets” and “derivative liabilities” on the Consolidated Balance Sheets. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets for the periods indicated (in thousands):
		September 30, 2013
Offsetting Derivative Assets:		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts		$	127,221			$	(33,795	)		$	93,426
Interest rate derivative contracts		156				—				156
Total derivative instruments		$	127,377			$	(33,795	)		$	93,582
Offsetting Derivative Liabilities:		Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts		$	(43,347	)		$	33,795			$	(9,552	)
Interest rate derivative contracts		(7,423		)		—				(7,423		)
Total derivative instruments		$	(50,770	)		$	33,795			$	(16,975	)
		December 31, 2012
Offsetting Derivative Assets:		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts		$	134,905			$	(35,001	)		$	99,904
Interest rate derivative contracts		132				(106		)		26
Total derivative instruments		$	135,037			$	(35,107	)		$	99,930
Offsetting Derivative Liabilities:		Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts		$	(41,775	)		$	35,001			$	(6,774	)
Interest rate derivative contracts		(10,694		)		106				(10,588		)
Total derivative instruments		$	(52,469	)		$	35,107			$	(17,362	)
By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. Our counterparties are participants in our Reserve-Based Credit Facility (See Note 3. Long-Term Debt for further discussion), which is secured by our oil and natural gas properties; therefore, we are not required to post any collateral. The maximum amount of loss due to credit risk that we would incur if our counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $127.4 million at September 30, 2013.
We minimize the credit risk in derivative instruments by: (i) entering into derivative instruments only with counterparties that are also lenders in our Reserve-Based Credit Facility and (ii) monitoring the creditworthiness of our counterparties on an ongoing basis. In accordance with our standard practice, our commodity and interest rate swap derivatives are subject to counterparty netting under agreements governing such derivatives, and therefore the risk of such loss is partially mitigated as of September 30, 2013.
Gain (Loss) on Derivative Contracts
Gains and losses on derivative contracts are reported on the accompanying Consolidated Statements of Operations in “realized or unrealized gain (loss) on commodity derivative contracts” and “realized or unrealized gain (loss) on interest rate derivative contracts.” Realized gains (losses) represent amounts related to the settlement of derivative instruments, offset by the amortization of premiums paid and the amortization of the value on derivative contracts acquired. Unrealized gains (losses) represent the change in fair value of the derivative instruments to be settled in the future and are non-cash items which fluctuate in value as commodity prices and interest rates change. The following presents our reported gains and losses on derivative instruments (in thousands):
		Three Months Ended September 30,								Nine Months Ended September 30,
		2013				2012				2013				2012
Realized gains (losses):
Commodity derivatives		$	(5,359	)		$	318			$	(2,175	)		$	(756	)
Interest rate swaps		(987		)		(468		)		(2,896		)		(1,610		)
		$	(6,346	)		$	(150	)		$	(5,071	)		$	(2,366	)
Unrealized gains (losses):
Commodity derivatives		$	(12,355	)		$	(51,332	)		$	13,781			$	9,243
Interest rate swaps		(742		)		(2,463		)		3,294				(5,507		)
		$	(13,097	)		$	(53,795	)		$	17,075			$	3,736
Net gains (losses):
Commodity derivatives		$	(17,714	)		$	(51,014	)		$	11,606			$	8,487
Interest rate swaps		(1,729		)		(2,931		)		398				(7,117		)
		$	(19,443	)		$	(53,945	)		$	12,004			$	1,370

Fair_Value_Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements	'
	Fair Value Measurements
	We estimate the fair values of financial and non-financial assets and liabilities under ASC Topic 820 “Fair Value Measurements and Disclosures” (“ASC Topic 820”). ASC Topic 820 provides a framework for consistent measurement of fair value for those assets and liabilities already measured at fair value under other accounting pronouncements. Certain specific fair value measurements, such as those related to share-based compensation, are not included in the scope of ASC Topic 820. Primarily, ASC Topic 820 is applicable to assets and liabilities related to financial instruments, to some long-term investments and liabilities, to initial valuations of assets and liabilities acquired in a business combination, recognition of asset retirement obligations and to long-lived assets written down to fair value when they are impaired. It does not apply to oil and natural gas properties accounted for under the full cost method, which are subject to impairment based on SEC rules. ASC Topic 820 applies to assets and liabilities carried at fair value on the Consolidated Balance Sheets, as well as to supplemental information about the fair values of financial instruments not carried at fair value.
	We have applied the provisions of ASC Topic 820 to assets and liabilities measured at fair value on a recurring basis, which includes our commodity and interest rate derivatives contracts, and on a nonrecurring basis, which includes goodwill, acquisitions of oil and natural gas properties and other intangible assets. ASC Topic 820 provides a definition of fair value and a framework for measuring fair value, as well as expanding disclosures regarding fair value measurements. The framework requires fair value measurement techniques to include all significant assumptions that would be made by willing participants in a market transaction.
	ASC Topic 820 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. ASC Topic 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to the “levels” described below. The hierarchy is based on the reliability of the inputs used in estimating fair value and requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The framework for fair value measurement assumes that transparent “observable” (Level 1) inputs generally provide the most reliable evidence of fair value and should be used to measure fair value whenever available. The classification of a fair value measurement is determined based on the lowest level (with Level 3 as the lowest) of significant input to the fair value estimation process.
	The standard describes three levels of inputs that may be used to measure fair value:
	Level 1	Quoted prices for identical instruments in active markets.
	Level 2	Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets.
	Level 3	Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used.
	As required by ASC Topic 820, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
	The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
	Financing arrangements. The carrying amounts of our bank borrowings outstanding approximate fair value because our current borrowing rates do not materially differ from market rates for similar bank borrowings. We consider this fair value estimate as a Level 2 input. The carrying amounts of our Senior Notes approximate fair value because they approximate the amounts for which the Senior Notes traded in the secondary market at September 30, 2013. We consider this fair value estimate as a Level 1 input.
	Derivative instruments. Our commodity derivative instruments consist of fixed-price swaps, basis swaps, swaptions, call options sold, put spread options, put options sold, collars, three-way collars and range bonus accumulators. We account for our commodity derivatives and interest rate derivatives at fair value on a recurring basis. We estimate the fair values of the fixed-price swaps, basis-swaps and swaptions based on published forward commodity price curves for the underlying commodities as of the date of the estimate. We estimate the option value of the contract floors, ceilings, collars and three-way collars using an option pricing model which takes into account market volatility, market prices and contract parameters. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. In order to estimate the fair value of our interest rate swaps, we use a yield curve based on money market rates and interest rate swaps, extrapolate a forecast of future interest rates, estimate each future cash flow, derive discount factors to value the fixed and floating rate cash flows of each swap, and then discount to present value all known (fixed) and forecasted (floating) swap cash flows. We consider the fair value estimate for these derivative instruments as a Level 2 input. We estimate the value of the range bonus accumulators using an option pricing model for both Asian Range Digital options and Asian Put options that takes into account market volatility, market prices and contract parameters. Range bonus accumulators are complex in structure requiring sophisticated valuation methods and greater subjectivity. As such, range bonus accumulators valuation may include inputs and assumptions that are less observable or require greater estimation, thereby resulting in valuations with less certainty. We consider the fair value estimate for range bonus accumulators as a Level 3 input.
	Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Management validates the data provided by third parties by understanding the pricing models used, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to our commodity derivatives and interest rate derivatives.
	Financial assets and financial liabilities measured at fair value on a recurring basis are summarized below (in thousands):
			September 30, 2013
			Fair Value Measurements Using									Assets/Liabilities
			Level 1			Level 2			Level 3			at Fair value
	Assets:
	Commodity price derivative contracts		$	—		$	93,426		$	—		$	93,426
	Interest rate derivative contracts		—			156			—			156
	Total derivative instruments		$	—		$	93,582		$	—		$	93,582
	Liabilities:
	Commodity price derivative contracts		$	—		$	(8,716	)	$	(836	)	$	(9,552	)
	Interest rate derivative contracts		—			(7,423		)	—			(7,423		)
	Total derivative instruments		$	—		$	(16,139	)	$	(836	)	$	(16,975	)
			December 31, 2012
			Fair Value Measurements Using									Assets/Liabilities
			Level 1			Level 2			Level 3			at Fair value
	Assets:
	Commodity price derivative contracts		$	—		$	99,904		$	—		$	99,904
	Interest rate derivative contracts		—			26			—			26
	Total derivative instruments		$	—		$	99,930		$	—		$	99,930
	Liabilities:
	Commodity price derivative contracts		$	—		$	(6,276	)	$	(498	)	$	(6,774	)
	Interest rate derivative contracts		—			(10,588		)	—			(10,588		)
	Total derivative instruments		$	—		$	(16,864	)	$	(498	)	$	(17,362	)
	The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:
			Unobservable Inputs (Level 3)
			(in thousands)
	Unobservable inputs at January 1, 2013		$	(498	)
	Total losses		(1,122		)
	Settlements		784
	Unobservable inputs at September 30, 2013		$	(836	)
	Change in unrealized gains included in earnings related to derivatives		$	(338	)
	still held as of September 30, 2013
	During periods of market disruption, including periods of volatile oil and natural gas prices, there may be certain asset classes that were in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments, other than the range bonus accumulators, may fall to Level 3 and thus require more subjectivity and management judgment. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition.
	We apply the provisions of ASC Topic 350 “Intangibles-Goodwill and Other.” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is assessed for impairment annually on October 1 or whenever indicators of impairment exist. The goodwill test is performed at the reporting unit level, which represents our oil and natural gas operations in the United States. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. We utilize a market approach to determine the fair value of our reporting unit. Any sharp prolonged decreases in the prices of oil and natural gas or any significant negative reserve adjustments from the October 1, 2012 assessment could change our estimates of the fair value of our reporting unit and could result in an impairment charge.
	Our nonfinancial assets and liabilities that are initially measured at fair value are comprised primarily of assets acquired in business combinations and asset retirement costs and obligations.  These assets and liabilities are recorded at fair value when acquired/incurred but not re-measured at fair value in subsequent periods. We classify such initial measurements as Level 3 since certain significant unobservable inputs are utilized in their determination. A reconciliation of the beginning and ending balance of our asset retirement obligations is presented in Note 6, in accordance with ASC Topic 410-20 "Asset Retirement Obligations."  During the nine months ended September 30, 2013 and 2012, in connection with new wells drilled and wells acquired during the period, we incurred and recorded asset retirement obligations totaling $10.4 million and $9.2 million, respectively, at fair value. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount.  Inputs to the valuation include: (1) estimated plug and abandonment cost per well based on our experience; (2) estimated remaining life per well based on average reserve life per field; (3) our credit-adjusted risk-free interest rate ranging between 4.8% and 5.5%; and (4) the average inflation factor (2.5%). These inputs require significant judgments and estimates by the Company's management at the time of the valuation and are the most sensitive and subject to change.

Asset_Retirement_Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2013
Asset Retirement Obligation [Abstract]	'
Asset Retirement Obligations	'
	Asset Retirement Obligations
	The asset retirement obligations as of September 30, reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the nine months ended September 30, were as follows (in thousands):
		2013			2012
	Asset retirement obligations at January 1,	$	63,114		$	35,921
	Liabilities added during the current period	10,428			9,248
	Accretion expense	2,032			914
	Retirements	(348		)	(451		)
	Change in estimate	(942		)	—
	Total asset retirement obligation at September 30,	74,284			45,632
	Less: current obligations	(4,225		)	(2,269		)
	Long-term asset retirement obligation at September 30,	$	70,059		$	43,363

Related_Party_Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	Related Party Transactions
	We previously owned properties and oil and natural gas reserves in the southern portion of the Appalachian Basin, primarily in southeast Kentucky and northeast Tennessee (the “Appalachian Basin”). On February 21, 2012, we and our 100% owned subsidiary, VNG, entered into a Unit Exchange Agreement with Majeed S. Nami Personal Endowment Trust and Majeed S. Nami Irrevocable Trust (collectively, the “Nami Parties”) to transfer our partnership interest in Trust Energy Company, LLC and Ariana Energy, LLC, which entities controlled all of our ownership interests in oil and natural gas properties in the Appalachian Basin, in exchange for 1.9 million of our common units valued at the closing price of our common units of $27.62 per unit at March 30, 2012, or $52.5 million, with an effective date of January 1, 2012 (the “Unit Exchange”). The Nami Parties are controlled by or affiliated with Majeed S. Nami who was a founding unitholder when the Company went public in October of 2007. We completed this transaction on March 30, 2012 for non-cash consideration of $52.5 million, which was offset by post-closing adjustments of $1.4 million. This transaction was accounted for as a reduction to the full cost pool and no gain or loss was recognized because the assets transferred were not a significant portion of the full cost pool.
	Prior to the completion of the Unit Exchange, we relied on Vinland Energy Eastern, LLC (“Vinland”) to execute our drilling program, operate our wells and gather our natural gas in the Appalachian Basin. We reimbursed Vinland $60.00 per well per month (in addition to normal third party operating costs) for operating our oil and natural gas properties in the Appalachian Basin under a Management Services Agreement (“MSA”) which costs were reflected in our lease operating expenses. Under a Gathering and Compression Agreement (“GCA”), Vinland received a $0.25 per Mcf transportation fee on existing wells drilled prior to December 31, 2006 and $0.55 per Mcf transportation fee on any new wells drilled after December 31, 2006 within the area of mutual interest or “AMI.” In June 2010, we began discussions with Vinland regarding an amendment to the GCA to go into effect beginning on July 1, 2010. The amended agreement would provide gathering and compression services based upon actual costs plus a margin of $0.055 per mcf. We and Vinland agreed in principle to this change effective July 1, 2010 and jointly operated on this basis, however, no formal agreement between us and Vinland was signed. Under the GCA, the transportation fee that we paid to Vinland only encompassed transporting the natural gas to third party pipelines at which point additional transportation fees to natural gas markets applied. These transportation fees were outlined in the GCA and are reflected in our lease operating expenses. Costs incurred under the MSA and GCA were $0.6 million and $0.4 million, respectively, for the nine months ended September 30, 2012. As a result of the Unit Exchange, the MSA and GCA were terminated, and thus no costs were incurred under the MSA or GCA in 2013.

Commitments_and_Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	Commitments and Contingencies
	Transportation Demand Charges
	On December 31, 2012 and effective with the acquisition of properties from the Rockies Acquisition, we assumed contracts that provide firm transportation capacity on pipeline systems. The remaining terms on these contracts range from one to seven years and require us to pay transportation demand charges regardless of the amount of pipeline capacity we utilize.
	The values in the table below represent gross future minimum transportation demand charges we are obligated to pay as of September 30, 2013. However, our financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property.
		(in thousands)
	October 1, 2013 - December 31, 2013	$	1,526
	2014	6,214
	2015	5,256
	2016	4,797
	2017	4,146
	Thereafter	8,636
	Total	$	30,575
	Legal Proceedings
	We are defendants in legal proceedings arising in the normal course of our business.  While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management does not believe that it is probable that the outcome of these actions will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flow. We are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.
	We were a party to litigation related to the ENP Merger ("ENP Litigation") as discussed in Part II—Item 8—Financial Statements Supplementary Data in our 2012 Annual Report. On July 22, 2013, the ENP Litigation was dismissed. Please see Part II—Item 1—Legal Proceedings in this Quarterly Report for a detailed discussion on the developments of the ENP Litigation.

Preferred_Units_Common_Units_a

Preferred Units, Common Units and Net Income per Common Unit	9 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]	'
Preferred Units, Common Units and Net Income per Unit	'
	Preferred Units, Common Units and Net Income per Common and Class B Unit
	Basic net income per common and Class B unit is computed in accordance with ASC Topic 260 “Earnings Per Share” (“ASC Topic 260”) by dividing net income available to common and Class B unitholders by the weighted average number of units outstanding during the period. Diluted net income per common and Class B unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. We use the treasury stock method to determine the dilutive effect. As of September 30, 2013, we had three classes of units outstanding: (i) units representing limited liability company interests (“common units”) listed on the NASDAQ under the symbol VNR, (ii) Class B units, granted to executive officers and an employee and (iii) Series A Cumulative Redeemable Perpetual Preferred Units representing preferred equity company interests ("Series A Preferred Units") listed on the NASDAQ under the symbol VNRAP as discussed in Note 11. Shelf Registration Statements. The Class B units participate in distributions; therefore, all Class B units were considered in the computation of basic net income per unit. Series A Preferred Units have no participation rights and accordingly are excluded from the computation of basic net income per unit.
	For the three and nine months ended September 30, 2013, the 561,934 phantom units granted to officers, board members and employees from 2010 to date under the Vanguard Natural Resources, LLC Long-Term Incentive Plan (“VNR LTIP”) have been included in the computation of diluted income per common and Class B unit as 265,152 and 429,990 additional common units that would have been issued and outstanding under the treasury stock method assuming the phantom units had been exercised at the beginning of the respective periods. Of the 561,934 phantom units granted to date, 522,500 of them were granted to officers prior to September 30, 2012 and have been excluded in the computation of net income per common and Class B unit for the three and nine months ended September 30, 2012 as they had no dilutive effect. For the three months ended September 30, 2012, the 125,000 options previously granted to officers under the VNR LTIP have been excluded in the computation of earnings per unit as they had no dilutive effect. These options are included for the nine months ended September 30, 2012 as 53,189 additional common units that would have been issued and outstanding under the treasury stock method assuming the options had been exercised at the beginning of the period. All options were exercised by the officers during the third and fourth quarter of 2012.
	In accordance with ASC Topic 260, dual presentation of basic and diluted net income per common and Class B unit has been presented in the Consolidated Statements of Operations for the three and nine months ended September 30, 2013 and 2012 including each class of units issued and outstanding during the respective periods: common units and Class B units.  Net income available to common and Class B unitholders per unit is allocated to the common units and the Class B units on an equal basis.
	The Series A Preferred Units rank senior to our common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up. The Series A Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by us or converted into our common units, at our option, in connection with a change of control. At any time on or after June 15, 2023, we may redeem the Series A Preferred Units, in whole or in part, out of amounts legally available therefore, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. We may also redeem the Series A Preferred Units in the event of a change of control. Holders of Series A Preferred Units will have no voting rights except for limited voting rights if we fail to pay dividends for eighteen or more monthly periods (whether or not consecutive) and in certain other limited circumstances or as required by law.
	Distributions Declared
	Distributions on the Series A Preferred Units are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by our board of directors. We will pay cumulative distributions in cash on the Series A Preferred Units on a monthly basis at a monthly rate of $0.1641 per preferred unit, or 7.875% of the liquidation preference of $25.00 per preferred unit, per year. The initial prorated monthly distribution of $0.1422 on the Series A Preferred Units was paid on July 15, 2013. Subsequent to the initial distribution, monthly distributions were declared and paid to preferred unitholders at the monthly rate of $0.1641 per preferred unit. On October 21, 2013, our board of directors declared a cash distribution for the Series A Preferred Units. See Note 12. Subsequent Events for further discussion.
	The following table shows the distribution amount per common and Class B unit, declared date, record date and payment date of the cash distributions we paid on each of our common and Class B units for each period presented. Future distributions are at the discretion of our board of directors and will depend on business conditions, earnings, our cash requirements and other relevant factors.
	On August 2, 2012, we announced a change in the payment of our cash distributions on our common and Class B units from quarterly to monthly commencing with the July 2012 distribution. On October 21, 2013, our board of directors declared a cash distribution on the common and Class B units attributable to the month of September 2013. See Note 12. Subsequent Events for further discussion.
		Cash Distributions
	Distribution	Per Unit		Declared Date	Record Date	Payment Date
	2013
	Third Quarter
	August	$	0.2075	September 12, 2013	October 1, 2013	October 15, 2013
	July	$	0.2075	August 20, 2013	September 3, 2013	September 13, 2013
	Second Quarter
	June	$	0.205	July 18, 2013	August 1, 2013	August 14, 2013
	May	$	0.205	June 20, 2013	July 1, 2013	July 15, 2013
	April	$	0.205	April 30, 2013	June 3, 2013	June 14, 2013
	First Quarter
	March	$	0.2025	April 19, 2013	May 1, 2013	May 15, 2013
	February	$	0.2025	March 21, 2013	April 1, 2013	April 12, 2013
	January	$	0.2025	February 18, 2013	March 1, 2013	March 15, 2013
	2012
	Fourth Quarter
	December	$	0.2025	January 25, 2013	February 4, 2013	February 14, 2013
	November	$	0.2025	December 19, 2012	January 2, 2013	January 14, 2013
	October	$	0.2025	November 16, 2012	December 3, 2012	December 14, 2012
	Third Quarter
	September	$	0.2	October 18, 2012	November 1, 2012	November 14, 2012
	August	$	0.2	September 17, 2012	October 1, 2012	October 15, 2012
	July	$	0.2	August 20, 2012	September 4, 2012	September 14, 2012
	Second Quarter	$	0.6	July 23, 2012	August 7, 2012	August 14, 2012
	First Quarter	$	0.5925	April 24, 2012	May 8, 2012	May 15, 2012
	2011
	Fourth Quarter	$	0.5875	January 18, 2012	February 7, 2012	February 14, 2012

UnitBased_Compensation

Unit-Based Compensation	9 Months Ended
	Sep. 30, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Unit-Based Compensation	'
	Unit-Based Compensation
	Executive Employment Agreements
	In June and July 2013, we and VNRH entered into new amended and restated executive employment agreements (the "Amended Agreements") with each of our three executive officers, Messrs. Smith, Robert and Pence. The Amended Agreements were effective January 1, 2013 and the initial term of the Amended Agreements ends on January 1, 2016, with a subsequent twelve month term extension automatically commencing on January 1, 2016 and each successive January 1 thereafter, provided that neither VNRH nor the executives deliver a timely non-renewal notice prior to a term expiration date.
	The Amended Agreements provide for an annual base salary and eligibility to receive an annual performance-based cash bonus award. The annual bonus will be calculated based upon three Company performance components: absolute target distribution growth, adjusted EBITDA growth, and relative unit performance to peer group, as well as a fourth component determined solely in the discretion of our board of directors. Each of the four components will be weighted equally in calculating the respective executive officer's annual bonus. The annual bonus does not require a minimum payout, although the maximum payout may not exceed two (2) times the executive's respective annual base salary. As of September 30, 2013, an accrued liability was recognized and compensation expense of $1.3 million was recorded related to these arrangements, which was classified in the selling, general and administrative expenses line item in the Consolidated Statement of Operations.
	In the event of the Company's Change in Control, as defined in the VNR LTIP, the executives are entitled to certain change in control payments and benefits, consisting of: (i) an amount equal to two (2) times their then-current base salary and annual bonus and (ii) accelerated vesting of any outstanding restricted units, phantom units, or any other awards granted under the VNR LTIP held by the executives at the time of the change of control, with any settlement of these awards being made according to the terms of the VNR LTIP and the applicable individual award agreement.
	The executives are entitled to severance payments and benefits upon certain qualifying terminations. Upon a termination by VNRH without "Cause" (as such term is defined in the Amended Agreements) or termination by either executive for "Good Reason" (as such term is defined in the Amended Agreements), the executive is entitled to (i) an amount equal to three (3) times the executive's then-current base salary and (ii) accelerated vesting of any outstanding restricted units, phantom units, or any other awards granted under the VNR LTIP held by the executives at the time of such termination, with any settlement of these awards being made according to the terms of the VNR LTIP. Upon an executive's termination by "Disability" (as such term is defined in the Amended Agreements) or death, the executive is entitled to (a) an amount equal to one times the executive's then-current base salary and (b) accelerated vesting of any outstanding restricted units, phantom units, or any other awards granted under the VNR LTIP held by the executives at the time of such termination, with any settlement of these awards being made according to the terms of the VNR LTIP. As a condition to receiving any of the severance payments and benefits heretofore described, the terminated executive (or his legal representative, as applicable) must execute and not revoke a customary severance and release agreement, including a waiver of all claims.
	The Amended Agreements also provide that the executives are eligible to participate in the benefit programs generally available to senior executives of VNRH. The Amended Agreements also contain standard non-competition, non-solicitation and confidentiality provisions.
	Restricted and Phantom Units
	Under the Amended Agreements, the executives are also eligible to receive annual equity-based compensation awards, consisting of restricted units and/or phantom units granted under the VNR LTIP. Each of the executives are eligible to receive annual equity-based compensation awards having an aggregate fair market value equal to the executive's then-current annual base salary times a set multiplier, which such multiplier is five (5) times in the case of Mr. Smith, three and a half (3.5) times in the case of Mr. Robert, and two and three-quarters (2.75) times in the case of Mr. Pence.
	The restricted units are subject to a three-year vesting period. One-third of the aggregate number of the units vest on each one-year anniversary of the date of grant so long as the executive remains continuously employed with the Company. The restricted units include a tandem grant of distribution equivalent rights (“DERs”), which entitle the executives to receive the value of any dividends made by us on our units generally with respect to the number of restricted units that the executives received pursuant to the grant. In the event the executive is terminated without “Cause”, or the executive resigns for “Good Reason”, or the executive is terminated due to his death or Disability, all unvested outstanding restricted units shall receive accelerated vesting. If the executive is terminated for Cause, all unvested restricted units are forfeited. Upon the occurrence of a Change of Control, all unvested outstanding restricted units shall receive accelerated vesting.
	The phantom units are also subject to a three-year vesting period. One-third of the aggregate number of the units vest on each one-year anniversary of the date of grant so long as the executive remains continuously employed with the Company. The phantom units include a tandem grant of DERs, which entitle the executives to receive the value of any dividends made by the Company on its units generally with respect to the number of phantom units that the executives received pursuant to the grant. In the event the executive is terminated without Cause, or the executive resigns for Good Reason, or the executive is terminated due to his death or Disability, all unvested outstanding phantom units shall receive accelerated vesting. If the executive is terminated for Cause, all unvested restricted units are forfeited. Upon the occurrence of a Change of Control, all unvested outstanding restricted units shall receive accelerated vesting.
	The restricted units and the phantom units are subject to all the terms and conditions of the VNR LTIP as well as the individual award agreements which govern the awards. Neither the restricted units nor the phantom units are transferable, other than by will or the laws of descent and distribution. The Company shall withhold from the settlement or payment of the awards, as applicable, any amounts or units necessary to satisfy the Company's withholding obligations.
	On August 1, 2012, three of our executives were granted a total of 390,000 phantom units. These phantom unit grants were made under the VNR LTIP and are subject to vesting in five equal annual installments, with the first vesting date being May 18, 2013, and each subsequent vesting date occurring on each annual anniversary of the first vesting date. During the nine months ended September 30, 2013, our four independent board members were granted a total of 18,684 phantom units which will vest one year from the date of grant and VNR employees were granted a total of 68,504 phantom units. The phantom units are accompanied by dividend equivalent rights, which entitle the board members and VNR employees to receive the value of any distributions made by us on our units generally with respect to the number of phantom shares that the board members and the VNR employees received pursuant to these grants.
	As of September 30, 2013, an accrued liability of $1.1 million has been recorded related to phantom units granted to executive officers, board members and employees and non-cash unit-based compensation expense of $0.2 million and $0.60 million has been recognized in the selling, general and administrative expense line item in the Consolidated Statements of Operations for three months ended September 30, 2013 and 2012, respectively, and $1.9 million and $0.9 million for the nine months ended September 30, 2013 and 2012, respectively.
	Non-Vested Restricted Unit Grants
	Historically, we have granted restricted common units to employees as partial consideration for services to be performed and have accounted for these grants under ASC Topic 718, "Compensation-Stock Compensation." The fair value of restricted units issued is determined based on the fair market value of common units on the date of the grant.  This value is amortized over the vesting period as referenced above.  A summary of the status of the non-vested units as of September 30, 2013 is presented below:
		Number of		Weighted Average
		Non-vested  Restricted Units		Grant Date Fair Value
	Non-vested restricted units at December 31, 2012	289,813		$	27.97
	Forfeited	(6,507	)	$	29.07
	Vested	(112,645	)	$	27.35
	Non-vested restricted units at September 30, 2013	170,661		$	28.34
	At September 30, 2013, there was approximately $3.5 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately 1.8 years. Our Consolidated Statements of Operations reflect non-cash compensation of $0.9 million and $1.4 million in the Selling, general and administrative expenses line item for the three months ended September 30, 2013 and 2012, respectively, and $4.4 million and $3.3 million for the nine months ended September 30, 2013 and 2012, respectively.

Shelf_Registration_Statements

Shelf Registration Statements	9 Months Ended
	Sep. 30, 2013
Shelf Registration Statement [Abstract]	'
Shelf Registration Statement	'
	Shelf Registration Statements
	During the third quarter 2009, we filed a registration statement with the SEC which registered offerings of up to $300.0 million (the “2009 Shelf Registration Statement”) of any combination of debt securities, common units and guarantees of debt securities by our subsidiaries. The 2009 Shelf Registration Statement expired in August 2012. In July 2010, we filed a registration statement with the SEC which registered offerings of up to $800.0 million (the “2010 Shelf Registration Statement”) of any combination of debt securities, common units and guarantees of debt securities by our subsidiaries. The 2010 Shelf Registration Statement expired in July 2013.
	In January 2012, we filed a registration statement (the “2012 Shelf Registration Statement”) with the SEC, which registered offerings of approximately 3.1 million common units held by certain selling unitholders. By means of the same registration statement, we also registered an indeterminate amount of common units, debt securities and guarantees of debt securities, which may be offered by us. In the future, we may issue additional debt and equity securities pursuant to a prospectus supplement to the 2012 Shelf Registration Statement. On June 12, 2013, we filed a post-effective amendment to the 2012 Shelf Registration Statement with the SEC, which registered an indeterminate amount of Series A Cumulative Redeemable Perpetual Preferred Units representing preferred equity interests in the Company.
	Net proceeds, terms and pricing of each offering of securities issued under the 2012 Shelf Registration Statement are determined at the time of such offerings. The 2012 Shelf Registration Statement does not provide assurance that we will or could sell any such securities. Our ability to utilize the 2012 Shelf Registration Statement for the purpose of issuing, from time to time, any combination of debt securities, common units or preferred units will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us.
	In August 2010, we entered into an Equity Distribution Program Distribution Agreement (the “2010 Distribution Agreement”) relating to our common units having an aggregate offering price of up to $60.0 million. Sales made pursuant to the 2010 Distribution Agreement were made through a prospectus supplement to our 2009 Shelf Registration Statement. Total net proceeds received under the 2010 Distribution Agreement through the expiration of the 2009 Shelf Registration Statement in August 2012 were approximately $6.3 million, after commissions, from the sales of 240,111 common units.
	On September 9, 2011, we entered into an amended and restated Equity Distribution Program Distribution Agreement (the “2011 Distribution Agreement”) which extended, for an additional three years, the existing agreement with our sales agent to act as our exclusive distribution agent with respect to the issuance and sale of our common units up to an aggregate gross sales price of $200.0 million. Of the $200.0 million common units provided for under the 2011 Distribution Agreement, approximately $4.0 million of our common units were issued and sold under a prospectus supplement to our 2009 Shelf Registration Statement, which expired in August 2012. The remaining $196.0 million of the common units may be offered pursuant to a new prospectus supplement to the 2012 Shelf Registration Statement. Total net proceeds received under the 2011 Distribution Agreement during the nine months ended September 30, 2013, were approximately $31.5 million, after commissions, from the sales of 1,103,499 common units.
	Equity Offerings
	Common Units
	On February 5, 2013, we completed a public offering of 9,200,000 of our common units at a price of $27.85 per unit, which includes 1,200,000 common units purchased pursuant to the underwriters' over-allotment option. Offers were made pursuant to a prospectus supplement to the 2012 Shelf Registration Statement. We received proceeds of approximately $246.1 million from this offering, after deducting underwriting discounts of $10.0 million and offering costs of $0.1 million. We used the net proceeds from this offering to repay indebtedness outstanding under our Reserve-Based Credit Facility.
	On June 4, 2013, we completed a public offering of 7,000,000 of our common units at a price of $28.35 per unit. Offers were made pursuant to a prospectus supplement to the 2012 Shelf Registration Statement. We received proceeds of approximately $190.9 million from this offering, after deducting underwriting discounts of $7.4 million and offering costs of $0.1 million. In July 2013, we received proceeds of $8.9 million from the sale of an additional 325,000 of our common units at a price of $28.35 per unit that were purchased by the underwriters to cover over-allotments. We used the net proceeds from this offering to repay indebtedness outstanding under our Reserve-Based Credit Facility.
	Preferred Units
	On June 19, 2013, we completed a public offering of 2,520,000 7.875% Series A Preferred Units at a price of $25.00 per unit. The total of 2,520,000 Series A Preferred Units includes 320,000 Series A Preferred Units purchased pursuant to the underwriters' over-allotment option. Offers were made pursuant to a prospectus supplement to the 2012 Shelf Registration Statement. We received proceeds of approximately $60.6 million from this offering, after deducting discounts of $2.0 million and offering costs of $0.4 million. We used the net proceeds from this offering to repay indebtedness outstanding under our Reserve-Based Credit Facility.
	Subsidiary Guarantors
	We and VNR Finance Corp., our wholly-owned finance subsidiary, may co-issue securities pursuant to the registration statements discussed above. VNR has no independent assets or operations. Debt securities that we may offer may be guaranteed by our subsidiaries. We contemplate that if we offer debt securities, the guarantees will be full and unconditional and joint and several (subject to certain customary release provisions), and any subsidiaries of Vanguard that do not guarantee the securities will be minor.

Subsequent_Events

Subsequent Events	9 Months Ended
	Sep. 30, 2013
Subsequent Events [Abstract]	'
Subsequent Event	'
	Subsequent Events
	Distributions
	On October 21, 2013, our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of September 2013 of $0.2075 per common and Class B unit ($2.49 on an annualized basis) expected to be paid on November 14, 2013 to Vanguard unitholders of record on November 1, 2013.
	Also on October 21, 2013, our board of directors declared a cash distribution for our preferred unitholders of $0.1641 per preferred unit expected to be paid on November 15, 2013 to Vanguard preferred unitholders of record on November 8, 2013.
	On October 30, 2013, our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of October 2013 of $0.2075 per common unit ($2.49 on an annualized basis) expected to be paid on December 13, 2013 to Vanguard unitholders of record on December 2, 2013.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Basis of Presentation and Principles of Consolidation	'
	Basis of Presentation and Principles of Consolidation:
	The consolidated financial statements as of September 30, 2013 and December 31, 2012 and for the three and nine months ended September 30, 2013 and 2012 include our accounts and those of our subsidiaries.  We present our financial statements in accordance with GAAP.  All intercompany transactions and balances have been eliminated upon consolidation.
Oil and Natural Gas Properties	'
	Oil and Natural Gas Properties:
	The full cost method of accounting is used to account for oil and natural gas properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil, natural gas and NGLs reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and subject to ceiling test limitations as discussed below.
	Capitalized costs associated with proved reserves are amortized over the life of the reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated, which occurs on a quarterly basis. Specifically, costs are transferred to the amortizable base when properties are determined to have proved reserves. In addition, we transfer unproved property costs to the amortizable base when unproved properties are evaluated as being impaired and as exploratory wells are determined to be unsuccessful. Additionally, the amortizable base includes estimated future development costs, dismantlement, restoration and abandonment costs net of estimated salvage values.
	Capitalized costs are limited to a ceiling based on the present value of future net revenues, computed using the 12-month unweighted average of first-day-of-the-month historical price (the “12-month average price”), discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is less than the total capitalized costs, we are required to write-down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write-downs are included in the Consolidated Statements of Operations as an impairment charge. No ceiling test impairment was required during the nine months ended September 30, 2013. We recorded a non-cash ceiling test impairment of oil and natural gas properties for the quarter ended September 30, 2012 of $18.0 million. The impairment was a result of a decline in natural gas prices at the measurement date, September 30, 2012. This impairment was calculated using the 12-month average price of $2.77 per MMBtu for natural gas and $95.26 per barrel of crude oil.
	When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties.
Use of Estimates	'
	Use of Estimates:
	The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related cash flow estimates used in impairment tests of oil and natural gas properties and goodwill, the acquisition of oil and natural gas properties, the fair value of derivative contracts and asset retirement obligations, accrued oil, natural gas and NGLs revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ from those estimates.

Acquisitions_Tables

Acquisitions (Tables)	9 Months Ended
	Sep. 30, 2013
Business Combinations [Abstract]	'
Pro Forma Information	'
	The pro forma results reflect the results of combining our statement of operations with the results of operations from the oil and natural gas properties acquired during 2013 and 2012, adjusted for (1) the assumption of asset retirement obligations and accretion expense for the properties acquired, (2) depletion expense applied to the adjusted basis of the properties acquired, (3) interest expense on additional borrowings necessary to finance the acquisitions, and (4) interest expense on the Senior Notes (defined in Note 3. Long-Term Debt), including the amortization of discount on bonds payable. The impact of the issuance of 1,075,000 VNR common units as consideration for one of our 2013 acquisitions is also reflected in the pro forma results. As discussed in Note 3 of our consolidated financial statements, we used a portion of the net proceeds from the Senior Notes offering to repay all indebtedness outstanding under a second lien term loan and applied the balance of the net proceeds to outstanding borrowings under our Reserve-Based Credit Facility. The repayment therefore resulted in an increase in the amount available for borrowing under our Reserve-Based Credit Facility. The pro forma results assume that the increase in borrowing capacity provided us available funding for the Arkoma Basin Acquisition. The unaudited pro forma results also reflect the impact of the Unit Exchange, including the elimination of the results of operations from the properties we previously owned in the Appalachian Basin and the receipt of the 1.9 million common units received as consideration for the exchange, as if it had occurred on January 1, 2011. The net gain and loss on acquisitions of oil and natural gas properties was excluded from the pro forma results for the three and nine months ended September 30, 2013 and 2012. The pro forma information is based upon these assumptions and is not necessarily indicative of future results of operations:
		Pro forma
		(in thousands, except per unit data)
		Three Months Ended September 30,						Nine Months Ended September 30,
		2013			2012			2013		2012
	Total revenues	$	103,796		$	65,635		$	362,510	$	407,845
	Net income (loss)	$	2,117		$	(68,987	)	$	52,972	$	31,670
	Net income (loss) per unit:
	Common & Class B units – basic and diluted	$	0.03		$	(1.27	)	$	0.73	$	0.6
Impact of Unit Exchange in Pro Forma Results	'
	The amount of revenues and excess of revenues over direct operating expenses that were eliminated to reflect the impact of the Unit Exchange in the pro forma results for the nine months ended September 30, 2012 presented above are as follows:
		(in thousands)
	Revenues	$	3,267
	Excess of revenues over direct operating expenses	$	(400	)
Revenues and Excess of Revenues Over Direct Operating Expenses	'
	The amount of revenues and excess of revenues over direct operating expenses included in the accompanying Consolidated Statements of Operations for all of our acquisitions are shown in the table that follows. Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes.
		Three Months Ended September 30,						Nine Months Ended September 30,
		2013			2012			2013		2012
		(in thousands)
	Arkoma Basin Acquisition
	Revenues	$	14,473		$	12,048		$	42,754	$	12,048
	Excess of revenues over direct operating expenses	$	11,894		$	9,953		$	35,186	$	9,953
	Rockies Acquisition
	Revenues	$	14,820		$	—		$	47,231	$	—
	Excess of revenues over direct operating expenses	$	8,827		$	—		$	31,215	$	—
	All other acquisitions
	Revenues	$	15,903		$	551		$	32,288	$	1,047
	Excess of revenues over direct operating expenses	$	11,285		$	400		$	21,983	$	782

LongTerm_Debt_Tables

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2013
Debt Disclosure [Abstract]	'
Financing Arrangements	'
	Our financing arrangements consisted of the following as of the date indicated:
							Amount Outstanding
	Description		Interest Rate		Maturity Date		September 30, 2013				December 31, 2012
							(in thousands)
	Senior Secured Reserve-Based		Variable (1)		April 16, 2018		$	410,000			$	700,000
	Credit Facility
	Senior Notes		7.875% (2)		April 1, 2020		550,000				550,000
							$	960,000			$	1,250,000
	Unamortized discount on Senior Notes						(2,185		)		(2,369		)
	Total long-term debt						$	957,815			$	1,247,631
	-1	Variable interest rate was 1.93% and 2.22% at September 30, 2013 and December 31, 2012, respectively.
	-2	Effective interest rate was 8.0%
Borrowing Base Utilization Grid	'
	Borrowing Base Utilization Grid
	Borrowing Base Utilization Percentage		<25%			>25% <50%			>50% <75%			>75% <90%		>90%
	Eurodollar Loans Margin		1.5	%		1.75	%		2	%		2.25	%	2.5	%
	ABR Loans Margin		0.5	%		0.75	%		1	%		1.25	%	1.5	%
	Commitment Fee Rate		0.5	%		0.5	%		0.375	%		0.375	%	0.375	%
	Letter of Credit Fee		0.5	%		0.75	%		1	%		1.25	%	1.5	%

Price_and_Interest_Rate_Risk_M1

Price and Interest Rate Risk Management Activities (Tables)	9 Months Ended
	Sep. 30, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Commodity Derivative Contracts Covering Anticipated Future Production	'
	As of September 30, 2013, we had open commodity derivative contracts covering our anticipated future production as follows:
	Fixed-Price Swaps
			Gas							Oil							NGLs
	Contract Period		MMBtu			Weighted Average				Bbls			Weighted Average				Bbls	Weighted Average
						Fixed Price							WTI Price					Fixed Price
	October 1, 2013 – December 31, 2013		12,024,400			$	4.63			538,200			$	90.47			46,001	$	40.3
	January 1, 2014 – December 31, 2014		39,750,225			$	4.55			1,669,875			$	90.07			273,750	$	40.87
	January 1, 2015 – December 31, 2015		38,507,500			$	4.58			619,000			$	91.26			91,250	$	42
	January 1, 2016 – December 31, 2016		34,953,000			$	4.67			73,200			$	92.25			—	$	—
	January 1, 2017 – December 31, 2017		7,602,000			$	4.75			—			$	—			—	$	—
	Swaptions and Call Options Sold
	Calls were sold or options were provided to counterparties under swaption agreements to extend the swap into subsequent years as follows:
			Gas							Oil
	Contract Period		MMBtu			Weighted Average				Bbls			Weighted Average
						Fixed Price							Fixed Price
	October 1, 2013 – December 31, 2013		—			$	—			46,000			$	99.5
	January 1, 2014 – December 31, 2014		1,642,500			$	5.69			492,750			$	117.22
	January 1, 2015 – December 31, 2015		—			$	—			508,445			$	105.98
	January 1, 2016 – December 31, 2016		—			$	—			622,200			$	125
	Basis Swaps
			Gas
	Contract Period		MMBtu			Weighted Avg. Basis				Pricing Index
						Differential
	October 1, 2013 – December 31, 2013		230,000			$	(0.32	)		Rocky Mountain CIG and NYMEX Henry Hub Basis Differential
	January 1, 2014 – December 31, 2014		452,500			$	(0.32	)		Rocky Mountain CIG and NYMEX Henry Hub Basis Differential
			Oil
	Contract Period		Bbls			Weighted Avg. Basis				Pricing Index
						Differential ($/Bbl)
	October 1, 2013 – December 31, 2013		147,200			$	(0.84	)		WTI Midland and WTI Cushing Basis Differential
			82,800			$	(1.05	)		West Texas Sour and WTI Cushing Basis Differential
			21,000			$	9.6			Light Louisiana Sweet Crude and WTI Basis Differential
	January 1, 2014 – December 31, 2014		584,000			$	(0.84	)		WTI Midland and WTI Cushing Basis Differential
			328,500			$	(1.05	)		West Texas Sour and WTI Cushing Basis Differential
			182,500			$	(3.95	)		Light Louisiana Sweet Crude and Brent Basis Differential
	January 1, 2015 – December 31, 2015		365,000			$	(0.90	)		WTI Midland and WTI Cushing Basis Differential
	Collars
			Oil
	Contract Period		Bbls			Floor				Ceiling
	October 1, 2013 – December 31, 2013		20,700			$	88.89			$	102.36
	January 1, 2014 – December 31, 2014		12,000			$	100			$	116.2
	Three-Way Collars
			Oil
	Contract Period		Bbls			Floor				Ceiling				Put Sold
	October 1, 2013 – December 31, 2013		299,000			$	93.85			$	101.67			$	72.19
	January 1, 2014 – December 31, 2014		1,313,850			$	93.47			$	101.26			$	72.57
	January 1, 2015 – December 31, 2015		924,055			$	92.1			$	101.55			$	72.04
	January 1, 2016 – December 31, 2016		549,000			$	90			$	95			$	70
	Put Options Sold
			Oil
	Contract Period		Bbls			Put Sold ($/Bbl)
	October 1, 2013 – December 31, 2013		202,400			$	65.34
	January 1, 2015 – December 31, 2015		619,000			$	72.05
	January 1, 2016 – December 31, 2016		73,200			$	75
	Put Spread Options
			Oil
	Contract Period		Bbls			Floor				Put Sold
	January 1, 2015 – December 31, 2015		255,500			$	100			$	75
	Range Bonus Accumulators
			Oil
	Contract Period		Bbls			Bonus				Range Ceiling				Range Floor
	October 1, 2013 – December 31, 2013		184,000			$	3.88			$	104.15			$	72.63
	January 1, 2014 – December 31, 2014		912,500			$	4.94			$	103.2			$	70.5
Interest Rate Derivative Contracts	'
	Interest Rate Swaps
	As of September 30, 2013, we had open interest rate derivative contracts as follows (in thousands):
	Period		Notional Amount				Fixed Libor Rates
	October 1, 2013 to December 10, 2016		$	20,000			2.17	%
	October 1, 2013 to October 31, 2016		$	40,000			1.65	%
	October 1, 2013 to August 5, 2015 (1)		$	30,000			2.25	%
	October 1, 2013 to August 6, 2016		$	25,000			1.8	%
	October 1, 2013 to October 31, 2016		$	20,000			1.78	%
	October 1, 2013 to September 23, 2016		$	75,000			1.15	%
	October 1, 2013 to March 7, 2016		$	75,000			1.08	%
	October 1, 2013 to September 7, 2016		$	25,000			1.25	%
	October 1, 2013 to December 10, 2015 (2)		$	50,000			0.21	%
	Total		$	360,000
	-1	The counterparty has the option to extend the termination date of this contract at 2.25% to August 5, 2018.
	-2	The counterparty has the option to require Vanguard to pay a fixed rate of 0.91% from December 10, 2015 to December 10, 2017.
Fair Value of Derivatives Outstanding	'
	Our commodity derivatives and interest rate swap derivatives are presented on a net basis in “derivative assets” and “derivative liabilities” on the Consolidated Balance Sheets. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets for the periods indicated (in thousands):
			September 30, 2013
	Offsetting Derivative Assets:		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
	Commodity price derivative contracts		$	127,221			$	(33,795	)		$	93,426
	Interest rate derivative contracts		156				—				156
	Total derivative instruments		$	127,377			$	(33,795	)		$	93,582
	Offsetting Derivative Liabilities:		Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
	Commodity price derivative contracts		$	(43,347	)		$	33,795			$	(9,552	)
	Interest rate derivative contracts		(7,423		)		—				(7,423		)
	Total derivative instruments		$	(50,770	)		$	33,795			$	(16,975	)
			December 31, 2012
	Offsetting Derivative Assets:		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
	Commodity price derivative contracts		$	134,905			$	(35,001	)		$	99,904
	Interest rate derivative contracts		132				(106		)		26
	Total derivative instruments		$	135,037			$	(35,107	)		$	99,930
	Offsetting Derivative Liabilities:		Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
	Commodity price derivative contracts		$	(41,775	)		$	35,001			$	(6,774	)
	Interest rate derivative contracts		(10,694		)		106				(10,588		)
	Total derivative instruments		$	(52,469	)		$	35,107			$	(17,362	)
Reported Gains and Losses on Derivative Instruments	'
	The following presents our reported gains and losses on derivative instruments (in thousands):
			Three Months Ended September 30,								Nine Months Ended September 30,
			2013				2012				2013				2012
	Realized gains (losses):
	Commodity derivatives		$	(5,359	)		$	318			$	(2,175	)		$	(756	)
	Interest rate swaps		(987		)		(468		)		(2,896		)		(1,610		)
			$	(6,346	)		$	(150	)		$	(5,071	)		$	(2,366	)
	Unrealized gains (losses):
	Commodity derivatives		$	(12,355	)		$	(51,332	)		$	13,781			$	9,243
	Interest rate swaps		(742		)		(2,463		)		3,294				(5,507		)
			$	(13,097	)		$	(53,795	)		$	17,075			$	3,736
	Net gains (losses):
	Commodity derivatives		$	(17,714	)		$	(51,014	)		$	11,606			$	8,487
	Interest rate swaps		(1,729		)		(2,931		)		398				(7,117		)
			$	(19,443	)		$	(53,945	)		$	12,004			$	1,370

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2013
Fair Value Disclosures [Abstract]	'
Financial Assets and Financial Liabilities Measured at Fair Value on a Recurring Basis	'
	Financial assets and financial liabilities measured at fair value on a recurring basis are summarized below (in thousands):
		September 30, 2013
		Fair Value Measurements Using									Assets/Liabilities
		Level 1			Level 2			Level 3			at Fair value
	Assets:
	Commodity price derivative contracts	$	—		$	93,426		$	—		$	93,426
	Interest rate derivative contracts	—			156			—			156
	Total derivative instruments	$	—		$	93,582		$	—		$	93,582
	Liabilities:
	Commodity price derivative contracts	$	—		$	(8,716	)	$	(836	)	$	(9,552	)
	Interest rate derivative contracts	—			(7,423		)	—			(7,423		)
	Total derivative instruments	$	—		$	(16,139	)	$	(836	)	$	(16,975	)
		December 31, 2012
		Fair Value Measurements Using									Assets/Liabilities
		Level 1			Level 2			Level 3			at Fair value
	Assets:
	Commodity price derivative contracts	$	—		$	99,904		$	—		$	99,904
	Interest rate derivative contracts	—			26			—			26
	Total derivative instruments	$	—		$	99,930		$	—		$	99,930
	Liabilities:
	Commodity price derivative contracts	$	—		$	(6,276	)	$	(498	)	$	(6,774	)
	Interest rate derivative contracts	—			(10,588		)	—			(10,588		)
	Total derivative instruments	$	—		$	(16,864	)	$	(498	)	$	(17,362	)
Reconciliation of changes in the fair value of assets and liabilities classified as Level 3	'
	The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:
		Unobservable Inputs (Level 3)
		(in thousands)
	Unobservable inputs at January 1, 2013	$	(498	)
	Total losses	(1,122		)
	Settlements	784
	Unobservable inputs at September 30, 2013	$	(836	)
	Change in unrealized gains included in earnings related to derivatives	$	(338	)
	still held as of September 30, 2013

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2013
Asset Retirement Obligation [Abstract]	'
Changes in Asset Retirement Obligations	'
	The asset retirement obligations as of September 30, reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the nine months ended September 30, were as follows (in thousands):
		2013			2012
	Asset retirement obligations at January 1,	$	63,114		$	35,921
	Liabilities added during the current period	10,428			9,248
	Accretion expense	2,032			914
	Retirements	(348		)	(451		)
	Change in estimate	(942		)	—
	Total asset retirement obligation at September 30,	74,284			45,632
	Less: current obligations	(4,225		)	(2,269		)
	Long-term asset retirement obligation at September 30,	$	70,059		$	43,363

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Future minimum transportation demand charges	'
	The values in the table below represent gross future minimum transportation demand charges we are obligated to pay as of September 30, 2013. However, our financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property.
		(in thousands)
	October 1, 2013 - December 31, 2013	$	1,526
	2014	6,214
	2015	5,256
	2016	4,797
	2017	4,146
	Thereafter	8,636
	Total	$	30,575

Preferred_Units_Common_Units_a1

Preferred Units, Common Units and Net Income per Common Unit (Tables)	9 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]	'
Distributions Declared	'
	The following table shows the distribution amount per common and Class B unit, declared date, record date and payment date of the cash distributions we paid on each of our common and Class B units for each period presented. Future distributions are at the discretion of our board of directors and will depend on business conditions, earnings, our cash requirements and other relevant factors.
	On August 2, 2012, we announced a change in the payment of our cash distributions on our common and Class B units from quarterly to monthly commencing with the July 2012 distribution. On October 21, 2013, our board of directors declared a cash distribution on the common and Class B units attributable to the month of September 2013. See Note 12. Subsequent Events for further discussion.
		Cash Distributions
	Distribution	Per Unit		Declared Date	Record Date	Payment Date
	2013
	Third Quarter
	August	$	0.2075	September 12, 2013	October 1, 2013	October 15, 2013
	July	$	0.2075	August 20, 2013	September 3, 2013	September 13, 2013
	Second Quarter
	June	$	0.205	July 18, 2013	August 1, 2013	August 14, 2013
	May	$	0.205	June 20, 2013	July 1, 2013	July 15, 2013
	April	$	0.205	April 30, 2013	June 3, 2013	June 14, 2013
	First Quarter
	March	$	0.2025	April 19, 2013	May 1, 2013	May 15, 2013
	February	$	0.2025	March 21, 2013	April 1, 2013	April 12, 2013
	January	$	0.2025	February 18, 2013	March 1, 2013	March 15, 2013
	2012
	Fourth Quarter
	December	$	0.2025	January 25, 2013	February 4, 2013	February 14, 2013
	November	$	0.2025	December 19, 2012	January 2, 2013	January 14, 2013
	October	$	0.2025	November 16, 2012	December 3, 2012	December 14, 2012
	Third Quarter
	September	$	0.2	October 18, 2012	November 1, 2012	November 14, 2012
	August	$	0.2	September 17, 2012	October 1, 2012	October 15, 2012
	July	$	0.2	August 20, 2012	September 4, 2012	September 14, 2012
	Second Quarter	$	0.6	July 23, 2012	August 7, 2012	August 14, 2012
	First Quarter	$	0.5925	April 24, 2012	May 8, 2012	May 15, 2012
	2011
	Fourth Quarter	$	0.5875	January 18, 2012	February 7, 2012	February 14, 2012

UnitBased_Compensation_Tables

Unit-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Summary of the status of the non-vested units	'
	A summary of the status of the non-vested units as of September 30, 2013 is presented below:
		Number of		Weighted Average
		Non-vested  Restricted Units		Grant Date Fair Value
	Non-vested restricted units at December 31, 2012	289,813		$	27.97
	Forfeited	(6,507	)	$	29.07
	Vested	(112,645	)	$	27.35
	Non-vested restricted units at September 30, 2013	170,661		$	28.34

Description_of_the_Business_De

Description of the Business (Details)	9 Months Ended
	Sep. 30, 2013
	operating_areas
Accounting Policies [Abstract]	'
Number of operating areas	9

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Details) (USD $)	1 Months Ended	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'	'	'	'	'
Discount rate used in determining limitation of capitalized costs (in hundredths)	'	'	'	10.00%	'
Impairment of Oil and Gas Properties	'	$0	$18,029	$0	$18,029
Average price of natural gas used in the impairment calculation (per MMBtu)	2.77	'	'	'	'
Average price of crude oil used in the impairment calculation (per BBL)	95.26	'	'	'	'

Acquisitions_Details

Acquisitions (Details) (USD $)	0 Months Ended	3 Months Ended		9 Months Ended		0 Months Ended		3 Months Ended	9 Months Ended		12 Months Ended
	Feb. 21, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Jun. 30, 2012	Dec. 31, 2012	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
						Arkoma Basin Acquisition [Member]	Rockies Acquisition [Member]	Other Acquistions [Member]	Other Acquistions [Member]	Other Acquistions [Member]	Other Acquistions [Member]
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Acquisition purchase price	'	'	'	'	'	$428,500,000	$324,700,000	'	$297,300,000	'	'
Payments to Acquire Oil and Gas Property	'	'	'	'	'	'	'	'	267,300,000	'	24,800,000
Common units issued for the acquisition of oil and gas properties	'	'	'	'	'	'	'	'	30,000,000	'	'
Common units issued for the acquisition of oil and gas properties, in units	'	'	'	1,075,000	'	'	'	'	1,075,000	'	'
Business acquisition, agreed price per unit	'	'	'	'	'	'	'	$27.65	$27.65	'	'
Business acquisition, unit closing price value	'	'	'	'	'	'	'	$27.90	$27.90	'	'
Gain on acquisition of oil and natural gas properties	'	'	'	'	'	'	'	'	7,300,000	14,100,000	'
Goodwill, Impairment Loss	'	'	'	'	'	'	'	-200,000	1,700,000	300,000	'
Gain (loss) on acquisition of oil and natural gas properties, net	'	($236,000)	$0	$5,591,000	$13,796,000	'	'	'	'	$13,800,000	'
Effective date of acquisition	'	'	'	'	'	1-Apr-12	1-Oct-12	'	'	'	'
Common units received in exchange for Appalachian Basin properties (in units)	1,900,000	'	'	1,900,000	'	'	'	'	'	'	'

Acquisitions_Pro_Forma_Details

Acquisitions (Pro Forma) (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]	'	'	'	'
Total revenues	$103,796	$65,635	$362,510	$407,845
Net income (loss)	2,117	-68,987	52,972	31,670
Net income (loss) per unit:	'	'	'	'
Common & Class B units b basic and diluted	$0.03	($1.27)	$0.73	$0.60
Unit Exchange [Member]	'	'	'	'
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]	'	'	'	'
Total revenues	'	'	'	3,267
Excess of revenues over direct operating expenses	'	'	'	($400)

Acquisitions_Acquisitions_Acqu

Acquisitions Acquisitions (Acquiree Earnings) (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Arkoma Basin Acquisition [Member]	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'
Business Combination, Revenue of Acquiree since Acquisition Date, Actual	$14,473	$12,048	$42,754	$12,048
Excess of revenues over direct operating expenses	11,894	9,953	35,186	9,953
Rockies Acquisition [Member]	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'
Business Combination, Revenue of Acquiree since Acquisition Date, Actual	14,820	0	47,231	0
Excess of revenues over direct operating expenses	8,827	0	31,215	0
Other Acquistions [Member]	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'
Business Combination, Revenue of Acquiree since Acquisition Date, Actual	15,903	551	32,288	1,047
Excess of revenues over direct operating expenses	$11,285	$400	$21,983	$782

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)	9 Months Ended		9 Months Ended			0 Months Ended		9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013	Apr. 17, 2013	Dec. 31, 2012	Oct. 09, 2012	Apr. 04, 2012	Sep. 30, 2013		Dec. 31, 2012	Sep. 30, 2013
			Senior Secured Reserve-Based Credit Facility [Member]	Senior Secured Reserve-Based Credit Facility [Member]	Senior Secured Reserve-Based Credit Facility [Member]	Senior Notes [Member]	Senior Notes [Member]	Senior Notes [Member]		Senior Notes [Member]	Standby Letters of Credit [Member]
											Senior Secured Reserve-Based Credit Facility [Member]
Senior Secured Reserve-Based Credit Facility [Abstract]	'	'	'	'	'	'	'	'		'	'
Maximum facility size	'	'	$1,500,000,000	'	'	'	'	'		'	'
Borrowing base	'	'	1,300,000,000	1,200,000,000	'	'	'	'		'	1,700,000
Oustanding borrowings	960,000,000	1,250,000,000	410,000,000	'	700,000,000	'	'	550,000,000		550,000,000	'
Remaining borrowing capacity	'	'	888,300,000	'	'	'	'	'		'	'
Maximum line of credit utilization	'	'	1,200,000,000	'	'	'	'	'		'	'
Potential increase in borrowing capacity	'	'	100,000,000	'	'	'	'	'		'	'
Senior Notes [Abstract]	'	'	'	'	'	'	'	'		'	'
Aggregate principal amount	'	'	'	'	'	200,000,000	350,000,000	'		'	'
Stated interest rate (in hundredths)	'	'	'	'	'	7.88%	7.88%	7.88%	[1]	'	'
Maturity date	'	'	16-Apr-18	'	'	1-Apr-20	1-Apr-20	1-Apr-20		'	'
Public offering price (in hundredths)	'	'	'	'	'	'	99.27%	'		'	'
Aggregate net proceeds from public offering of debt	'	'	'	'	'	196,400,000	338,700,000	'		'	'
Underwriter Discount	'	'	'	'	'	3,500,000	10,400,000	'		'	'
Payments of Debt Issuance Costs	'	'	'	'	'	100,000	900,000	'		'	'
Percentage of ownership in subsidiaries	100.00%	'	'	'	'	'	'	'		'	'
Members' equity available for distributions	$389,400,000	'	'	'	'	'	'	'		'	'
Redemption price of aggregate principal amount of senior notes on or after April 1, 2016 (in hundredths)	'	'	'	'	'	'	'	103.94%		'	'
Redemption price of aggregate principal amount of senior notes on April 1, 2018 and thereafter (in hundredths)	'	'	'	'	'	'	'	100.00%		'	'
Redemption price of aggregate principal amount of senior notes at any time prior to April 1, 2016 (in hundredths)	'	'	'	'	'	'	'	100.00%		'	'
Percentage of aggregate principal amount of senior notes that can be redeemed (in hundredths)	'	'	'	'	'	'	'	35.00%		'	'
Redemption price of aggregate principal amount of senior notes before April 1, 2015 (in hundredths)	'	'	'	'	'	'	'	107.88%		'	'
Percentage of aggregate principal amount of senior notes remained outstanding (in hundredths)	'	'	'	'	'	'	'	65.00%		'	'
Period of redemption of senior notes within equity offering (in days)	'	'	'	'	'	'	'	'180 days		'	'
Required repurchase price of aggregate principal amount of senior notes, lower range (in hundredths)	'	'	'	'	'	'	'	100.00%		'	'
Required repurchase price of aggregate principal amount of senior notes, upper range (in hundredths)	'	'	'	'	'	'	'	101.00%		'	'
[1]	Effective interest rate was 8.0%.

LongTerm_Debt_Financing_Arrang

Long-Term Debt - Financing Arrangements (Details) (USD $)	0 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Oct. 09, 2012	Apr. 04, 2012	Sep. 30, 2013		Dec. 31, 2012
Debt Instrument [Line Items]	'	'	'		'
Debt amount outstanding, gross	'	'	$960,000		$1,250,000
Unamortized discount	'	'	-2,185		-2,369
Total long-term debt	'	'	957,815		1,247,631
Senior Secured Reserve-Based Credit Facility [Member]	'	'	'		'
Debt Instrument [Line Items]	'	'	'		'
Interest rate description	'	'	'Variable (1)	[1]	'
Maturity date	'	'	16-Apr-18		'
Debt amount outstanding, gross	'	'	410,000		700,000
Variable iterest rate (in hundredths)	'	'	1.93%		2.22%
Senior Notes [Member]	'	'	'		'
Debt Instrument [Line Items]	'	'	'		'
Stated interest rate (in hundredths)	7.88%	7.88%	7.88%	[2]	'
Maturity date	1-Apr-20	1-Apr-20	1-Apr-20		'
Debt amount outstanding, gross	'	'	$550,000		$550,000
Effective interest rate (in hundredths)	'	'	8.00%		'
[1]	Variable interest rate was 1.93% and 2.22% at SeptemberB 30, 2013 and DecemberB 31, 2012, respectively.
[2]	Effective interest rate was 8.0%.

LongTerm_Debt_Borrowing_Base_U

Long-Term Debt - Borrowing Base Utilization Grid (Details)	9 Months Ended
	Sep. 30, 2013
Borrowing Base Utilization Less Than 25% [Member]	'
Debt Instrument [Line Items]	'
Commitment fee rate (in hundredths)	0.50%
Letter of credit fee (in hundredths)	0.50%
Borrowing Base Utilization Less Than 25% [Member] | Eurodollar Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	1.50%
Borrowing Base Utilization Less Than 25% [Member] | ABR Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	0.50%
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50% [Member]	'
Debt Instrument [Line Items]	'
Commitment fee rate (in hundredths)	0.50%
Letter of credit fee (in hundredths)	0.75%
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50% [Member] | Eurodollar Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	1.75%
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50% [Member] | ABR Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	0.75%
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75% [Member]	'
Debt Instrument [Line Items]	'
Commitment fee rate (in hundredths)	0.38%
Letter of credit fee (in hundredths)	1.00%
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75% [Member] | Eurodollar Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	2.00%
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75% [Member] | ABR Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	1.00%
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90% [Member]	'
Debt Instrument [Line Items]	'
Commitment fee rate (in hundredths)	0.38%
Letter of credit fee (in hundredths)	1.25%
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90% [Member] | Eurodollar Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	2.25%
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90% [Member] | ABR Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	1.25%
Borrowing Base Utilization Equal To Or Greater Than 90% [Member]	'
Debt Instrument [Line Items]	'
Commitment fee rate (in hundredths)	0.38%
Letter of credit fee (in hundredths)	1.50%
Borrowing Base Utilization Equal To Or Greater Than 90% [Member] | Eurodollar Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	2.50%
Borrowing Base Utilization Equal To Or Greater Than 90% [Member] | ABR Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	1.50%

Price_and_Interest_Rate_Risk_M2

Price and Interest Rate Risk Management Activities (Details) (USD $)	9 Months Ended
	Sep. 30, 2013
	bbl
Fair value of derivatives [Abstract]	'
Maximum potential loss due to credit risk	$127,400,000
Fixed-Price Swaps [Member] | Gas [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	39,750,225
Weighted average fixed price (in dollars per unit)	4.55
Fixed-Price Swaps [Member] | Gas [Member] | January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	38,507,500
Weighted average fixed price (in dollars per unit)	4.58
Fixed-Price Swaps [Member] | Gas [Member] | January 1, 2016 - December 31, 2016 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	34,953,000
Weighted average fixed price (in dollars per unit)	4.67
Fixed-Price Swaps [Member] | Gas [Member] | January 1, 2017 to December 31, 2017 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	7,602,000
Weighted average fixed price (in dollars per unit)	4.75
Fixed-Price Swaps [Member] | Gas [Member] | Contract Period October 1, 2013 to December 31, 2013 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	12,024,400
Weighted average fixed price (in dollars per unit)	4.63
Fixed-Price Swaps [Member] | Oil [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	1,669,875
Weighted average fixed price (in dollars per unit)	90.07
Fixed-Price Swaps [Member] | Oil [Member] | January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	619,000
Weighted average fixed price (in dollars per unit)	91.26
Fixed-Price Swaps [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	73,200
Weighted average fixed price (in dollars per unit)	92.25
Fixed-Price Swaps [Member] | Oil [Member] | January 1, 2017 to December 31, 2017 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	0
Weighted average fixed price (in dollars per unit)	0
Fixed-Price Swaps [Member] | Oil [Member] | Contract Period October 1, 2013 to December 31, 2013 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	538,200
Weighted average fixed price (in dollars per unit)	90.47
Fixed-Price Swaps [Member] | Natural Gas Liquids [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	273,750
Weighted average fixed price (in dollars per unit)	40.87
Fixed-Price Swaps [Member] | Natural Gas Liquids [Member] | January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	91,250
Weighted average fixed price (in dollars per unit)	42
Fixed-Price Swaps [Member] | Natural Gas Liquids [Member] | January 1, 2016 - December 31, 2016 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	0
Weighted average fixed price (in dollars per unit)	0
Fixed-Price Swaps [Member] | Natural Gas Liquids [Member] | January 1, 2017 to December 31, 2017 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	0
Weighted average fixed price (in dollars per unit)	0
Fixed-Price Swaps [Member] | Natural Gas Liquids [Member] | Contract Period October 1, 2013 to December 31, 2013 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	46,001
Weighted average fixed price (in dollars per unit)	40.3
Swaptions and Call Options Sold [Member] | Gas [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	1,642,500
Weighted average fixed price (in dollars per unit)	5.69
Swaptions and Call Options Sold [Member] | Gas [Member] | January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	0
Weighted average fixed price (in dollars per unit)	0
Swaptions and Call Options Sold [Member] | Gas [Member] | January 1, 2016 - December 31, 2016 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	0
Weighted average fixed price (in dollars per unit)	0
Swaptions and Call Options Sold [Member] | Gas [Member] | Contract Period October 1, 2013 to December 31, 2013 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	0
Weighted average fixed price (in dollars per unit)	0
Swaptions and Call Options Sold [Member] | Oil [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	492,750
Weighted average fixed price (in dollars per unit)	117.22
Swaptions and Call Options Sold [Member] | Oil [Member] | January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	508,445
Weighted average fixed price (in dollars per unit)	105.98
Swaptions and Call Options Sold [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	622,200
Weighted average fixed price (in dollars per unit)	125
Swaptions and Call Options Sold [Member] | Oil [Member] | Contract Period October 1, 2013 to December 31, 2013 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	46,000
Weighted average fixed price (in dollars per unit)	99.5
Basis Swaps [Member] | Gas [Member] | January 1, 2014 - December 31, 2014 [Member] | NYMEX-Henry Hub Index [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	452,500
Weighted average basis differential (in dollars per unit)	-0.32
Basis Swaps [Member] | Gas [Member] | Contract Period October 1, 2013 to December 31, 2013 [Member] | NYMEX-Henry Hub Index [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	230,000
Weighted average basis differential (in dollars per unit)	-0.32
Basis Swaps [Member] | Oil [Member] | January 1, 2015 - December 31, 2015 [Member] | Midland-Cushing Index [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	365,000
Weighted average basis differential (in dollars per unit)	-0.9
Basis Swaps [Member] | Oil [Member] | January 1, 2014 - December 31, 2014 [Member] | Midland-Cushing Index [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	584,000
Weighted average basis differential (in dollars per unit)	-0.84
Basis Swaps [Member] | Oil [Member] | January 1, 2014 - December 31, 2014 [Member] | Midland-WTS Index [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	328,500
Weighted average basis differential (in dollars per unit)	-1.05
Basis Swaps [Member] | Oil [Member] | January 1, 2014 - December 31, 2014 [Member] | LLS-Brent Index [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	182,500
Weighted average basis differential (in dollars per unit)	-3.95
Basis Swaps [Member] | Oil [Member] | Contract Period October 1, 2013 to December 31, 2013 [Member] | Midland-Cushing Index [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	147,200
Weighted average basis differential (in dollars per unit)	-0.84
Basis Swaps [Member] | Oil [Member] | Contract Period October 1, 2013 to December 31, 2013 [Member] | Midland-WTS Index [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	82,800
Weighted average basis differential (in dollars per unit)	-1.05
Basis Swaps [Member] | Oil [Member] | Contract Period October 1, 2013 to December 31, 2013 [Member] | LLS-WTI Index [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	21,000
Weighted average basis differential (in dollars per unit)	9.6
Collars [Member] | Oil [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	12,000
Floor (in dollars per unit)	100
Ceiling (in dollars per unit)	116.2
Collars [Member] | Oil [Member] | Contract Period October 1, 2013 to December 31, 2013 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	20,700
Floor (in dollars per unit)	88.89
Ceiling (in dollars per unit)	102.36
Three-Way Collars [Member] | Oil [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	1,313,850
Floor (in dollars per unit)	93.47
Ceiling (in dollars per unit)	101.26
Put sold (in dollars per unit)	72.57
Three-Way Collars [Member] | Oil [Member] | January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	924,055
Floor (in dollars per unit)	92.1
Ceiling (in dollars per unit)	101.55
Put sold (in dollars per unit)	72.04
Three-Way Collars [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	549,000
Floor (in dollars per unit)	90
Ceiling (in dollars per unit)	95
Put sold (in dollars per unit)	70
Three-Way Collars [Member] | Oil [Member] | Contract Period October 1, 2013 to December 31, 2013 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	299,000
Floor (in dollars per unit)	93.85
Ceiling (in dollars per unit)	101.67
Put sold (in dollars per unit)	72.19
Puts [Member] | Oil [Member] | January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	619,000
Weighted average price (in dollars per unit)	72.05
Puts [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	73,200
Weighted average price (in dollars per unit)	75
Puts [Member] | Oil [Member] | Contract Period October 1, 2013 to December 31, 2013 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	202,400
Weighted average price (in dollars per unit)	65.34
Put Spreads [Member] | Oil [Member] | January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	255,500
Floor (in dollars per unit)	100
Put sold (in dollars per unit)	75
Range Bonus Accumulators [Member] | Oil [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Put sold (in dollars per unit)	70.5
Notional volume (Bbls)	912,500
Bonus (in dollars per unit)	4.94
Digital call sold (in dollars per unit)	103.2
Range Bonus Accumulators [Member] | Oil [Member] | Contract Period October 1, 2013 to December 31, 2013 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Put sold (in dollars per unit)	72.63
Notional volume (Bbls)	184,000
Bonus (in dollars per unit)	3.88
Digital call sold (in dollars per unit)	104.15
Interest Rate Swaps [Member]	'
Interest rate derivative contracts [Abstract]	'
Notional amount	360,000,000
Interest Rate Swaps [Member] | Contract Period December 10, 2015 to December 10, 2017 [Member]	'
Interest rate derivative contracts [Abstract]	'
Fixed Libor Rates (in hundredths)	0.91%
Interest Rate Swaps [Member] | Contract period Oct. 1, 2013 to Dec. 10, 2016 [Member]	'
Interest rate derivative contracts [Abstract]	'
Notional amount	20,000,000
Fixed Libor Rates (in hundredths)	2.17%
Interest Rate Swaps [Member] | Contract period Oct. 1, 2013 to Oct. 31, 2016, Swap A [Member]	'
Interest rate derivative contracts [Abstract]	'
Notional amount	40,000,000
Fixed Libor Rates (in hundredths)	1.65%
Interest Rate Swaps [Member] | Contract period Oct. 1, 2013 to Aug. 5, 2015 [Member]	'
Interest rate derivative contracts [Abstract]	'
Notional amount	30,000,000	[1]
Fixed Libor Rates (in hundredths)	2.25%	[1]
Interest Rate Swaps [Member] | Contract period Oct. 1, 2013 to Aug. 6, 2016 [Member]	'
Interest rate derivative contracts [Abstract]	'
Notional amount	25,000,000
Fixed Libor Rates (in hundredths)	1.80%
Interest Rate Swaps [Member] | Contract period Oct. 1, 2013 to Oct. 31, 2016, Swap B [Member]	'
Interest rate derivative contracts [Abstract]	'
Notional amount	20,000,000
Fixed Libor Rates (in hundredths)	1.78%
Interest Rate Swaps [Member] | Contract period Oct. 1, 2013 to Sept. 23, 2016 [Member]	'
Interest rate derivative contracts [Abstract]	'
Notional amount	75,000,000
Fixed Libor Rates (in hundredths)	1.15%
Interest Rate Swaps [Member] | Contract period Oct. 1, 2013 to Mar. 7, 2016 [Member]	'
Interest rate derivative contracts [Abstract]	'
Notional amount	75,000,000
Fixed Libor Rates (in hundredths)	1.08%
Interest Rate Swaps [Member] | Contract period Oct. 1, 2013 to Sept. 7, 2016 [Member]	'
Interest rate derivative contracts [Abstract]	'
Notional amount	25,000,000
Fixed Libor Rates (in hundredths)	1.25%
Interest Rate Swaps [Member] | Contract period Oct. 1, 2013 to Dec. 10, 2015 [Member]	'
Interest rate derivative contracts [Abstract]	'
Notional amount	$50,000,000	[2]
Fixed Libor Rates (in hundredths)	0.21%	[2]
[1]	The counterparty has the option to extend the termination date of this contract at 2.25% to August 5, 2018.
[2]	The counterparty has the option to require Vanguard to pay a fixed rate of 0.91% from DecemberB 10, 2015 to DecemberB 10, 2017.

Price_and_Interest_Rate_Risk_M3

Price and Interest Rate Risk Management Activities - Balance Sheet Presentation (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Offsetting Derivative Assets:	'	'
Gross amounts of recognized assets	$127,377	$135,037
Gross amounts offset in the consolidated balance sheets	-33,795	-35,107
Net Amounts Presented in the Consolidated Balance Sheets	93,582	99,930
Offsetting Derivative Liabilities:	'	'
Gross amounts of recognized liabilities	-50,770	-52,469
Gross amounts offset in the consolidated balance sheets	33,795	35,107
Net Amounts Presented in the Consolidated Balance Sheets	-16,975	-17,362
Commodity Contract [Member]	'	'
Offsetting Derivative Assets:	'	'
Gross amounts of recognized assets	127,221	134,905
Gross amounts offset in the consolidated balance sheets	-33,795	-35,001
Net Amounts Presented in the Consolidated Balance Sheets	93,426	99,904
Offsetting Derivative Liabilities:	'	'
Gross amounts of recognized liabilities	-43,347	-41,775
Gross amounts offset in the consolidated balance sheets	33,795	35,001
Net Amounts Presented in the Consolidated Balance Sheets	-9,552	-6,774
Interest Rate Contract [Member]	'	'
Offsetting Derivative Assets:	'	'
Gross amounts of recognized assets	156	132
Gross amounts offset in the consolidated balance sheets	0	-106
Net Amounts Presented in the Consolidated Balance Sheets	156	26
Offsetting Derivative Liabilities:	'	'
Gross amounts of recognized liabilities	-7,423	-10,694
Gross amounts offset in the consolidated balance sheets	0	106
Net Amounts Presented in the Consolidated Balance Sheets	($7,423)	($10,588)

Price_and_Interest_Rate_Risk_M4

Price and Interest Rate Risk Management Activities - Net Gains (Losses) (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Realized gains (losses):	'	'	'	'
Realized gains (losses)	($6,346)	($150)	($5,071)	($2,366)
Unrealized gains (losses):	'	'	'	'
Unrealized gains (losses)	-13,097	-53,795	17,075	3,736
Net losses:	'	'	'	'
Net losses	-19,443	-53,945	12,004	1,370
Commodity Contract [Member]	'	'	'	'
Realized gains (losses):	'	'	'	'
Realized gains (losses)	-5,359	318	-2,175	-756
Unrealized gains (losses):	'	'	'	'
Unrealized gains (losses)	-12,355	-51,332	13,781	9,243
Net losses:	'	'	'	'
Net losses	-17,714	-51,014	11,606	8,487
Interest Rate Swap [Member]	'	'	'	'
Realized gains (losses):	'	'	'	'
Realized gains (losses)	-987	-468	-2,896	-1,610
Unrealized gains (losses):	'	'	'	'
Unrealized gains (losses)	-742	-2,463	3,294	-5,507
Net losses:	'	'	'	'
Net losses	($1,729)	($2,931)	$398	($7,117)

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)

9 Months Ended

9 Months Ended

In Thousands, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Fair Value Measured on a Recurring Basis [Member]

Fair Value Measured on a Recurring Basis [Member]

Fair Value Measured on a Recurring Basis [Member]

Fair Value Measured on a Recurring Basis [Member]

Fair Value Measured on a Recurring Basis [Member]

Fair Value Measured on a Recurring Basis [Member]

Fair Value Measured on a Recurring Basis [Member]

Fair Value Measured on a Recurring Basis [Member]

Minimum [Member]

Maximum [Member]

Fair Value Measurements Using Level 1 [Member]

Fair Value Measurements Using Level 1 [Member]

Fair Value Measurements Using Level 2 [Member]

Fair Value Measurements Using Level 2 [Member]

Fair Value Measurements Using Level 3 [Member]

Fair Value Measurements Using Level 3 [Member]

Assets:

'

'

'

'

'

'

'

'

'

'

'

'

Commodity price derivative contracts

'

'

$93,426

$99,904

$0

$0

$93,426

$99,904

$0

$0

'

'

Interest rate derivative contracts

'

'

156

26

0

0

156

26

0

0

'

'

Total derivative instruments

'

'

93,582

99,930

0

0

93,582

99,930

0

0

'

'

Liabilities:

'

'

'

'

'

'

'

'

'

'

'

'

Commodity price derivative contracts

'

'

-9,552

-6,774

0

0

-8,716

-6,276

-836

-498

'

'

Interest rate derivative contracts

'

'

-7,423

-10,588

0

0

-7,423

-10,588

0

0

'

'

Total derivative instruments

'

'

-16,975

-17,362

0

0

-16,139

-16,864

-836

-498

'

'

Asset retirement obligations incurred and recorded

$10,428

$9,248

'

'

'

'

'

'

'

'

'

'

Credit-adjusted risk-free interest rate (in hundredths)

'

'

'

'

'

'

'

'

'

'

4.83%

5.50%

Average inflation rate (in hundredths)

2.50%

'

'

'

'

'

'

'

'

'

'

'

Fair_Value_Measurements_Unobse

Fair Value Measurements - Unobservable Inputs Reconciliation (Details) (Fair Value Measurements Using Level 3 [Member], USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013
Fair Value Measurements Using Level 3 [Member]	'
Unobservable inputs reconciliation	'
Unobservable inputs at January 1, 2013	($498)
Total losses	-1,122
Settlements	784
Unobservable inputs at September 30, 2013	-836
Change in unrealized gains included in earnings related to derivatives still held as of September 30, 2013	($338)

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Changes in asset retirement obligations [Abstract]	'	'	'
Asset retirement obligations at beginning of period	$63,114	$35,921	'
Liabilities added during the current period	10,428	9,248	'
Accretion expense	2,032	914	'
Retirements	-348	-451	'
Change in estimate	-942	0	'
Total asset retirement obligations at end of period	74,284	45,632	'
Less: current obligations	-4,225	-2,269	'
Long-term asset retirement obligation at end of period	$70,059	$43,363	$60,096

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	0 Months Ended		9 Months Ended		12 Months Ended
Share data in Millions, except Per Share data, unless otherwise specified	Mar. 30, 2012	Feb. 21, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Related Party Transactions [Abstract]	'	'	'	'	'
Percentage of ownership in subsidiaries	'	'	100.00%	'	'
Common units received in exchange for Appalachian Basin properties (in units)	'	1.9	1.9	'	'
Share Price	$27.62	'	'	'	'
Common units received in exchange for Appalachian Basin properties	$52,500,000	'	'	'	($52,480,000)
Noncash Consideration After Closing Adjustments	52,500,000	'	'	'	'
Closing Adjustment Under Unit Exchange Agreement	1,400,000	'	'	'	'
Monthly operating cost per well (in dollars per well)	'	'	'	60	'
Transportation fee on existing wells (in dollars per mcf)	'	'	'	0.25	'
Transportation fee on new wells (in dollars per mcf)	'	'	'	0.55	'
Transportation fee charged above actual cost under amended agreement (in dollars per mcf)	'	'	'	0.055	'
Cost incurred under MSA	'	'	'	600,000	'
Cost incurred under GCA	'	'	'	$400,000	'

Commitments_and_Contingencies_1

Commitments and Contingencies Commitments and Contingencies (Transportation Demand Charges) (Details) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013
Gross future minimum transportation demand	'
October 1, 2013 - December 31, 2013	1,526
2014	6,214
2015	5,256
2016	4,797
2017	4,146
Thereafter	8,636
Total	30,575
Minimum [Member]	'
Oil and Gas Delivery Commitments and Contracts	'
Oil and Gas Delivery Commitments and Contracts, Length of Contract	'1 year
Maximum [Member]	'
Oil and Gas Delivery Commitments and Contracts	'
Oil and Gas Delivery Commitments and Contracts, Length of Contract	'7 years

Preferred_Units_Common_Units_a2

Preferred Units, Common Units and Net Income per Common Unit (Details) (USD $)

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

0 Months Ended

3 Months Ended

9 Months Ended

1 Months Ended

3 Months Ended

In Thousands, except Share data, unless otherwise specified

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2012

Sep. 30, 2012

Jul. 15, 2013

Sep. 30, 2013

Sep. 30, 2013

Aug. 31, 2013

Jul. 31, 2013

Jun. 30, 2013

31-May-13

Apr. 30, 2013

Mar. 31, 2013

Feb. 28, 2013

Jan. 31, 2013

Dec. 31, 2012

Nov. 30, 2012

Oct. 31, 2012

Sep. 30, 2012

Aug. 31, 2012

Jul. 31, 2012

Sep. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

class

Phantom Units [Member]

Phantom Units [Member]

Phantom Units [Member]

Phantom Units [Member]

Options [Member]

Options [Member]

Series A Preferred Units [Member]

Series A Preferred Units [Member]

Series A Preferred Units [Member]

Common Units

Common Units

Common Units

Common Units

Common Units

Common Units

Common Units

Common Units

Common Units

Common Units

Common Units

Common Units

Common Units

Common Units

Common Units

Common Units

Common Units

Dilutive Securities Included in Computation of Earnings Per Share [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Class of units outstanding

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Share-based payment award granted and excluded in the computation of earnings per unit

'

'

'

'

561,934

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Share-based payment award granted and included in the computation of earnings per unit

'

'

265,152

'

429,990

'

'

53,189

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount

'

'

'

522,500

'

522,500

125,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Distributions Declared [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred unit, redemption price

'

'

'

'

'

'

'

'

'

$25

$25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred unit, monthly distribution per unit

'

'

'

'

'

'

'

'

$0.14

'

$0.16

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred Unit, Distribution Rate, Percentage

'

'

'

'

'

'

'

'

'

7.88%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Distribution payable

$16,339

$11,919

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash Distributions Per Unit (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

$0.21

$0.21

$0.21

$0.21

$0.21

$0.20

$0.20

$0.20

$0.20

$0.20

$0.20

$0.20

$0.20

$0.20

$0.60

$0.59

$0.59

Cash Distributions Declared Date

'

'

'

'

'

'

'

'

'

'

'

12-Sep-13

20-Aug-13

18-Jul-13

20-Jun-13

30-Apr-13

19-Apr-13

21-Mar-13

18-Feb-13

25-Jan-13

19-Dec-12

16-Nov-12

18-Oct-12

17-Sep-12

20-Aug-12

23-Jul-12

24-Apr-12

18-Jan-12

Cash Distributions Record Date

'

'

'

'

'

'

'

'

'

'

'

1-Oct-13

3-Sep-13

1-Aug-13

1-Jul-13

3-Jun-13

1-May-13

1-Apr-13

1-Mar-13

4-Feb-13

2-Jan-13

3-Dec-12

1-Nov-12

1-Oct-12

4-Sep-12

7-Aug-12

8-May-12

7-Feb-12

Cash Distributions Payment Date

'

'

'

'

'

'

'

'

'

'

'

15-Oct-13

13-Sep-13

14-Aug-13

15-Jul-13

14-Jun-13

15-May-13

12-Apr-13

15-Mar-13

14-Feb-13

14-Jan-13

14-Dec-12

14-Nov-12

15-Oct-12

14-Sep-12

14-Aug-12

15-May-12

14-Feb-12

UnitBased_Compensation_Executi

Unit-Based Compensation - Executive Employment Agreements (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013
Amended Agreements [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Number of executives in amended agreements	3
Number of company performance elements related to annual bonus	4
Number of times executive annual base salary may not be exceeded by maximum payout	2
VNR Long Term Incentive Plan [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Number of times executive annual salary may not be exceeded by the amount of compensation to be received upon change in control	2
Number of times executive salary may not be exceeded by the amount of compensation to be received upon termination without cause or for good reason	3
Selling, General and Administrative Expenses [Member] | Amended Agreements [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Non-cash compensation	1.3

UnitBased_Compensation_Restric

Unit-Based Compensation - Restricted and Phantom Units (Details) (USD $)

Sep. 30, 2013

Aug. 02, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Aug. 02, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

In Millions, except Share data, unless otherwise specified

Board Member [Member]

Board Member [Member]

Executive - Scott Smith [Member]

Executive - Richard Robert [Member]

Executive - Britt Pence [Member]

Phantom Units [Member]

Phantom Units [Member]

Phantom Units [Member]

Amended Agreements [Member]

Amended Agreements [Member]

VNR Long Term Incentive Plan [Member]

Selling, General and Administrative Expenses [Member]

Selling, General and Administrative Expenses [Member]

Selling, General and Administrative Expenses [Member]

Selling, General and Administrative Expenses [Member]

Selling, General and Administrative Expenses [Member]

board_member

board_member

Board Member [Member]

Employee [Member]

Restricted Units [Member]

Phantom Units [Member]

Board Member [Member]

Phantom Units [Member]

Phantom Units [Member]

Phantom Units [Member]

Phantom Units [Member]

Amended Agreements [Member]

installment

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of times executive annual base salary may not be exceeded by annual equity-based compensation

'

'

5

3.5

2.75

'

'

'

'

'

'

'

'

'

'

'

Vesting period

'

'

'

'

'

'

'1 year

'

'3 years

'3 years

'

'

'

'

'

'

Percent of units vesting on each one-year anniversary

'

'

'

'

'

'

'

'

33.33%

33.33%

'

'

'

'

'

'

Number of individuals granted phantom units

4

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of phantom units granted to each executive (in units)

'

'

'

'

'

'

'

'

'

'

390,000

'

'

'

'

'

Number of annual installments

'

'

'

'

'

'

'

'

'

'

5

'

'

'

'

'

Accrued liability

'

'

'

'

'

$1.10

'

'

'

'

'

'

'

'

'

'

Non-cash compensation

'

'

'

'

'

'

'

'

'

'

'

$0.20

$0.60

$1.90

$0.90

$1.30

Common units granted to VNR employees and board member (in units)

'

'

'

'

'

'

18,684

68,504

'

'

'

'

'

'

'

'

UnitBased_Compensation_NonVest

Unit-Based Compensation - Non-Vested Restricted Unit Grants (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Non-cash compensation	'	'	$4,445,000	$3,258,000
Restricted Units [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Unrecognized compensation cost	3,500,000	'	3,500,000	'
Unrecognized compensation cost recognition period (in years)	'	'	'1 year 9 months	'
Number of Non-vested Units	'	'	'	'
Non-vested units at December 31, 2012 (in units)	'	'	289,813	'
Forfeited (in units)	'	'	-6,507	'
Vested (in units)	'	'	-112,645	'
Non-vested units at end of period (in units)	170,661	'	170,661	'
Weighted Average Grant Date Fair Value	'	'	'	'
Non-vested units at December 31, 2012 (in dollars per unit)	'	'	$27.97	'
Forfeited (in dollars per unit)	'	'	$29.07	'
Vested (in dollars per unit)	'	'	$27.35	'
Non-vested units at end of period (in dollars per unit)	$28.34	'	$28.34	'
Selling, General and Administrative Expenses [Member] | Restricted and Phantom Units [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Allocated Share-based Compensation Expense	$900,000	$1,400,000	$4,400,000	$3,300,000

Shelf_Registration_Statements_

Shelf Registration Statements (Details) (USD $)

9 Months Ended

3 Months Ended

1 Months Ended

0 Months Ended

9 Months Ended

3 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Aug. 31, 2010

Sep. 09, 2011

Sep. 30, 2013

Sep. 30, 2009

Sep. 09, 2011

Jul. 31, 2010

Sep. 09, 2011

Jun. 04, 2013

Feb. 05, 2013

Jul. 31, 2013

Jan. 31, 2012

Jun. 19, 2013

Jul. 02, 2013

Series A Preferred Units [Member]

Distribution Agreement 2010 [Member]

Distribution Agreement 2011 [Member]

Distribution Agreement 2011 [Member]

Shelf Registration Statement 2009 [Member]

Shelf Registration Statement 2009 [Member]

Shelf Registration Statement 2010 [Member]

Shelf Registration Statement 2012 [Member]

Shelf Registration Statement 2012 [Member]

Shelf Registration Statement 2012 [Member]

Shelf Registration Statement 2012 [Member]

Shelf Registration Statement 2012 [Member]

Shelf Registration Statement 2012 [Member]

Common Units

Distribution Agreement 2011 [Member]

Common Units

Common Units

Common Units

Common Units

Series A Preferred Units [Member]

Shelf Registration Statements [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Registered offerings under registration statement

'

'

'

'

'

'

$300,000,000

'

$800,000,000

'

'

'

'

'

'

'

Units issued under public offerings (in units)

'

'

'

240,111

'

1,103,499

'

'

'

'

7,000,000

9,200,000

'

3,100,000

2,520,000

'

Offering of common units, maximum

'

'

'

60,000,000

200,000,000

'

'

'

'

196,000,000

'

'

'

'

'

'

Proceeds from issuance of commun units

477,279,000

322,021,000

'

6,300,000

'

31,500,000

'

4,000,000

'

'

190,900,000

246,100,000

8,900,000

'

'

'

Number of years extension of distribution agreement

'

'

'

'

'3 years

'

'

'

'

'

'

'

'

'

'

'

Issue price of units (in dollars per share)

'

'

'

'

'

'

'

'

'

'

$28.35

$27.85

'

'

$25

$28.35

Units issued, underwriter's overallotment option, in units

'

'

'

'

'

'

'

'

'

'

'

1,200,000

325,000

'

320,000

'

Preferred Unit, Distribution Rate, Percentage

'

'

7.88%

'

'

'

'

'

'

'

'

'

'

'

7.88%

'

Proceeds from issuance of preferred units

60,635,000

0

'

'

'

'

'

'

'

'

'

'

'

'

60,600,000

'

Underwriter discount

'

'

'

'

'

'

'

'

'

'

7,400,000

10,000,000

'

'

2,000,000

'

Offering costs

'

'

'

'

'

'

'

'

'

'

$100,000

$100,000

'

'

$400,000

'

Subsequent_Events_Details

Subsequent Events (Details) (Subsequent Event [Member], USD $)	0 Months Ended
	Oct. 30, 2013	Oct. 21, 2013
Common Units	'	'
Subsequent Event [Line Items]	'	'
Cash distribution, declaration date	30-Oct-13	21-Oct-13
Cash distribution attributable, per common unit	$0.21	$0.21
Cash distribution attributable on an annualiized basis, per common unit	$2.49	$2.49
Preferred units	'	'
Subsequent Event [Line Items]	'	'
Cash distribution, declaration date	'	21-Oct-13
Cash distribution attributable, per common unit	'	$0.16