Grizzly Energy (GRZZP) 10-Q 4 Nov 14 2014 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Sep. 30, 2014	Oct. 31, 2014
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	'	83,587,351
Document Fiscal Year Focus	'2014	'
Document Period End Date	30-Sep-14	'
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, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Revenues:	'	'	'	'
Oil sales	$69,034	$77,236	$211,197	$205,454
Natural gas sales	67,827	30,655	201,175	94,189
NGLs sales	16,766	13,619	55,514	35,286
Net gains (losses) on commodity derivative contracts	83,311	-17,714	-11,125	11,606
Total revenues	236,938	103,796	456,761	346,535
Production:	'	'	'	'
Lease operating expenses	31,011	25,339	95,726	76,021
Production and other taxes	15,130	11,097	46,693	30,404
Depreciation, depletion, amortization and accretion	55,680	41,750	150,798	123,354
Selling, general and administrative expenses	7,140	5,730	23,042	19,179
Total costs and expenses	108,961	83,916	316,259	248,958
Income from operations	127,977	19,880	140,502	97,577
Other income (expense):	'	'	'	'
Interest expense	-16,721	-14,832	-49,529	-46,233
Net gains (losses) on interest rate derivative contracts	511	-1,729	-1,068	398
Net gains (losses) on acquisitions of oil and natural gas properties	2,409	-236	34,523	5,591
Other	-77	38	54	66
Total other expense	-13,878	-16,759	-16,020	-40,178
Net income	114,099	3,121	124,482	57,399
Distributions to Preferred unitholders	-4,949	-1,240	-11,507	-1,392
Net income attributable to Common and Class B unitholders	$109,150	$1,881	$112,975	$56,007
Net income per common and Class B unit, Basic	$1.31	$0.02	$1.39	$0.78
Net income per common and class B unit, Diluted	$1.30	$0.02	$1.38	$0.78
Weighted Average Number of Shares Outstanding, Basic	83,525	77,903	81,377	71,351
Weighted Average Number of Shares Outstanding, Diluted	83,753	78,168	81,651	71,781
Common Units	'	'	'	'
Other income (expense):	'	'	'	'
Weighted Average Number of Shares Outstanding, Basic	83,105	77,483	80,957	70,931
Weighted Average Number of Shares Outstanding, Diluted	83,333	77,748	81,231	71,361
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, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets	'	'
Cash and cash equivalents	$43,956	$11,818
Trade accounts receivable, net	102,357	70,109
Derivative assets	38,967	21,314
Other currents assets	4,591	2,916
Total current assets	189,871	106,157
Oil and natural gas properties, at cost	4,077,926	2,523,671
Accumulated depletion, amortization and impairment	-858,608	-713,154
Oil and natural gas properties evaluated, net - full cost method	3,219,318	1,810,517
Other assets	'	'
Goodwill	420,955	420,955
Derivative assets	37,287	60,474
Other assets	28,357	91,538
Total assets	3,895,788	2,489,641
Accounts payable:	'	'
Trade	10,258	9,824
Affiliates	580	249
Accrued liabilities:	'	'
Lease operating	17,192	12,882
Developmental capital	32,716	10,543
Interest	22,551	11,989
Production and other taxes	28,831	16,251
Derivative liabilities	4,179	10,992
Oil and natural gas revenue payable	31,260	23,245
Distribution payable	18,662	16,499
Other	15,970	12,929
Total current liabilities	182,199	125,403
Long-term debt	1,923,078	1,007,879
Derivative liabilities	2,528	4,085
Asset retirement obligations, net of current portion	132,987	82,208
Other long-term liabilities	0	1,731
Total liabilities	2,240,792	1,221,306
Commitments and contingencies	'	'
Members' equity	'	'
Members' Equity	1,654,996	1,268,335
Total liabilities and members' equity	3,895,788	2,489,641
Cumulative Preferred Units [Member]	'	'
Members' equity	'	'
Members' Equity	335,542	61,021
Common Units	'	'
Members' equity	'	'
Members' Equity	1,311,839	1,199,699
Class B Units [Member]	'	'
Members' equity	'	'
Members' Equity	$7,615	$7,615

CONSOLIDATED_BALANCE_SHEETS_Un1

CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical)	Sep. 30, 2014	Dec. 31, 2013
Members' equity	'	'
Preferred units, issued	13,881,873	2,535,927
Preferred units, outstanding	13,881,873	2,535,927
Common Units	'	'
Members' equity	'	'
Common units, issued	83,559,668	78,337,259
Common units, outstanding	83,559,668	78,337,259
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	Cumulative Preferred units	Common Units	Common Units	Class B Units [Member]
In Thousands, unless otherwise specified		Member Units [Member]		Member Units [Member]	Member Units [Member]
Balance at Dec. 31, 2012	$797,464	$0	'	$789,849	$7,615
Increase (Decrease) in Members' Equity [Roll Forward]	'	'	'	'	'
Issuance of Common units for the acquisition of oil and natural gas properties	29,992	'	'	29,992	'
Distributions to Preferred unitholders	-2,634	'	-2,634	'	'
Distributions to Common and Class B unitholders	-181,926	'	'	-181,926	'
Issuance of units, net of offering costs	'	61,021	'	498,360	'
Unit-based compensation	6,547	'	'	6,547	'
Net income	59,511	'	'	59,511	'
Balance at Dec. 31, 2013	1,268,335	61,021	'	1,199,699	7,615
Increase (Decrease) in Members' Equity [Roll Forward]	'	'	'	'	'
Distributions to Preferred unitholders	-11,507	'	-11,507	'	'
Distributions to Common and Class B unitholders	-154,666	'	'	-154,666	'
Issuance of units, net of offering costs	'	274,521	'	147,841	'
Unit-based compensation	5,990	'	'	5,990	'
Net income	124,482	'	'	124,482	'
Balance at Sep. 30, 2014	$1,654,996	$335,542	'	$1,311,839	$7,615

CONSOLIDATED_STATEMENTS_OF_MEM1

CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY (Unaudited) (Parenthetical) (Member Units [Member], USD $)	9 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Common Units	'	'
Issuance of members' units, offering costs	$60	$415
Cumulative Preferred units	'	'
Issuance of members' units, offering costs	$272	$402

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013
Operating activities	'	'
Net income	$124,482	$57,399
Adjustments to reconcile net income to net cash provided by operating activities:	'	'
Depreciation, depletion, amortization and accretion	150,798	123,354
Amortization of deferred financing costs	2,586	2,811
Amortization of debt discount	199	184
Compensation related items	5,437	4,445
Net (gains) losses on commodity and interest rate derivative contracts	12,193	-12,004
Cash settlement received on matured commodity derivative contracts	-13,347	20,862
Cash settlements and fees paid on interest rate derivative contracts	-3,026	-2,896
Net gains on acquisitions of oil and natural gas properties	-34,523	-5,591
Changes in operating assets and liabilities:	'	'
Trade accounts receivable	-32,248	-27,006
Other current assets	-1,991	-1,093
Premiums paid on commodity derivative contracts	0	-147
Accounts payable and oil and natural gas revenue payable	8,449	12,328
Payables to affiliates	331	131
Accrued expenses and other current liabilities	26,733	26,488
Other assets	-384	-132
Net cash provided by operating activities	245,689	199,133
Investing activities	'	'
Additions to property and equipment	-1,148	-1,735
Additions to oil and natural gas properties	-79,514	-42,192
Acquisitions of oil and natural gas properties	-1,303,035	-270,097
Deposits and prepayments of oil and natural gas properties	-4,957	-5,262
Proceeds from sale of leasehold interests	1,950	0
Net cash used in investing activities	-1,386,704	-319,286
Financing activities	'	'
Proceeds from long-term debt	1,321,000	435,500
Repayment of long-term debt	-406,000	-725,500
Proceeds from preferred unit offerings, net	274,521	60,635
Proceeds from Common unit offerings, net	147,841	477,279
Distributions to Preferred unitholders	-10,600	-1,185
Distributions to Common and Class B unitholders	-153,410	-128,657
Financing fees	-199	-2,056
Net cash provided by financing activities	1,173,153	116,016
Net increase (decrease) in cash and cash equivalents	32,138	-4,137
Cash and cash equivalents, beginning of period	11,818	11,563
Cash and cash equivalents, end of period	43,956	7,426
Supplemental cash flow information:	'	'
Cash paid for interest	36,143	32,344
Non-cash financing and investing activities:	'	'
Asset retirement obligations	51,081	9,138
Common units issued for the acquisition of oil and gas properties	$0	$29,992

Description_of_the_Business

Description of the Business	9 Months Ended
	Sep. 30, 2014
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 Green River Basin in Wyoming;
	•	the Piceance Basin in Colorado;
	•	the Permian Basin in West Texas and New Mexico;
	•	the Gulf Coast Basin in Texas, Louisiana and Mississippi;
	•	the Big Horn Basin in Wyoming and Montana;
	•	the Arkoma Basin in Arkansas and Oklahoma;
	•	the Williston Basin in North Dakota and Montana;
	•	the Wind River Basin in Wyoming; and
	•	the Powder River Basin in Wyoming.
	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”), an exchange of the NASDAQ OMX Group Inc. (Nasdaq: NDAQ), under the symbol “VNR.” Our Series A, Series B and Series C Cumulative Preferred units are also listed on the NASDAQ under the symbols “VNRAP”, “VNRBP” and “VNRCP,” respectively.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2014
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, 2013, from the audited financial statements contained in our 2013 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 2013 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, 2014, our significant accounting policies are consistent with those discussed in Note 1 of our consolidated financial statements contained in our 2013 Annual Report.
	(a)	Basis of Presentation and Principles of Consolidation:
	The consolidated financial statements as of September 30, 2014 and December 31, 2013 and for the three and nine months ended September 30, 2014 and 2013 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. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income or members’ equity.
	(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, 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, 2014 or 2013.
	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)	New Pronouncement Issued But Not Yet Adopted:
	In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU No. 2014-09”), which amends the FASB ASC by adding new FASB ASC Topic 606, Revenue from Contracts with Customers, and superseding the revenue recognition requirements in FASB ASC 605, Revenue Recognition, and in most industry-specific topics. ASU No. 2014-09 provides new guidance concerning recognition and measurement of revenue and requires additional disclosures about the nature, timing and uncertainty of revenue and cash flows arising from contracts with customers. ASU No. 2014-09 becomes effective at the beginning of 2017. We are still evaluating the impact of ASU No. 2014-09 on our financial position or results of operations.
	(d)	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, 2014
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.
	2014 Acquisitions
	Pinedale Acquisition
	On January 31, 2014, we completed the acquisition of natural gas and oil properties in the Pinedale and Jonah fields of Southwestern Wyoming for approximately $555.6 million in cash with an effective date of October 1, 2013. We refer to this acquisition as the “Pinedale Acquisition.” The purchase price was funded with borrowings under our Reserve-Based Credit Facility (as defined below). In accordance with ASC Topic 805, this acquisition resulted in a gain of $32.1 million, as reflected in the table below, primarily due to the increase in natural gas prices between the date the purchase and sale agreement was entered into and the closing date.
	Fair value of assets and liabilities acquired	(in thousands)
	Oil and natural gas properties	$	600,123
	Inventory	244
	Asset retirement obligations	(12,404		)
	Imbalance liabilities	(171		)
	Other	(125		)
	Total fair value of assets and liabilities acquired	587,667
	Fair value of consideration transferred	555,553
	Gain on acquisition	$	32,114
	Piceance Acquisition
	On September 30, 2014, we completed the acquisition of natural gas, oil and NGLs assets in the Piceance Basin in Colorado for approximately $502.1 million in cash. We refer to this acquisition as the “Piceance Acquisition.” The purchase price was funded with borrowings under our Reserve-Based Credit Facility and is subject to additional customary post-closing adjustments to be determined based on an effective date of July 1, 2014. In accordance with ASC Topic 805, this acquisition resulted in goodwill of $0.4 million, as reflected in the table below, which was immediately impaired and recorded as a loss in current period earnings. The loss resulted primarily from the changes in natural gas prices between the date the purchase and sale agreement was entered into and the closing date, which were used to value the reserves acquired.
	Fair value of assets and liabilities acquired	(in thousands)
	Oil and natural gas properties	$	521,401
	Asset retirement obligations	(19,452		)
	Imbalance and suspense liabilities	(236		)
	Total fair value of assets and liabilities acquired	501,713
	Fair value of consideration transferred	502,140
	Loss on acquisition	$	(427	)
	Other Acquisitions
	On May 1, 2014, we completed an asset exchange transaction with Marathon Oil Company in which we acquired natural gas and NGLs properties in the Wamsutter natural gas field in Wyoming in exchange for 75% of our working interests in the Gooseberry Field properties in Wyoming. The total consideration for this transaction was the mutual exchange and assignment of interests in the properties and cash consideration of $9.6 million paid to Marathon Oil Company. The cash consideration was funded with borrowings under our existing Reserve-Based Credit Facility and is subject to customary final post-closing adjustments to be determined based on an effective date of January 1, 2014.
	On August 29, 2014, we completed the acquisition of certain natural gas, oil and NGLs properties located in North Louisiana and East Texas for an adjusted purchase price of $269.9 million. We refer to this acquisition as the “Gulf Coast Acquisition.” The purchase price was funded with borrowings under our existing Reserve-Based Credit Facility and is subject to additional customary post-closing adjustments to be determined based on an effective date of June 1, 2014.
	During the nine months ended September 30, 2014, we completed other smaller acquisitions of certain natural gas, oil and NGLs properties located in the Permian Basin and Powder River Basin in Wyoming for an aggregate purchase price of $17.7 million which was funded with borrowings under our existing Reserve-Based Credit Facility.
	2013 Acquisitions
	On April 1, 2013, we completed the acquisition of certain natural gas, oil and NGLs properties located in the Permian Basin of Southeastern New Mexico and West Texas for an adjusted purchase price of $266.2 million. This acquisition had an effective date of January 1, 2013.
	On June 28, 2013, we completed the acquisition of certain natural gas, oil and NGLs properties located in the Permian Basin in Texas and the San Juan and D-J Basins in Colorado with an effective date of July 1, 2013 for an adjusted purchase price of $29.9 million. The consideration for this acquisition was paid in common equity by issuing 1,075,000 VNR common units, at an agreed price of $27.65 per common unit, valued for financial reporting purposes at the closing price of $27.90 at the closing date of the acquisition.
	We also completed other acquisitions during 2013 including the acquisition of additional working interests in certain acquired properties for an aggregate adjusted purchase price of $2.5 million.
	The following presents the values assigned to the net assets acquired in our 2013 acquisitions:
	Fair value of assets and liabilities acquired	(in thousands)
	Oil and natural gas properties	$	317,573
	Inventory	899
	Asset retirement obligations	(11,381		)
	Oil and natural gas revenue payable and imbalance liabilities	(2,843		)
	Total fair value of assets and liabilities acquired	304,248
	Fair value of consideration transferred	298,657
	Gain on acquisition	$	5,591
	Pro Forma Operating Results
	In accordance with ASC Topic 805, presented below are unaudited pro forma results for the three and nine months ended September 30, 2014 and 2013 to show the effect on our consolidated results of operations as if our acquisitions completed in 2014 had occurred on January 1, 2013, and as if our acquisitions completed during 2013 had occurred on January 1, 2012.
	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 2014 and 2013, adjusted for (i) the assumption of asset retirement obligations and accretion expense for the properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired, (iii) interest expense on additional borrowings necessary to finance the acquisitions, and (iv) common units issued in the acquisition of properties completed on June 28, 2013. The net gains and losses on acquisitions of oil and natural gas properties were excluded from the pro forma results for the three and nine months ended September 30, 2014 and 2013. 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					Nine Months Ended
		September 30,					September 30,
		2014			2013		2014		2013
	Total revenues	$	279,601		$	197,151	$	616,234	$	639,492
	Net income attributable to Common and Class B	$	124,002		$	27,965	$	139,451	$	127,918
	unitholders
	Net income per Common and Class B unit:
	Basic	$	1.48		$	0.36	$	1.71	$	1.78
	Diluted	$	1.48		$	0.36	$	1.7	$	1.76
	Post-Acquisition Operating Results
	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					Nine Months Ended
		September 30,					September 30,
		2014			2013		2014		2013
		(in thousands)
	Pinedale Acquisition
	Revenues	$	36,947		$	—	$	106,163	$	—
	Excess of revenues over direct operating expenses	$	29,423		$	—	$	82,709	$	—
Piceance Acquisition
Revenues	$	283		$	—	$	283	$	—
Excess of revenues over direct operating expenses	$	227		$	—	$	227	$	—
All other acquisitions
Revenues	$	20,442		$	12,849	$	52,489	$	23,649
Excess of revenues over direct operating expenses	$	7,284		$	9,283	$	26,092	$	16,708

LongTerm_Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2014
Debt Disclosure [Abstract]	'
Long-Term 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, 2014				December 31, 2013
							(in thousands)
	Senior Secured Reserve-Based		Variable (1)		April 16, 2018		$	1,375,000			$	460,000
	Credit Facility
	Senior Notes		7.875% (2)		April 1, 2020		550,000				550,000
							$	1,925,000			$	1,010,000
	Unamortized discount on Senior Notes						(1,922		)		(2,121		)
	Total long-term debt						$	1,923,078			$	1,007,879
	-1	Variable interest rate was 2.16% and 1.92% at September 30, 2014 and December 31, 2013, 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 $3.5 billion and an initial borrowing base of $2.0 billion (the “Reserve-Based Credit Facility”). As of September 30, 2014, there were approximately $1.4 billion of outstanding borrowings and $622.2 million of borrowing capacity under the Reserve-Based Credit Facility, after consideration of a $2.8 million reduction in availability for letters of credit (discussed below). The Company’s borrowing base was increased from $1.525 billion to $2.0 billion effective September 30, 2014 as a result of the Company’s request for an increase in the borrowing base in connection with its Gulf Coast and Piceance acquisitions, which were completed on August 29 and September 30, 2014, respectively.
	On October 30, 2014, we entered into the Seventh Amendment to the Credit Agreement with an effective date of October 30, 2014. See Note 11. Subsequent Events for further discussion.
	Interest rates under the Reserve-Based Credit Facility are based on Eurodollar (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, 2014, 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, 2014, 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, 2014, we have unused irrevocable standby letters of credit of approximately $2.8 million. 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
	We have $550.0 million outstanding in aggregate principal amount of 7.875% senior notes due 2020 (the “Senior Notes”). The issuers of the 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, 2014, based on the most restrictive covenants of the Indenture, the Company’s cash balance and the borrowings available under the Reserve-Based Credit Facility, approximately $349.0 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. 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, 2014
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 primarily with counterparties that are also 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 is based on certain market indexes and prices at our primary sales points. During the nine months ended September 30, 2014, our derivative transactions included fixed-price swaps, basis swap contracts, collars, three-way collars, swaptions, call options sold, put options sold and range bonus accumulators.
	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.
	As of September 30, 2014, 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, 2014 – December 31, 2014		17,725,180			$	4.42			457,700			$	90.83		69,000	$	40.87
	January 1, 2015 – December 31, 2015		66,795,000			$	4.4			692,000			$	91.18		246,375	$	46.34
	January 1, 2016 – December 31, 2016		55,083,000			$	4.47			146,400			$	89.98		—	$	—
	January 1, 2017 – December 31, 2017		27,677,000			$	4.32			73,000			$	86.6		—	$	—
	Call Options Sold
			Oil
	Contract Period		Bbls			Weighted Average
						Fixed Price
	October 1, 2014 – December 31, 2014		124,200			$	102.41
	January 1, 2015 – December 31, 2015		252,945			$	119.23
	January 1, 2016 – December 31, 2016		622,200			$	125
	Swaptions Sold
			Oil
	Contract Period		Bbls			Weighted Average
						Fixed Price
	January 1, 2015 – December 31, 2015		346,000			$	93.42
	Basis Swaps
			Gas
	Contract Period		MMBtu			Weighted Avg. Basis				Pricing Index
						Differential ($/MMBtu)
	October 1, 2014 – December 31, 2014		7,360,000			$	(0.20	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2015 – December 31, 2015		29,200,000			$	(0.28	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2016 – December 31, 2016		18,300,000			$	(0.24	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2017 – December 31, 2017		10,950,000			$	(0.22	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
			Oil
	Contract Period		Bbls			Weighted Avg. Basis				Pricing Index
						Differential ($/Bbl)
	October 1, 2014 – December 31, 2014		147,200			$	(0.84	)		WTI Midland and WTI Cushing Basis Differential
	October 1, 2014 – December 31, 2014		82,800			$	(1.05	)		West Texas Sour and WTI Cushing Basis Differential
	October 1, 2014 – December 31, 2014		46,000			$	(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
	Three-Way Collars
			Gas
	Contract Period		MMBtu			Floor				Ceiling				Put Sold
	October 1, 2014 – December 31, 2014		1,840,000			$	4.11			$	4.84			$	3.5
	January 1, 2015 – December 31, 2015		11,862,500			$	4.06			$	4.78			$	3.48
	January 1, 2016 – December 31, 2016		7,320,000			$	4			$	4.65			$	3.5
	January 1, 2017 – December 31, 2017		7,300,000			$	4			$	4.65			$	3.5
			Oil
	Contract Period		Bbls			Floor				Ceiling				Put Sold
	October 1, 2014 – December 31, 2014		326,600			$	93.52			$	101.29			$	72.54
	January 1, 2015 – December 31, 2015		1,984,055			$	91.84			$	99.45			$	74.41
	January 1, 2016 – December 31, 2016		1,061,400			$	90			$	96.18			$	73.62
	Put Options Sold
			Gas							Oil
	Contract Period		MMBtu			Put Sold				Bbls			Put Sold
						($/MMBtu)							($/Bbl)
	October 1, 2014 – December 31, 2014		920,000			$	3.5			18,400			$	75
	January 1, 2015 – December 31, 2015		9,125,000			$	3.5			692,000			$	72.36
	January 1, 2016 – December 31, 2016		1,830,000			$	3.5			146,400			$	75
	January 1, 2017 – December 31, 2017		1,825,000			$	3.5			73,000			$	75
	Range Bonus Accumulators
			Gas
	Contract Period		MMBtu			Bonus				Range Ceiling				Range Floor
	October 1, 2014 – December 31, 2014		368,000			$	0.2			$	4.75			$	3.25
January 1, 2015 – December 31, 2015		1,460,000			$	0.2			$	4.75			$	3.25
		Oil
Contract Period		Bbls			Bonus				Range Ceiling				Range Floor
October 1, 2014 – December 31, 2014		230,000			$	4.94			$	103.2			$	70.5
Interest Rate Swaps
As of September 30, 2014, we had open interest rate derivative contracts as follows (in thousands):
Period		Notional Amount				Fixed LIBOR Rates
October 1, 2014 to December 10, 2016		$	20,000			2.17	%
October 1, 2014 to October 31, 2016		$	40,000			1.65	%
October 1, 2014 to August 5, 2015 (1)		$	30,000			2.25	%
October 1, 2014 to August 6, 2016		$	25,000			1.8	%
October 1, 2014 to October 31, 2016		$	20,000			1.78	%
October 1, 2014 to September 23, 2016		$	75,000			1.15	%
October 1, 2014 to March 7, 2016		$	75,000			1.08	%
October 1, 2014 to September 7, 2016		$	25,000			1.25	%
October 1, 2014 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 to August 5, 2018 at 2.25%.
-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, 2014
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		$	98,336			$	(22,134	)		$	76,202
Interest rate derivative contracts		52				—				52
Total derivative instruments		$	98,388			$	(22,134	)		$	76,254
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		$	(23,976	)		$	22,134			$	(1,842	)
Interest rate derivative contracts		(4,865		)		—				(4,865		)
Total derivative instruments		$	(28,841	)		$	22,134			$	(6,707	)
		December 31, 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		$	107,307			$	(25,617	)		$	81,690
Interest rate derivative contracts		98				—				98
Total derivative instruments		$	107,405			$	(25,617	)		$	81,788
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		$	(33,825	)		$	25,617			$	(8,208	)
Interest rate derivative contracts		(6,869		)		—				(6,869		)
Total derivative instruments		$	(40,694	)		$	25,617			$	(15,077	)
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 $98.4 million at September 30, 2014. 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 somewhat mitigated as of September 30, 2014. We minimize the credit risk in derivative instruments by: (i) entering into derivative instruments primarily with counterparties that are also lenders in our Reserve-Based Credit Facility and (ii) monitoring the creditworthiness of our counterparties on an ongoing basis.
Changes in fair value of our commodity and interest rate derivatives for the nine months ended September 30, 2014 and the year ended December 31, 2013 are as follows:
	Nine Months Ended September 30, 2014				Year Ended December 31, 2013
	(in thousands)
Derivative asset at beginning of period, net	$	66,711			$	82,568
Fair value of derivatives acquired	(1,344		)		—
Net gains (losses) on commodity and interest rate derivative contracts	(12,193		)		11,160
Settlements
Cash settlements paid (received) on matured commodity derivative contracts	13,347				(30,905		)
Cash settlements paid on matured interest rate derivative contracts	3,026				3,888
Derivative asset at end of period, net	$	69,547			$	66,711

Fair_Value_Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2014
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. As of September 30, 2014, the fair value of our Senior Notes was estimated to be $572.0 million. We consider the inputs to the valuation of our Senior Notes to be Level 1 as fair value was estimated based on prices quoted from a third-party financial institution.
	Derivative instruments. Our commodity derivative instruments consist of fixed-price swaps, basis swaps, swaptions, call options sold, put options sold, 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 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, 2014
			Fair Value Measurements Using								Assets/Liabilities
			Level 1			Level 2			Level 3		at Fair value
	Assets:
	Commodity price derivative contracts		$	—		$	75,022		$	1,180	$	76,202
	Interest rate derivative contracts		—			52			—		52
	Total derivative instruments		$	—		$	75,074		$	1,180	$	76,254
	Liabilities:
	Commodity price derivative contracts		$	—		$	(1,842	)	$	—	$	(1,842	)
	Interest rate derivative contracts		—			(4,865		)	—		(4,865		)
	Total derivative instruments		$	—		$	(6,707	)	$	—	$	(6,707	)
			December 31, 2013
			Fair Value Measurements Using								Assets/Liabilities
			Level 1			Level 2			Level 3		at Fair value
	Assets:
	Commodity price derivative contracts		$	—		$	81,124		$	566	$	81,690
	Interest rate derivative contracts		—			98			—		98
	Total derivative instruments		$	—		$	81,222		$	566	$	81,788
	Liabilities:
	Commodity price derivative contracts		$	—		$	(8,208	)	$	—	$	(8,208	)
	Interest rate derivative contracts		—			(6,869		)	—		(6,869		)
	Total derivative instruments		$	—		$	(15,077	)	$	—	$	(15,077	)
	The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 (unobservable inputs) in the fair value hierarchy:
			Nine Months Ended
			September 30,
			2014			2013
			(in thousands)
	Unobservable inputs, beginning of period		$	566		$	(498	)
	Total gains (losses)		798			(1,122		)
	Settlements		(184		)	784
	Unobservable inputs, end of period		$	1,180		$	(836	)
	Change in fair value included in earnings related to derivatives		$	1,132		$	(12	)
	still held as of September 30, 2014 and 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, 2013 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, 2014 and year ended December 31, 2013, in connection with new wells drilled and wells acquired during the period, we incurred and recorded asset retirement obligations totaling $52.1 million and $11.7 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 from 5.1% to 5.6%; and (4) the average inflation factor (2.4%). 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, 2014
Asset Retirement Obligation [Abstract]	'
Asset Retirement Obligations	'
	Asset Retirement Obligations
	The asset retirement obligations as of September 30, 2014 and December 31, 2013 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the nine months ended September 30, 2014 and year ended December 31, 2013 were as follows (in thousands):
		September 30, 2014			December 31, 2013
	Asset retirement obligations, beginning of period	$	87,967		$	63,114
	Liabilities added during the current period	52,141			11,738
	Accretion expense	4,107			2,789
	Retirements	(443		)	(628		)
	Disposition of properties	(1,060		)	—
	Change in estimate	—			10,954
	Asset retirement obligation, end of period	142,712			87,967
	Less: current obligations	(9,725		)	(5,759		)
	Long-term asset retirement obligation, end of period	$	132,987		$	82,208

Commitments_and_Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	Commitments and Contingencies
	Transportation Demand Charges
	As of September 30, 2014, we have contracts that provide firm transportation capacity on pipeline systems. The remaining terms on these contracts range from one to six 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, 2014. 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.
		30-Sep-14
		(in thousands)
	October 1, 2014 - December 31, 2014	$	4,814
	2015	17,461
	2016	13,987
	2017	11,840
	2018	11,261
	Thereafter	10,611
	Total	$	69,974
	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.

Members_Equity_and_Net_Income_

Members' Equity and Net Income per Common and Class B Unit	9 Months Ended
	Sep. 30, 2014
Equity [Abstract]	'
Members' Equity and Net Income per Common and Class B Unit	'
	Members’ Equity and Net Income per Common and Class B Unit
	Cumulative Preferred Units
	The following table summarizes the Company’s Cumulative Preferred units outstanding at September 30, 2014 and December 31, 2013:
								September 30, 2014					December 31, 2013
		Earliest		Liquidation Preference		Distribution Rate		Units Outstanding		Carrying Value			Units Outstanding	Carrying Value
		Redemption Date		Per Share						(in thousands)				(in thousands)
	Series A	June 15, 2023		$25.00		7.88%		2,581,873		$	62,200		2,535,927	$	61,021
	Series B	April 15, 2024		$25.00		7.63%		7,000,000		$	169,265		—	$	—
	Series C	October 15, 2024		$25.00		7.75%		4,300,000		$	104,077		—	$	—
	Total Cumulative Preferred Units							13,881,873		$	335,542		2,535,927	$	61,021
	The Cumulative 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. The Cumulative Preferred Units can be redeemed, 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 Cumulative Preferred Units in the event of a change of control. Holders of the Cumulative 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. The Cumulative Preferred Units have a liquidation preference which is equal to the redemption price described above.
	See Note 10. Shelf Registration Statement for a discussion of the changes in our Cumulative Preferred units during nine months ended September 30, 2014.
	Common and Class B Units
	The common units represent limited liability company interests. Holders of Class B units have substantially the same rights and obligations as the holders of common units.
	The following is a summary of the changes in our common units issued during the nine months ended September 30, 2014 and the year ended December 31, 2013 (in thousands):
		September 30, 2014			December 31, 2013
	Beginning of period	78,337			58,706
	Issuance of Common units for the acquisition of oil and natural	—			1,075
	gas properties
	Issuance of Common units	4,864			18,377
	Unit-based compensation	359			179
	End of period	83,560			78,337
	There was no change in issued and outstanding Class B units during the nine months ended September 30, 2014 or the year ended December 31, 2013.
	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 attributable 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. Class B units participate in distributions; therefore, all Class B units were considered in the computation of basic net income per unit. The Cumulative Preferred Units have no participation rights and accordingly are excluded from the computation of basic net income per unit.
	The net income attributable to common and Class B unitholders and the weighted average units for calculating basic and diluted net income per common and Class B unit were as follows:
		Three Months Ended							Nine Months Ended
		September 30,							September 30,
		2014				2013			2014			2013
		(in thousands, except per unit amounts)
	Net income attributable to common and Class B unitholders	$	109,150			$	1,881		$	112,975		$	56,007
	Weighted average number of common and Class B units outstanding - basic	83,525				77,903			81,377			71,351
	Effect of dilutive securities:
	Phantom units	228				265			274			430
	Weighted average number of common and Class B units outstanding - diluted	83,753				78,168			81,651			71,781
	Net income per common and Class B unit
	Basic	$	1.31			$	0.02		$	1.39		$	0.78
	Diluted	$	1.3			$	0.02		$	1.38		$	0.78
	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 nine months ended September 30, 2014 and 2013 including each class of units issued and outstanding during the respective periods: common units and Class B units.
	Distributions Declared
	The Cumulative 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. Distributions on the 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 Preferred Units on a monthly basis at a monthly rate of 7.875% per annum of the liquidation preference of $25.00 per Series A Cumulative Preferred Unit, a monthly rate of 7.625% per annum of the liquidation preference of $25.00 per Series B Cumulative Preferred Unit and a monthly rate of 7.75% per annum of the liquidation preference of $25.00 per Series C Cumulative Preferred Unit.
	The following table shows the distribution amount, 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 October 20, 2014, our board of directors declared a cash distribution on the Cumulative Preferred Units and common and Class B units attributable to the month of September 2014. See Note 11. Subsequent Events for further discussion.
		Cash Distributions
	Distribution	Per Unit				Declared Date		Record Date	Payment Date
	2014
	Third Quarter
	August	$	0.21			September 19, 2014		October 1, 2014	October 15, 2014
	July	$	0.21			August 19, 2014		September 2, 2014	September 12, 2014
	Second Quarter
	June	$	0.21			July 16, 2014		August 1, 2014	August 14, 2014
	May	$	0.21			June 24, 2014		July 1, 2014	July 15, 2014
	April	$	0.21			May 20, 2014		June 2, 2014	June 13, 2014
	First Quarter
	March	$	0.21			April 17, 2014		May 1, 2014	May 15, 2014
	February	$	0.21			March 17, 2014		April 1, 2014	April 14, 2014
	January	$	0.2075			February 20, 2014		March 3, 2014	March 17, 2014
	2013
	Fourth Quarter
	December	$	0.2075			January 16, 2014		February 3, 2014	February 14, 2014
	November	$	0.2075			December 17, 2013		January 2, 2014	January 15, 2014
	October	$	0.2075			November 19, 2013		December 2, 2013	December 13, 2013
	Third Quarter
September	$	0.2075			October 21, 2013		November 1, 2013	November 14, 2013
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

UnitBased_Compensation

Unit-Based Compensation	9 Months Ended
	Sep. 30, 2014
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. As of September 30, 2014, an accrued liability was recognized and compensation expense of $0.9 million was recorded for the nine months ended September 30, 2014, related to these arrangements, which was classified in the selling, general and administrative expenses line item in the Consolidated Statement of Operations.
	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 Vanguard Natural Resources, LLC Long-Term Incentive Plan (“VNR LTIP”).
	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 distributions made by us on our units generally with respect to the number of restricted units that the executives received pursuant to the grant.
	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 distributions made by the Company on its units generally with respect to the number of phantom units that the executives received pursuant to the grant.
	On January 1, 2014, the executives were granted a total of 182,377 restricted units in accordance with the Amended Agreements.
	During the nine months ended September 30, 2014, our three independent board members were granted a total of 13,137 restricted units which will vest one year from the date of grant. In addition, VNR employees were granted a total of 66,150 restricted units under the VNR LTIP which will vest three years from the date of grant.
	As of September 30, 2014, an accrued liability of $0.7 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 has been recognized in the selling, general and administrative expense line item in the Consolidated Statements of Operations for each of the three months ended September 30, 2014 and 2013, and $1.3 million and $1.9 million for the nine months ended September 30, 2014 and 2013, respectively.
	Non-Vested Restricted Unit Grants
	Historically, we have granted restricted common units to employees and board members 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, 2014 is presented below:
		Number of		Weighted Average
		Non-vested  Restricted Units		Grant Date Fair Value
	Non-vested restricted units at December 31, 2013	248,611		$	28.57
	Granted	261,664		$	29.65
	Forfeited	(5,659	)	$	29.34
	Vested	(79,291	)	$	28.82
	Non-vested restricted units at September 30, 2014	425,325		$	29.18
	At September 30, 2014, there was approximately $9.2 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately 1.6 years.
	Our Consolidated Statements of Operations reflect non-cash compensation of $1.4 million and $0.9 million in the selling, general and administrative expenses line item for the three months ended September 30, 2014 and 2013, respectively, and $6.4 million and $4.4 million for the nine months ended September 30, 2014 and 2013, respectively.

Shelf_Registration_Statements

Shelf Registration Statements	9 Months Ended
	Sep. 30, 2014
Shelf Registration Statement [Abstract]	'
Shelf Registration Statement	'
	Shelf Registration Statement
	We have registered an indeterminate amount of Series A Cumulative Preferred Units, Series B Cumulative Preferred Units, Series C Cumulative Preferred Units common units, debt securities and guarantees of debt securities under our currently effective shelf registration statement filed with the SEC, as amended (the “Shelf Registration Statement”). In the future, we may issue additional debt and equity securities pursuant to a prospectus supplement to the Shelf Registration Statement.
	Net proceeds, terms and pricing of each offering of securities issued under the Shelf Registration Statement are determined at the time of such offerings. The Shelf Registration Statement does not provide assurance that we will or could sell any such securities. Our ability to utilize the Shelf Registration Statement for the purpose of issuing, from time to time, any combination of debt securities, common units or Cumulative 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.
	We have entered into an equity distribution agreement with respect to the issuance and sale of our Series A Cumulative Preferred Units and common units. Pursuant to the terms of the equity distribution agreement, we may sell from time to time through our sales agents, (i) our common units representing limited liability company interests having an aggregate offering price of up to $500.0 million, and (ii) our Series A Cumulative Preferred Units having an aggregate offering price of up to $250.0 million. The common units and Series A Cumulative Preferred Units to be sold under the equity distribution agreement are registered under our existing Shelf Registration Statement. During the nine months ended 2014, total net proceeds received under the equity distribution agreement were approximately $147.9 million, after commissions and fees, from the sales of 4,863,690 common units and $1.2 million, after commissions and fees, from the sales of 45,946 Series A Cumulative Preferred Units.
	Preferred Unit Equity Offerings
	On March 11, 2014, we completed a public offering of 7,000,000 7.625% Series B Cumulative Preferred Units at a price of $25.00 per unit. Offers were made pursuant to a prospectus supplement to the Shelf Registration Statement. We received proceeds of approximately $169.3 million from this offering, after deducting discounts of $5.5 million and offering costs of $0.2 million. We used the net proceeds from this offering to repay indebtedness outstanding under our Reserve-Based Credit Facility.
	On September 15, 2014, we completed a public offering of 4,000,000 7.75% Series C Cumulative Preferred Units at a price of $25.00 per unit. Offers were made pursuant to a prospectus supplement to the Shelf Registration Statement. We received proceeds of approximately $96.9 million from this offering, after deducting discounts of $3.2 million. On September 23, 2014, we received additional proceeds of approximately $7.3 million from the sale of an additional 300,000 Series C Cumulative Preferred Units that were purchased pursuant to the underwriters’ over-allotment option. We used the net proceeds from this offering to repay indebtedness outstanding under our Reserve-Based Credit Facility.
	Subsidiary Guarantors
	We and VNRF, our wholly-owned finance subsidiary, may co-issue securities pursuant to the registration statement 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 VNR that do not guarantee the securities will be minor.

Subsequent_Events

Subsequent Events	9 Months Ended
	Sep. 30, 2014
Subsequent Events [Abstract]	'
Subsequent Event	'
	Subsequent Events
	Common Unit Buyback Program
	On October 15, 2014, our Board of Directors authorized a $10.0 million dollar common unit buyback program. The program was approved for an initial three month period which authorizes us to make open market purchases pursuant to the Securities and Exchange Commission guidelines of Rule 10B-18. We intend to hold the common units to fund our long-term incentive plan as directed by the Compensation Committee.
	Distributions
	On October 20, 2014, our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of September 2014 of $0.21 per common and Class B unit ($2.52 on an annualized basis) expected to be paid on November 14, 2014 to Vanguard unitholders of record on November 3, 2014.
	Also on October 20, 2014, our board of directors declared a cash distribution for our preferred unitholders of $0.1641 per Series A Cumulative Preferred Unit, $0.15885 per Series B Cumulative Preferred Unit and $0.32292 per Series C Cumulative Preferred Unit to be paid on November 14, 2014 to Vanguard preferred unitholders of record on November 3, 2014. This marks the initial distribution payment of our Series C Cumulative Preferred Units for the period September 15, 2014 through November 14, 2014. Future monthly cash distributions for our Series C Cumulative Preferred Units will be $0.16146 per unit.
	Seventh Amendment to the Credit Agreement
	On October 30, 2014, we entered into the Seventh Amendment to the Credit Agreement, which provided for, among others, (a) the increase in the maximum amount of debt under capital leases from $2.0 million to $35.0 million and (b) the increase in the aggregate amount of restricted payments that can be used to repurchase the Company’s units over the term of the Credit Agreement from $10.0 million to $50.0 million.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2014
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, 2014 and December 31, 2013 and for the three and nine months ended September 30, 2014 and 2013 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. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income or members’ equity.
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, 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, 2014 or 2013.
	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.
New Pronouncements Issued But Not Yet Adopted	'
	New Pronouncement Issued But Not Yet Adopted:
	In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU No. 2014-09”), which amends the FASB ASC by adding new FASB ASC Topic 606, Revenue from Contracts with Customers, and superseding the revenue recognition requirements in FASB ASC 605, Revenue Recognition, and in most industry-specific topics. ASU No. 2014-09 provides new guidance concerning recognition and measurement of revenue and requires additional disclosures about the nature, timing and uncertainty of revenue and cash flows arising from contracts with customers. ASU No. 2014-09 becomes effective at the beginning of 2017. We are still evaluating the impact of ASU No. 2014-09 on our financial position or results of operations.
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, 2014
Business Acquisition [Line Items]	'
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 2014 and 2013, adjusted for (i) the assumption of asset retirement obligations and accretion expense for the properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired, (iii) interest expense on additional borrowings necessary to finance the acquisitions, and (iv) common units issued in the acquisition of properties completed on June 28, 2013. The net gains and losses on acquisitions of oil and natural gas properties were excluded from the pro forma results for the three and nine months ended September 30, 2014 and 2013. 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					Nine Months Ended
		September 30,					September 30,
		2014			2013		2014		2013
	Total revenues	$	279,601		$	197,151	$	616,234	$	639,492
	Net income attributable to Common and Class B	$	124,002		$	27,965	$	139,451	$	127,918
	unitholders
	Net income per Common and Class B unit:
	Basic	$	1.48		$	0.36	$	1.71	$	1.78
	Diluted	$	1.48		$	0.36	$	1.7	$	1.76
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					Nine Months Ended
		September 30,					September 30,
		2014			2013		2014		2013
		(in thousands)
	Pinedale Acquisition
	Revenues	$	36,947		$	—	$	106,163	$	—
	Excess of revenues over direct operating expenses	$	29,423		$	—	$	82,709	$	—
	Piceance Acquisition
	Revenues	$	283		$	—	$	283	$	—
	Excess of revenues over direct operating expenses	$	227		$	—	$	227	$	—
	All other acquisitions
	Revenues	$	20,442		$	12,849	$	52,489	$	23,649
	Excess of revenues over direct operating expenses	$	7,284		$	9,283	$	26,092	$	16,708
Pinedale Acquisition [Member]	'
Business Acquisition [Line Items]	'
Fair value of assets and liabilities acquired	'
	Fair value of assets and liabilities acquired	(in thousands)
	Oil and natural gas properties	$	600,123
	Inventory	244
	Asset retirement obligations	(12,404		)
	Imbalance liabilities	(171		)
	Other	(125		)
	Total fair value of assets and liabilities acquired	587,667
	Fair value of consideration transferred	555,553
	Gain on acquisition	$	32,114
Piceance Acquisition [Member]	'
Business Acquisition [Line Items]	'
Fair value of assets and liabilities acquired	'
	Fair value of assets and liabilities acquired	(in thousands)
	Oil and natural gas properties	$	521,401
	Asset retirement obligations	(19,452		)
	Imbalance and suspense liabilities	(236		)
	Total fair value of assets and liabilities acquired	501,713
	Fair value of consideration transferred	502,140
	Loss on acquisition	$	(427	)
2013 Acquisitions [Member]	'
Business Acquisition [Line Items]	'
Fair value of assets and liabilities acquired	'
	The following presents the values assigned to the net assets acquired in our 2013 acquisitions:
	Fair value of assets and liabilities acquired	(in thousands)
	Oil and natural gas properties	$	317,573
	Inventory	899
	Asset retirement obligations	(11,381		)
	Oil and natural gas revenue payable and imbalance liabilities	(2,843		)
	Total fair value of assets and liabilities acquired	304,248
	Fair value of consideration transferred	298,657
	Gain on acquisition	$	5,591

LongTerm_Debt_Tables

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2014
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, 2014				December 31, 2013
							(in thousands)
	Senior Secured Reserve-Based		Variable (1)		April 16, 2018		$	1,375,000			$	460,000
	Credit Facility
	Senior Notes		7.875% (2)		April 1, 2020		550,000				550,000
							$	1,925,000			$	1,010,000
	Unamortized discount on Senior Notes						(1,922		)		(2,121		)
	Total long-term debt						$	1,923,078			$	1,007,879
	-1	Variable interest rate was 2.16% and 1.92% at September 30, 2014 and December 31, 2013, 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, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Commodity Derivative Contracts Covering Anticipated Future Production	'
	As of September 30, 2014, 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, 2014 – December 31, 2014		17,725,180			$	4.42			457,700			$	90.83		69,000	$	40.87
	January 1, 2015 – December 31, 2015		66,795,000			$	4.4			692,000			$	91.18		246,375	$	46.34
	January 1, 2016 – December 31, 2016		55,083,000			$	4.47			146,400			$	89.98		—	$	—
	January 1, 2017 – December 31, 2017		27,677,000			$	4.32			73,000			$	86.6		—	$	—
	Call Options Sold
			Oil
	Contract Period		Bbls			Weighted Average
						Fixed Price
	October 1, 2014 – December 31, 2014		124,200			$	102.41
	January 1, 2015 – December 31, 2015		252,945			$	119.23
	January 1, 2016 – December 31, 2016		622,200			$	125
	Swaptions Sold
			Oil
	Contract Period		Bbls			Weighted Average
						Fixed Price
	January 1, 2015 – December 31, 2015		346,000			$	93.42
	Basis Swaps
			Gas
	Contract Period		MMBtu			Weighted Avg. Basis				Pricing Index
						Differential ($/MMBtu)
	October 1, 2014 – December 31, 2014		7,360,000			$	(0.20	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2015 – December 31, 2015		29,200,000			$	(0.28	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2016 – December 31, 2016		18,300,000			$	(0.24	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2017 – December 31, 2017		10,950,000			$	(0.22	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
			Oil
	Contract Period		Bbls			Weighted Avg. Basis				Pricing Index
						Differential ($/Bbl)
	October 1, 2014 – December 31, 2014		147,200			$	(0.84	)		WTI Midland and WTI Cushing Basis Differential
	October 1, 2014 – December 31, 2014		82,800			$	(1.05	)		West Texas Sour and WTI Cushing Basis Differential
	October 1, 2014 – December 31, 2014		46,000			$	(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
	Three-Way Collars
			Gas
	Contract Period		MMBtu			Floor				Ceiling				Put Sold
	October 1, 2014 – December 31, 2014		1,840,000			$	4.11			$	4.84			$	3.5
	January 1, 2015 – December 31, 2015		11,862,500			$	4.06			$	4.78			$	3.48
	January 1, 2016 – December 31, 2016		7,320,000			$	4			$	4.65			$	3.5
	January 1, 2017 – December 31, 2017		7,300,000			$	4			$	4.65			$	3.5
			Oil
	Contract Period		Bbls			Floor				Ceiling				Put Sold
	October 1, 2014 – December 31, 2014		326,600			$	93.52			$	101.29			$	72.54
	January 1, 2015 – December 31, 2015		1,984,055			$	91.84			$	99.45			$	74.41
	January 1, 2016 – December 31, 2016		1,061,400			$	90			$	96.18			$	73.62
	Put Options Sold
			Gas							Oil
	Contract Period		MMBtu			Put Sold				Bbls			Put Sold
						($/MMBtu)							($/Bbl)
	October 1, 2014 – December 31, 2014		920,000			$	3.5			18,400			$	75
	January 1, 2015 – December 31, 2015		9,125,000			$	3.5			692,000			$	72.36
	January 1, 2016 – December 31, 2016		1,830,000			$	3.5			146,400			$	75
	January 1, 2017 – December 31, 2017		1,825,000			$	3.5			73,000			$	75
	Range Bonus Accumulators
			Gas
	Contract Period		MMBtu			Bonus				Range Ceiling				Range Floor
	October 1, 2014 – December 31, 2014		368,000			$	0.2			$	4.75			$	3.25
	January 1, 2015 – December 31, 2015		1,460,000			$	0.2			$	4.75			$	3.25
			Oil
	Contract Period		Bbls			Bonus				Range Ceiling				Range Floor
October 1, 2014 – December 31, 2014		230,000			$	4.94			$	103.2			$	70.5
Interest Rate Derivative Contracts	'
	Interest Rate Swaps
	As of September 30, 2014, we had open interest rate derivative contracts as follows (in thousands):
	Period		Notional Amount				Fixed LIBOR Rates
	October 1, 2014 to December 10, 2016		$	20,000			2.17	%
	October 1, 2014 to October 31, 2016		$	40,000			1.65	%
	October 1, 2014 to August 5, 2015 (1)		$	30,000			2.25	%
	October 1, 2014 to August 6, 2016		$	25,000			1.8	%
	October 1, 2014 to October 31, 2016		$	20,000			1.78	%
	October 1, 2014 to September 23, 2016		$	75,000			1.15	%
	October 1, 2014 to March 7, 2016		$	75,000			1.08	%
	October 1, 2014 to September 7, 2016		$	25,000			1.25	%
	October 1, 2014 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 to August 5, 2018 at 2.25%.
	-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, 2014
	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		$	98,336			$	(22,134	)		$	76,202
	Interest rate derivative contracts		52				—				52
	Total derivative instruments		$	98,388			$	(22,134	)		$	76,254
	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		$	(23,976	)		$	22,134			$	(1,842	)
	Interest rate derivative contracts		(4,865		)		—				(4,865		)
	Total derivative instruments		$	(28,841	)		$	22,134			$	(6,707	)
			December 31, 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		$	107,307			$	(25,617	)		$	81,690
	Interest rate derivative contracts		98				—				98
	Total derivative instruments		$	107,405			$	(25,617	)		$	81,788
	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		$	(33,825	)		$	25,617			$	(8,208	)
	Interest rate derivative contracts		(6,869		)		—				(6,869		)
	Total derivative instruments		$	(40,694	)		$	25,617			$	(15,077	)
Reported Gains and Losses on Derivative Instruments	'
	Changes in fair value of our commodity and interest rate derivatives for the nine months ended September 30, 2014 and the year ended December 31, 2013 are as follows:
		Nine Months Ended September 30, 2014				Year Ended December 31, 2013
		(in thousands)
	Derivative asset at beginning of period, net	$	66,711			$	82,568
	Fair value of derivatives acquired	(1,344		)		—
	Net gains (losses) on commodity and interest rate derivative contracts	(12,193		)		11,160
	Settlements
	Cash settlements paid (received) on matured commodity derivative contracts	13,347				(30,905		)
	Cash settlements paid on matured interest rate derivative contracts	3,026				3,888
	Derivative asset at end of period, net	$	69,547			$	66,711

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2014
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, 2014
		Fair Value Measurements Using								Assets/Liabilities
		Level 1			Level 2			Level 3		at Fair value
	Assets:
	Commodity price derivative contracts	$	—		$	75,022		$	1,180	$	76,202
	Interest rate derivative contracts	—			52			—		52
	Total derivative instruments	$	—		$	75,074		$	1,180	$	76,254
	Liabilities:
	Commodity price derivative contracts	$	—		$	(1,842	)	$	—	$	(1,842	)
	Interest rate derivative contracts	—			(4,865		)	—		(4,865		)
	Total derivative instruments	$	—		$	(6,707	)	$	—	$	(6,707	)
		December 31, 2013
		Fair Value Measurements Using								Assets/Liabilities
		Level 1			Level 2			Level 3		at Fair value
	Assets:
	Commodity price derivative contracts	$	—		$	81,124		$	566	$	81,690
	Interest rate derivative contracts	—			98			—		98
	Total derivative instruments	$	—		$	81,222		$	566	$	81,788
	Liabilities:
	Commodity price derivative contracts	$	—		$	(8,208	)	$	—	$	(8,208	)
	Interest rate derivative contracts	—			(6,869		)	—		(6,869		)
	Total derivative instruments	$	—		$	(15,077	)	$	—	$	(15,077	)
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 (unobservable inputs) in the fair value hierarchy:
		Nine Months Ended
		September 30,
		2014			2013
		(in thousands)
	Unobservable inputs, beginning of period	$	566		$	(498	)
	Total gains (losses)	798			(1,122		)
	Settlements	(184		)	784
	Unobservable inputs, end of period	$	1,180		$	(836	)
	Change in fair value included in earnings related to derivatives	$	1,132		$	(12	)
	still held as of September 30, 2014 and 2013

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2014
Asset Retirement Obligation [Abstract]	'
Changes in Asset Retirement Obligations	'
	The asset retirement obligations as of September 30, 2014 and December 31, 2013 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the nine months ended September 30, 2014 and year ended December 31, 2013 were as follows (in thousands):
		September 30, 2014			December 31, 2013
	Asset retirement obligations, beginning of period	$	87,967		$	63,114
	Liabilities added during the current period	52,141			11,738
	Accretion expense	4,107			2,789
	Retirements	(443		)	(628		)
	Disposition of properties	(1,060		)	—
	Change in estimate	—			10,954
	Asset retirement obligation, end of period	142,712			87,967
	Less: current obligations	(9,725		)	(5,759		)
	Long-term asset retirement obligation, end of period	$	132,987		$	82,208

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2014
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, 2014. 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.
		30-Sep-14
		(in thousands)
	October 1, 2014 - December 31, 2014	$	4,814
	2015	17,461
	2016	13,987
	2017	11,840
	2018	11,261
	Thereafter	10,611
	Total	$	69,974

Members_Equity_and_Net_Income_1

Members' Equity and Net Income per Common and Class B Unit (Tables)	9 Months Ended
	Sep. 30, 2014
Equity [Abstract]	'
Cumulative Preferred Units	'
	The following table summarizes the Company’s Cumulative Preferred units outstanding at September 30, 2014 and December 31, 2013:
								September 30, 2014					December 31, 2013
		Earliest		Liquidation Preference		Distribution Rate		Units Outstanding		Carrying Value			Units Outstanding	Carrying Value
		Redemption Date		Per Share						(in thousands)				(in thousands)
	Series A	June 15, 2023		$25.00		7.88%		2,581,873		$	62,200		2,535,927	$	61,021
	Series B	April 15, 2024		$25.00		7.63%		7,000,000		$	169,265		—	$	—
	Series C	October 15, 2024		$25.00		7.75%		4,300,000		$	104,077		—	$	—
	Total Cumulative Preferred Units							13,881,873		$	335,542		2,535,927	$	61,021
Schedule of Common and Class B Units Outstanding Roll Forward	'
	The following is a summary of the changes in our common units issued during the nine months ended September 30, 2014 and the year ended December 31, 2013 (in thousands):
		September 30, 2014			December 31, 2013
	Beginning of period	78,337			58,706
	Issuance of Common units for the acquisition of oil and natural	—			1,075
	gas properties
	Issuance of Common units	4,864			18,377
	Unit-based compensation	359			179
	End of period	83,560			78,337
Schedule of Earnings Per Share, Basic and Diluted	'
	The net income attributable to common and Class B unitholders and the weighted average units for calculating basic and diluted net income per common and Class B unit were as follows:
		Three Months Ended							Nine Months Ended
		September 30,							September 30,
		2014				2013			2014			2013
		(in thousands, except per unit amounts)
	Net income attributable to common and Class B unitholders	$	109,150			$	1,881		$	112,975		$	56,007
	Weighted average number of common and Class B units outstanding - basic	83,525				77,903			81,377			71,351
	Effect of dilutive securities:
	Phantom units	228				265			274			430
	Weighted average number of common and Class B units outstanding - diluted	83,753				78,168			81,651			71,781
	Net income per common and Class B unit
	Basic	$	1.31			$	0.02		$	1.39		$	0.78
	Diluted	$	1.3			$	0.02		$	1.38		$	0.78
Distributions Declared	'
	The following table shows the distribution amount, 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 October 20, 2014, our board of directors declared a cash distribution on the Cumulative Preferred Units and common and Class B units attributable to the month of September 2014. See Note 11. Subsequent Events for further discussion.
		Cash Distributions
	Distribution	Per Unit				Declared Date		Record Date	Payment Date
	2014
	Third Quarter
	August	$	0.21			September 19, 2014		October 1, 2014	October 15, 2014
	July	$	0.21			August 19, 2014		September 2, 2014	September 12, 2014
	Second Quarter
	June	$	0.21			July 16, 2014		August 1, 2014	August 14, 2014
	May	$	0.21			June 24, 2014		July 1, 2014	July 15, 2014
	April	$	0.21			May 20, 2014		June 2, 2014	June 13, 2014
	First Quarter
	March	$	0.21			April 17, 2014		May 1, 2014	May 15, 2014
	February	$	0.21			March 17, 2014		April 1, 2014	April 14, 2014
	January	$	0.2075			February 20, 2014		March 3, 2014	March 17, 2014
	2013
	Fourth Quarter
	December	$	0.2075			January 16, 2014		February 3, 2014	February 14, 2014
	November	$	0.2075			December 17, 2013		January 2, 2014	January 15, 2014
	October	$	0.2075			November 19, 2013		December 2, 2013	December 13, 2013
	Third Quarter
	September	$	0.2075			October 21, 2013		November 1, 2013	November 14, 2013
	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

UnitBased_Compensation_Tables

Unit-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2014
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, 2014 is presented below:
		Number of		Weighted Average
		Non-vested  Restricted Units		Grant Date Fair Value
	Non-vested restricted units at December 31, 2013	248,611		$	28.57
	Granted	261,664		$	29.65
	Forfeited	(5,659	)	$	29.34
	Vested	(79,291	)	$	28.82
	Non-vested restricted units at September 30, 2014	425,325		$	29.18

Description_of_the_Business_De

Description of the Business (Details)	9 Months Ended
	Sep. 30, 2014
	operating_areas
Accounting Policies [Abstract]	'
Number of operating areas	9

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Details)	9 Months Ended
	Sep. 30, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Discount rate used in determining limitation of capitalized costs (in hundredths)	10.00%

Acquisitions_Details

Acquisitions (Details) (USD $)	0 Months Ended						9 Months Ended	12 Months Ended
	Jan. 31, 2014	Sep. 30, 2014	2-May-14	Aug. 29, 2014	Jun. 28, 2013	Apr. 02, 2013	Sep. 30, 2014	Dec. 31, 2013
	Pinedale Acquisition [Member]	Piceance Acquisition [Member]	Wamsutter Property Acquisition [Member]	Gulf Coast Acquisition [Member]	2013 Acquisitions [Member]	2013 Acquisitions [Member]	Other Smaller Acquisitions [Member]	Other Smaller Acquisitions [Member]
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'
Ownership interest conveyed	'	'	75.00%	'	'	'	'	'
Fair value of consideration transferred	$555,553,000	$502,140,000	$9,600,000	$269,900,000	'	$266,200,000	$17,700,000	$2,500,000
Effective date of acquisition	1-Oct-13	1-Jul-14	'	1-Jun-14	1-Jul-13	1-Jan-13	'	'
Gain on acquisition of oil and natural gas properties	32,114,000	'	'	'	'	'	'	'
Goodwill, Impairment Loss	'	427,000	'	'	'	'	'	'
Common units issued for the acquisition of oil and gas properties	'	'	'	'	$29,900,000	'	'	'
Common units issued for the acquisition of oil and gas properties, in units	'	'	'	'	1,075,000	'	'	'
Business acquisition, agreed price per unit	'	'	'	'	$27.65	'	'	'
Business acquisition, unit closing price value	'	'	'	'	$27.90	'	'	'

Acquisitions_Fair_Value_of_Ass

Acquisitions (Fair Value of Assets and Liabilities Acquired) (Details) (USD $)	0 Months Ended			12 Months Ended
	Jan. 31, 2014	Sep. 30, 2014	Sep. 30, 2014	Dec. 31, 2013
	Pinedale Acquisition [Member]	Piceance Acquisition [Member]	Piceance Acquisition [Member]	Other Acquistions [Member]
Fair value of assets and liabilities acquired	'	'	'	'
Oil and Gas Properties	$600,123,000	'	$521,401,000	$317,573,000
Inventory	244,000	'	'	899,000
Asset retirement obligations	-12,404,000	'	-19,452,000	-11,381,000
Imbalance liabilities	-171,000	'	-236,000	-2,843,000
Other	-125,000	'	'	'
Total fair value of assets and liabilities acquired	587,667,000	'	501,713,000	304,248,000
Fair value of consideration transferred	555,553,000	502,140,000	'	298,657,000
Gain on acquisition of oil and natural gas properties	32,114,000	'	'	5,591,000
Loss on acquisition	'	($427,000)	'	'

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, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Business Acquisition, Pro Forma Information [Abstract]	'	'	'	'
Proforma revenues	$279,601	$197,151	$616,234	$639,492
Proforma Net income (loss)	$124,002	$27,965	$139,451	$127,918
Net income per Common and Class B unit:	'	'	'	'
Business Acquisition, Pro Forma Earnings Per Share, Basic	$1.48	$0.36	$1.71	$1.78
Business Acquisition, Pro Forma Earnings Per Share, Diluted	$1.48	$0.36	$1.70	$1.76

Acquisitions_Acquiree_Earnings

Acquisitions (Acquiree Earnings) (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Pinedale Acquisition [Member]	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'
Revenues	$36,947	$0	$106,163	$0
Excess of revenues over direct operating expenses	29,423	0	82,709	0
Piceance Acquisition [Member]	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'
Revenues	283	0	283	0
Excess of revenues over direct operating expenses	227	0	227	0
Other Acquistions [Member]	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'
Revenues	20,442	12,849	52,489	23,649
Excess of revenues over direct operating expenses	$7,284	$9,283	$26,092	$16,708

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)	9 Months Ended
	Sep. 30, 2014		Sep. 29, 2014	Dec. 31, 2013
Senior Secured Reserve-Based Credit Facility [Abstract]	'		'	'
Outstanding borrowings	$1,925,000,000		'	$1,010,000,000
Senior Notes [Abstract]	'		'	'
Percentage of ownership in subsidiaries	100.00%		'	'
Members' equity available for distributions	349,000,000		'	'
Senior Secured Reserve-Based Credit Facility [Member]	'		'	'
Senior Secured Reserve-Based Credit Facility [Abstract]	'		'	'
Line of Credit Facility, Maximum Borrowing Capacity	3,500,000,000		'	'
Line of Credit Facility, Current Borrowing Capacity	2,000,000,000		1,525,000,000	'
Outstanding borrowings	1,375,000,000		'	460,000,000
Remaining borrowing capacity	622,200,000		'	'
Senior Notes [Abstract]	'		'	'
Maturity date	16-Apr-18		'	'
Senior Notes [Member]	'		'	'
Senior Secured Reserve-Based Credit Facility [Abstract]	'		'	'
Outstanding borrowings	550,000,000		'	550,000,000
Senior Notes [Abstract]	'		'	'
Aggregate principal amount	550,000,000		'	'
Stated interest rate (in hundredths)	7.88%	[1]	'	'
Maturity date	1-Apr-20		'	'
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%		'	'
Standby Letters of Credit [Member] | Senior Secured Reserve-Based Credit Facility [Member]	'		'	'
Senior Secured Reserve-Based Credit Facility [Abstract]	'		'	'
Line of Credit Facility, Current Borrowing Capacity	$2,800,000		'	'
[1]	Effective interest rate was 8.0%.

LongTerm_Debt_Financing_Arrang

Long-Term Debt - Financing Arrangements (Details) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Debt Instrument [Line Items]	'		'
Debt amount outstanding, gross	$1,925,000		$1,010,000
Unamortized discount	-1,922		-2,121
Total long-term debt	1,923,078		1,007,879
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	1,375,000		460,000
Variable interest rate	2.16%		1.92%
Senior Notes [Member]	'		'
Debt Instrument [Line Items]	'		'
Stated interest rate (in hundredths)	7.88%	[2]	'
Maturity date	1-Apr-20		'
Debt amount outstanding, gross	$550,000		$550,000
Effective interest rate (in hundredths)	8.00%		'
[1]	Variable interest rate was 2.16% and 1.92% at SeptemberB 30, 2014 and DecemberB 31, 2013, 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, 2014
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, 2014
	MMBTU
Fair value of derivatives [Abstract]	'
Maximum potential loss due to credit risk	$98,400,000
Fixed-Price Swaps [Member] | Gas [Member] | October 1, 2014 to December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	17,725,180
Weighted average fixed price (in dollars per unit)	4.42
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)	66,795,000
Weighted average fixed price (in dollars per unit)	4.4
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)	55,083,000
Weighted average fixed price (in dollars per unit)	4.47
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)	27,677,000
Weighted average fixed price (in dollars per unit)	4.32
Fixed-Price Swaps [Member] | Oil [Member] | October 1, 2014 to December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	457,700
Weighted average fixed price (in dollars per unit)	90.83
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)	692,000
Weighted average fixed price (in dollars per unit)	91.18
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)	146,400
Weighted average fixed price (in dollars per unit)	89.98
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)	73,000
Weighted average fixed price (in dollars per unit)	86.6
Fixed-Price Swaps [Member] | Natural Gas Liquids [Member] | October 1, 2014 to December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	69,000
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)	246,375
Weighted average fixed price (in dollars per unit)	46.34
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
Call Option Sold [Member] | Oil [Member] | October 1, 2014 to December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	124,200
Weighted average fixed price (in dollars per unit)	102.41
Call Option 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)	252,945
Weighted average fixed price (in dollars per unit)	119.23
Call Option 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 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)	346,000
Weighted average fixed price (in dollars per unit)	93.42
Basis Swaps [Member] | Gas [Member] | October 1, 2014 to December 31, 2014 [Member] | NW Rocky Mt-Henry Hub Index [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	7,360,000
Weighted average basis differential (in dollars per unit)	-0.2
Basis Swaps [Member] | Gas [Member] | January 1, 2015 - December 31, 2015 [Member] | NW Rocky Mt-Henry Hub Index [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	29,200,000
Weighted average basis differential (in dollars per unit)	-0.28
Basis Swaps [Member] | Gas [Member] | January 1, 2016 - December 31, 2016 [Member] | NW Rocky Mt-Henry Hub Index [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	18,300,000
Weighted average basis differential (in dollars per unit)	-0.24
Basis Swaps [Member] | Gas [Member] | January 1, 2017 to December 31, 2017 [Member] | NW Rocky Mt-Henry Hub Index [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	10,950,000
Weighted average basis differential (in dollars per unit)	-0.22
Basis Swaps [Member] | Oil [Member] | October 1, 2014 to December 31, 2014 [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] | October 1, 2014 to December 31, 2014 [Member] | WTS-Cushing 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] | October 1, 2014 to December 31, 2014 [Member] | LLS-Brent Index [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	46,000
Weighted average basis differential (in dollars per unit)	-3.95
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
Three-Way Collars [Member] | Gas [Member] | October 1, 2014 to December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	1,840,000
Weighted average price (in dollars per unit)	3.5
Floor (in dollars per unit)	4.11
Ceiling (in dollars per unit)	4.84
Three-Way Collars [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)	11,862,500
Weighted average price (in dollars per unit)	3.48
Floor (in dollars per unit)	4.06
Ceiling (in dollars per unit)	4.78
Three-Way Collars [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)	7,320,000
Weighted average price (in dollars per unit)	3.5
Floor (in dollars per unit)	4
Ceiling (in dollars per unit)	4.65
Three-Way Collars [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)	7,300,000
Weighted average price (in dollars per unit)	3.5
Floor (in dollars per unit)	4
Ceiling (in dollars per unit)	4.65
Three-Way Collars [Member] | Oil [Member] | October 1, 2014 to December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	326,600
Weighted average price (in dollars per unit)	72.54
Floor (in dollars per unit)	93.52
Ceiling (in dollars per unit)	101.29
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)	1,984,055
Weighted average price (in dollars per unit)	74.41
Floor (in dollars per unit)	91.84
Ceiling (in dollars per unit)	99.45
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)	1,061,400
Weighted average price (in dollars per unit)	73.62
Floor (in dollars per unit)	90
Ceiling (in dollars per unit)	96.18
Put Options Sold [Member] | Gas [Member] | October 1, 2014 to December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	920,000
Weighted average price (in dollars per unit)	3.5
Put 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)	9,125,000
Weighted average price (in dollars per unit)	3.5
Put 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)	1,830,000
Weighted average price (in dollars per unit)	3.5
Put Options Sold [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)	1,825,000
Weighted average price (in dollars per unit)	3.5
Put Options Sold [Member] | Oil [Member] | October 1, 2014 to December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	18,400
Weighted average price (in dollars per unit)	75
Put 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)	692,000
Weighted average price (in dollars per unit)	72.36
Put 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)	146,400
Weighted average price (in dollars per unit)	75
Put Options Sold [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)	73,000
Weighted average price (in dollars per unit)	75
Range Bonus Accumulators [Member] | Gas [Member] | October 1, 2014 to December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Floor (in dollars per unit)	3.25
Ceiling (in dollars per unit)	4.75
Notional amount (in MMBtu)	368,000
Bonus (in dollars per unit)	0.2
Range Bonus Accumulators [Member] | Gas [Member] | January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Floor (in dollars per unit)	3.25
Ceiling (in dollars per unit)	4.75
Notional amount (in MMBtu)	1,460,000
Bonus (in dollars per unit)	0.2
Range Bonus Accumulators [Member] | Oil [Member] | October 1, 2014 to December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Floor (in dollars per unit)	70.5
Ceiling (in dollars per unit)	103.2
Notional amount (in BBls)	230,000
Bonus (in dollars per unit)	4.94
Interest Rate Swaps [Member]	'
Interest rate derivative contracts [Abstract]	'
Notional amount	360,000,000
Interest Rate Swaps [Member] | Contract period October 1, 2014 to December 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 October 1, 2014 to October 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 October 1, 2014 to August 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 October 1, 2014 to August 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 October 1, 2014 to October 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 October 1, 2014 to September 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 October 1, 2014 to March 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 October 1, 2014 to September 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 October 1, 2014 to December 10, 2015 [Member]	'
Interest rate derivative contracts [Abstract]	'
Notional amount	$50,000,000	[2]
Fixed Libor Rates (in hundredths)	0.21%	[2]
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%
[1]	The counterparty has the option to extend the termination date of this contract to August 5, 2018 at 2.25%.
[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, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Offsetting Derivative Assets:	'	'
Gross amounts of recognized assets	$98,388	$107,405
Gross amounts offset in the consolidated balance sheets	-22,134	-25,617
Net Amounts Presented in the Consolidated Balance Sheets	76,254	81,788
Offsetting Derivative Liabilities:	'	'
Gross amounts of recognized liabilities	-28,841	-40,694
Gross amounts offset in the consolidated balance sheets	22,134	25,617
Net Amounts Presented in the Consolidated Balance Sheets	-6,707	-15,077
Commodity Contract [Member]	'	'
Offsetting Derivative Assets:	'	'
Gross amounts of recognized assets	98,336	107,307
Gross amounts offset in the consolidated balance sheets	-22,134	-25,617
Net Amounts Presented in the Consolidated Balance Sheets	76,202	81,690
Offsetting Derivative Liabilities:	'	'
Gross amounts of recognized liabilities	-23,976	-33,825
Gross amounts offset in the consolidated balance sheets	22,134	25,617
Net Amounts Presented in the Consolidated Balance Sheets	-1,842	-8,208
Interest Rate Contract [Member]	'	'
Offsetting Derivative Assets:	'	'
Gross amounts of recognized assets	52	98
Gross amounts offset in the consolidated balance sheets	0	0
Net Amounts Presented in the Consolidated Balance Sheets	52	98
Offsetting Derivative Liabilities:	'	'
Gross amounts of recognized liabilities	-4,865	-6,869
Gross amounts offset in the consolidated balance sheets	0	0
Net Amounts Presented in the Consolidated Balance Sheets	($4,865)	($6,869)

Price_and_Interest_Rate_Risk_M4

Price and Interest Rate Risk Management Activities - Change in Fair Value of Derivatives (Details) (USD $)	9 Months Ended		12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Fair Value, Net Derivative Asset (Liability), Reconciliation [Roll Forward]	'	'	'
Derivative asset at beginning of period, net	$66,711	$82,568	$82,568
Fair value of derivatives acquired	-1,344	'	0
Net gains (losses) on commodity and interest rate derivative contracts	-12,193	12,004	11,160
Cash settlement received on matured commodity derivative contracts	13,347	-20,862	-30,905
Cash settlements paid on matured interest rate derivative contracts	3,026	2,896	3,888
Derivative asset at end of period, net	$69,547	'	$66,711

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Debt Instrument, Fair Value Disclosure	$572,000,000	'
Liabilities:	'	'
Asset retirement obligations incurred and recorded	52,141,000	11,738,000
Average inflation rate (in hundredths)	2.40%	'
Fair Value Measured on a Recurring Basis [Member]	'	'
Assets:	'	'
Commodity price derivative contracts	76,202,000	81,690,000
Interest rate derivative contracts	52,000	98,000
Total derivative instruments	76,254,000	81,788,000
Liabilities:	'	'
Commodity price derivative contracts	-1,842,000	-8,208,000
Interest rate derivative contracts	-4,865,000	-6,869,000
Total derivative instruments	-6,707,000	-15,077,000
Fair Value Measured on a Recurring Basis [Member] | Fair Value Measurements Using Level 1 [Member]	'	'
Assets:	'	'
Commodity price derivative contracts	0	0
Interest rate derivative contracts	0	0
Total derivative instruments	0	0
Liabilities:	'	'
Commodity price derivative contracts	0	0
Interest rate derivative contracts	0	0
Total derivative instruments	0	0
Fair Value Measured on a Recurring Basis [Member] | Fair Value Measurements Using Level 2 [Member]	'	'
Assets:	'	'
Commodity price derivative contracts	75,022,000	81,124,000
Interest rate derivative contracts	52,000	98,000
Total derivative instruments	75,074,000	81,222,000
Liabilities:	'	'
Commodity price derivative contracts	-1,842,000	-8,208,000
Interest rate derivative contracts	-4,865,000	-6,869,000
Total derivative instruments	-6,707,000	-15,077,000
Fair Value Measured on a Recurring Basis [Member] | Fair Value Measurements Using Level 3 [Member]	'	'
Assets:	'	'
Commodity price derivative contracts	1,180,000	566,000
Interest rate derivative contracts	0	0
Total derivative instruments	1,180,000	566,000
Liabilities:	'	'
Commodity price derivative contracts	0	0
Interest rate derivative contracts	0	0
Total derivative instruments	$0	$0
Minimum [Member]	'	'
Liabilities:	'	'
Credit-adjusted risk-free interest rate (in hundredths)	5.08%	'
Maximum [Member]	'	'
Liabilities:	'	'
Credit-adjusted risk-free interest rate (in hundredths)	5.60%	'

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, 2014	Sep. 30, 2013	Jun. 30, 2013
Fair Value Measurements Using Level 3 [Member]	'	'	'
Unobservable inputs reconciliation	'	'	'
Unobservable inputs, beginning of period	$566	($498)	($836)
Total gains (losses)	798	-1,122	'
Settlements	-184	784	'
Unobservable inputs, end of period	1,180	'	-836
Change in fair value included in earnings related to derivatives still held as of September 30, 2014 and 2013	$1,132	($12)	'

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	9 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Changes in asset retirement obligations [Abstract]	'	'
Asset retirement obligations at beginning of period	$87,967	$63,114
Liabilities added during the current period	52,141	11,738
Accretion expense	4,107	2,789
Retirements	-443	-628
Disposition of properties	-1,060	0
Change in estimate	0	10,954
Total asset retirement obligations at end of period	142,712	87,967
Less: current obligations	-9,725	-5,759
Long-term asset retirement obligation at end of period	$132,987	$82,208

Commitments_and_Contingencies_1

Commitments and Contingencies (Transportation Demand Charges) (Details) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014
Gross future minimum transportation demand	'
October 1, 2014 - December 31, 2014	4,814
2015	17,461
2016	13,987
2017	11,840
2018	11,261
Thereafter	10,611
Total	69,974
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	'6 years

Members_Equity_and_Net_Income_2

Members' Equity and Net Income per Common and Class B Unit - Preferred Units Outstanding (Details) (USD $)	9 Months Ended
In Thousands, except Share data, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Class of Stock [Line Items]	'	'
Preferred Unit, Liquidation Preference Per Share	$25	'
Preferred units, outstanding	13,881,873	2,535,927
Preferred units, carrying value	$335,542	$61,021
Series A Preferred Units [Member]	'	'
Class of Stock [Line Items]	'	'
Preferred Unit, Liquidation Preference Per Share	$25	'
Preferred Unit, Distribution Rate, Percentage	7.88%	'
Preferred units, outstanding	2,581,873	2,535,927
Preferred units, carrying value	62,200	61,021
Series B Preferred Unit [Member]	'	'
Class of Stock [Line Items]	'	'
Preferred Unit, Liquidation Preference Per Share	$25	'
Preferred Unit, Distribution Rate, Percentage	7.63%	'
Preferred units, outstanding	7,000,000	0
Preferred units, carrying value	169,265	0
Series C Preferred Units [Member]	'	'
Class of Stock [Line Items]	'	'
Preferred Unit, Liquidation Preference Per Share	$25	'
Preferred Unit, Distribution Rate, Percentage	7.75%	'
Preferred units, outstanding	4,300,000	0
Preferred units, carrying value	$104,077	$0

Members_Equity_and_Net_Income_3

Members' Equity and Net Income per Common and Class B Unit - Common and Class B Units Rollforward (Details) (Common Units)	9 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Common Units	'	'
Increase (Decrease) in Members' Equity [Roll Forward]	'	'
Beginning of period	78,337	58,706
Issuance of Common units for the acquisition of oil and natural gas properties	0	1,075
Issuance of Common units	4,864	18,377
Unit-based compensation	359	179
End of period	83,560	78,337

Members_Equity_and_Net_Income_4

Members' Equity and Net Income per Common and Class B Unit - Net Income per Unit (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Equity [Abstract]	'	'	'	'
Preferred Unit, Liquidation Preference Per Share	$25	'	$25	'
Dilutive Securities Included in Computation of Earnings Per Share [Line Items]	'	'	'	'
Net Income Available to Common and Class B unitholders, Basic	$109,150	$1,881	$112,975	$56,007
Weighted Average Number of Shares Outstanding, Basic	83,525	77,903	81,377	71,351
Weighted Average Number of Shares Outstanding, Diluted	83,753	78,168	81,651	71,781
Net income per common and Class B unit, Basic	$1.31	$0.02	$1.39	$0.78
Net income per common and class B unit, Diluted	$1.30	$0.02	$1.38	$0.78
Phantom Share Units (PSUs) [Member]	'	'	'	'
Dilutive Securities Included in Computation of Earnings Per Share [Line Items]	'	'	'	'
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	228	265	274	430

Members_Equity_and_Net_Income_5

Members' Equity and Net Income per Common and Class B Unit - Distributions Declared (Details) (USD $)

Sep. 30, 2014

Aug. 31, 2014

Jul. 31, 2014

Jun. 30, 2014

31-May-14

Apr. 30, 2014

Mar. 31, 2014

Feb. 28, 2014

Jan. 31, 2014

Dec. 31, 2013

Nov. 30, 2013

Oct. 31, 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

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

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

Common Units

Common Units

Common Units

Common Units

Series A Preferred Units [Member]

Series B Preferred Unit [Member]

Series C Preferred Units [Member]

Class of Stock [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred Unit, Distribution Rate, Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7.88%

7.63%

7.75%

Preferred Unit, Liquidation Preference Per Share

$25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$25

$25

$25

Cash Distributions per Unit

'

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.20

$0.20

$0.20

$0.20

'

'

'

Cash distribution, declaration date

'

19-Sep-14

19-Aug-14

16-Jul-14

24-Jun-14

20-May-14

17-Apr-14

17-Mar-14

20-Feb-14

16-Jan-14

17-Dec-13

19-Nov-13

21-Oct-13

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

'

'

'

Cash Distributions Record Date

'

1-Oct-14

2-Sep-14

1-Aug-14

1-Jul-14

2-Jun-14

1-May-14

1-Apr-14

3-Mar-14

3-Feb-14

2-Jan-14

2-Dec-13

1-Nov-13

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

'

'

'

Cash Distributions Payment Date

'

15-Oct-14

12-Sep-14

14-Aug-14

15-Jul-14

13-Jun-14

15-May-14

14-Apr-14

17-Mar-14

14-Feb-14

15-Jan-14

13-Dec-13

14-Nov-13

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

'

'

'

UnitBased_Compensation_Executi

Unit-Based Compensation - Executive Employment Agreements (Details) (Amended Agreements [Member], USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014
	officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Number of executives in amended agreements	3
Selling, General and Administrative Expenses [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Non-cash compensation	0.9

UnitBased_Compensation_Restric

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

Sep. 30, 2014

Sep. 30, 2014

Jan. 01, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

In Millions, except Share data, unless otherwise specified

Board Member [Member]

Restricted Stock Units (RSUs) [Member]

Restricted Stock Units (RSUs) [Member]

Restricted Stock Units (RSUs) [Member]

Phantom Share Units (PSUs) [Member]

Phantom Share Units (PSUs) [Member]

Amended Agreements [Member]

Amended Agreements [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]

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 [Member]

Executive Officer [Member]

Employee [Member]

Board Member [Member]

Restricted Stock Units (RSUs) [Member]

Phantom Share Units (PSUs) [Member]

Phantom Share Units (PSUs) [Member]

Phantom Share Units (PSUs) [Member]

Phantom Share Units (PSUs) [Member]

Phantom Share Units (PSUs) [Member]

Restricted and Phantom Units [Member]

Restricted and Phantom Units [Member]

Restricted and Phantom Units [Member]

Restricted and Phantom Units [Member]

Amended Agreements [Member]

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Vesting period

'

'

'

'

'

'1 year

'3 years

'3 years

'

'

'

'

'

'

'

'

'

Percent of units vesting on each one-year anniversary

'

'

'

'

'

'

33.33%

33.33%

'

'

'

'

'

'

'

'

'

Phantom units granted, numbers of executives

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

13,137

182,377

66,150

'

'

'

'

'

'

'

'

'

'

'

'

'

Accrued liability

'

'

'

'

$0.70

'

'

'

'

'

'

'

'

'

'

'

'

Non-cash compensation

'

'

'

'

'

'

'

'

$0.20

$0.20

$1.30

$1.90

$1.40

$0.90

$6.40

$4.40

$0.90

UnitBased_Compensation_NonVest

Unit-Based Compensation - Non-Vested Restricted Unit Grants (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Restricted Stock Units (RSUs) [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Unrecognized compensation cost	$9.20	'	$9.20	'
Unrecognized compensation cost recognition period (in years)	'	'	'1 year 7 months	'
Number of Non-vested Units	'	'	'	'
Non-vested units at beginning of period (in units)	'	'	248,611	'
Granted (in units)	'	'	261,664	'
Forfeited (in units)	'	'	-5,659	'
Vested (in units)	'	'	-79,291	'
Non-vested units at end of period (in units)	425,325	'	425,325	'
Weighted Average Grant Date Fair Value	'	'	'	'
Non-vested units at beginning of period (in dollars per unit)	'	'	$28.57	'
Granted (in dollars per unit)	'	'	$29.65	'
Forfeited (in dollars per unit)	'	'	$29.34	'
Vested (in dollars per unit)	'	'	$28.82	'
Non-vested units at end of period (in dollars per unit)	$29.18	'	$29.18	'
Restricted and Phantom Units [Member] | Selling, General and Administrative Expenses [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Non-cash compensation	$1.40	$0.90	$6.40	$4.40

Shelf_Registration_Statements_

Shelf Registration Statements (Details) (USD $)	9 Months Ended					0 Months Ended				9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Mar. 11, 2014	Sep. 23, 2014	Sep. 15, 2014	Sep. 15, 2014	Sep. 30, 2014	Sep. 30, 2014
			Series A Preferred Units [Member]	Series B Preferred Unit [Member]	Series C Preferred Units [Member]	Shelf Registration Statement 2012 [Member]	Shelf Registration Statement 2012 [Member]	Shelf Registration Statement 2012 [Member]	Shelf Registration Statement 2012 [Member]	Distribution Agreement 2013 [Member]	Distribution Agreement 2013 [Member]
						Series B Preferred Unit [Member]	Series C Preferred Units [Member]	Series C Preferred Units [Member]	Series C Preferred Units [Member]	Common Units	Series A Preferred Units [Member]
Shelf Registration Statements [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Maximum offering under equity distribution agreement	'	'	'	'	'	'	'	'	'	$500,000,000	$250,000,000
Proceeds from Issuance or Sale of Equity	'	'	'	'	'	'	'	'	'	147,900,000	1,200,000
Units issued under public offerings (in units)	'	'	'	'	'	7,000,000	'	4,000,000	'	4,863,690	45,946
Preferred Unit, Distribution Rate, Percentage	'	'	7.88%	7.63%	7.75%	7.63%	'	7.75%	'	'	'
Units issued related to underwriter's overallotment option	'	'	'	'	'	'	300,000	'	'	'	'
Issue price of units (in dollars per share)	'	'	'	'	'	$25	'	'	$25	'	'
Offering costs	'	'	'	'	'	200,000	'	'	'	'	'
Proceeds from preferred unit offerings, net	274,521,000	60,635,000	'	'	'	169,300,000	7,300,000	96,900,000	'	'	'
Underwriter Discount	'	'	'	'	'	$5,500,000	'	$3,200,000	'	'	'

Subsequent_Events_Details

Subsequent Events (Details) (USD $)

Sep. 30, 2014

Oct. 15, 2014

Oct. 30, 2014

Aug. 31, 2014

Jul. 31, 2014

Jun. 30, 2014

31-May-14

Apr. 30, 2014

Mar. 31, 2014

Feb. 28, 2014

Jan. 31, 2014

Dec. 31, 2013

Nov. 30, 2013

Oct. 31, 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

Oct. 20, 2014

Oct. 20, 2014

Oct. 20, 2014

Oct. 20, 2014

Oct. 20, 2014

Oct. 20, 2014

Sep. 30, 2014

Oct. 30, 2014

Dec. 31, 2014

Subsequent Event [Member]

Subsequent Event [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

Common Units

Common Units

Common Units

Common Units

Common Units

Class B Units [Member]

Series A Preferred Units [Member]

Series B Preferred Unit [Member]

Series C Preferred Units [Member]

Cumulative Preferred units

Capital Lease Obligations [Member]

Capital Lease Obligations [Member]

Scenario, Forecast [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Series C Preferred Units [Member]

Subsequent Event [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock repurchase program, authorized amount

'

$10,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock repurchase program, initial period to make open market purchases

'

'3 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash distribution, declaration date

'

'

'

19-Sep-14

19-Aug-14

16-Jul-14

24-Jun-14

20-May-14

17-Apr-14

17-Mar-14

20-Feb-14

16-Jan-14

17-Dec-13

19-Nov-13

21-Oct-13

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

20-Oct-14

'

'

'

'

20-Oct-14

'

'

'

Cash distribution attributable, per unit

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$0.21

$0.21

$0.16

$0.16

$0.32

'

'

'

$0.16

Line of Credit Facility, Maximum Borrowing Capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,000,000

35,000,000

'

Cash distribution, annualized basis, per unit

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$2.52

$2.52

'

'

'

'

'

'

'

Maximum amount of restricted payment for unit repurchase allowed under the credit agreement

$10,000,000

'

$50,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'