Grizzly Energy (GRZZP) Inactive 10-Q5 Aug 142014 Q2 Quarterly reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information	6 Months Ended
Document and Entity Information	Jun. 30, 2014	Jul. 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	'	83,055,732
Document Fiscal Year Focus	'2014	'
Document Period End Date	30-Jun-14	'
Document Fiscal Period Focus	'Q2	'
Document Type	'10-Q	'
Amendment Flag	'false	'

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (USD $)	3 Months Ended		6 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Revenues:	'	'	'	'
Oil sales	$73,963	$69,701	$142,163	$128,217
Natural gas sales	69,806	36,010	133,348	63,534
NGLs revenue	17,750	11,026	38,748	21,668
Net gains (losses) on commodity derivative contracts	-38,398	58,595	-94,436	29,320
Total revenues	123,121	175,332	219,823	242,739
Production:	'	'	'	'
Lease operating expenses	34,293	26,509	64,715	50,682
Production and other taxes	16,529	9,964	31,563	19,307
Depreciation, depletion, amortization and accretion	51,508	42,911	95,118	81,604
Selling, general and administrative expenses	7,864	6,900	15,902	13,449
Total costs and expenses	110,194	86,284	207,298	165,042
Income from operations	12,927	89,048	12,525	77,697
Other income (expense):	'	'	'	'
Interest expense	-16,549	-15,963	-32,808	-31,401
Net gains (losses) on interest rate derivative contracts	-1,121	2,412	-1,579	2,127
Gains on acquisitions of oil and natural gas properties	0	5,827	32,114	5,827
Other	6	-23	131	28
Total other income (expense)	-17,664	-7,747	-2,142	-23,419
Net income (loss)	-4,737	81,301	10,383	54,278
Distributions to Preferred unitholders	-4,596	-152	-6,558	-152
Net income (loss) attributable to Common and Class B unitholders	($9,333)	$81,149	$3,825	$54,126
Net income (loss) per Common and Class B unit â€“ basic and diluted	($0.12)	$1.14	$0.05	$0.80
Common Units	'	'	'	'
Other income (expense):	'	'	'	'
Weighted Average Number of Shares Outstanding, Basic and Diluted	80,536	70,798	79,865	67,601
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 $)	Jun. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Current assets	'	'
Cash and cash equivalents	$22,113	$11,818
Trade accounts receivable, net	91,337	70,109
Derivative assets	9,432	21,314
Other currents assets	3,597	2,916
Total current assets	126,479	106,157
Oil and natural gas properties, at cost	3,213,473	2,523,671
Accumulated depletion, amortization and impairment	-804,814	-713,154
Oil and natural gas properties evaluated, net - full cost method	2,408,659	1,810,517
Other assets	'	'
Goodwill	420,955	420,955
Derivative assets	25,030	60,474
Other assets	29,196	91,538
Total assets	3,010,319	2,489,641
Accounts payable:	'	'
Trade	18,051	9,824
Affiliates	401	249
Accrued liabilities:	'	'
Lease operating	14,905	12,882
Developmental capital	19,894	10,543
Interest	11,646	11,989
Production and other taxes	23,371	16,251
Derivative liabilities	35,794	10,992
Oil and natural gas revenue payable	21,627	23,245
Distribution payable	17,996	16,499
Other	13,882	12,929
Total current liabilities	177,567	125,403
Long-term debt	1,273,011	1,007,879
Derivative liabilities	7,931	4,085
Asset retirement obligations, net of current portion	106,775	82,208
Other long-term liabilities	0	1,731
Total liabilities	1,565,284	1,221,306
Commitments and contingencies	'	'
Members' equity	'	'
Members' Equity	1,445,035	1,268,335
Total liabilities and members' equity	3,010,319	2,489,641
Series A Preferred Units [Member]	'	'
Members' equity	'	'
Members' Equity	61,682	61,021
Series B Preferred Unit [Member]	'	'
Members' equity	'	'
Members' Equity	169,265	0
Common Units	'	'
Members' equity	'	'
Members' Equity	1,206,473	1,199,699
Class B Units [Member]	'	'
Members' equity	'	'
Members' Equity	$7,615	$7,615

CONSOLIDATED_BALANCE_SHEETS_Un1

CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical)	Jun. 30, 2014	Dec. 31, 2013
Series A Preferred Units [Member]	'	'
Members' equity	'	'
Preferred units, issued	2,561,661	2,535,927
Preferred units, outstanding	2,561,661	2,535,927
Series B Preferred Unit [Member]	'	'
Members' equity	'	'
Preferred units, issued	7,000,000	0
Preferred units, outstanding	7,000,000	0
Common Units	'	'
Members' equity	'	'
Common units, issued	82,017,879	78,337,259
Common units, outstanding	82,017,879	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	Preferred units	Series A Preferred Units [Member]	Series B Preferred Unit [Member]	Common Units	Class B Units [Member]
In Thousands, except Share data, unless otherwise specified	Total	Preferred units	Series A Preferred Units [Member]	Series B Preferred Unit [Member]	Common Units	Class B Units [Member]
Balance at Dec. 31, 2012	$797,464	'	$0	$0	$789,849	$7,615
Balance (in units) at Dec. 31, 2012	'	'	0	0	58,706,000	420,000
Increase (Decrease) in Members' Equity [Roll Forward]	'	'	'	'	'	'
Issuance of Common units for the acquisition of oil and natural gas properties	29,992	'	'	'	29,992	'
Issuance of Common units for the acquisition of oil and natural gas properties (in units)	'	'	'	'	1,075,000	'
Distributions to Preferred unitholders	-2,634	'	'	'	'	'
Distributions to Common and Class B unitholders	-181,926	'	'	'	-181,926	0
Issuance of units, net of offering costs	'	61,021	61,021	0	498,360	'
Issuance of units, net of offering costs (in units)	'	'	2,536	0	18,377,000	'
Unit-based compensation	6,547	'	'	'	6,547	'
Unit-based compensation (in units)	'	'	'	'	179,000	'
Net income	59,511	'	'	'	59,511	'
Balance at Dec. 31, 2013	1,268,335	'	61,021	0	1,199,699	7,615
Balance (in units) at Dec. 31, 2013	'	'	2,536,000	0	78,337,000	420,000
Increase (Decrease) in Members' Equity [Roll Forward]	'	'	'	'	'	'
Distributions to Preferred unitholders	-6,558	'	'	'	'	'
Distributions to Common and Class B unitholders	-101,646	'	'	'	-101,646	0
Issuance of units, net of offering costs	'	169,926	661	169,265	100,397	'
Issuance of units, net of offering costs (in units)	'	'	26,000	7,000,000	3,324,000	'
Unit-based compensation	4,198	'	'	'	4,198	'
Unit-based compensation (in units)	'	'	'	'	357,000	'
Net income	10,383	'	'	'	10,383	'
Balance at Jun. 30, 2014	$1,445,035	'	$61,682	$169,265	$1,206,473	$7,615
Balance (in units) at Jun. 30, 2014	'	'	2,562,000	7,000,000	82,018,000	420,000

CONSOLIDATED_STATEMENTS_OF_MEM1

CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY (Unaudited) (Parenthetical) (USD $)	6 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Common Units	'	'
Issuance of members' units, offering costs	$38	$415
Preferred units	'	'
Issuance of members' units, offering costs	$222	$402

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)	6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
Operating activities	'	'
Net income (loss)	$10,383	$54,278
Adjustments to reconcile net income to net cash provided by operating activities:	'	'
Depreciation, depletion, amortization and accretion	95,118	81,604
Amortization of deferred financing costs	1,720	1,909
Amortization of debt discount	132	121
Compensation related items	4,010	3,503
Net (gains) losses on commodity and interest rate derivative contracts	96,015	-31,447
Cash settlement received on matured commodity derivative contracts	-19,380	18,721
Cash settlements and fees paid on interest rate derivative contracts	-2,005	-1,909
Gain on acquisition of oil and natural gas properties	-32,114	-5,827
Changes in operating assets and liabilities:	'	'
Trade accounts receivable	-21,228	-24,177
Other current assets	3	-783
Premiums paid on commodity derivative contracts	-983	-93
Accounts payable and oil and natural gas revenue payable	6,609	1,070
Payables to affiliates	152	234
Accrued expenses and other current liabilities	16,898	22,117
Other assets	-403	-366
Net cash provided by operating activities	154,927	118,955
Investing activities	'	'
Additions to property and equipment	-480	-1,545
Additions to oil and natural gas properties	-61,524	-29,418
Acquisitions of oil and natural gas properties	-509,416	-270,535
Deposits and prepayments of oil and natural gas properties	-3,685	-1,047
Proceeds from Sale of Oil and Gas Property and Equipment	1,950	0
Net cash used in investing activities	-573,155	-302,545
Financing activities	'	'
Proceeds from long-term debt	595,000	388,500
Repayment of long-term debt	-330,000	-638,500
Proceeds from preferred unit offerings, net	169,926	60,880
Proceeds from issuance of common units, net	100,397	468,100
Distributions to Preferred unitholders	-5,792	0
Distributions to Common and Class B unitholders	-100,915	-80,289
Financing fees	-93	-2,053
Net cash provided by financing activities	428,523	196,638
Net increase in cash and cash equivalents	10,295	13,048
Cash and cash equivalents, beginning of period	11,818	11,563
Cash and cash equivalents, end of period	22,113	24,611
Supplemental cash flow information:	'	'
Cash paid for interest	31,238	29,470
Non-cash financing and investing activities:	'	'
Asset retirement obligations	$25,328	$9,855

Description_of_the_Business

Description of the Business	6 Months Ended
	Jun. 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 Permian Basin in West Texas and New Mexico;


	•	the Green River Basin in Wyoming;


	•	the Big Horn Basin in Wyoming and Montana;


	•	the Arkoma Basin in Arkansas and Oklahoma;


	•	the Gulf Coast Basin in Texas and Mississippi;


	•	the Piceance Basin in Colorado;


	•	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 and Series B preferred units are also listed on the NASDAQ under the symbols “VNRAP” and “VNRBP,” respectively.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 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 June 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 June 30, 2014 and December 31, 2013 and for the three and six months ended June 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 six months ended June 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 Pronouncements 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	6 Months Ended
	Jun. 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

	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 $549.1 million in cash. We refer to this acquisition as the “Pinedale Acquisition.” The purchase price is subject to additional customary post-closing adjustments to be determined based on an effective date of October 1, 2013. 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		$	593,695

	Inventory		244

	Asset retirement obligations		(12,404		)
	Imbalance liabilities		(209		)
	Other		(124		)
	Total fair value of assets and liabilities acquired		581,202

	Fair value of consideration transferred		549,088

	Gain on acquisition		$	32,114


	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 (as defined below) and is subject to customary final post-closing adjustments to be determined based on an effective date of January 1, 2014.

	During the six months ended June 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 $4.2 million.

	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 six months ended June 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 gain on acquisition of oil and natural gas properties was excluded from the pro forma results for the six months ended June 30, 2014. 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						Six Months Ended
		June 30,						June 30,
		2014				2013		2014			2013
Total revenues		$	123,373			$	221,151	$	235,540		$	331,800

Net income (loss) attributable to Common and Class B		$	(9,690	)		$	86,868	$	(26,599	)	$	67,861
unitholders
Net income (loss) per unit:
Common & Class B units – basic and diluted		$	(0.12	)		$	1.2	$	(0.33	)	$	0.98


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 June 30,						Six Months Ended June 30,
		2014				2013		2014			2013
		(in thousands)
Pinedale Acquisition
Revenues		$	39,575			$	—	$	69,216		$	—

Excess of revenues over direct operating expenses		$	30,196			$	—	$	53,286		$	—

All other acquisitions

Revenues		$	17,212			$	10,800	$	32,047		$	10,800

Excess of revenues over direct operating expenses		$	11,186			$	7,425	$	20,910		$	7,425

LongTerm_Debt

Long-Term Debt	6 Months Ended
Long-Term Debt	Jun. 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		June 30, 2014				December 31, 2013
							(in thousands)
	Senior Secured Reserve-Based		Variable (1)		April 16, 2018		$	725,000			$	460,000
	Credit Facility		Variable (1)		April 16, 2018		$	725,000			$	460,000
	Senior Notes		7.875% (2)		April 1, 2020		550,000				550,000
	Senior Notes		7.875% (2)		April 1, 2020		550,000				550,000
							$	1,275,000			$	1,010,000
							$	1,275,000			$	1,010,000
	Unamortized discount on Senior Notes						(1,989		)		(2,121		)
	Total long-term debt						$	1,273,011			$	1,007,879
	Total long-term debt						$	1,273,011			$	1,007,879


	-1	Variable interest rate was 1.90% and 1.92% at June 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 $1.525 billion (the “Reserve-Based Credit Facility”). As of June 30, 2014, there were $725.0 million of outstanding borrowings and $797.2 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).

	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 June 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 June 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 June 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 June 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, $355.1 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	6 Months Ended
Price and Interest Rate Risk Management Activities	Jun. 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 six months ended June 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 June 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
	Contract Period		MMBtu			Fixed Price				Bbls			WTI Price		Bbls	Fixed Price
	July 1, 2014 – December 31, 2014		35,450,360			$	4.42			915,400			$	90.83	138,000	$	40.87
	July 1, 2014 – December 31, 2014		35,450,360			$	4.42			915,400			$	90.83	138,000	$	40.87
	January 1, 2015 – December 31, 2015		69,532,500			$	4.39			692,000			$	91.18	91,250	$	42
	January 1, 2015 – December 31, 2015		69,532,500			$	4.39			692,000			$	91.18	91,250	$	42
	January 1, 2016 – December 31, 2016		53,253,000			$	4.48			146,400			$	89.98	—	$	—
	January 1, 2016 – December 31, 2016		53,253,000			$	4.48			146,400			$	89.98	—	$	—
	January 1, 2017 – December 31, 2017		25,852,000			$	4.32			73,000			$	86.6	—	$	—
	January 1, 2017 – December 31, 2017		25,852,000			$	4.32			73,000			$	86.6	—	$	—

	Swaptions and Call Options Sold

	Calls were sold or options were provided to counterparties under swaption agreements to extend the swap into subsequent years as follows:



			Oil
	Contract Period		Bbls			Weighted Average
	Contract Period		Bbls			Fixed Price
	July 1, 2014 – December 31, 2014		248,400			$	102.41
	July 1, 2014 – December 31, 2014		248,400			$	102.41
	January 1, 2015 – December 31, 2015		598,945			$	104.32
	January 1, 2015 – December 31, 2015		598,945			$	104.32
	January 1, 2016 – December 31, 2016		622,200			$	125
	January 1, 2016 – December 31, 2016		622,200			$	125

	Basis Swaps


			Gas
	Contract Period		MMBtu			Weighted Avg. Basis				Pricing Index
	Contract Period		MMBtu			Differential ($/MMBtu)				Pricing Index
	July 1, 2014 – December 31, 2014		14,720,000			$	(0.20	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	July 1, 2014 – December 31, 2014		14,720,000			$	(0.20	)
	January 1, 2015 – December 31, 2015		29,200,000			$	(0.28	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2015 – December 31, 2015		29,200,000			$	(0.28	)
	January 1, 2016 – December 31, 2016		18,300,000			$	(0.24	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2016 – December 31, 2016		18,300,000			$	(0.24	)
	January 1, 2017 – December 31, 2017		10,950,000			$	(0.22	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2017 – December 31, 2017		10,950,000			$	(0.22	)



			Oil
	Contract Period		Bbls			Weighted Avg. Basis				Pricing Index
	Contract Period		Bbls			Differential ($/Bbl)				Pricing Index
	July 1, 2014 – December 31, 2014		294,400			$	(0.84	)		WTI Midland and WTI Cushing Basis Differential
	July 1, 2014 – December 31, 2014		294,400			$	(0.84	)		WTI Midland and WTI Cushing Basis Differential
	July 1, 2014 – December 31, 2014		165,600			$	(1.05	)		West Texas Sour and WTI Cushing Basis Differential
	July 1, 2014 – December 31, 2014		165,600			$	(1.05	)		West Texas Sour and WTI Cushing Basis Differential
July 1, 2014 – December 31, 2014		92,000			$	(3.95	)		Light Louisiana Sweet Crude and Brent Basis Differential
July 1, 2014 – December 31, 2014		92,000			$	(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
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
July 1, 2014 – December 31, 2014		1,840,000			$	4.21			$	5			$	3.5
July 1, 2014 – December 31, 2014		1,840,000			$	4.21			$	5			$	3.5



		Oil
Contract Period		Bbls			Floor				Ceiling				Put Sold
July 1, 2014 – December 31, 2014		653,200			$	93.52			$	101.29			$	72.54
July 1, 2014 – December 31, 2014		653,200			$	93.52			$	101.29			$	72.54
January 1, 2015 – December 31, 2015		1,838,055			$	91.99			$	99.75			$	74.16
January 1, 2015 – December 31, 2015		1,838,055			$	91.99			$	99.75			$	74.16
January 1, 2016 – December 31, 2016		915,000			$	90			$	96.25			$	70
January 1, 2016 – December 31, 2016		915,000			$	90			$	96.25			$	70


Put Options Sold


		Gas							Oil
Contract Period		MMBtu			Put Sold				Bbls			Put Sold
Contract Period		MMBtu			($/MMBtu)				Bbls			($/Bbl)
July 1, 2014 – December 31, 2014		1,840,000			$	3.5			36,800			$	75
July 1, 2014 – December 31, 2014		1,840,000			$	3.5			36,800			$	75
January 1, 2015 – December 31, 2015		7,300,000			$	3.5			692,000			$	72.36
January 1, 2015 – December 31, 2015		7,300,000			$	3.5			692,000			$	72.36
January 1, 2016 – December 31, 2016		—			$	—			146,400			$	75
January 1, 2016 – December 31, 2016		—			$	—			146,400			$	75
January 1, 2017 – December 31, 2017		—			$	—			73,000			$	75
January 1, 2017 – December 31, 2017		—			$	—			73,000			$	75



Range Bonus Accumulators


		Gas
Contract Period		MMBtu			Bonus				Range Ceiling				Range Floor
July 1, 2014 – December 31, 2014		736,000			$	0.2			$	4.75			$	3.25
July 1, 2014 – December 31, 2014		736,000			$	0.2			$	4.75			$	3.25
January 1, 2015 – December 31, 2015		1,460,000			$	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
July 1, 2014 – December 31, 2014		460,000			$	4.94			$	103.2			$	70.5
July 1, 2014 – December 31, 2014		460,000			$	4.94			$	103.2			$	70.5


Interest Rate Swaps

As of June 30, 2014, we had open interest rate derivative contracts as follows (in thousands):


Period		Notional Amount				Fixed LIBOR Rates
July 1, 2014 to December 10, 2016		$	20,000			2.17	%
July 1, 2014 to December 10, 2016		$	20,000			2.17	%
July 1, 2014 to October 31, 2016		$	40,000			1.65	%
July 1, 2014 to October 31, 2016		$	40,000			1.65	%
July 1, 2014 to August 5, 2015 (1)		$	30,000			2.25	%
July 1, 2014 to August 5, 2015 (1)		$	30,000			2.25	%
July 1, 2014 to August 6, 2016		$	25,000			1.8	%
July 1, 2014 to August 6, 2016		$	25,000			1.8	%
July 1, 2014 to October 31, 2016		$	20,000			1.78	%
July 1, 2014 to October 31, 2016		$	20,000			1.78	%
July 1, 2014 to September 23, 2016		$	75,000			1.15	%
July 1, 2014 to September 23, 2016		$	75,000			1.15	%
July 1, 2014 to March 7, 2016		$	75,000			1.08	%
July 1, 2014 to March 7, 2016		$	75,000			1.08	%
July 1, 2014 to September 7, 2016		$	25,000			1.25	%
July 1, 2014 to September 7, 2016		$	25,000			1.25	%
July 1, 2014 to December 10, 2015 (2)		$	50,000			0.21	%
July 1, 2014 to December 10, 2015 (2)		$	50,000			0.21	%
Total		$	360,000
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):



		June 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		$	62,496			$	(28,034	)		$	34,462
Commodity price derivative contracts		$	62,496			$	(28,034	)		$	34,462
Total derivative instruments		$	62,496			$	(28,034	)		$	34,462
Total derivative instruments		$	62,496			$	(28,034	)		$	34,462

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		$	(65,414	)		$	28,034			$	(37,380	)
Commodity price derivative contracts		$	(65,414	)		$	28,034			$	(37,380	)
Interest rate derivative contracts		(6,345		)		—				(6,345		)
Interest rate derivative contracts		(6,345		)		—				(6,345		)
Total derivative instruments		$	(71,759	)		$	28,034			$	(43,725	)
Total derivative instruments		$	(71,759	)		$	28,034			$	(43,725	)


		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
Commodity price derivative contracts		$	107,307			$	(25,617	)		$	81,690
Interest rate derivative contracts		98				—				98
Interest rate derivative contracts		98				—				98
Total derivative instruments		$	107,405			$	(25,617	)		$	81,788
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	)
Commodity price derivative contracts		$	(33,825	)		$	25,617			$	(8,208	)
Interest rate derivative contracts		(6,869		)		—				(6,869		)
Interest rate derivative contracts		(6,869		)		—				(6,869		)
Total derivative instruments		$	(40,694	)		$	25,617			$	(15,077	)
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 $62.5 million at June 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 June 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 six months ended June 30, 2014 and the year ended December 31, 2013 are as follows:



	Six Months Ended June 30, 2014				Year Ended December 31, 2013
	(in thousands)
Derivative asset at beginning of period, net	$	66,711			$	82,568
Derivative asset at beginning of period, net	$	66,711			$	82,568
Fair value of derivatives acquired	(1,344		)		—
Fair value of derivatives acquired	(1,344		)		—
Net gains (losses) on commodity and interest rate derivative contracts	(96,015		)		11,160
	(96,015		)		11,160
Settlements
Cash settlements paid (received) on matured commodity derivative contracts	19,380				(30,905		)
	19,380				(30,905		)
Cash settlements paid on matured interest rate derivative contracts	2,005				3,888
	2,005				3,888
Derivative asset (liability) at end of period, net	$	(9,263	)		$	66,711
Derivative asset (liability) at end of period, net	$	(9,263	)		$	66,711

Fair_Value_Measurements

Fair Value Measurements	6 Months Ended
	Jun. 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 June 30, 2014, the fair value of our Senior Notes was estimated to be $597.4 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):



			June 30, 2014
			Fair Value Measurements Using											Assets/Liabilities
			Level 1			Level 2				Level 3				at Fair value
	Assets:
	Commodity price derivative contracts		$	—		$	34,462			$	—			$	34,462

	Total derivative instruments		$	—		$	34,462			$	—			$	34,462

	Liabilities:
	Commodity price derivative contracts		$	—		$	(35,626	)		$	(1,754	)		$	(37,380	)

	Interest rate derivative contracts		—			(6,345		)						(6,345		)

	Total derivative instruments		$	—		$	(41,971	)		$	(1,754	)		$	(43,725	)




			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 in the fair value hierarchy:


		Unobservable Inputs
		(Level 3)
		Six Months Ended
		June 30,
		2014			2013
		(in thousands)
Unobservable inputs, beginning of period		$	566		$	(498	)

Total gains (losses)		(1,606		)	671

Settlements		(714		)	1,200

Unobservable inputs, end of period		$	(1,754	)	$	1,373


Change in fair value included in earnings related to derivatives		$	(1,965	)	$	2,324
still held as of June 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 six months ended June 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 $25.3 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	6 Months Ended
	Jun. 30, 2014
Asset Retirement Obligation [Abstract]	'
Asset Retirement Obligations	'
	Asset Retirement Obligations

	The asset retirement obligations as of June 30, 2014 and December 31, 2013 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the six months ended June 30, 2014 and year ended December 31, 2013 were as follows (in thousands):


		June 30, 2014			December 31, 2013
	Asset retirement obligations, beginning of period	$	87,967		$	63,114

	Liabilities added during the current period	25,328			11,738

	Accretion expense	2,603			2,789

	Retirements	(601		)	(628		)
	Disposition of properties	(875		)	—

	Change in estimate	—			10,954

	Asset retirement obligation, end of period	114,422			87,967

	Less: current obligations	(7,647		)	(5,759		)
	Long-term asset retirement obligation, end of period	$	106,775		$	82,208

Commitments_and_Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	Commitments and Contingencies

	Transportation Demand Charges

	As of June 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 June 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.


		(in thousands)
	July 1, 2014 - December 31, 2014	$	5,300

	2015	7,912

	2016	5,530

	2017	3,978

	2018	3,398

	Thereafter	3,404

	Total	$	29,522


	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.

Preferred_Units_Common_Units_a

Preferred Units, Common Units and Net Income per Common Unit	6 Months Ended
	Jun. 30, 2014
Earnings Per Share [Abstract]	'
Preferred Units, Common Units and Net Income per Unit	'
	Members’ Equity and Net Income per Common and Class B Unit

	Preferred Units

	Preferred units represent preferred equity company interests. As of June 30, 2014, preferred units issued and outstanding include our 7.875% Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Preferred Units”) and our 7.625% Series B Cumulative Redeemable Perpetual Preferred Units (“Series B Preferred Units”) (collectively the “Preferred Units”).

	The 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. We may redeem the Series A Preferred Units at any time on or after June 15, 2023 and we may redeem our Series B Preferred Units at any time on or after April 15, 2024. The 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 Preferred Units in the event of a change of control. Holders of the 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 Preferred Units have a liquidation preference which is equal to the redemption price described above.

	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.

	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 Preferred Units have no participation rights and accordingly are excluded from the computation of basic net income per unit.

	For the three and six months ended June 30, 2014, 485,038 unvested phantom units granted to officers, board members and employees under the VNR LTIP have been excluded in the computation of net income per common and Class B unit as they had no dilutive effect. For the three and six months ended June 30, 2013, 561,934 unvested phantom units granted to officers, board members and employees under the VNR LTIP date have been excluded in the computation of net income per common and Class B unit as they had no dilutive effect.

	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 six months ended June 30, 2014 and 2013 including each class of units issued and outstanding during the respective periods: common units and Class B units. Net income attributable to common and Class B unitholders per unit is allocated to the common units and the Class B units on an equal basis.

	Distributions Declared

	The 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 Preferred Unit and a monthly rate of 7.625% per annum of the liquidation preference of $25.00 per Series B 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 July 16, 2014, our board of directors declared a cash distribution on the Preferred Units and common and Class B units attributable to the month of June 2014. See Note 11. Subsequent Events for further discussion.



			Cash Distributions
	Distribution		Per Unit			Declared Date		Record Date		Payment Date
	2014
	Second Quarter
	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	6 Months Ended
	Jun. 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. Each of the four components will be weighted equally in calculating the respective executive officer’s annual bonus. The annual bonus does not require a minimum payout, although the maximum payout may not exceed two (2) times the executive’s respective annual base salary. As of June 30, 2014, an accrued liability was recognized and compensation expense of $0.6 million was recorded related to these arrangements, which was classified in the selling, general and administrative expenses line item in the Consolidated Statement of Operations.

	In the event of the Company’s Change in Control, as defined in the Vanguard Natural Resources, LLC Long-Term Incentive Plan (“VNR LTIP”), the executives are entitled to certain change in control payments and benefits, consisting of: (i) an amount equal to two (2) times their then-current base salary and annual bonus and (ii) accelerated vesting of any outstanding restricted units, phantom units, or any other awards granted under the VNR LTIP held by the executives at the time of the change of control, with any settlement of these awards being made according to the terms of the VNR LTIP and the applicable individual award agreement.

	The executives are entitled to severance payments and benefits upon certain qualifying terminations. Upon a termination by VNRH without “Cause” (as such term is defined in the Amended Agreements) or termination by either executive for “Good Reason” (as such term is defined in the Amended Agreements), the executive is entitled to (i) an amount equal to three (3) times the executive’s then-current base salary and (ii) accelerated vesting of any outstanding restricted units, phantom units or any other awards granted under the VNR LTIP held by the executives at the time of such termination, with any settlement of these awards being made according to the terms of the VNR LTIP. Upon an executive’s termination by “Disability” (as such term is defined in the Amended Agreements) or death, the executive is entitled to (a) an amount equal to one times the executive’s then-current base salary and (b) accelerated vesting of any outstanding restricted units, phantom units or any other awards granted under the VNR LTIP held by the executives at the time of such termination, with any settlement of these awards being made according to the terms of the VNR LTIP. As a condition to receiving any of the severance payments and benefits heretofore described, the terminated executive (or his legal representative, as applicable) must execute and not revoke a customary severance and release agreement, including a waiver of all claims.

	The Amended Agreements also provide that the executives are eligible to participate in the benefit programs generally available to senior executives of VNRH. The Amended Agreements also contain standard non-competition, non-solicitation and confidentiality provisions.

	Restricted and Phantom Units

	Under the Amended Agreements, the executives are also eligible to receive annual equity-based compensation awards, consisting of restricted units and/or phantom units granted under the VNR LTIP. Each of the executives is eligible to receive annual equity-based compensation awards having an aggregate fair market value equal to the executive’s then-current annual base salary times a set multiplier, which such multiplier is five (5) times in the case of Mr. Smith, three and a half (3.5) times in the case of Mr. Robert, and two and three-quarters (2.75) times in the case of Mr. Pence.

	The restricted units are subject to a three-year vesting period. One-third of the aggregate number of the units vest on each one-year anniversary of the date of grant so long as the executive remains continuously employed with the Company. The restricted units include a tandem grant of distribution equivalent rights (“DERs”), which entitle the executives to receive the value of any distributions made by us on our units generally with respect to the number of restricted units that the executives received pursuant to the grant. In the event the executive is terminated without Cause, or the executive resigns for Good Reason, or the executive is terminated due to his death or Disability, all unvested outstanding restricted units shall receive accelerated vesting. If the executive is terminated for Cause, all unvested restricted units are forfeited. Upon the occurrence of a Change of Control, all unvested outstanding restricted units shall receive accelerated vesting.


	The phantom units are also subject to a three-year vesting period. One-third of the aggregate number of the units vest on each one-year anniversary of the date of grant so long as the executive remains continuously employed with the Company. The phantom units include a tandem grant of DERs, which entitle the executives to receive the value of any 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. In the event the executive is terminated without Cause, or the executive resigns for Good Reason, or the executive is terminated due to his death or Disability, all unvested outstanding phantom units shall receive accelerated vesting. If the executive is terminated for Cause, all unvested restricted units are forfeited. Upon the occurrence of a Change of Control, all unvested outstanding restricted units shall receive accelerated vesting.

	The restricted units and the phantom units are subject to all the terms and conditions of the VNR LTIP as well as the individual award agreements which govern the awards. Neither the restricted units nor the phantom units are transferable, other than by will or the laws of descent and distribution. The Company shall withhold from the settlement or payment of the awards, as applicable, any amounts or units necessary to satisfy the Company’s withholding obligations.

	On January 1, 2014, the executives were granted a total of 182,377 restricted units in accordance with the Amended Agreements.

	During the six months ended June 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 June 30, 2014, an accrued liability of $1.1 million has been recorded related to phantom units granted to executive officers, board members and employees and non-cash unit-based compensation expense of $0.7 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 June 30, 2014 and 2013, and $1.1 million and $1.7 million for the six months ended June 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 June 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	(1,000	)	$	29.19

	Vested	(69,369	)	$	28.88

	Non-vested restricted units at June 30, 2014	439,906		$	29.17


	At June 30, 2014, there was approximately $10.4 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately 1.7 years.

	Our Consolidated Statements of Operations reflect non-cash compensation of $2.1 million and $1.8 million in the selling, general and administrative expenses line item for the three months ended June 30, 2014 and 2013, respectively, and $5.0 million and $3.5 million for the six months ended June 30, 2014 and 2013, respectively.

Shelf_Registration_Statements

Shelf Registration Statements	6 Months Ended
Shelf Registration Statements	Jun. 30, 2014
Shelf Registration Statement [Abstract]	'
Shelf Registration Statement	'
	Shelf Registration Statement

	We have registered an indeterminate amount of Series A Preferred Units, Series B 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 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 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 Preferred Units having an aggregate offering price of up to $250.0 million. The common units and Series A Preferred Units to be sold under the equity distribution agreement are registered under our existing Shelf Registration Statement. During the six months ended 2014, total net proceeds received under the equity distribution agreement were approximately $100.4 million, after commissions and fees, from the sales of 3,323,411 common units and $0.7 million, after commissions and fees, from the sales of 25,734 Series A Preferred Units.

	Preferred Unit Equity Offering

	On March 11, 2014, we completed a public offering of 7,000,000 7.625% Series B 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.

	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	6 Months Ended
Subsequent Events	Jun. 30, 2014
Subsequent Events [Abstract]	'
Subsequent Event	'
	Subsequent Events

	Distributions

	On July 16, 2014, our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of June 2014 of $0.21 per common and Class B unit ($2.52 on an annualized basis) expected to be paid on August 14, 2014 to Vanguard unitholders of record on August 1, 2014.

	Also on July 16, 2014, our board of directors declared a cash distribution for our preferred unitholders of $0.1641 per Series A Preferred Unit and $0.15885 per Series B Preferred Unit to be paid on August 15, 2014 to Vanguard preferred unitholders of record on August 1, 2014.

	Acquisition

	On July 30 2014, we entered into a purchase and sale agreement to acquire natural gas and oil properties in North Louisiana and East Texas for a purchase price of $278.0 million. The effective date of the acquisition is June 1, 2014 and we anticipate closing on or before October 1, 2014. We intend to fund this acquisition with borrowings under our existing reserve-based credit facility.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	6 Months Ended
Summary of Significant Accounting Policies (Policies)	Jun. 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 June 30, 2014 and December 31, 2013 and for the three and six months ended June 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 six months ended June 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 Pronouncements 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)	6 Months Ended
	Jun. 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 gain on acquisition of oil and natural gas properties was excluded from the pro forma results for the six months ended June 30, 2014. 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					Six Months Ended
		June 30,					June 30,
		2014			2013		2014			2013
	Total revenues	$	123,373		$	221,151	$	235,540		$	331,800

	Net income (loss) attributable to Common and Class B	$	(9,690	)	$	86,868	$	(26,599	)	$	67,861
	unitholders
	Net income (loss) per unit:
	Common & Class B units – basic and diluted	$	(0.12	)	$	1.2	$	(0.33	)	$	0.98

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 June 30,					Six Months Ended June 30,
		2014			2013		2014			2013
		(in thousands)
	Pinedale Acquisition
	Revenues	$	39,575		$	—	$	69,216		$	—

	Excess of revenues over direct operating expenses	$	30,196		$	—	$	53,286		$	—

	All other acquisitions

	Revenues	$	17,212		$	10,800	$	32,047		$	10,800

	Excess of revenues over direct operating expenses	$	11,186		$	7,425	$	20,910		$	7,425

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	$	593,695

	Inventory	244

	Asset retirement obligations	(12,404		)
	Imbalance liabilities	(209		)
	Other	(124		)
	Total fair value of assets and liabilities acquired	581,202

	Fair value of consideration transferred	549,088

	Gain on acquisition	$	32,114

Other Acquistions [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)	6 Months Ended
Long-Term Debt (Tables)	Jun. 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		June 30, 2014				December 31, 2013
							(in thousands)
	Senior Secured Reserve-Based		Variable (1)		April 16, 2018		$	725,000			$	460,000
	Credit Facility		Variable (1)		April 16, 2018		$	725,000			$	460,000
	Senior Notes		7.875% (2)		April 1, 2020		550,000				550,000
	Senior Notes		7.875% (2)		April 1, 2020		550,000				550,000
							$	1,275,000			$	1,010,000
							$	1,275,000			$	1,010,000
	Unamortized discount on Senior Notes						(1,989		)		(2,121		)
	Total long-term debt						$	1,273,011			$	1,007,879
	Total long-term debt						$	1,273,011			$	1,007,879


	-1	Variable interest rate was 1.90% and 1.92% at June 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)	6 Months Ended
Price and Interest Rate Risk Management Activities (Tables)	Jun. 30, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Commodity Derivative Contracts Covering Anticipated Future Production	'
	As of June 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
	Contract Period		MMBtu			Fixed Price				Bbls			WTI Price		Bbls	Fixed Price
	July 1, 2014 – December 31, 2014		35,450,360			$	4.42			915,400			$	90.83	138,000	$	40.87
	July 1, 2014 – December 31, 2014		35,450,360			$	4.42			915,400			$	90.83	138,000	$	40.87
	January 1, 2015 – December 31, 2015		69,532,500			$	4.39			692,000			$	91.18	91,250	$	42
	January 1, 2015 – December 31, 2015		69,532,500			$	4.39			692,000			$	91.18	91,250	$	42
	January 1, 2016 – December 31, 2016		53,253,000			$	4.48			146,400			$	89.98	—	$	—
	January 1, 2016 – December 31, 2016		53,253,000			$	4.48			146,400			$	89.98	—	$	—
	January 1, 2017 – December 31, 2017		25,852,000			$	4.32			73,000			$	86.6	—	$	—
	January 1, 2017 – December 31, 2017		25,852,000			$	4.32			73,000			$	86.6	—	$	—

	Swaptions and Call Options Sold

	Calls were sold or options were provided to counterparties under swaption agreements to extend the swap into subsequent years as follows:



			Oil
	Contract Period		Bbls			Weighted Average
	Contract Period		Bbls			Fixed Price
	July 1, 2014 – December 31, 2014		248,400			$	102.41
	July 1, 2014 – December 31, 2014		248,400			$	102.41
	January 1, 2015 – December 31, 2015		598,945			$	104.32
	January 1, 2015 – December 31, 2015		598,945			$	104.32
	January 1, 2016 – December 31, 2016		622,200			$	125
	January 1, 2016 – December 31, 2016		622,200			$	125

	Basis Swaps


			Gas
	Contract Period		MMBtu			Weighted Avg. Basis				Pricing Index
	Contract Period		MMBtu			Differential ($/MMBtu)				Pricing Index
	July 1, 2014 – December 31, 2014		14,720,000			$	(0.20	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	July 1, 2014 – December 31, 2014		14,720,000			$	(0.20	)
	January 1, 2015 – December 31, 2015		29,200,000			$	(0.28	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2015 – December 31, 2015		29,200,000			$	(0.28	)
	January 1, 2016 – December 31, 2016		18,300,000			$	(0.24	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2016 – December 31, 2016		18,300,000			$	(0.24	)
	January 1, 2017 – December 31, 2017		10,950,000			$	(0.22	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2017 – December 31, 2017		10,950,000			$	(0.22	)



			Oil
	Contract Period		Bbls			Weighted Avg. Basis				Pricing Index
	Contract Period		Bbls			Differential ($/Bbl)				Pricing Index
	July 1, 2014 – December 31, 2014		294,400			$	(0.84	)		WTI Midland and WTI Cushing Basis Differential
	July 1, 2014 – December 31, 2014		294,400			$	(0.84	)		WTI Midland and WTI Cushing Basis Differential
	July 1, 2014 – December 31, 2014		165,600			$	(1.05	)		West Texas Sour and WTI Cushing Basis Differential
	July 1, 2014 – December 31, 2014		165,600			$	(1.05	)		West Texas Sour and WTI Cushing Basis Differential
	July 1, 2014 – December 31, 2014		92,000			$	(3.95	)		Light Louisiana Sweet Crude and Brent Basis Differential
	July 1, 2014 – December 31, 2014		92,000			$	(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
	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
July 1, 2014 – December 31, 2014		1,840,000			$	4.21			$	5			$	3.5
July 1, 2014 – December 31, 2014		1,840,000			$	4.21			$	5			$	3.5



		Oil
Contract Period		Bbls			Floor				Ceiling				Put Sold
July 1, 2014 – December 31, 2014		653,200			$	93.52			$	101.29			$	72.54
July 1, 2014 – December 31, 2014		653,200			$	93.52			$	101.29			$	72.54
January 1, 2015 – December 31, 2015		1,838,055			$	91.99			$	99.75			$	74.16
January 1, 2015 – December 31, 2015		1,838,055			$	91.99			$	99.75			$	74.16
January 1, 2016 – December 31, 2016		915,000			$	90			$	96.25			$	70
January 1, 2016 – December 31, 2016		915,000			$	90			$	96.25			$	70


Put Options Sold


		Gas							Oil
Contract Period		MMBtu			Put Sold				Bbls			Put Sold
Contract Period		MMBtu			($/MMBtu)				Bbls			($/Bbl)
July 1, 2014 – December 31, 2014		1,840,000			$	3.5			36,800			$	75
July 1, 2014 – December 31, 2014		1,840,000			$	3.5			36,800			$	75
January 1, 2015 – December 31, 2015		7,300,000			$	3.5			692,000			$	72.36
January 1, 2015 – December 31, 2015		7,300,000			$	3.5			692,000			$	72.36
January 1, 2016 – December 31, 2016		—			$	—			146,400			$	75
January 1, 2016 – December 31, 2016		—			$	—			146,400			$	75
January 1, 2017 – December 31, 2017		—			$	—			73,000			$	75
January 1, 2017 – December 31, 2017		—			$	—			73,000			$	75



Range Bonus Accumulators


		Gas
Contract Period		MMBtu			Bonus				Range Ceiling				Range Floor
July 1, 2014 – December 31, 2014		736,000			$	0.2			$	4.75			$	3.25
July 1, 2014 – December 31, 2014		736,000			$	0.2			$	4.75			$	3.25
January 1, 2015 – December 31, 2015		1,460,000			$	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
July 1, 2014 – December 31, 2014		460,000			$	4.94			$	103.2			$	70.5
July 1, 2014 – December 31, 2014		460,000			$	4.94			$	103.2			$	70.5
Interest Rate Derivative Contracts	'
	Interest Rate Swaps

	As of June 30, 2014, we had open interest rate derivative contracts as follows (in thousands):


	Period		Notional Amount				Fixed LIBOR Rates
	July 1, 2014 to December 10, 2016		$	20,000			2.17	%
	July 1, 2014 to December 10, 2016		$	20,000			2.17	%
	July 1, 2014 to October 31, 2016		$	40,000			1.65	%
	July 1, 2014 to October 31, 2016		$	40,000			1.65	%
	July 1, 2014 to August 5, 2015 (1)		$	30,000			2.25	%
	July 1, 2014 to August 5, 2015 (1)		$	30,000			2.25	%
	July 1, 2014 to August 6, 2016		$	25,000			1.8	%
	July 1, 2014 to August 6, 2016		$	25,000			1.8	%
	July 1, 2014 to October 31, 2016		$	20,000			1.78	%
	July 1, 2014 to October 31, 2016		$	20,000			1.78	%
	July 1, 2014 to September 23, 2016		$	75,000			1.15	%
	July 1, 2014 to September 23, 2016		$	75,000			1.15	%
	July 1, 2014 to March 7, 2016		$	75,000			1.08	%
	July 1, 2014 to March 7, 2016		$	75,000			1.08	%
	July 1, 2014 to September 7, 2016		$	25,000			1.25	%
	July 1, 2014 to September 7, 2016		$	25,000			1.25	%
	July 1, 2014 to December 10, 2015 (2)		$	50,000			0.21	%
	July 1, 2014 to December 10, 2015 (2)		$	50,000			0.21	%
	Total		$	360,000
	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):



			June 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		$	62,496			$	(28,034	)		$	34,462
	Commodity price derivative contracts		$	62,496			$	(28,034	)		$	34,462
	Total derivative instruments		$	62,496			$	(28,034	)		$	34,462
	Total derivative instruments		$	62,496			$	(28,034	)		$	34,462

	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		$	(65,414	)		$	28,034			$	(37,380	)
	Commodity price derivative contracts		$	(65,414	)		$	28,034			$	(37,380	)
	Interest rate derivative contracts		(6,345		)		—				(6,345		)
	Interest rate derivative contracts		(6,345		)		—				(6,345		)
	Total derivative instruments		$	(71,759	)		$	28,034			$	(43,725	)
	Total derivative instruments		$	(71,759	)		$	28,034			$	(43,725	)


			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
	Commodity price derivative contracts		$	107,307			$	(25,617	)		$	81,690
	Interest rate derivative contracts		98				—				98
	Interest rate derivative contracts		98				—				98
	Total derivative instruments		$	107,405			$	(25,617	)		$	81,788
	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	)
	Commodity price derivative contracts		$	(33,825	)		$	25,617			$	(8,208	)
	Interest rate derivative contracts		(6,869		)		—				(6,869		)
	Interest rate derivative contracts		(6,869		)		—				(6,869		)
	Total derivative instruments		$	(40,694	)		$	25,617			$	(15,077	)
	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 six months ended June 30, 2014 and the year ended December 31, 2013 are as follows:



		Six Months Ended June 30, 2014				Year Ended December 31, 2013
		(in thousands)
	Derivative asset at beginning of period, net	$	66,711			$	82,568
	Derivative asset at beginning of period, net	$	66,711			$	82,568
	Fair value of derivatives acquired	(1,344		)		—
	Fair value of derivatives acquired	(1,344		)		—
	Net gains (losses) on commodity and interest rate derivative contracts	(96,015		)		11,160
		(96,015		)		11,160
	Settlements
	Cash settlements paid (received) on matured commodity derivative contracts	19,380				(30,905		)
		19,380				(30,905		)
	Cash settlements paid on matured interest rate derivative contracts	2,005				3,888
		2,005				3,888
	Derivative asset (liability) at end of period, net	$	(9,263	)		$	66,711
	Derivative asset (liability) at end of period, net	$	(9,263	)		$	66,711

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 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):



		June 30, 2014
		Fair Value Measurements Using									Assets/Liabilities
		Level 1			Level 2			Level 3			at Fair value
	Assets:
	Commodity price derivative contracts	$	—		$	34,462		$	—		$	34,462

	Total derivative instruments	$	—		$	34,462		$	—		$	34,462

	Liabilities:
	Commodity price derivative contracts	$	—		$	(35,626	)	$	(1,754	)	$	(37,380	)

	Interest rate derivative contracts	—			(6,345		)				(6,345		)

	Total derivative instruments	$	—		$	(41,971	)	$	(1,754	)	$	(43,725	)




		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 in the fair value hierarchy:


		Unobservable Inputs
		(Level 3)
		Six Months Ended
		June 30,
		2014			2013
		(in thousands)
	Unobservable inputs, beginning of period	$	566		$	(498	)

	Total gains (losses)	(1,606		)	671

	Settlements	(714		)	1,200

	Unobservable inputs, end of period	$	(1,754	)	$	1,373


	Change in fair value included in earnings related to derivatives	$	(1,965	)	$	2,324
	still held as of June 30, 2014 and 2013

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2014
Asset Retirement Obligation [Abstract]	'
Changes in Asset Retirement Obligations	'
	The asset retirement obligations as of June 30, 2014 and December 31, 2013 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the six months ended June 30, 2014 and year ended December 31, 2013 were as follows (in thousands):


		June 30, 2014			December 31, 2013
	Asset retirement obligations, beginning of period	$	87,967		$	63,114

	Liabilities added during the current period	25,328			11,738

	Accretion expense	2,603			2,789

	Retirements	(601		)	(628		)
	Disposition of properties	(875		)	—

	Change in estimate	—			10,954

	Asset retirement obligation, end of period	114,422			87,967

	Less: current obligations	(7,647		)	(5,759		)
	Long-term asset retirement obligation, end of period	$	106,775		$	82,208

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	6 Months Ended
	Jun. 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 June 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.


		(in thousands)
	July 1, 2014 - December 31, 2014	$	5,300

	2015	7,912

	2016	5,530

	2017	3,978

	2018	3,398

	Thereafter	3,404

	Total	$	29,522

Preferred_Units_Common_Units_a1

Preferred Units, Common Units and Net Income per Common Unit (Tables)	6 Months Ended
	Jun. 30, 2014
Earnings Per Share [Abstract]	'
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 July 16, 2014, our board of directors declared a cash distribution on the Preferred Units and common and Class B units attributable to the month of June 2014. See Note 11. Subsequent Events for further discussion.



		Cash Distributions
	Distribution	Per Unit		Declared Date	Record Date	Payment Date
	2014
	Second Quarter
	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)	6 Months Ended
	Jun. 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 June 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	(1,000	)	$	29.19

	Vested	(69,369	)	$	28.88

	Non-vested restricted units at June 30, 2014	439,906		$	29.17

Description_of_the_Business_De

Description of the Business (Details)	6 Months Ended
	Jun. 30, 2014
	operating_areas
Accounting Policies [Abstract]	'
Number of operating areas	9

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Details)	6 Months Ended
Summary of Significant Accounting Policies (Details)	Jun. 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 $)	12 Months Ended	0 Months Ended				6 Months Ended	12 Months Ended
	Dec. 31, 2013	Jan. 31, 2014	2-May-14	Jun. 28, 2013	Apr. 02, 2013	Jun. 30, 2014	Dec. 31, 2013
	Dec. 31, 2013	Pinedale Acquisition [Member]	Other Acquistions [Member]	Other Acquistions [Member]	Other Acquistions [Member]	Other Acquistions [Member]	Other Acquistions [Member]
Business Acquisition [Line Items]	'	'	'	'	'	'	'
Fair value of consideration transfered	$2,500,000	$549,088,000	$9,600,000	'	$266,200,000	$4,200,000	$298,657,000
Effective date of acquisition	'	1-Oct-13	'	1-Jul-13	1-Jan-13	'	'
Gain on acquisition of oil and natural gas properties	'	32,114,000	'	'	'	'	5,591,000
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	'	'	'
Ownership interest conveyed	'	'	0.00%	'	'	'	'

Acquisitions_Fair_Value_of_Ass

Acquisitions (Fair Value of Assets and Liabilities Acquired) (Details) (USD $)	12 Months Ended	0 Months Ended			6 Months Ended	12 Months Ended
	Dec. 31, 2013	Jan. 31, 2014	2-May-14	Apr. 02, 2013	Jun. 30, 2014	Dec. 31, 2013
	Dec. 31, 2013	Pinedale Acquisition [Member]	Other Acquistions [Member]	Other Acquistions [Member]	Other Acquistions [Member]	Other Acquistions [Member]
Fair value of assets and liabilities acquired	'	'	'	'	'	'
Oil and Gas Properties	'	$593,695,000	'	'	'	$317,573,000
Inventory	'	244,000	'	'	'	899,000
Asset retirement obligations	'	-12,404,000	'	'	'	-11,381,000
Imbalance liabilities	'	-209,000	'	'	'	-2,843,000
Other	'	-124,000	'	'	'	'
Total fair value of assets and liabilities acquired	'	581,202,000	'	'	'	304,248,000
Fair value of consideration transfered	2,500,000	549,088,000	9,600,000	266,200,000	4,200,000	298,657,000
Gain on acquisition of oil and natural gas properties	'	$32,114,000	'	'	'	$5,591,000

Acquisitions_Pro_Forma_Details

Acquisitions (Pro Forma) (Details) (USD $)	3 Months Ended		6 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Business Acquisition, Pro Forma Information [Abstract]	'	'	'	'
Proforma revenues	$123,373	$221,151	$235,540	$331,800
Proforma Net income (loss)	($9,690)	$86,868	($26,599)	$67,861
Net income (loss) per unit:	'	'	'	'
Common & Class B units b basic and diluted	($0.12)	$1.20	($0.33)	$0.98

Acquisitions_Acquisitions_Acqu

Acquisitions Acquisitions (Acquiree Earnings) (Details) (USD $)	3 Months Ended		6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Pinedale Acquisition [Member]	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'
Revenues	$39,575	$0	$69,216	$0
Excess of revenues over direct operating expenses	30,196	0	53,286	0
Other Acquistions [Member]	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'
Revenues	17,212	10,800	32,047	10,800
Excess of revenues over direct operating expenses	$11,186	$7,425	$20,910	$7,425

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)	6 Months Ended
Long-Term Debt (Details) (USD $)	Jun. 30, 2014		Dec. 31, 2013
Senior Secured Reserve-Based Credit Facility [Abstract]	'		'
Oustanding borrowings	$1,275,000,000		$1,010,000,000
Senior Notes [Abstract]	'		'
Percentage of ownership in subsidiaries	100.00%		'
Members' equity available for distributions	355,100,000		'
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	1,525,000,000		'
Oustanding borrowings	725,000,000		460,000,000
Remaining borrowing capacity	797,200,000		'
Senior Notes [Abstract]	'		'
Maturity date	16-Apr-18		'
Senior Notes [Member]	'		'
Senior Secured Reserve-Based Credit Facility [Abstract]	'		'
Oustanding 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 $)	6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014		Dec. 31, 2013
Debt Instrument [Line Items]	'		'
Debt amount outstanding, gross	$1,275,000		$1,010,000
Unamortized discount	-1,989		-2,121
Total long-term debt	1,273,011		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	725,000		460,000
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	1.90%		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 1.90% and 1.92% at JuneB 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)	6 Months Ended
Long-Term Debt - Borrowing Base Utilization Grid (Details)	Jun. 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 $)	6 Months Ended
	Jun. 30, 2014
	MMBTU
Fair value of derivatives [Abstract]	'
Maximum potential loss due to credit risk	$62,500,000
Fixed-Price Swaps [Member] \| Gas [Member] \| July 1, 2014 to December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	35,450,360
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)	69,532,500
Weighted average fixed price (in dollars per unit)	4.39
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)	53,253,000
Weighted average fixed price (in dollars per unit)	4.48
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)	25,852,000
Weighted average fixed price (in dollars per unit)	4.32
Fixed-Price Swaps [Member] \| Oil [Member] \| July 1, 2014 to December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	915,400
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] \| July 1, 2014 to December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	138,000
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)	91,250
Weighted average fixed price (in dollars per unit)	42
Fixed-Price Swaps [Member] \| Natural Gas Liquids [Member] \| January 1, 2016 - December 31, 2016 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	0
Weighted average fixed price (in dollars per unit)	0
Fixed-Price Swaps [Member] \| Natural Gas Liquids [Member] \| January 1, 2017 to December 31, 2017 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	0
Weighted average fixed price (in dollars per unit)	0
Swaptions and Call Options Sold [Member] \| Oil [Member] \| July 1, 2014 to December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	248,400
Weighted average fixed price (in dollars per unit)	102.41
Swaptions and Call Options Sold [Member] \| Oil [Member] \| January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	598,945
Weighted average fixed price (in dollars per unit)	104.32
Swaptions and Call Options Sold [Member] \| Oil [Member] \| January 1, 2016 - December 31, 2016 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	622,200
Weighted average fixed price (in dollars per unit)	125
Basis Swaps [Member] \| Gas [Member] \| July 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)	14,720,000
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] \| July 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)	294,400
Weighted average basis differential (in dollars per unit)	-0.84
Basis Swaps [Member] \| Oil [Member] \| July 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)	165,600
Weighted average basis differential (in dollars per unit)	-1.05
Basis Swaps [Member] \| Oil [Member] \| July 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)	92,000
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] \| July 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
Floor (in dollars per unit)	4.21
Ceiling (in dollars per unit)	5
Derivative, Price Risk Option Strike Price	3.5
Three-Way Collars [Member] \| Oil [Member] \| July 1, 2014 to December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	653,200
Floor (in dollars per unit)	93.52
Ceiling (in dollars per unit)	101.29
Derivative, Price Risk Option Strike Price	72.54
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)	1,838,055
Floor (in dollars per unit)	91.99
Ceiling (in dollars per unit)	99.75
Derivative, Price Risk Option Strike Price	74.16
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)	915,000
Floor (in dollars per unit)	90
Ceiling (in dollars per unit)	96.25
Derivative, Price Risk Option Strike Price	70
Puts [Member] \| Gas [Member] \| July 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
Puts [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)	7,300,000
Weighted average price (in dollars per unit)	3.5
Puts [Member] \| Gas [Member] \| January 1, 2016 - December 31, 2016 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	0
Weighted average price (in dollars per unit)	0
Puts [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)	0
Weighted average price (in dollars per unit)	0
Puts [Member] \| Oil [Member] \| July 1, 2014 to December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	36,800
Weighted average price (in dollars per unit)	75
Puts [Member] \| Oil [Member] \| January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	692,000
Weighted average price (in dollars per unit)	72.36
Puts [Member] \| Oil [Member] \| January 1, 2016 - December 31, 2016 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	146,400
Weighted average price (in dollars per unit)	75
Puts [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] \| July 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)	736,000
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] \| July 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)	460,000
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 December 10, 2015 to December 10, 2017 [Member]	'
Interest rate derivative contracts [Abstract]	'
Fixed Libor Rates (in hundredths)	0.91%
Interest Rate Swaps [Member] \| Contract period July 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 July 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 July 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 July 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 July 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 July 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 July 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 July 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 July 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]

[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 $)	Jun. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Offsetting Derivative Assets:	'	'
Gross amounts of recognized assets	$62,496	$107,405
Gross amounts offset in the consolidated balance sheets	-28,034	-25,617
Net Amounts Presented in the Consolidated Balance Sheets	34,462	81,788
Offsetting Derivative Liabilities:	'	'
Gross amounts of recognized liabilities	-71,759	-40,694
Gross amounts offset in the consolidated balance sheets	28,034	25,617
Net Amounts Presented in the Consolidated Balance Sheets	-43,725	-15,077
Commodity Contract [Member]	'	'
Offsetting Derivative Assets:	'	'
Gross amounts of recognized assets	62,496	107,307
Gross amounts offset in the consolidated balance sheets	-28,034	-25,617
Net Amounts Presented in the Consolidated Balance Sheets	34,462	81,690
Offsetting Derivative Liabilities:	'	'
Gross amounts of recognized liabilities	-65,414	-33,825
Gross amounts offset in the consolidated balance sheets	28,034	25,617
Net Amounts Presented in the Consolidated Balance Sheets	-37,380	-8,208
Interest Rate Contract [Member]	'	'
Offsetting Derivative Assets:	'	'
Gross amounts of recognized assets	'	98
Gross amounts offset in the consolidated balance sheets	'	0
Net Amounts Presented in the Consolidated Balance Sheets	'	98
Offsetting Derivative Liabilities:	'	'
Gross amounts of recognized liabilities	-6,345	-6,869
Gross amounts offset in the consolidated balance sheets	0	0
Net Amounts Presented in the Consolidated Balance Sheets	($6,345)	($6,869)

Price_and_Interest_Rate_Risk_M4

Price and Interest Rate Risk Management Activities - Change in Fair Value of Derivatives (Details) (USD $)	6 Months Ended		12 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 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	-96,015	31,447	11,160
Cash settlement received on matured commodity derivative contracts	19,380	-18,721	-30,905
Cash settlements paid on matured interest rate derivative contracts	2,005	1,909	3,888
Derivative asset at end of period, net	($9,263)	'	$66,711

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	6 Months Ended	12 Months Ended
Fair Value Measurements (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Debt Instrument, Fair Value Disclosure	$597,400,000	'
Liabilities:	'	'
Asset retirement obligations incurred and recorded	25,328,000	11,738,000
Average inflation rate (in hundredths)	2.40%	'
Fair Value Measured on a Recurring Basis [Member]	'	'
Assets:	'	'
Commodity price derivative contracts	34,462,000	81,690,000
Interest rate derivative contracts	'	98,000
Total derivative instruments	34,462,000	81,788,000
Liabilities:	'	'
Commodity price derivative contracts	-37,380,000	-8,208,000
Interest rate derivative contracts	-6,345,000	-6,869,000
Total derivative instruments	-43,725,000	-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
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	34,462,000	81,124,000
Interest rate derivative contracts	'	98,000
Total derivative instruments	34,462,000	81,222,000
Liabilities:	'	'
Commodity price derivative contracts	-35,626,000	-8,208,000
Interest rate derivative contracts	-6,345,000	-6,869,000
Total derivative instruments	-41,971,000	-15,077,000
Fair Value Measured on a Recurring Basis [Member] \| Fair Value Measurements Using Level 3 [Member]	'	'
Assets:	'	'
Commodity price derivative contracts	0	566,000
Interest rate derivative contracts	'	0
Total derivative instruments	0	566,000
Liabilities:	'	'
Commodity price derivative contracts	-1,754,000	0
Interest rate derivative contracts	'	0
Total derivative instruments	($1,754,000)	$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 $)	6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
Fair Value Measurements Using Level 3 [Member]	'	'
Unobservable inputs reconciliation	'	'
Unobservable inputs, beginning of period	$566	($498)
Total gains (losses)	-1,606	671
Settlements	-714	1,200
Unobservable inputs, end of period	-1,754	1,373
Change in fair value included in earnings related to derivatives still held as of June 30, 2014 and 2013	($1,965)	$2,324

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	6 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Jun. 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	25,328	11,738
Accretion expense	2,603	2,789
Retirements	-601	-628
Disposition of properties	-875	0
Change in estimate	0	10,954
Total asset retirement obligations at end of period	114,422	87,967
Less: current obligations	-7,647	-5,759
Long-term asset retirement obligation at end of period	$106,775	$82,208

Commitments_and_Contingencies_1

Commitments and Contingencies Commitments and Contingencies (Transportation Demand Charges) (Details) (USD $)	6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014
Gross future minimum transportation demand	'
July 1, 2014 - December 31, 2014	5,300
2015	7,912
2016	5,530
2017	3,978
2018	3,398
Thereafter	3,404
Total	29,522
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

Preferred_Units_Common_Units_a2

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

3 Months Ended

6 Months Ended

1 Months Ended

6 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

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

Jun. 30, 2014

Phantom Share Units (PSUs) [Member]

Common Units

Preferred units

Series A Preferred Units [Member]

Series B Preferred Unit [Member]

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

Preferred Unit, Distribution Rate, Percentage

7.88%

7.63%

Preferred Unit, Redemption Price Per Share

$25

Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount

485,038

561,934

485,038

531,934

Distributions Declared [Abstract]

Cash Distributions Per Unit (in dollars per share)

$0.21

$0.20

Cash Distributions Declared Date

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-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-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) (USD $)	6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014
Amended Agreements [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Number of executives in amended agreements	3
Number of company performance elements related to annual bonus	4
Number of times executive annual base salary may not be exceeded by maximum payout	2
VNR Long Term Incentive Plan [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Number of times executive annual salary may not be exceeded by the amount of compensation to be received upon change in control	2
Number of times executive salary may not be exceeded by the amount of compensation to be received upon termination without cause or for good reason	3
Selling, General and Administrative Expenses [Member] \| Amended Agreements [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Non-cash compensation	0.6

UnitBased_Compensation_Restric

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

Jun. 30, 2014

Jan. 01, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

In Millions, except Share data, unless otherwise specified

Board Member [Member]

Executive - Scott Smith [Member]

Executive - Richard Robert [Member]

Executive - Britt Pence [Member]

Restricted Stock Units (RSUs) [Member]

Phantom Share Units (PSUs) [Member]

Amended Agreements [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]

Restricted and Phantom Units [Member]

Amended Agreements [Member]

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

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

3.5

2.75

Vesting period

'1 year

'3 years

Percent of units vesting on each one-year anniversary

33.33%

Phantom units granted, numbers of executives

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

13,137

182,377

66,150

Accrued liability

$1.10

Non-cash compensation

$0.70

$0.66

$1.10

$1.70

$2.10

$1.80

$3.50

$0.60

UnitBased_Compensation_NonVest

Unit-Based Compensation - Non-Vested Restricted Unit Grants (Details) (USD $)	3 Months Ended		6 Months Ended
In Millions, except Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Restricted Stock Units (RSUs) [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Unrecognized compensation cost	$10.40	'	$10.40	'
Unrecognized compensation cost recognition period (in years)	'	'	'1 year 8 months	'
Number of Non-vested Units	'	'	'	'
Non-vested units at December 31, 2012 (in units)	'	'	248,611	'
Granted (in units)	'	'	261,664	'
Forfeited (in units)	'	'	-1,000	'
Vested (in units)	'	'	-69,369	'
Non-vested units at end of period (in units)	439,906	'	439,906	'
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)	'	'	$29.19	'
Vested (in dollars per unit)	'	'	$28.88	'
Non-vested units at end of period (in dollars per unit)	$29.17	'	$29.17	'
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	$2.10	$1.80	$5	$3.50

Shelf_Registration_Statements_

Shelf Registration Statements (Details) (USD $)	6 Months Ended				0 Months Ended	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2014	Mar. 11, 2014	Jun. 30, 2014	Jun. 30, 2014
			Series A Preferred Units [Member]	Series B Preferred Unit [Member]	Shelf Registration Statement 2012 [Member]	Distribution Agreement 2013 [Member]	Distribution Agreement 2013 [Member]
					Series B Preferred Unit [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	'	'	'	'	'	100,400,000	700,000
Units issued under public offerings (in units)	'	'	'	'	7,000,000	3,323,411	25,734
Preferred Unit, Distribution Rate, Percentage	'	'	7.88%	7.63%	7.63%	'	'
Issue price of units (in dollars per share)	'	'	'	'	$25	'	'
Offering costs	'	'	'	'	200,000	'	'
Proceeds from preferred unit offerings, net	169,926,000	60,880,000	'	'	169,300,000	'	'
Underwriter Discount	'	'	'	'	$5,500,000	'	'

Subsequent_Events_Details

Subsequent Events (Details) (USD $)

12 Months Ended

1 Months Ended

0 Months Ended

Dec. 31, 2013

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

Jul. 17, 2014

Jul. 30, 2014

Common Units

Class B Units [Member]

Preferred units

Series A Preferred Units [Member]

Series B Preferred Unit [Member]

Louisiana acquisition - Hunt oil [Member]

Subsequent Event [Member]

Subsequent Event [Line Items]

Cash distribution, declaration date

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

16-Jul-14

Cash distribution attributable, per unit

$0.21

$0.16

Cash distribution, annualized basis, per unit

$2.52

Fair value of consideration transfered

$2,500,000

$278,000,000

Business Acquisition, Effective Date of Acquisition

1-Jun-14