Grizzly Energy (GRZZP) 10-Q 4 May 15 2015 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2015	Apr. 27, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	Vanguard Natural Resources, LLC
Entity Central Index Key	1384072
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	31-Mar-15
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Amendment Flag	FALSE
Entity Common Stock, Shares Outstanding		85,959,185

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Revenues:
Oil sales	$35,790	$68,199
Natural gas sales	55,754	63,543
NGLs sales	7,350	20,998
Net gains (losses) on commodity derivative contracts	59,033	-56,037
Total revenues	157,927	96,703
Production:
Lease operating expenses	35,478	30,421
Production and other taxes	11,426	15,034
Depreciation, depletion, amortization and accretion	66,840	43,610
Impairment of oil and natural gas properties	132,610	0
Selling, general and administrative expenses	9,051	8,038
Total costs and expenses	255,405	97,103
Income from operations	-97,478	-400
Other income (expense):
Interest expense	-20,189	-16,259
Net losses on interest rate derivative contracts	-1,203	-458
Gain on acquisition of oil and natural gas properties	0	32,114
Other	40	124
Total other income (expense)	-21,352	15,521
Net income (loss)	-118,830	15,121
Distributions to Preferred unitholders	-6,690	-1,962
Net income (loss) attributable to Common and Class B unitholders	($125,520)	$13,159
Net income per common and Class B unit, Basic (usd per share)	($1.49)	$0.17
Net income per common and class B unit, Diluted (usd per share)	($1.49)	$0.16
Weighted Average Number of Shares Outstanding, Basic (shares)	84,164	79,606
Weighted Average Number of Shares Outstanding, Diluted (shares)	84,164	79,892
Common Units
Other income (expense):
Weighted Average Number of Shares Outstanding, Basic (shares)	83,744	79,186
Weighted Average Number of Shares Outstanding, Diluted (shares)	83,744	79,472
Class B Units
Other income (expense):
Weighted Average Number of Shares Outstanding, Basic and Diluted (shares)	420	420

CONSOLIDATED_BALANCE_SHEETS_Un

CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Current assets
Cash and cash equivalents	$14,523	$0
Trade accounts receivable, net	83,663	140,017
Derivative assets	148,898	142,114
Other currents assets	3,736	4,102
Total current assets	250,820	286,233
Oil and natural gas properties, at cost	4,166,553	4,140,527
Accumulated depletion, amortization and impairment	-1,360,595	-1,164,721
Oil and natural gas properties evaluated, net - full cost method	2,805,958	2,975,806
Other assets
Goodwill	420,955	420,955
Derivative assets	100,957	83,583
Other assets	25,705	27,015
Total assets	3,604,395	3,793,592
Accounts payable:
Trade	8,809	15,118
Affiliates	1,025	823
Accrued liabilities:
Lease operating	16,589	19,822
Developmental capital	14,685	24,706
Interest	22,346	11,517
Production and other taxes	39,905	29,981
Derivative liabilities	3,868	3,583
Oil and natural gas revenue payable	33,678	40,117
Distribution payable	11,050	18,640
Other	12,804	14,297
Total current liabilities	164,759	178,604
Long-term debt	1,901,778	1,932,816
Derivative liabilities	1,025	1,380
Asset retirement obligations, net of current portion	148,591	146,676
Other long-term liabilities	2,182	0
Total liabilities	2,218,335	2,259,476
Commitments and contingencies
Members' equity
Members' Equity	1,386,060	1,534,116
Total liabilities and members' equity	3,604,395	3,793,592
Cumulative Preferred Units
Members' equity
Members' Equity	335,444	335,444
Common Units
Members' equity
Members' Equity	1,043,001	1,191,057
Class B Units
Members' equity
Members' Equity	$7,615	$7,615

CONSOLIDATED_BALANCE_SHEETS_Un1

CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical)	Mar. 31, 2015	Dec. 31, 2014
Members' equity
Preferred units, issued (shares)	13,881,873	13,881,873
Preferred units, outstanding (shares)	13,881,873	13,881,873
Common Units
Members' equity
Common units, issued (shares)	84,769,537	83,451,746
Common units, outstanding (shares)	84,769,537	83,451,746
Class B Units
Members' equity
Common units, issued (shares)	420,000	420,000
Common units, outstanding (shares)	420,000	420,000

CONSOLIDATED_STATEMENTS_OF_MEM

CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY (Unaudited) (USD $)	Total	Member Units	Cumulative Preferred units	Common Units	Class B Units
In Thousands, unless otherwise specified			Member Units	Member Units	Member Units
Balance at Dec. 31, 2013		$1,268,335	$61,021	$1,199,699	$7,615
Increase (Decrease) in Members' Equity [Roll Forward]
Issuance of units, net of offering costs			274,423	147,814
Distributions to Preferred unitholders		-18,197		-18,197
Distributions to Common and Class B unitholders		-207,883		-207,883
Repurchase of units under the common unit buyback program		-2,498		-2,498
Unit-based compensation		7,777		7,777
Net income		64,345		64,345
Balance at Dec. 31, 2014		1,534,116	335,444	1,191,057	7,615
Increase (Decrease) in Members' Equity [Roll Forward]
Issuance of units, net of offering costs		12,213		12,213
Distributions to Preferred unitholders		-6,690		-6,690
Distributions to Common and Class B unitholders		-37,745		-37,745
Repurchase of units under the common unit buyback program		-2,399		-2,399
Unit-based compensation		5,395		5,395
Net income	-118,830	-118,830		-118,830
Balance at Mar. 31, 2015		$1,386,060	$335,444	$1,043,001	$7,615

CONSOLIDATED_STATEMENTS_OF_MEM1

CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY (Unaudited) (Parenthetical) (Member Units, USD $)	3 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Common Units
Issuance of members' units, offering costs	$221	$88
Cumulative Preferred units
Issuance of members' units, offering costs	$0	$371

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Operating activities
Net income (loss)	($118,830)	$15,121
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	66,840	43,610
Impairment of oil and natural gas properties	132,610	0
Amortization of debt discount	70	65
Compensation related items	5,395	2,872
Net (gains) losses on commodity and interest rate derivative contracts	-57,830	56,495
Cash settlements received (paid) on matured commodity derivative contracts	38,291	-11,969
Cash settlements paid on matured interest rate derivative contracts	-990	-990
Net gain on acquisition of oil and natural gas properties	0	-32,114
Changes in operating assets and liabilities:
Trade accounts receivable	56,354	-18,472
Other current assets	632	-365
Premiums paid on commodity derivative contracts	-795	3
Accounts payable and oil and natural gas revenue payable	-12,748	575
Payable to affiliates	202	25
Accrued expenses and other current liabilities	3,345	24,423
Other assets	1,104	374
Net cash provided by operating activities	113,650	79,653
Investing activities
Additions to property and equipment	-85	-228
Additions to oil and natural gas properties	-25,070	-27,986
Acquisitions of oil and natural gas properties	-694	-496,663
Deposits and prepayments of oil and natural gas properties	-4	-299
Net cash used in investing activities	-25,853	-525,176
Financing activities
Proceeds from long-term debt	71,500	539,000
Repayment of long-term debt	-102,563	-238,000
Proceeds from preferred unit offerings, net	0	170,026
Proceeds from Common unit offerings, net	12,213	34,545
Repurchase of units under the Common unit buyback program	-2,399	0
Distributions to Preferred unitholders	-6,690	-1,047
Distributions to Common and Class B unitholders	-45,335	-49,914
Net cash provided by (used in) financing activities	-73,274	454,610
Net increase cash and cash equivalents	14,523	9,087
Cash and cash equivalents, beginning of period	0	11,818
Cash and cash equivalents, end of period	14,523	20,905
Supplemental cash flow information:
Cash paid for interest	19,210	4,994
Non-cash financing and investing activities:
Asset retirement obligations	$360	$13,213

Description_of_the_Business

Description of the Business	3 Months Ended
	Mar. 31, 2015
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, as of March 31, 2015, we own properties and oil and natural gas reserves primarily located in nine operating areas:
	•	the Green River Basin in Wyoming;
	•	the Piceance Basin in Colorado;
	•	the Permian Basin in West Texas and New Mexico;
	•	the Gulf Coast Basin in Texas, Louisiana and Mississippi;
	•	the Big Horn Basin in Wyoming and Montana;
	•	the Arkoma Basin in Arkansas and Oklahoma;
	•	the Williston Basin in North Dakota and Montana;
	•	the Wind River Basin in Wyoming; and
	•	the Powder River Basin in Wyoming.
	We were formed in October 2006 and completed our initial public offering in October 2007. Our common units are listed on the NASDAQ Global Select Market (“NASDAQ”), an exchange of the NASDAQ OMX Group Inc. (Nasdaq: NDAQ), under the symbol “VNR.” Our Series A, Series B and Series C Cumulative Preferred units are also listed on the NASDAQ under the symbols “VNRAP”, “VNRBP” and “VNRCP,” respectively.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2015
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, 2014, from the audited financial statements contained in our 2014 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 2014 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 March 31, 2015, our significant accounting policies are consistent with those discussed in Note 1 of our consolidated financial statements contained in our 2014 Annual Report.
	(a)	Basis of Presentation and Principles of Consolidation:
	The consolidated financial statements as of March 31, 2015 and December 31, 2014 and for the three months ended March 31, 2015 and 2014 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, the “12-month average price” discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is less than the total capitalized costs, we are required to write-down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write-downs are included in the Consolidated Statements of Operations as an impairment charge. No ceiling test impairment was required during the three months ended March 31, 2014.
	We recorded a non-cash ceiling test impairment of oil and natural gas properties for the three months ended March 31, 2015 of $132.6 million as a result of a decline in oil and natural gas prices at the measurement date, March 31, 2015. The first quarter 2015 impairment was calculated based on the 12-month average price of $3.91 per MMBtu for natural gas and $82.62 per barrel of crude oil.
	When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties.
	(c)	New Pronouncement Issued But Not Yet Adopted:
	In April 2015, the FASB issued Accounting Standards Update (“ASU”) No. 2015-03, Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (“ASU No. 2015-03”), which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 is to be applied retrospectively and is effective for periods beginning after December 15, 2015. The Company will adopt ASU No. 2015-03 by the date required, which will affect the presentation of debt issuance costs in the balance sheet but will not have any impact on the Company’s results of operations or financial position.
	(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	3 Months Ended
	Mar. 31, 2015
Business Combinations [Abstract]
Acquisitions	Acquisitions
	Our acquisitions are accounted for under the acquisition method of accounting in accordance with ASC Topic 805, “Business Combinations” (“ASC Topic 805”). An acquisition may result in the recognition of a gain or goodwill based on the measurement of the fair value of the assets acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. Any such gain or any loss resulting from the impairment of goodwill is recognized in current period earnings and classified in other income and expense in the accompanying Consolidated Statements of Operations. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of the properties acquired in our acquisitions have been included in the consolidated financial statements since the closing dates of the acquisitions.
	2014 Acquisitions
	Pinedale Acquisition
	On January 31, 2014, we completed the acquisition of natural gas and oil properties in the Pinedale and Jonah fields of Southwestern Wyoming for approximately $555.6 million in cash with an effective date of October 1, 2013. We refer to this acquisition as the “Pinedale Acquisition.” The purchase price was funded with borrowings under our Reserve-Based Credit Facility (as defined below). In accordance with ASC Topic 805, this acquisition resulted in a gain of $32.1 million, as reflected in the table below, primarily due to the increase in natural gas prices between the date the purchase and sale agreement was entered into and the closing date.
	Fair value of assets and liabilities acquired		(in thousands)
	Oil and natural gas properties		$	600,123
	Inventory		244
	Asset retirement obligations		(12,404		)
	Imbalance liabilities		(171		)
	Other		(125		)
	Total fair value of assets and liabilities acquired		587,667
	Fair value of consideration transferred		555,553
	Gain on acquisition		$	32,114
	Piceance Acquisition
	On September 30, 2014, we completed the acquisition of natural gas, oil and NGLs assets in the Piceance Basin in Colorado for approximately $496.4 million in cash with an effective date of July 1, 2014. We refer to this acquisition as the “Piceance Acquisition.” The purchase price was funded with borrowings under our Reserve-Based Credit Facility. In accordance with ASC Topic 805, this acquisition resulted in goodwill of $0.4 million, as reflected in the table below, which was immediately impaired and recorded as a loss in current period earnings. The loss resulted primarily from the changes in natural gas prices between the date the purchase and sale agreement was entered into and the closing date, which were used to value the reserves acquired.
	Fair value of assets and liabilities acquired		(in thousands)
	Oil and natural gas properties		$	523,537
	Asset retirement obligations		(19,452		)
	Production and ad valorem taxes payable		(7,552		)
	Suspense liabilities		(445		)
	Other		(124		)
	Total fair value of assets and liabilities acquired		495,964
	Fair value of consideration transferred		496,391
	Loss on acquisition		$	(427	)
	Other Acquisitions
	On May 1, 2014, we completed an asset exchange transaction with Marathon Oil Company in which we acquired natural gas and NGLs properties in the Wamsutter natural gas field in Wyoming in exchange for 75% of our working interests in the Gooseberry Field properties in Wyoming. The total consideration for this transaction was the mutual exchange and assignment of interests in the properties and cash consideration of $6.8 million paid to Marathon Oil Company. The cash consideration was funded with borrowings under our existing Reserve-Based Credit Facility. The effective date of the acquisition is January 1, 2014.
	On August 29, 2014, we completed the acquisition of certain natural gas, oil and NGLs properties located in North Louisiana and East Texas for an adjusted purchase price of $265.1 million. We refer to this acquisition as the “Gulf Coast Acquisition.” The purchase price was funded with borrowings under our existing Reserve-Based Credit Facility. The effective date of the acquisition is June 1, 2014.
	During the year ended December 31, 2014, we completed other smaller acquisitions of certain natural gas, oil and NGLs properties located in the Permian Basin and Powder River Basin in Wyoming for an aggregate purchase price of $17.7 million which was funded with borrowings under our existing Reserve-Based Credit Facility.
	Pro Forma Operating Results
	In accordance with ASC Topic 805, presented below are unaudited pro forma results for the three months ended March 31, 2014 to show the effect on our consolidated results of operations as if our acquisitions completed in 2014 had occurred on January 1, 2013.
	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, 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, and (iii) interest expense on additional borrowings necessary to finance the acquisitions. The net gain on acquisition of oil and natural gas properties was excluded from the pro forma results for the three months ended March 31, 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 March 31, 2014
	Total revenues		$	166,486
	Net income attributable to Common and Class B unitholders		$	9,741
	Net income per Common and Class B unit, Basic and Diluted		$	0.12
	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
			March 31,
			2015			2014
		(in thousands)
	Pinedale Acquisition
	Revenues		$	23,733		$	29,641
	Excess of revenues over direct operating expenses		$	16,578		$	23,091
	Piceance Acquisition
	Revenues		$	11,773		$	—
	Excess of revenues over direct operating expenses		$	6,073		$	—
	All other acquisitions
	Revenues		$	9,393		$	—
	Excess of revenues over direct operating expenses		$	4,939		$	—

LongTerm_Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2015
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		March 31, 2015				December 31, 2014
							(in thousands)
	Senior Secured Reserve-Based		Variable (1)		April 16, 2018		$	1,330,000			$	1,360,000
	Credit Facility
	Senior Notes		7.875% (2)		April 1, 2020		550,000				550,000
	Lease Financing Obligation		4.16%		August 10, 2020 (3)		$	27,923			28,986
							$	1,907,923			$	1,938,986
	Less:
	Unamortized discount on Senior Notes						(1,782		)		(1,852		)
	Current portion of Lease Financing Obligation						(4,363		)		(4,318		)
	Total long-term debt						$	1,901,778			$	1,932,816
	-1	Variable interest rate was 2.18% and 2.17% at March 31, 2015 and December 31, 2014, respectively.
	-2	Effective interest rate was 8.0%.
	-3	The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021.
	Senior Secured Reserve-Based Credit Facility
	The Company’s Third Amended and Restated Credit Agreement (the “Credit Agreement”) provides a maximum credit facility of $3.5 billion and an initial borrowing base of $2.0 billion (the “Reserve-Based Credit Facility”). As of March 31, 2015, there were approximately $1.33 billion of outstanding borrowings and $665.5 million of borrowing capacity under the Reserve-Based Credit Facility, after consideration of a $4.5 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 March 31, 2015, 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. Specifically, as of the end of each fiscal quarter, we may not permit the following: (a) our current ratio to be less than 1.0 to 1.0 and (b) our total leverage ratio to be more than 4.0 to 1.0. In addition, we are subject to various other covenants including, but not limited to, those limiting 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 March 31, 2015, we were in compliance with all of our debt covenants. Based on projected market conditions and lower commodity prices, we currently expect that we will not be in compliance with our total leverage ratio covenant in certain future periods. We have been in discussions with certain banks in our Reserve-Based Credit Facility regarding amending our leverage ratio covenant during our next scheduled borrowing base redetermination. Based on those discussions, it is our expectation that the covenant will be changed to provide for more flexibility given lower forecasted adjusted EBITDA due to the lower commodity price environment. We expect our borrowing base to be reduced as a result of this redetermination. Absent the success of amending our leverage ratio, a resultant breach of the covenants under our Reserve-Based Credit Facility would cause a default under the reserve-based credit agreement and the lenders would be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. This, in turn, would cause a default under the senior notes due in 2020 and permit the holders of those notes to accelerate their maturity. We are currently in the process of our semi-annual borrowing base redetermination and anticipate its completion in May 2015.
	Letters of Credit
	At March 31, 2015, we have unused irrevocable standby letters of credit of approximately $4.5 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 March 31, 2015, based on the most restrictive covenants of the Indenture, the Company’s cash balance and the borrowings available under the Reserve-Based Credit Facility, approximately $74.5 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.
	Lease Financing Obligations
	On October 24, 2014, in connection with our Piceance Acquisition, we entered into an assignment and assumption agreement, whereby we acquired compressors and related facilities and assumed the related financing obligations (the “Lease Financing Obligations”). Certain rights, title, interest and obligations under the Lease Financing Obligations have been assigned to several lenders and are covered by separate assignment agreements, which expire on August 10, 2020 and July 10, 2021. We have the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligations also contain an early buyout option whereby the Company may purchase the equipment for $16.0 million on February 10, 2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 4.16%.

Price_and_Interest_Rate_Risk_M

Price and Interest Rate Risk Management Activities	3 Months Ended
	Mar. 31, 2015
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.
	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.
	During the first quarter of 2015, we have taken steps to restructure our hedge portfolio to limit further downside and volatility due to the current commodity price environment. Specifically, we have converted a significant portion of our three-way collars in 2015 to fixed-price swaps or lowered the pricing on existing short puts.
	At March 31, 2015, the Company had open commodity derivative contracts covering our anticipated future production as follows:
	Fixed-Price Swaps
			Gas							Oil						NGLs
	Contract Period		MMBtu			Weighted Average				Bbls			Weighted Average			Bbls	Weighted Average
						Fixed Price							WTI Price				Fixed Price
	April 1, 2015 – December 31, 2015		66,137,500			$	4.26			1,846,750			$	73.07		185,625	$	46.34
	January 1, 2016 – December 31, 2016		55,083,000			$	4.47			146,400			$	89.98		—	$	—
	January 1, 2017 – December 31, 2017		24,027,000			$	4.35			—			$	—		—	$	—
	Call Options Sold
			Gas							Oil
	Contract Period		MMBtu			Weighted Average				Bbls			Weighted Average
						Fixed Price							Fixed Price
	April 1, 2015 – December 31, 2015		—			$	—			55,000			$	105
	January 1, 2016 – December 31, 2016		9,150,000			$	4.25			622,200			$	125
	January 1, 2017 – December 31, 2017		9,125,000			$	4.5			365,000			$	95
	Basis Swaps
			Gas
	Contract Period		MMBtu			Weighted Avg. Basis				Pricing Index
						Differential ($/MMBtu)
	April 1, 2015 – December 31, 2015		22,000,000			$	(0.28	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2016 – December 31, 2016		18,300,000			$	(0.24	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2017 – December 31, 2017		10,950,000			$	(0.22	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
			Oil
	Contract Period		Bbls			Weighted Avg. Basis				Pricing Index
						Differential ($/Bbl)
	April 1, 2015 – December 31, 2015		385,000			$	(1.68	)		WTI Midland and WTI Cushing Basis Differential
	April 1, 2015 – December 31, 2015		110,000			$	(2.33	)		West Texas Sour and WTI Cushing Basis Differential
	April 1, 2015 – December 31, 2015		550,000			$	(14.50	)		WTI and West Canadian Select Basis Differential
	Three-Way Collars
			Gas
	Contract Period		MMBtu			Floor				Ceiling				Put Sold
	January 1, 2016 – December 31, 2016		12,810,000			$	3.95			$	4.25			$	3
	January 1, 2017 – December 31, 2017		16,425,000			$	3.92			$	4.23			$	3.37
			Oil
	Contract Period		Bbls			Floor				Ceiling				Put Sold
	April 1, 2015 – December 31, 2015		160,750			$	90			$	97.26			$	76.43
	January 1, 2016 – December 31, 2016		1,061,400			$	90			$	96.18			$	73.62
	Put Options Sold
			Gas							Oil
	Contract Period		MMBtu			Put Sold				Bbls			Put Sold
						($/MMBtu)							($/Bbl)
	April 1, 2015 – December 31, 2015		19,937,500			$	2.99			476,000			$	72.11
	January 1, 2016 – December 31, 2016		1,830,000			$	3			146,400			$	75
	January 1, 2017 – December 31, 2017		1,825,000			$	3.5			73,000			$	75
	Range Bonus Accumulators
			Gas
	Contract Period		MMBtu			Bonus				Range Ceiling				Range Floor
	April 1, 2015 – December 31, 2015		1,100,000			$	0.16			$	4			$	2.5
			Oil
	Contract Period		Bbls			Bonus				Range Ceiling				Range Floor
	April 1, 2015 – December 31, 2015		137,500			$	4			$	100			$	75
	January 1, 2016 – December 31, 2016		183,000			$	4			$	100			$	75
	Collars
			Oil
	Contract Period		Bbls			Floor Price ($/Bbl)				Ceiling Price ($/Bbl)
	April 1, 2015 – December 31, 2015		274,500			$	50			$	56.85
	Call Spreads
			Oil
	Contract Period		Bbls			Call Price ($/Bbl)				Short Call Price ($/Bbl)
	April 1, 2015 – December 31, 2015		947,600			$	70			$	85
Puts
		Oil
Contract Period		Bbls			Put Price ($/Bbl)
January 1, 2016 – December 31, 2016		366,000			$	60
Interest Rate Swaps
At March 31, 2015, we had open interest rate derivative contracts as follows (in thousands):
Period		Notional Amount				Fixed LIBOR Rates
April 1, 2015 to December 10, 2016		$	20,000			2.17	%
April 1, 2015 to October 31, 2016		$	40,000			1.65	%
April 1, 2015 to August 5, 2015 (1)		$	30,000			2.25	%
April 1, 2015 to August 6, 2016		$	25,000			1.8	%
April 1, 2015 to October 31, 2016		$	20,000			1.78	%
April 1, 2015 to September 23, 2016		$	75,000			1.15	%
April 1, 2015 to March 7, 2016		$	75,000			1.08	%
April 1, 2015 to September 7, 2016		$	25,000			1.25	%
April 1, 2015 to December 10, 2015 (2)		$	50,000			0.21	%
Total		$	360,000
-1	The counterparty has the option to extend the termination date of this contract to August 5, 2018 at 2.25%.
-2	The counterparty has the option to require Vanguard to pay a fixed rate of 0.91% from December 10, 2015 to December 10, 2017.
Balance Sheet Presentation
Our commodity derivatives and interest rate swap derivatives are presented on a net basis in “derivative assets” and “derivative liabilities” on the Consolidated Balance Sheets. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets for the periods indicated (in thousands):
		March 31, 2015
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		$	309,531			$	(59,676	)		$	249,855
Total derivative instruments		$	309,531			$	(59,676	)		$	249,855
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		$	(59,688	)		$	59,676			$	(12	)
Interest rate derivative contracts		(4,881		)		—				(4,881		)
Total derivative instruments		$	(64,569	)		$	59,676			$	(4,893	)
		December 31, 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		$	289,018			$	(63,321	)		$	225,697
Total derivative instruments		$	289,018			$	(63,321	)		$	225,697
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		$	(63,615	)		$	63,321			$	(294	)
Interest rate derivative contracts		(4,669		)		—				(4,669		)
Total derivative instruments		$	(68,284	)		$	63,321			$	(4,963	)
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 $309.5 million at March 31, 2015. 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 March 31, 2015. 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 three months ended March 31, 2015 and the year ended December 31, 2014 are as follows:
	Three Months Ended				Year Ended December 31, 2014
	31-Mar-15
	(in thousands)
Derivative asset at beginning of period, net	$	220,734			$	66,711
Purchases
Fair value of derivatives acquired	35,644				(1,344		)
Net gains on commodity and interest rate derivative contracts	57,830				161,519
Settlements
Cash settlements received on matured commodity derivative contracts	(38,291		)		(10,187		)
Cash settlements paid on matured interest rate derivative contracts	990				4,035
Termination of derivative contracts	(31,945		)		—
Derivative asset at end of period, net	$	244,962			$	220,734

Fair_Value_Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2015
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 March 31, 2015, the fair value of our Senior Notes was estimated to be $509.3 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, call options sold, put options sold, call spreads, call options, put options, 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 and basis-swaps 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):
			March 31, 2015
			Fair Value Measurements Using									Assets/Liabilities
			Level 1			Level 2			Level 3			at Fair value
	Assets:
	Commodity price derivative contracts		$	—		$	256,190		$	(6,335	)	$	249,855
	Total derivative instruments		$	—		$	256,190		$	(6,335	)	$	249,855
	Liabilities:
	Commodity price derivative contracts		$	—		$	(12	)	$	—		$	(12	)
	Interest rate derivative contracts		—			(4,881		)	—			(4,881		)
	Total derivative instruments		$	—		$	(4,893	)	$	—		$	(4,893	)
			December 31, 2014
			Fair Value Measurements Using									Assets/Liabilities
			Level 1			Level 2			Level 3			at Fair value
	Assets:
	Commodity price derivative contracts		$	—		$	232,167		$	(6,470	)	$	225,697
	Total derivative instruments		$	—		$	232,167		$	(6,470	)	$	225,697
	Liabilities:
	Commodity price derivative contracts		$	—		$	(294	)	$	—		$	(294	)
	Interest rate derivative contracts		—			(4,669		)	—			(4,669		)
	Total derivative instruments		$	—		$	(4,963	)	$	—		$	(4,963	)
	The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 (unobservable inputs) in the fair value hierarchy:
			Three Months Ended
			March 31,
			2015			2014
			(in thousands)
	Unobservable inputs, beginning of period		$	(6,470	)	$	566
	Total gains (losses)		1,287			(957		)
	Settlements		(1,152		)	36
	Unobservable inputs, end of period		$	(6,335	)	$	(355	)
	Change in fair value included in earnings related to derivatives		$	(804	)	$	(670	)
	still held as of March 31,
	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. While no goodwill impairment was recognized at March 31, 2015, any further significant decline in prices of oil and natural gas or significant negative reserve adjustments could change our estimate of the fair value of the 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 three months ended March 31, 2015 and year ended December 31, 2014, in connection with new wells drilled and wells acquired during the period, we incurred and recorded asset retirement obligations totaling $0.4 million and $52.8 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 of 4.6%; and (4) the average inflation factor (2.3%). 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	3 Months Ended
	Mar. 31, 2015
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations
	The asset retirement obligations as of March 31, 2015 and December 31, 2014 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the three months ended March 31, 2015 and year ended December 31, 2014 were as follows (in thousands):
		March 31, 2015			December 31, 2014
	Asset retirement obligations, beginning of period	$	149,062		$	87,967
	Liabilities added during the current period	360			52,829
	Accretion expense	1,835			5,889
	Retirements	(280		)	(450		)
	Disposition of properties	—			(1,291		)
	Change in estimate	—			4,118
	Asset retirement obligation, end of period	150,977			149,062
	Less: current obligations	(2,386		)	(2,386		)
	Long-term asset retirement obligation, end of period	$	148,591		$	146,676

Commitments_and_Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies
	Transportation Demand Charges
	As of March 31, 2015, we have contracts that provide firm transportation capacity on pipeline systems. The remaining terms on these contracts range from one to five 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 March 31, 2015. 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.
		31-Mar-15
		(in thousands)
	April 1, 2015 - December 31, 2015	$	13,046
	2016	14,508
	2017	12,362
	2018	11,696
	2019	9,661
	Thereafter	410
	Total	$	61,683
	Legal Proceedings
	We are defendants in legal proceedings arising in the normal course of our business.  While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management does not believe that it is probable that the outcome of these actions will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flow. We are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

Members_Equity_and_Net_Income_

Members' Equity and Net Income per Common and Class B Unit	3 Months Ended
	Mar. 31, 2015
Equity [Abstract]
Members' Equity and Net Income per Common and Class B Unit	Members’ Equity and Net Income per Common and Class B Unit
	Cumulative Preferred Units
	The following table summarizes the Company’s Cumulative Preferred units outstanding at March 31, 2015 and December 31, 2014:
									March 31, 2015				December 31, 2014
			Earliest		Liquidation Preference		Distribution Rate		Units Outstanding		Carrying Value		Units Outstanding	Carrying Value
			Redemption Date		Per Share						(in thousands)			(in thousands)
	Series A		June 15, 2023		$25.00		7.88%		2,581,873		$	62,200	2,581,873	$	62,200
	Series B		April 15, 2024		$25.00		7.63%		7,000,000		$	169,265	7,000,000	$	169,265
	Series C		October 15, 2024		$25.00		7.75%		4,300,000		$	103,979	4,300,000	$	103,979
	Total Cumulative Preferred Units								13,881,873		$	335,444	13,881,873	$	335,444
	The Cumulative Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by us or converted into our common units, at our option, commencing on the redemptions dates as stated above. The Cumulative Preferred Units can be redeemed, in whole or in part, out of amounts legally available therefore, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared.
	Upon the occurrence of a change of control, each holder of Cumulative Preferred Units will have the right to convert some or all of the their Cumulative Preferred Units into our common units unless prior to the change of control, we provide notice of our election to redeem the Cumulative Preferred Units or we exercise any of our redemption rights relating to the units prior to the change of control conversion date as set by our board of directors. Also upon the occurrence of a change of control we may, at our option and subject to certain restrictions, redeem the Cumulative Preferred Units by paying $25.00 per unit, plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared.
	Holders of the Cumulative Preferred Units will have no voting rights except for limited voting rights if we fail to pay dividends for eighteen or more monthly periods (whether or not consecutive) and in certain other limited circumstances or as required by law. The Cumulative Preferred Units have a liquidation preference which is equal to the redemption price described above.
	Common and Class B Units
	The common units represent limited liability company interests. Holders of Class B units have substantially the same rights and obligations as the holders of common units.
	The following is a summary of the changes in our common units issued during the three months ended March 31, 2015 and the year ended December 31, 2014 (in thousands):
			March 31, 2015			December 31, 2014
	Beginning of period		83,452			78,337
	Issuance of Common units for cash		849			4,864
	Repurchase of units under the Common unit buyback program		(157	)		(135	)
	Reissuance of Common units for restricted unit grants		292			—
	Unit-based compensation		334			386
	End of period		84,770			83,452
	There was no change in issued and outstanding Class B units during the three months ended March 31, 2015 or the year ended December 31, 2014.
	Net Income per Common and Class B Unit
	Basic net income per common and Class B unit is computed in accordance with ASC Topic 260 “Earnings Per Share” (“ASC Topic 260”) by dividing net income attributable to common and Class B unitholders by the weighted average number of units outstanding during the period. Diluted net income per common and Class B unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. We use the treasury stock method to determine the dilutive effect. Class B units participate in distributions; therefore, all Class B units were considered in the computation of basic net income per unit. The Cumulative Preferred Units have no participation rights and accordingly are excluded from the computation of basic net income per unit.
	The net income (loss) attributable to common and Class B unitholders and the weighted average units for calculating basic and diluted net income (loss) per common and Class B unit were as follows (in thousands, except per unit data):
			Three Months Ended
			March 31,
			2015				2014
	Net income (loss) attributable to common and Class B unitholders		$	(125,520	)		$	13,159
	Weighted average number of common and Class B units outstanding - basic		84,164				79,606
	Effect of dilutive securities:
	Phantom units (a)		—				286
	Weighted average number of common and Class B units outstanding - diluted		84,164				79,892
	Net income (loss) per common and Class B unit
	Basic		$	(1.49	)		$	0.17
	Diluted		$	(1.49	)		$	0.16
	(a)	For the three months ended March 31, 2015, 202,407 phantom units were excluded from the calculation of diluted earnings per unit due to their antidilutive effect as we were in a loss position.
	Distributions Declared
	The Cumulative Preferred Units rank senior to our common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up. Distributions on the Preferred Units are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by our board of directors. We will pay cumulative distributions in cash on the Preferred Units on a monthly basis at a monthly rate of 7.875% per annum of the liquidation preference of $25.00 per Series A Cumulative Preferred Unit, a monthly rate of 7.625% per annum of the liquidation preference of $25.00 per Series B Cumulative Preferred Unit and a monthly rate of 7.75% per annum of the liquidation preference of $25.00 per Series C Cumulative Preferred Unit.
	The following table shows the distribution amount, declared date, record date and payment date of the cash distributions we paid on each of our common and Class B units for each period presented. Future distributions are at the discretion of our board of directors and will depend on business conditions, earnings, our cash requirements and other relevant factors.
	On April 15, 2015, our board of directors declared a cash distribution on the Cumulative Preferred Units and common and Class B units attributable to the month of March 2015. See Note 11. Subsequent Events for further discussion.
			Cash Distributions
	Distribution		Per Unit				Declared Date		Record Date	Payment Date
	2015
	February		$	0.1175			March 18, 2015		April 1, 2015	April 14, 2015
	January		$	0.1175			February 17, 2015		March 2, 2015	March 17, 2015
	2014
	Fourth Quarter
	December		$	0.21			January 22, 2015		February 2, 2015	February 13, 2015
	November		$	0.21			December 16, 2014		January 2, 2015	January 14, 2015
	October		$	0.21			November 20, 2014		December 1, 2014	December 15, 2014
	Third Quarter
	September		$	0.21			October 20, 2014		November 3, 2014	November 14, 2014
	August		$	0.21			September 19, 2014		October 1, 2014	October 15, 2014
	July		$	0.21			August 19, 2014		September 2, 2014	September 12, 2014
	Second Quarter
	June		$	0.21			July 16, 2014		August 1, 2014	August 14, 2014
	May		$	0.21			June 24, 2014		July 1, 2014	July 15, 2014
	April		$	0.21			May 20, 2014		June 2, 2014	June 13, 2014
	First Quarter
	March		$	0.21			April 17, 2014		May 1, 2014	May 15, 2014
	February		$	0.21			March 17, 2014		April 1, 2014	April 14, 2014
January		$	0.2075			February 20, 2014		March 3, 2014	March 17, 2014
2013
Fourth Quarter
December		$	0.2075			January 16, 2014		February 3, 2014	February 14, 2014

UnitBased_Compensation

Unit-Based Compensation	3 Months Ended
	Mar. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Unit-Based Compensation	Unit-Based Compensation
	Long-Term Incentive Plan
	The Vanguard Natural Resources, LLC Long-Term Incentive Plan (the “VNR LTIP”) was adopted by the Board of Directors of the Company to compensate employees and nonemployee directors of the Company and its affiliates who perform services for the Company under the terms of the plan. The VNR LTIP is administered by the compensation committee of the board of directors (the “Compensation Committee”) and permits the grant of unrestricted units, restricted units, phantom units, unit options and unit appreciation rights.
	Restricted and Phantom Units
	A restricted unit is a unit grant that vests over a period of time and that during such time is subject to forfeiture. A phantom unit grant represents the equivalent of one common unit of the Company. The phantom units, once vested, are settled through the delivery of a number of common units equal to the number of such vested units, or an amount of cash equal to the fair market value of such common units on the vesting date to be paid in a single lump sum payment, as determined by the compensation committee in its discretion. The Compensation Committee may grant tandem distribution equivalent rights (“DERs”) with respect to the phantom units that entitle the holder to receive the value of any distributions made by us on our units while the phantom units are outstanding.
	The fair value of restricted unit and phantom unit awards is measured based on the fair market value of the Company units on the date of grant. The values of restricted unit grants and phantom unit grants that are required to be settled in units are recognized as expense over the vesting period of the grants with a corresponding charge to members’ equity. When the Company has the option to settle the phantom unit grants by issuing Company units or through cash settlement, the Company recognizes the value of those grants utilizing the liability method as defined under ASC Topic 718 based on the Company’s historical practice of settling phantom units predominantly in cash. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period.
	Executive Employment Agreements
	In June and July 2013, we and VNRH entered into new amended and restated executive employment agreements (the “Amended Agreements”) with each of our three executive officers, Messrs. Smith, Robert and Pence. The Amended Agreements were effective January 1, 2013 and the initial term of the Amended Agreements ends on January 1, 2016, with a subsequent twelve-month term extension automatically commencing on January 1, 2016 and each successive January 1 thereafter, provided that neither VNRH nor the executives deliver a timely non-renewal notice prior to a term expiration date.
	The Amended Agreements provide for an annual base salary and eligibility to receive an annual performance-based cash bonus award. The annual bonus will be calculated based upon three Company performance components: absolute target distribution growth, adjusted EBITDA growth and relative unit performance to peer group, as well as a fourth component determined solely in the discretion of our board of directors. As of March 31, 2015, an accrued liability was recognized and compensation expense of $0.4 million was recorded for the three months ended March 31, 2015 related to these arrangements, which was classified in the selling, general and administrative expenses line item in the Consolidated Statement of Operations.
	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. Any restricted units and phantom units granted to executives under the Amended Agreements 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. Both the restricted and phantom units include a tandem grant of DERs.
	Restricted Unit Grants
	In January 2015, the executives were granted a total of 360,762 restricted units in accordance with the Amended Agreements. Also, during the three months ended March 31, 2015, our three independent board members were granted a total of 26,334 restricted units which will vest one year from the date of grant. The restricted units granted to the executives and our board members are accompanied by DERs.
	A summary of the status of the non-vested restricted units as of March 31, 2015 is presented below:
		Number of		Weighted Average
		Non-vested  Restricted Units		Grant Date Fair Value
	Non-vested restricted units at December 31, 2014	440,047		$	28.87
	Granted	387,096		$	15.05
	Forfeited	(1,443	)	$	30.01
	Vested	(110,056	)	$	29.48
	Non-vested restricted units at March 31, 2015	715,644		$	21.3
	At March 31, 2015, there was approximately $12.6 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately 1.8 years. Our Consolidated Statements of Operations reflect non-cash compensation of $3.5 million and $2.4 million in the selling, general and administrative expense line item for the three months ended March 31, 2015 and 2014, respectively.
	Phantom Unit Grants
	We did not grant any phantom units during the three months ended March 31, 2015 and 2014.
	A summary of the status of the non-vested phantom units under the VNR LTIP as of March 31, 2015 is presented below:
		Number of		Weighted Average
		Non-vested		Grant Date Fair Value
		Phantom Units
	Non-vested phantom units at December 31, 2014	330,446		$	28.58
	Forfeited	(1,493	)	$	28.43
	Vested	(30,000	)	$	27.63
	Non-vested phantom units at March 31, 2015	298,953		$	28.67
	At March 31, 2015, there was approximately $8.6 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately 2.3 years. For the three months ended March 31, 2015 and 2014, non-cash unit-based compensation expense of $0.4 million and $0.5 million, respectively, has been recognized in the selling, general and administrative expense line item in the Consolidated Statements of Operations.

Shelf_Registration_Statements

Shelf Registration Statements	3 Months Ended
	Mar. 31, 2015
Shelf Registration Statement [Abstract]
Shelf Registration Statement	Shelf Registration Statement
	We have registered an indeterminate amount of Series A Cumulative Preferred Units, Series B Cumulative Preferred Units, Series C Cumulative Preferred Units, common units, debt securities and guarantees of debt securities under our currently effective shelf registration statement filed with the SEC, as amended (the “Shelf Registration Statement”). In the future, we may issue additional debt and equity securities pursuant to a prospectus supplement to the Shelf Registration Statement.
	Net proceeds, terms and pricing of each offering of securities issued under the Shelf Registration Statement are determined at the time of such offerings. The Shelf Registration Statement does not provide assurance that we will or could sell any such securities. Our ability to utilize the Shelf Registration Statement for the purpose of issuing, from time to time, any combination of debt securities, common units or Cumulative Preferred Units will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us.
	We have entered into an equity distribution agreement with respect to the issuance and sale of our Series A Cumulative Preferred Units, Series B Cumulative Preferred Units, Series C Cumulative Preferred Units, and common units. Pursuant to the terms of the equity distribution agreement, we may sell from time to time through our sales agents, (i) our common units representing limited liability company interests having an aggregate offering price of up to $400.0 million, (ii) our Series A Cumulative Preferred Units having an aggregate offering price of up to $50.0 million, (iii) our Series B Cumulative Preferred Units having an aggregate offering price of up to $100.0 million or (iv) our Series C Cumulative Preferred Units having an aggregate offering price of up to $75.0 million. The common units and Preferred Units to be sold under the equity distribution agreement are registered under our existing Shelf Registration Statement. During the three months ended March 31, 2015, total net proceeds received under the equity distribution agreement were approximately $12.2 million, after commissions and fees, from the sale of 849,217 common units.
	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	3 Months Ended
	Mar. 31, 2015
Subsequent Events [Abstract]
Subsequent Event	Subsequent Events
	Acquisition
	On April 20, 2015, we entered into a Purchase Agreement and Plan of Merger (“Merger Agreement”) with LRR Energy, L.P. (“LRR Energy” or “LRE”), pursuant to which a subsidiary of Vanguard will merge into LRR Energy and, at the same time, Vanguard will acquire LRE GP, LLC, the general partner of LRR Energy for total consideration of $251.0 million in Vanguard common units, valued as of April 20, 2015, and the assumption of LRE’s net debt of $288.0 million. As a result of the transaction, LRR Energy and its general partner will become wholly owned subsidiaries of Vanguard.
	Under the terms of the Merger Agreement, (i) each outstanding common unit representing a limited partner interest in LRE (a “LRE Common Unit”) will be converted into the right to receive 0.55 newly issued Vanguard Common Units or, in the case of fractional Vanguard Common Units, cash (the “Merger Consideration”) and (ii) Vanguard will purchase all of the outstanding limited liability company interests in the LRE GP in exchange for 12,320 newly issued Vanguard Common Units. Further, in connection with the Merger Agreement, each award of restricted LRE Common Units issued under LRE’s long-term incentive plan that is subject to time-based vesting and that is outstanding and unvested immediately prior to the effective time of the Merger will become fully vested and will be deemed to be a LRE Common Unit with the right to receive the Merger Consideration.
	The merger is subject to customary closing conditions, including the approval of the LRR Energy unitholders. We expect that the transaction will close in the third quarter of 2015.
	Distributions
	On April 15, 2015, our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of March 2015 of $0.1175 per common and Class B unit ($1.41 on an annualized basis) expected to be paid on May 15, 2015 to Vanguard unitholders of record on May 1, 2015.
	Also on April 15, 2015, our board of directors declared a cash distribution for our preferred unitholders of $0.1641 per Series A Cumulative Preferred Unit, $0.15885 per Series B Cumulative Preferred Unit and $0.16146 per Series C Cumulative Preferred Unit, which will be paid on May 15, 2015 to Vanguard preferred unitholders of record on May 1, 2015.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2015
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 March 31, 2015 and December 31, 2014 and for the three months ended March 31, 2015 and 2014 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, the “12-month average price” discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is less than the total capitalized costs, we are required to write-down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write-downs are included in the Consolidated Statements of Operations as an impairment charge. No ceiling test impairment was required during the three months ended March 31, 2014.
	We recorded a non-cash ceiling test impairment of oil and natural gas properties for the three months ended March 31, 2015 of $132.6 million as a result of a decline in oil and natural gas prices at the measurement date, March 31, 2015. The first quarter 2015 impairment was calculated based on the 12-month average price of $3.91 per MMBtu for natural gas and $82.62 per barrel of crude oil.
	When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties.
New Pronouncements Issued But Not Yet Adopted	New Pronouncement Issued But Not Yet Adopted:
	In April 2015, the FASB issued Accounting Standards Update (“ASU”) No. 2015-03, Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (“ASU No. 2015-03”), which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 is to be applied retrospectively and is effective for periods beginning after December 15, 2015. The Company will adopt ASU No. 2015-03 by the date required, which will affect the presentation of debt issuance costs in the balance sheet but will not have any impact on the Company’s results of operations or financial position.
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)	3 Months Ended
	Mar. 31, 2015
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, 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, and (iii) interest expense on additional borrowings necessary to finance the acquisitions. The net gain on acquisition of oil and natural gas properties was excluded from the pro forma results for the three months ended March 31, 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 March 31, 2014
	Total revenues		$	166,486
	Net income attributable to Common and Class B unitholders		$	9,741
	Net income per Common and Class B unit, Basic and Diluted		$	0.12
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
			March 31,
			2015			2014
		(in thousands)
	Pinedale Acquisition
	Revenues		$	23,733		$	29,641
	Excess of revenues over direct operating expenses		$	16,578		$	23,091
	Piceance Acquisition
	Revenues		$	11,773		$	—
	Excess of revenues over direct operating expenses		$	6,073		$	—
	All other acquisitions
	Revenues		$	9,393		$	—
	Excess of revenues over direct operating expenses		$	4,939		$	—
Pinedale Acquisition
Business Acquisition [Line Items]
Fair value of assets and liabilities acquired
	Fair value of assets and liabilities acquired		(in thousands)
	Oil and natural gas properties		$	600,123
	Inventory		244
	Asset retirement obligations		(12,404		)
	Imbalance liabilities		(171		)
	Other		(125		)
	Total fair value of assets and liabilities acquired		587,667
	Fair value of consideration transferred		555,553
	Gain on acquisition		$	32,114
Piceance Acquisition
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		$	523,537
	Asset retirement obligations		(19,452		)
	Production and ad valorem taxes payable		(7,552		)
	Suspense liabilities		(445		)
	Other		(124		)
	Total fair value of assets and liabilities acquired		495,964
	Fair value of consideration transferred		496,391
	Loss on acquisition		$	(427	)

LongTerm_Debt_Tables

Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [Abstract]
Financing Arrangements	Our financing arrangements consisted of the following as of the date indicated:
							Amount Outstanding
	Description		Interest Rate		Maturity Date		March 31, 2015				December 31, 2014
							(in thousands)
	Senior Secured Reserve-Based		Variable (1)		April 16, 2018		$	1,330,000			$	1,360,000
	Credit Facility
	Senior Notes		7.875% (2)		April 1, 2020		550,000				550,000
	Lease Financing Obligation		4.16%		August 10, 2020 (3)		$	27,923			28,986
							$	1,907,923			$	1,938,986
	Less:
	Unamortized discount on Senior Notes						(1,782		)		(1,852		)
	Current portion of Lease Financing Obligation						(4,363		)		(4,318		)
	Total long-term debt						$	1,901,778			$	1,932,816
	-1	Variable interest rate was 2.18% and 2.17% at March 31, 2015 and December 31, 2014, respectively.
	-2	Effective interest rate was 8.0%.
	-3	The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021.
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)	3 Months Ended
	Mar. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivative Contracts Covering Anticipated Future Production	At March 31, 2015, the Company had open commodity derivative contracts covering our anticipated future production as follows:
	Fixed-Price Swaps
			Gas							Oil						NGLs
	Contract Period		MMBtu			Weighted Average				Bbls			Weighted Average			Bbls	Weighted Average
						Fixed Price							WTI Price				Fixed Price
	April 1, 2015 – December 31, 2015		66,137,500			$	4.26			1,846,750			$	73.07		185,625	$	46.34
	January 1, 2016 – December 31, 2016		55,083,000			$	4.47			146,400			$	89.98		—	$	—
	January 1, 2017 – December 31, 2017		24,027,000			$	4.35			—			$	—		—	$	—
	Call Options Sold
			Gas							Oil
	Contract Period		MMBtu			Weighted Average				Bbls			Weighted Average
						Fixed Price							Fixed Price
	April 1, 2015 – December 31, 2015		—			$	—			55,000			$	105
	January 1, 2016 – December 31, 2016		9,150,000			$	4.25			622,200			$	125
	January 1, 2017 – December 31, 2017		9,125,000			$	4.5			365,000			$	95
	Basis Swaps
			Gas
	Contract Period		MMBtu			Weighted Avg. Basis				Pricing Index
						Differential ($/MMBtu)
	April 1, 2015 – December 31, 2015		22,000,000			$	(0.28	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2016 – December 31, 2016		18,300,000			$	(0.24	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2017 – December 31, 2017		10,950,000			$	(0.22	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
			Oil
	Contract Period		Bbls			Weighted Avg. Basis				Pricing Index
						Differential ($/Bbl)
	April 1, 2015 – December 31, 2015		385,000			$	(1.68	)		WTI Midland and WTI Cushing Basis Differential
	April 1, 2015 – December 31, 2015		110,000			$	(2.33	)		West Texas Sour and WTI Cushing Basis Differential
	April 1, 2015 – December 31, 2015		550,000			$	(14.50	)		WTI and West Canadian Select Basis Differential
	Three-Way Collars
			Gas
	Contract Period		MMBtu			Floor				Ceiling				Put Sold
	January 1, 2016 – December 31, 2016		12,810,000			$	3.95			$	4.25			$	3
	January 1, 2017 – December 31, 2017		16,425,000			$	3.92			$	4.23			$	3.37
			Oil
	Contract Period		Bbls			Floor				Ceiling				Put Sold
	April 1, 2015 – December 31, 2015		160,750			$	90			$	97.26			$	76.43
	January 1, 2016 – December 31, 2016		1,061,400			$	90			$	96.18			$	73.62
	Put Options Sold
			Gas							Oil
	Contract Period		MMBtu			Put Sold				Bbls			Put Sold
						($/MMBtu)							($/Bbl)
	April 1, 2015 – December 31, 2015		19,937,500			$	2.99			476,000			$	72.11
	January 1, 2016 – December 31, 2016		1,830,000			$	3			146,400			$	75
	January 1, 2017 – December 31, 2017		1,825,000			$	3.5			73,000			$	75
	Range Bonus Accumulators
			Gas
	Contract Period		MMBtu			Bonus				Range Ceiling				Range Floor
	April 1, 2015 – December 31, 2015		1,100,000			$	0.16			$	4			$	2.5
			Oil
	Contract Period		Bbls			Bonus				Range Ceiling				Range Floor
	April 1, 2015 – December 31, 2015		137,500			$	4			$	100			$	75
	January 1, 2016 – December 31, 2016		183,000			$	4			$	100			$	75
	Collars
			Oil
	Contract Period		Bbls			Floor Price ($/Bbl)				Ceiling Price ($/Bbl)
	April 1, 2015 – December 31, 2015		274,500			$	50			$	56.85
	Call Spreads
			Oil
	Contract Period		Bbls			Call Price ($/Bbl)				Short Call Price ($/Bbl)
	April 1, 2015 – December 31, 2015		947,600			$	70			$	85
	Puts
			Oil
	Contract Period		Bbls			Put Price ($/Bbl)
	January 1, 2016 – December 31, 2016		366,000			$	60
Interest Rate Derivative Contracts	Interest Rate Swaps
	At March 31, 2015, we had open interest rate derivative contracts as follows (in thousands):
	Period		Notional Amount				Fixed LIBOR Rates
	April 1, 2015 to December 10, 2016		$	20,000			2.17	%
	April 1, 2015 to October 31, 2016		$	40,000			1.65	%
	April 1, 2015 to August 5, 2015 (1)		$	30,000			2.25	%
	April 1, 2015 to August 6, 2016		$	25,000			1.8	%
	April 1, 2015 to October 31, 2016		$	20,000			1.78	%
	April 1, 2015 to September 23, 2016		$	75,000			1.15	%
	April 1, 2015 to March 7, 2016		$	75,000			1.08	%
	April 1, 2015 to September 7, 2016		$	25,000			1.25	%
	April 1, 2015 to December 10, 2015 (2)		$	50,000			0.21	%
	Total		$	360,000
	-1	The counterparty has the option to extend the termination date of this contract to August 5, 2018 at 2.25%.
	-2	The counterparty has the option to require Vanguard to pay a fixed rate of 0.91% from December 10, 2015 to December 10, 2017.
Fair Value of Derivatives Outstanding	Our commodity derivatives and interest rate swap derivatives are presented on a net basis in “derivative assets” and “derivative liabilities” on the Consolidated Balance Sheets. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets for the periods indicated (in thousands):
			March 31, 2015
	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		$	309,531			$	(59,676	)		$	249,855
	Total derivative instruments		$	309,531			$	(59,676	)		$	249,855
	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		$	(59,688	)		$	59,676			$	(12	)
	Interest rate derivative contracts		(4,881		)		—				(4,881		)
	Total derivative instruments		$	(64,569	)		$	59,676			$	(4,893	)
			December 31, 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		$	289,018			$	(63,321	)		$	225,697
	Total derivative instruments		$	289,018			$	(63,321	)		$	225,697
	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		$	(63,615	)		$	63,321			$	(294	)
	Interest rate derivative contracts		(4,669		)		—				(4,669		)
	Total derivative instruments		$	(68,284	)		$	63,321			$	(4,963	)
Reported Gains and Losses on Derivative Instruments	Changes in fair value of our commodity and interest rate derivatives for the three months ended March 31, 2015 and the year ended December 31, 2014 are as follows:
		Three Months Ended				Year Ended December 31, 2014
		31-Mar-15
		(in thousands)
	Derivative asset at beginning of period, net	$	220,734			$	66,711
	Purchases
	Fair value of derivatives acquired	35,644				(1,344		)
	Net gains on commodity and interest rate derivative contracts	57,830				161,519
	Settlements
	Cash settlements received on matured commodity derivative contracts	(38,291		)		(10,187		)
	Cash settlements paid on matured interest rate derivative contracts	990				4,035
	Termination of derivative contracts	(31,945		)		—
	Derivative asset at end of period, net	$	244,962			$	220,734

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2015
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):
		March 31, 2015
		Fair Value Measurements Using									Assets/Liabilities
		Level 1			Level 2			Level 3			at Fair value
	Assets:
	Commodity price derivative contracts	$	—		$	256,190		$	(6,335	)	$	249,855
	Total derivative instruments	$	—		$	256,190		$	(6,335	)	$	249,855
	Liabilities:
	Commodity price derivative contracts	$	—		$	(12	)	$	—		$	(12	)
	Interest rate derivative contracts	—			(4,881		)	—			(4,881		)
	Total derivative instruments	$	—		$	(4,893	)	$	—		$	(4,893	)
		December 31, 2014
		Fair Value Measurements Using									Assets/Liabilities
		Level 1			Level 2			Level 3			at Fair value
	Assets:
	Commodity price derivative contracts	$	—		$	232,167		$	(6,470	)	$	225,697
	Total derivative instruments	$	—		$	232,167		$	(6,470	)	$	225,697
	Liabilities:
	Commodity price derivative contracts	$	—		$	(294	)	$	—		$	(294	)
	Interest rate derivative contracts	—			(4,669		)	—			(4,669		)
	Total derivative instruments	$	—		$	(4,963	)	$	—		$	(4,963	)
Reconciliation of changes in the fair value of assets and liabilities classified as Level 3	The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 (unobservable inputs) in the fair value hierarchy:
		Three Months Ended
		March 31,
		2015			2014
		(in thousands)
	Unobservable inputs, beginning of period	$	(6,470	)	$	566
	Total gains (losses)	1,287			(957		)
	Settlements	(1,152		)	36
	Unobservable inputs, end of period	$	(6,335	)	$	(355	)
	Change in fair value included in earnings related to derivatives	$	(804	)	$	(670	)
	still held as of March 31,

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2015
Asset Retirement Obligation [Abstract]
Changes in Asset Retirement Obligations	The asset retirement obligations as of March 31, 2015 and December 31, 2014 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the three months ended March 31, 2015 and year ended December 31, 2014 were as follows (in thousands):
		March 31, 2015			December 31, 2014
	Asset retirement obligations, beginning of period	$	149,062		$	87,967
	Liabilities added during the current period	360			52,829
	Accretion expense	1,835			5,889
	Retirements	(280		)	(450		)
	Disposition of properties	—			(1,291		)
	Change in estimate	—			4,118
	Asset retirement obligation, end of period	150,977			149,062
	Less: current obligations	(2,386		)	(2,386		)
	Long-term asset retirement obligation, end of period	$	148,591		$	146,676

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	3 Months Ended
	Mar. 31, 2015
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 March 31, 2015. 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.
		31-Mar-15
		(in thousands)
	April 1, 2015 - December 31, 2015	$	13,046
	2016	14,508
	2017	12,362
	2018	11,696
	2019	9,661
	Thereafter	410
	Total	$	61,683

Members_Equity_and_Net_Income_1

Members' Equity and Net Income per Common and Class B Unit (Tables)	3 Months Ended
	Mar. 31, 2015
Equity [Abstract]
Cumulative Preferred Units	The following table summarizes the Company’s Cumulative Preferred units outstanding at March 31, 2015 and December 31, 2014:
								March 31, 2015				December 31, 2014
		Earliest		Liquidation Preference		Distribution Rate		Units Outstanding		Carrying Value		Units Outstanding	Carrying Value
		Redemption Date		Per Share						(in thousands)			(in thousands)
	Series A	June 15, 2023		$25.00		7.88%		2,581,873		$	62,200	2,581,873	$	62,200
	Series B	April 15, 2024		$25.00		7.63%		7,000,000		$	169,265	7,000,000	$	169,265
	Series C	October 15, 2024		$25.00		7.75%		4,300,000		$	103,979	4,300,000	$	103,979
	Total Cumulative Preferred Units							13,881,873		$	335,444	13,881,873	$	335,444
Schedule of Common and Class B Units Outstanding Roll Forward	The following is a summary of the changes in our common units issued during the three months ended March 31, 2015 and the year ended December 31, 2014 (in thousands):
		March 31, 2015			December 31, 2014
	Beginning of period	83,452			78,337
	Issuance of Common units for cash	849			4,864
	Repurchase of units under the Common unit buyback program	(157	)		(135	)
	Reissuance of Common units for restricted unit grants	292			—
	Unit-based compensation	334			386
	End of period	84,770			83,452
Schedule of Earnings Per Share, Basic and Diluted	The net income (loss) attributable to common and Class B unitholders and the weighted average units for calculating basic and diluted net income (loss) per common and Class B unit were as follows (in thousands, except per unit data):
		Three Months Ended
		March 31,
		2015				2014
	Net income (loss) attributable to common and Class B unitholders	$	(125,520	)		$	13,159
	Weighted average number of common and Class B units outstanding - basic	84,164				79,606
	Effect of dilutive securities:
	Phantom units (a)	—				286
	Weighted average number of common and Class B units outstanding - diluted	84,164				79,892
	Net income (loss) per common and Class B unit
	Basic	$	(1.49	)		$	0.17
	Diluted	$	(1.49	)		$	0.16
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 April 15, 2015, our board of directors declared a cash distribution on the Cumulative Preferred Units and common and Class B units attributable to the month of March 2015. See Note 11. Subsequent Events for further discussion.
		Cash Distributions
	Distribution	Per Unit				Declared Date		Record Date	Payment Date
	2015
	February	$	0.1175			March 18, 2015		April 1, 2015	April 14, 2015
	January	$	0.1175			February 17, 2015		March 2, 2015	March 17, 2015
	2014
	Fourth Quarter
	December	$	0.21			January 22, 2015		February 2, 2015	February 13, 2015
	November	$	0.21			December 16, 2014		January 2, 2015	January 14, 2015
	October	$	0.21			November 20, 2014		December 1, 2014	December 15, 2014
	Third Quarter
	September	$	0.21			October 20, 2014		November 3, 2014	November 14, 2014
	August	$	0.21			September 19, 2014		October 1, 2014	October 15, 2014
	July	$	0.21			August 19, 2014		September 2, 2014	September 12, 2014
	Second Quarter
	June	$	0.21			July 16, 2014		August 1, 2014	August 14, 2014
	May	$	0.21			June 24, 2014		July 1, 2014	July 15, 2014
	April	$	0.21			May 20, 2014		June 2, 2014	June 13, 2014
	First Quarter
	March	$	0.21			April 17, 2014		May 1, 2014	May 15, 2014
	February	$	0.21			March 17, 2014		April 1, 2014	April 14, 2014
	January	$	0.2075			February 20, 2014		March 3, 2014	March 17, 2014
	2013
	Fourth Quarter
	December	$	0.2075			January 16, 2014		February 3, 2014	February 14, 2014

UnitBased_Compensation_Tables

Unit-Based Compensation (Tables)	3 Months Ended
	Mar. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Share-based Compensation, Restricted Stock Units Award Activity	A summary of the status of the non-vested restricted units as of March 31, 2015 is presented below:
		Number of		Weighted Average
		Non-vested  Restricted Units		Grant Date Fair Value
	Non-vested restricted units at December 31, 2014	440,047		$	28.87
	Granted	387,096		$	15.05
	Forfeited	(1,443	)	$	30.01
	Vested	(110,056	)	$	29.48
	Non-vested restricted units at March 31, 2015	715,644		$	21.3
Schedule of Nonvested Phantom Units Activity	A summary of the status of the non-vested phantom units under the VNR LTIP as of March 31, 2015 is presented below:
		Number of		Weighted Average
		Non-vested		Grant Date Fair Value
		Phantom Units
	Non-vested phantom units at December 31, 2014	330,446		$	28.58
	Forfeited	(1,493	)	$	28.43
	Vested	(30,000	)	$	27.63
	Non-vested phantom units at March 31, 2015	298,953		$	28.67

Description_of_the_Business_De

Description of the Business (Details)	3 Months Ended
	Mar. 31, 2015
	operating_areas
Accounting Policies [Abstract]
Number of operating areas	9

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Discount rate used in determining limitation of capitalized costs (in hundredths)	10.00%
Impairment of oil and natural gas properties	$132,610	$0
Average price of natural gas used in the impairment calculation	3.91
Average price of crude oil used in the impairment calculation	82.62

Acquisitions_Details

Acquisitions (Details) (USD $)	0 Months Ended				3 Months Ended
In Thousands, unless otherwise specified	Jan. 31, 2014	Sep. 30, 2014	2-May-14	Aug. 29, 2014	Mar. 31, 2015
Pinedale Acquisition
Business Acquisition [Line Items]
Fair value of consideration transferred	$555,553
Effective date of acquisition	1-Oct-13
Gain on acquisition of oil and natural gas properties	32,114
Piceance Acquisition
Business Acquisition [Line Items]
Fair value of consideration transferred		496,391
Effective date of acquisition	1-Jul-14
Goodwill, Impairment Loss		427
Wamsutter Property Acquisition
Business Acquisition [Line Items]
Ownership interest conveyed			75.00%
Fair value of consideration transferred			6,800
Gulf Coast Acquisition
Business Acquisition [Line Items]
Fair value of consideration transferred				265,100
Effective date of acquisition				1-Jun-14
Other Smaller Acquisitions
Business Acquisition [Line Items]
Fair value of consideration transferred					$17,700

Acquisitions_Fair_Value_of_Ass

Acquisitions (Fair Value of Assets and Liabilities Acquired) (Details) (USD $)	0 Months Ended
In Thousands, unless otherwise specified	Jan. 31, 2014	Sep. 30, 2014
Pinedale Acquisition
Fair value of assets and liabilities acquired
Oil and Gas Properties	$600,123
Inventory	244
Asset retirement obligations	-12,404
Imbalance and Suspense liabilities	-171
Other	-125
Total fair value of assets and liabilities acquired	587,667
Fair value of consideration transferred	555,553
Gain on acquisition of oil and natural gas properties	32,114
Piceance Acquisition
Fair value of assets and liabilities acquired
Oil and Gas Properties		523,537
Asset retirement obligations		-19,452
Production and ad valorem taxes payable		-7,552
Imbalance and Suspense liabilities		-445
Other		-124
Total fair value of assets and liabilities acquired		495,964
Fair value of consideration transferred		496,391
Loss on acquisition		($427)

Acquisitions_Pro_Forma_Details

Acquisitions (Pro Forma) (Details) (USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2014
Business Acquisition, Pro Forma Information [Abstract]
Proforma revenues	$166,486
Proforma Net income (loss)	$9,741
Net income per Common and Class B unit:
Business Acquisition, Pro Forma Earnings Per Share, Basic and Diluted	$0.12

Acquisitions_Acquiree_Earnings

Acquisitions (Acquiree Earnings) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Pinedale Acquisition
Business Acquisition [Line Items]
Revenues	$23,733	$29,641
Excess of revenues over direct operating expenses	16,578	23,091
Piceance Acquisition
Business Acquisition [Line Items]
Revenues	11,773	0
Excess of revenues over direct operating expenses	6,073	0
Other Acquisitions
Business Acquisition [Line Items]
Revenues	9,393	0
Excess of revenues over direct operating expenses	$4,939	$0

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)	3 Months Ended
	Mar. 31, 2015		Dec. 31, 2014
Senior Secured Reserve-Based Credit Facility [Abstract]
Outstanding borrowings	$1,907,923,000		$1,938,986,000
Current Ratio	100.00%
Debt to EBITDA ratio	400.00%
Senior Notes [Abstract]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%
Percentage of ownership in subsidiaries	100.00%
Members' equity available for distributions	74,500,000
Aggregate Cost, Early Buyout Option to Purchase equipment	16,000,000
Senior Secured Reserve-Based Credit Facility
Senior Secured Reserve-Based Credit Facility [Abstract]
Line of Credit Facility, Maximum Borrowing Capacity	3,500,000,000
Line of Credit Facility, Current Borrowing Capacity	2,000,000,000
Outstanding borrowings	1,330,000,000		1,360,000,000
Remaining borrowing capacity	665,500,000
Senior Notes [Abstract]
Maturity date	16-Apr-18
Senior Notes
Senior Secured Reserve-Based Credit Facility [Abstract]
Outstanding borrowings	550,000,000		550,000,000
Senior Notes [Abstract]
Aggregate principal amount	550,000,000
Stated interest rate (in hundredths)	7.88%	[1]
Maturity date	1-Apr-20
Redemption price of aggregate principal amount of senior notes on or after April 1, 2016 (in hundredths)	103.94%
Redemption price of aggregate principal amount of senior notes on April 1, 2018 and thereafter (in hundredths)	100.00%
Redemption price of aggregate principal amount of senior notes at any time prior to April 1, 2016 (in hundredths)	100.00%
Percentage of aggregate principal amount of senior notes that can be redeemed (in hundredths)	35.00%
Redemption price of aggregate principal amount of senior notes before April 1, 2015 (in hundredths)	107.88%
Percentage of aggregate principal amount of senior notes remained outstanding (in hundredths)	65.00%
Period of redemption of senior notes within equity offering (in days)	180 days
Required repurchase price of aggregate principal amount of senior notes, lower range (in hundredths)	100.00%
Required repurchase price of aggregate principal amount of senior notes, upper range (in hundredths)	101.00%
Lease Financing Obligations
Senior Secured Reserve-Based Credit Facility [Abstract]
Outstanding borrowings	27,923,000		28,986,000
Senior Notes [Abstract]
Stated interest rate (in hundredths)	4.16%
Maturity date	10-Aug-20	[2]
Standby Letters of Credit | Senior Secured Reserve-Based Credit Facility
Senior Secured Reserve-Based Credit Facility [Abstract]
Line of Credit Facility, Current Borrowing Capacity	$4,500,000
[1]	Effective interest rate was 8.0%.
[2]	The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021.

LongTerm_Debt_Financing_Arrang

Long-Term Debt - Financing Arrangements (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014
Debt Instrument [Line Items]
Outstanding borrowings	$1,907,923		$1,938,986
Debt Instrument, Unamortized Discount	-1,782		-1,852
Short-term Debt	-4,363		-4,318
Total long-term debt	1,901,778		1,932,816
Senior Secured Reserve-Based Credit Facility
Debt Instrument [Line Items]
Interest rate description	Variable (1)	[1]
Maturity date	16-Apr-18
Outstanding borrowings	1,330,000		1,360,000
Variable interest rate	2.18%		2.17%
Senior Notes
Debt Instrument [Line Items]
Stated interest rate (in hundredths)	7.88%	[2]
Maturity date	1-Apr-20
Outstanding borrowings	550,000		550,000
Effective interest rate (in hundredths)	8.00%
Lease Financing Obligations
Debt Instrument [Line Items]
Stated interest rate (in hundredths)	4.16%
Maturity date	10-Aug-20	[3]
Outstanding borrowings	$27,923		$28,986
[1]	Variable interest rate was 2.18% and 2.17% at MarchB 31, 2015 and DecemberB 31, 2014, respectively.
[2]	Effective interest rate was 8.0%.
[3]	The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021.

LongTerm_Debt_Borrowing_Base_U

Long-Term Debt - Borrowing Base Utilization Grid (Details)	3 Months Ended
	Mar. 31, 2015
Borrowing Base Utilization Less Than 25%
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% | Eurodollar Loans Margin
Debt Instrument [Line Items]
Loans margin (in hundredths)	1.50%
Borrowing Base Utilization Less Than 25% | ABR Loans Margin
Debt Instrument [Line Items]
Loans margin (in hundredths)	0.50%
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50%
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% | Eurodollar Loans Margin
Debt Instrument [Line Items]
Loans margin (in hundredths)	1.75%
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50% | ABR Loans Margin
Debt Instrument [Line Items]
Loans margin (in hundredths)	0.75%
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75%
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% | Eurodollar Loans Margin
Debt Instrument [Line Items]
Loans margin (in hundredths)	2.00%
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75% | ABR Loans Margin
Debt Instrument [Line Items]
Loans margin (in hundredths)	1.00%
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90%
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% | Eurodollar Loans Margin
Debt Instrument [Line Items]
Loans margin (in hundredths)	2.25%
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90% | ABR Loans Margin
Debt Instrument [Line Items]
Loans margin (in hundredths)	1.25%
Borrowing Base Utilization Equal To Or Greater Than 90%
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% | Eurodollar Loans Margin
Debt Instrument [Line Items]
Loans margin (in hundredths)	2.50%
Borrowing Base Utilization Equal To Or Greater Than 90% | ABR Loans Margin
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 $)	3 Months Ended
	Mar. 31, 2015
	MMBTU
Fair value of derivatives [Abstract]
Maximum potential loss due to credit risk	$309,500,000
Fixed-Price Swaps | Gas | April 1, 2015 - December 31, 2015
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future gas production (in units)	66,137,500
Weighted average fixed price (in dollars per unit)	4.26
Fixed-Price Swaps | Gas | Contract Period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future gas production (in units)	55,083,000
Weighted average fixed price (in dollars per unit)	4.47
Fixed-Price Swaps | Gas | January 1, 2017 to December 31, 2017
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future gas production (in units)	24,027,000
Weighted average fixed price (in dollars per unit)	4.35
Fixed-Price Swaps | Oil | April 1, 2015 - December 31, 2015
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future oil production (in units)	1,846,750
Weighted average fixed price (in dollars per unit)	73.07
Fixed-Price Swaps | Oil | Contract Period January 1, 2016 to December, 31 2016
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 | Oil | January 1, 2017 to December 31, 2017
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 | Natural Gas Liquids | April 1, 2015 - December 31, 2015
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future oil production (in units)	185,625
Weighted average fixed price (in dollars per unit)	46.34
Fixed-Price Swaps | Natural Gas Liquids | Contract Period January 1, 2016 to December, 31 2016
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 | Natural Gas Liquids | January 1, 2017 to December 31, 2017
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future oil production (in units)	0
Weighted average fixed price (in dollars per unit)	0
Call Option Sold | Gas | April 1, 2015 - December 31, 2015
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future gas production (in units)	0
Weighted average fixed price (in dollars per unit)	0
Call Option Sold | Gas | Contract Period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future gas production (in units)	9,150,000
Weighted average fixed price (in dollars per unit)	4.25
Call Option Sold | Gas | January 1, 2017 to December 31, 2017
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future gas production (in units)	9,125,000
Weighted average fixed price (in dollars per unit)	4.5
Call Option Sold | Oil | April 1, 2015 - December 31, 2015
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future oil production (in units)	55,000
Weighted average fixed price (in dollars per unit)	105
Call Option Sold | Oil | Contract Period January 1, 2016 to December, 31 2016
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
Call Option Sold | Oil | January 1, 2017 to December 31, 2017
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future oil production (in units)	365,000
Weighted average fixed price (in dollars per unit)	95
Basis Swaps | Gas | April 1, 2015 - December 31, 2015 | NW Rocky Mt-Henry Hub Index
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future gas production (in units)	22,000,000
Weighted average basis differential (in dollars per unit)	-0.28
Basis Swaps | Gas | Contract Period January 1, 2016 to December, 31 2016 | NW Rocky Mt-Henry Hub Index
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 | Gas | January 1, 2017 to December 31, 2017 | NW Rocky Mt-Henry Hub Index
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 | Oil | April 1, 2015 - December 31, 2015 | Midland-Cushing Index
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future oil production (in units)	385,000
Weighted average basis differential (in dollars per unit)	-1.68
Basis Swaps | Oil | April 1, 2015 - December 31, 2015 | WTS-Cushing Index
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future oil production (in units)	110,000
Weighted average basis differential (in dollars per unit)	-2.33
Basis Swaps | Oil | April 1, 2015 - December 31, 2015 | WTI-WCS Index
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future oil production (in units)	550,000
Weighted average basis differential (in dollars per unit)	-14.5
Three-Way Collars | Gas | Contract Period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future gas production (in units)	12,810,000
Weighted average price (in dollars per unit)	3
Floor (in dollars per unit)	3.95
Ceiling (in dollars per unit)	4.25
Three-Way Collars | Gas | January 1, 2017 to December 31, 2017
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future gas production (in units)	16,425,000
Weighted average price (in dollars per unit)	3.37
Floor (in dollars per unit)	3.92
Ceiling (in dollars per unit)	4.23
Three-Way Collars | Oil | April 1, 2015 - December 31, 2015
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future oil production (in units)	160,750
Weighted average price (in dollars per unit)	76.43
Floor (in dollars per unit)	90
Ceiling (in dollars per unit)	97.26
Three-Way Collars | Oil | Contract Period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future oil production (in units)	1,061,400
Weighted average price (in dollars per unit)	73.62
Floor (in dollars per unit)	90
Ceiling (in dollars per unit)	96.18
Put Options Sold | Gas | April 1, 2015 - December 31, 2015
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future gas production (in units)	19,937,500
Weighted average price (in dollars per unit)	2.99
Put Options Sold | Gas | Contract Period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future gas production (in units)	1,830,000
Weighted average price (in dollars per unit)	3
Put Options Sold | Gas | January 1, 2017 to December 31, 2017
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future gas production (in units)	1,825,000
Weighted average price (in dollars per unit)	3.5
Put Options Sold | Oil | April 1, 2015 - December 31, 2015
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future oil production (in units)	476,000
Weighted average price (in dollars per unit)	72.11
Put Options Sold | Oil | Contract Period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future oil production (in units)	146,400
Weighted average price (in dollars per unit)	75
Put Options Sold | Oil | January 1, 2017 to December 31, 2017
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 | Gas | April 1, 2015 - December 31, 2015
Commodity derivative contracts covering our anticipated future production [Abstract]
Floor (in dollars per unit)	2.5
Ceiling (in dollars per unit)	4
Notional amount (in MMBtu)	1,100,000
Bonus (in dollars per unit)	0.16
Range Bonus Accumulators | Oil | April 1, 2015 - December 31, 2015
Commodity derivative contracts covering our anticipated future production [Abstract]
Floor (in dollars per unit)	75
Derivative, Nonmonetary Notional Amount, Volume	137,500
Ceiling (in dollars per unit)	100
Bonus (in dollars per unit)	4
Range Bonus Accumulators | Oil | Contract Period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Floor (in dollars per unit)	75
Derivative, Nonmonetary Notional Amount, Volume	183,000
Ceiling (in dollars per unit)	100
Bonus (in dollars per unit)	4
Collars | Oil | April 1, 2015 - December 31, 2015
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future oil production (in units)	274,500
Floor (in dollars per unit)	50
Ceiling (in dollars per unit)	56.85
Call Spreads | Oil | April 1, 2015 - December 31, 2015
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future oil production (in units)	947,600
Derivative, Price Risk Option Strike Price	70
Call option short call price	85
Puts | Oil | Contract Period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Anticipated future oil production (in units)	366,000
Derivative, Price Risk Option Strike Price	60
Interest Rate Swaps
Interest rate derivative contracts [Abstract]
Notional amount	360,000,000
Interest Rate Swaps | Contract period April 1, 2015 to December 10, 2016
Interest rate derivative contracts [Abstract]
Notional amount	20,000,000
Fixed Libor Rates (in hundredths)	2.17%
Interest Rate Swaps | Contract period April 1, 2015 to October 31, 2016 Swap A
Interest rate derivative contracts [Abstract]
Notional amount	40,000,000
Fixed Libor Rates (in hundredths)	1.65%
Interest Rate Swaps | Contract period April 1, 2015 to August 5, 2015
Interest rate derivative contracts [Abstract]
Notional amount	30,000,000	[1]
Fixed Libor Rates (in hundredths)	2.25%	[1]
Interest Rate Swaps | Contract period April 1, 2015 to August 6, 2016
Interest rate derivative contracts [Abstract]
Notional amount	25,000,000
Fixed Libor Rates (in hundredths)	1.80%
Interest Rate Swaps | Contract period April 1, 2015 to October 31, 2016 Swap B
Interest rate derivative contracts [Abstract]
Notional amount	20,000,000
Fixed Libor Rates (in hundredths)	1.78%
Interest Rate Swaps | Contract period April 1, 2015 to September 23, 2016
Interest rate derivative contracts [Abstract]
Notional amount	75,000,000
Fixed Libor Rates (in hundredths)	1.15%
Interest Rate Swaps | Contract period April 1, 2015 to March 7, 2016
Interest rate derivative contracts [Abstract]
Notional amount	75,000,000
Fixed Libor Rates (in hundredths)	1.08%
Interest Rate Swaps | Contract period April 1, 2015 to September 7, 2016
Interest rate derivative contracts [Abstract]
Notional amount	25,000,000
Fixed Libor Rates (in hundredths)	1.25%
Interest Rate Swaps | Contract period April 1, 2015 to December 10, 2015
Interest rate derivative contracts [Abstract]
Notional amount	$50,000,000	[2]
Fixed Libor Rates (in hundredths)	0.21%	[2]
Interest Rate Swaps | Contract Period December 10, 2015 to December 10, 2017
Interest rate derivative contracts [Abstract]
Fixed Libor Rates (in hundredths)	0.91%
[1]	The counterparty has the option to extend the termination date of this contract to August 5, 2018 at 2.25%.
[2]	The counterparty has the option to require Vanguard to pay a fixed rate of 0.91% from DecemberB 10, 2015 to DecemberB 10, 2017.

Price_and_Interest_Rate_Risk_M3

Price and Interest Rate Risk Management Activities - Balance Sheet Presentation (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Offsetting Derivative Assets:
Gross amounts of recognized assets	$309,531	$289,018
Gross amounts offset in the consolidated balance sheets	-59,676	-63,321
Net Amounts Presented in the Consolidated Balance Sheets	249,855	225,697
Offsetting Derivative Liabilities:
Gross amounts of recognized liabilities	-64,569	-68,284
Gross amounts offset in the consolidated balance sheets	59,676	63,321
Net Amounts Presented in the Consolidated Balance Sheets	-4,893	-4,963
Commodity Contract
Offsetting Derivative Assets:
Gross amounts of recognized assets	309,531	289,018
Gross amounts offset in the consolidated balance sheets	-59,676	-63,321
Net Amounts Presented in the Consolidated Balance Sheets	249,855	225,697
Offsetting Derivative Liabilities:
Gross amounts of recognized liabilities	-59,688	-63,615
Gross amounts offset in the consolidated balance sheets	59,676	63,321
Net Amounts Presented in the Consolidated Balance Sheets	-12	-294
Interest Rate Contract
Offsetting Derivative Liabilities:
Gross amounts of recognized liabilities	-4,881	-4,669
Gross amounts offset in the consolidated balance sheets	0	0
Net Amounts Presented in the Consolidated Balance Sheets	($4,881)	($4,669)

Price_and_Interest_Rate_Risk_M4

Price and Interest Rate Risk Management Activities - Change in Fair Value of Derivatives (Details) (USD $)	3 Months Ended		12 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Fair Value, Net Derivative Asset (Liability), Reconciliation [Roll Forward]
Derivative asset at beginning of period, net	$220,734	$66,711	$66,711
Fair value of derivatives acquired	35,644		-1,344
Net gains (losses) on commodity and interest rate derivative contracts	57,830	-56,495	161,519
Cash settlement received on matured commodity derivative contracts	-38,291	11,969	-10,187
Cash settlements paid on matured interest rate derivative contracts	990	990	4,035
Fair value of derivative contracts terminated	-31,945		0
Derivative asset at end of period, net	$244,962		$220,734

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	$509,300,000
Liabilities:
Asset retirement obligations incurred and recorded	360,000	52,829,000
Credit-adjusted risk-free interest rate (in hundredths)	4.60%
Average inflation rate (in hundredths)	2.29%
Fair Value Measured on a Recurring Basis
Assets:
Commodity price derivative contracts	249,855,000	225,697,000
Total derivative instruments	249,855,000	225,697,000
Liabilities:
Commodity price derivative contracts	-12,000	-294,000
Interest rate derivative contracts	-4,881,000	-4,669,000
Total derivative instruments	-4,893,000	-4,963,000
Fair Value Measured on a Recurring Basis | Fair Value Measurements Using Level 1
Assets:
Commodity price derivative contracts	0	0
Total derivative instruments	0	0
Liabilities:
Commodity price derivative contracts	0	0
Interest rate derivative contracts	0	0
Total derivative instruments	0	0
Fair Value Measured on a Recurring Basis | Fair Value Measurements Using Level 2
Assets:
Commodity price derivative contracts	256,190,000	232,167,000
Total derivative instruments	256,190,000	232,167,000
Liabilities:
Commodity price derivative contracts	-12,000	-294,000
Interest rate derivative contracts	-4,881,000	-4,669,000
Total derivative instruments	-4,893,000	-4,963,000
Fair Value Measured on a Recurring Basis | Fair Value Measurements Using Level 3
Assets:
Commodity price derivative contracts	-6,335,000	-6,470,000
Total derivative instruments	-6,335,000	-6,470,000
Liabilities:
Commodity price derivative contracts	0	0
Interest rate derivative contracts	0	0
Total derivative instruments	$0	$0

Fair_Value_Measurements_Unobse

Fair Value Measurements - Unobservable Inputs Reconciliation (Details) (Fair Value Measurements Using Level 3, USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Fair Value Measurements Using Level 3
Unobservable inputs reconciliation
Unobservable inputs, beginning of period	($6,470)	$566
Total gains (losses)	1,287	-957
Settlements	-1,152	36
Unobservable inputs, end of period	-6,335	-355
Change in fair value included in earnings related to derivatives still held as of March 31,	($804)	($670)

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	3 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Changes in asset retirement obligations [Abstract]
Asset retirement obligations at beginning of period	$149,062	$87,967
Liabilities added during the current period	360	52,829
Accretion expense	1,835	5,889
Retirements	-280	-450
Disposition of properties	0	-1,291
Change in estimate	0	4,118
Total asset retirement obligations at end of period	150,977	149,062
Less: current obligations	-2,386	-2,386
Long-term asset retirement obligation at end of period	$148,591	$146,676

Commitments_and_Contingencies_1

Commitments and Contingencies (Transportation Demand Charges) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015
Gross future minimum transportation demand
April 1, 2015 - December 31, 2015	13,046
2016	14,508
2017	12,362
2018	11,696
2019	9,661
Thereafter	410
Total	61,683
Minimum
Oil and Gas Delivery Commitments and Contracts
Oil and Gas Delivery Commitments and Contracts, Length of Contract	1 year
Maximum
Oil and Gas Delivery Commitments and Contracts
Oil and Gas Delivery Commitments and Contracts, Length of Contract	5 years

Members_Equity_and_Net_Income_2

Members' Equity and Net Income per Common and Class B Unit - Preferred Units Outstanding (Details) (USD $)	3 Months Ended
In Thousands, except Share data, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Preferred Unit, Liquidation Preference Per Share (usd per share)	$25
Preferred units, outstanding (shares)	13,881,873	13,881,873
Preferred units, carrying value	$335,444	$335,444
Series A Preferred Units
Class of Stock [Line Items]
Preferred Unit, Liquidation Preference Per Share (usd per share)	$25
Preferred Unit, Distribution Rate, Percentage	7.88%
Preferred units, outstanding (shares)	2,581,873	2,581,873
Preferred units, carrying value	62,200	62,200
Series B Preferred Unit
Class of Stock [Line Items]
Preferred Unit, Liquidation Preference Per Share (usd per share)	$25
Preferred Unit, Distribution Rate, Percentage	7.63%
Preferred units, outstanding (shares)	7,000,000	7,000,000
Preferred units, carrying value	169,265	169,265
Series C Preferred Units
Class of Stock [Line Items]
Preferred Unit, Liquidation Preference Per Share (usd per share)	$25
Preferred Unit, Distribution Rate, Percentage	7.75%
Preferred units, outstanding (shares)	4,300,000	4,300,000
Preferred units, carrying value	$103,979	$103,979

Members_Equity_and_Net_Income_3

Members' Equity and Net Income per Common and Class B Unit - Common and Class B Units Rollforward (Details) (Common Units)	3 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Common Units
Increase (Decrease) in Members' Equity [Roll Forward]
Beginning of period	83,452	78,337
Issuance of Common units for cash	849	4,864
Treasury Stock, Shares, Acquired	-157	-135
Stock Issued During Period, Shares, Treasury Stock Reissued	292	0
Unit-based compensation	334	386
End of period	84,770	83,452

Members_Equity_and_Net_Income_4

Members' Equity and Net Income per Common and Class B Unit - Net Income per Unit (Details) (USD $)	3 Months Ended
In Thousands, except Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Dilutive Securities Included in Computation of Earnings Per Share [Line Items]
Preferred Unit, Liquidation Preference Per Share (usd per share)	$25
Net Income Available to Common and Class B unitholders, Basic	($125,520)	$13,159
Weighted Average Number of Shares Outstanding, Basic (shares)	84,164,000	79,606,000
Weighted Average Number of Shares Outstanding, Diluted (shares)	84,164,000	79,892,000
Net income per common and Class B unit, Basic (usd per share)	($1.49)	$0.17
Net income per common and class B unit, Diluted (usd per share)	($1.49)	$0.16
Antidilutive securities excluded from computation (shares)	202,407
Phantom Share Units (PSUs)
Dilutive Securities Included in Computation of Earnings Per Share [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	0	286,000

Members_Equity_and_Net_Income_5

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

1 Months Ended

3 Months Ended

Feb. 28, 2015

Jan. 31, 2015

Dec. 31, 2014

Nov. 30, 2014

Oct. 31, 2014

Sep. 30, 2014

Aug. 31, 2014

Jul. 31, 2014

Jun. 30, 2014

31-May-14

Apr. 30, 2014

Mar. 31, 2014

Feb. 28, 2014

Jan. 31, 2014

Dec. 31, 2013

Mar. 31, 2015

Class of Stock [Line Items]

Preferred Unit, Liquidation Preference Per Share (usd per share)

$25

Common Units

Class of Stock [Line Items]

Cash Distributions per Unit (usd per share)

$0.12

$0.12

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

Cash distribution, declaration date

18-Mar-15

17-Feb-15

22-Jan-15

16-Dec-14

20-Nov-14

20-Oct-14

19-Sep-14

19-Aug-14

16-Jul-14

24-Jun-14

20-May-14

17-Apr-14

17-Mar-14

20-Feb-14

16-Jan-14

Cash Distributions Record Date

1-Apr-15

2-Mar-15

2-Feb-15

2-Jan-15

1-Dec-14

3-Nov-14

1-Oct-14

2-Sep-14

1-Aug-14

1-Jul-14

2-Jun-14

1-May-14

1-Apr-14

3-Mar-14

3-Feb-14

Cash Distributions Payment Date

14-Apr-15

17-Mar-15

13-Feb-15

14-Jan-15

15-Dec-14

14-Nov-14

15-Oct-14

12-Sep-14

14-Aug-14

15-Jul-14

13-Jun-14

15-May-14

14-Apr-14

17-Mar-14

14-Feb-14

Series A Preferred Units

Class of Stock [Line Items]

Preferred Unit, Distribution Rate, Percentage

7.88%

Preferred Unit, Liquidation Preference Per Share (usd per share)

$25

Series B Preferred Unit

Class of Stock [Line Items]

Preferred Unit, Distribution Rate, Percentage

7.63%

Preferred Unit, Liquidation Preference Per Share (usd per share)

$25

Series C Preferred Units

Class of Stock [Line Items]

Preferred Unit, Distribution Rate, Percentage

7.75%

Preferred Unit, Liquidation Preference Per Share (usd per share)

$25

UnitBased_Compensation_Details

Unit-Based Compensation (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Accrued liability	$0.40
Amended Agreements
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of executives in amended agreements	3
Selling, General and Administrative Expenses | Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash compensation	3.5	2.4
Selling, General and Administrative Expenses | Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash compensation	$0.40	$0.50

UnitBased_Compensation_Summary

Unit-Based Compensation - Summary of Non-Vested Restricted Units (Details) (USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Board Member
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	1 year
Amended Agreements | Executive Officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted units granted (in units)	360,762
VNR Long Term Incentive Plan | Board Member
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted units granted (in units)	26,334
Restricted Stock Units (RSUs)
Number of Non-vested Units
Non-vested units at beginning of period (in units)	440,047
Granted (in units)	387,096
Forfeited (in units)	1,443
Vested (in units)	110,056
Non-vested units at end of period (in units)	715,644
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per unit)	$28.87
Granted (in dollars per unit)	$15.05
Forfeited (in dollars per unit)	$30.01
Vested (in dollars per unit)	$29.48
Non-vested units at end of period (in dollars per unit)	$21.30
Restricted Stock Units (RSUs) | Amended Agreements
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percent of units vesting on each one-year anniversary	33.33%
Phantom Share Units (PSUs)
Number of Non-vested Units
Non-vested units at beginning of period (in units)	330,446
Forfeited (in units)	1,493
Vested (in units)	30,000
Non-vested units at end of period (in units)	298,953
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per unit)	$28.58
Forfeited (in dollars per unit)	$28.43
Vested (in dollars per unit)	$27.63
Non-vested units at end of period (in dollars per unit)	$28.67
Phantom Share Units (PSUs) | Amended Agreements
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percent of units vesting on each one-year anniversary	33.33%
Selling, General and Administrative Expenses | Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash compensation	$3.50	$2.40
Selling, General and Administrative Expenses | Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash compensation	$0.40	$0.50

UnitBased_Compensation_Summary1

Unit-Based Compensation - Summary of Non-Vested Phantom Units (Details) (USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$12.60
Unrecognized compensation cost recognition period (in years)	1 year 10 months
Number of Non-vested Units
Non-vested units at beginning of period (in units)	440,047
Forfeited (in units)	-1,443
Vested (in units)	-110,056
Non-vested units at end of period (in units)	715,644
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per unit)	$28.87
Forfeited (in dollars per unit)	$30.01
Vested (in dollars per unit)	$29.48
Non-vested units at end of period (in dollars per unit)	$21.30
Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	8.6
Unrecognized compensation cost recognition period (in years)	2 years 4 months
Number of Non-vested Units
Non-vested units at beginning of period (in units)	330,446
Forfeited (in units)	-1,493
Vested (in units)	-30,000
Non-vested units at end of period (in units)	298,953
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per unit)	$28.58
Forfeited (in dollars per unit)	$28.43
Vested (in dollars per unit)	$27.63
Non-vested units at end of period (in dollars per unit)	$28.67
Selling, General and Administrative Expenses | Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash compensation	3.5	2.4
Selling, General and Administrative Expenses | Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash compensation	$0.40	$0.50

Shelf_Registration_Statements_

Shelf Registration Statements (Details) (USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2015
Common Units
Shelf Registration Statements [Line Items]
Maximum offering under equity distribution agreement	$400
Proceeds from Issuance or Sale of Equity	12.2
Units issued under public offerings (in units)	849,217
Series A Preferred Units
Shelf Registration Statements [Line Items]
Maximum offering under equity distribution agreement	50
Series B Preferred Unit
Shelf Registration Statements [Line Items]
Maximum offering under equity distribution agreement	100
Series C Preferred Units
Shelf Registration Statements [Line Items]
Maximum offering under equity distribution agreement	$75

Subsequent_Events_Details

Subsequent Events (Details) (USD $)

0 Months Ended

1 Months Ended

0 Months Ended

In Millions, except Share data, unless otherwise specified

Apr. 20, 2015

Feb. 28, 2015

Jan. 31, 2015

Dec. 31, 2014

Nov. 30, 2014

Oct. 31, 2014

Sep. 30, 2014

Aug. 31, 2014

Jul. 31, 2014

Jun. 30, 2014

31-May-14

Apr. 30, 2014

Mar. 31, 2014

Feb. 28, 2014

Jan. 31, 2014

Dec. 31, 2013

Apr. 15, 2015

Subsequent Event

Subsequent Event [Line Items]

Business Combination, Consideration Transferred, Equity Interests Issued and Issuable Fair Value Method

251

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt

$288

Business Acquisition, Equity Interest Issued or Issuable, Exchange Ratio

100.00%

Business Acquisition, Equity Interest Issued or Issuable, Number of Shares

12,320

Common Units

Subsequent Event [Line Items]

Cash distribution, declaration date

18-Mar-15

17-Feb-15

22-Jan-15

16-Dec-14

20-Nov-14

20-Oct-14

19-Sep-14

19-Aug-14

16-Jul-14

24-Jun-14

20-May-14

17-Apr-14

17-Mar-14

20-Feb-14

16-Jan-14

Common Units | Subsequent Event

Subsequent Event [Line Items]

Cash distribution, declaration date

15-Apr-15

Cash distribution attributable, per unit

$0.12

Cash distribution, annualized basis, per unit

$1.41

Class B Units | Subsequent Event

Subsequent Event [Line Items]

Cash distribution attributable, per unit

$0.12

Cash distribution, annualized basis, per unit

$1.41

Series A Preferred Units | Subsequent Event

Subsequent Event [Line Items]

Cash distribution attributable, per unit

$0.16

Series B Preferred Unit | Subsequent Event

Subsequent Event [Line Items]

Cash distribution attributable, per unit

$0.16

Series C Preferred Units | Subsequent Event

Subsequent Event [Line Items]

Cash distribution attributable, per unit

$0.16

Cumulative Preferred units | Subsequent Event

Subsequent Event [Line Items]

Cash distribution, declaration date

15-Apr-15