Grizzly Energy (GRZZP) 10-K 28 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 25, 2014	Jun. 28, 2013
Document and Entity Information [Abstract]	'	'	'
Entity Registrant Name	'Vanguard Natural Resources, LLC	'	'
Entity Central Index Key	'0001384072	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Public Float	'	'	$2,136,497,142
Entity Common Stock, Shares Outstanding	'	79,365,361	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Amendment Flag	'false	'	'

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues:	'	'	'
Oil sales	$268,922	$233,153	$236,003
Natural gas sales	124,513	47,270	47,977
NGLs sales	49,813	29,933	28,862
Net gains on commodity derivative contracts	11,256	36,846	6,735
Total revenues	454,504	347,202	319,577
Production:	'	'	'
Lease operating expenses	105,502	74,366	63,944
Production and other taxes	40,430	29,369	28,621
Depreciation, depletion, amortization and accretion	167,535	104,542	84,857
Impairment of oil and natural gas properties	0	247,722	0
Selling, general and administrative expenses	25,942	22,466	19,779
Total costs and expenses	339,409	478,465	197,201
Income (loss) from operations	115,095	-131,263	122,376
Other income (expense):	'	'	'
Other income	69	220	77
Interest expense	-61,148	-41,891	-28,994
Net losses on interest rate derivative contracts	-96	-6,992	-4,962
Net gain (loss) on acquisition of oil and natural gas properties	5,591	11,111	-367
Total other expense	-55,584	-37,552	-34,246
Net income (loss)	59,511	-168,815	88,130
Less: Net income attributable to non-controlling interest	0	0	-26,067
Net income (loss) attributable to Vanguard unitholders	59,511	-168,815	62,063
Less: Distributions to Preferred unitholders	-2,634	0	0
Net income (loss) available to Common and Class B unitholders	$56,877	($168,815)	$62,063
Net income (loss) per Common and Class B unit:	'	'	'
Basic (in dollars per share)	$0.78	($3.11)	$1.95
Diluted (in dollars per share)	$0.77	($3.11)	$1.95
Common Units [Member]	'	'	'
Weighted average units outstanding:	'	'	'
Weighted average units outstanding - basic	72,644	53,777	31,370
Weighted average units outstanding - diluted	72,992	53,777	31,430
Class B Units [Member]	'	'	'
Weighted average units outstanding:	'	'	'
Weighted average units outstanding - basic and diluted	420	420	420

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Comprehensive Income [Abstract]	'	'	'
Net income (loss)	$59,511	($168,815)	$88,130
Net income from derivative contracts:	'	'	'
Reclassification adjustments for settlements	0	0	3,032
Other comprehensive income	0	0	3,032
Comprehensive income (loss)	$59,511	($168,815)	$91,162

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets	'	'
Cash and cash equivalents	$11,818	$11,563
Trade accounts receivable, net	70,109	51,880
Derivative assets	21,314	46,690
Other currents assets	2,916	3,858
Total current assets	106,157	113,991
Oil and natural gas properties, at cost	2,523,671	2,126,268
Accumulated depletion, amortization and impairment	-713,154	-550,032
Oil and natural gas properties evaluated, net – full cost method	1,810,517	1,576,236
Other assets	'	'
Goodwill	420,955	420,955
Derivative assets	60,474	53,240
Other assets	91,538	35,712
Total assets	2,489,641	2,200,134
Accounts payable:	'	'
Trade	9,824	8,417
Affiliates	249	32
Accrued liabilities:	'	'
Lease operating	12,882	7,884
Developmental capital	10,543	4,754
Interest	11,989	11,573
Production and other taxes	16,251	12,852
Derivative liabilities	10,992	5,366
Oil and natural gas revenue payable	23,245	8,226
Distributions payable	16,499	11,919
Other	12,929	8,479
Total current liabilities	125,403	79,502
Long-term debt	1,007,879	1,247,631
Derivative liabilities	4,085	11,996
Asset retirement obligations	82,208	60,096
Other long-term liabilities	1,731	3,445
Total liabilities	1,221,306	1,402,670
Commitments and contingencies (Note 8)	'	'
Members’ equity	'	'
Members' Equity	1,268,335	797,464
Total liabilities and members’ equity	2,489,641	2,200,134
Preferred Stock [Member]	'	'
Members’ equity	'	'
Members' Equity	61,021	0
Common Units [Member]	'	'
Members’ equity	'	'
Members' Equity	1,205,311	794,426
Class B Units [Member]	'	'
Members’ equity	'	'
Members' Equity	$2,003	$3,038

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical)	Dec. 31, 2013	Dec. 31, 2012
Members’ equity	'	'
Preferred Unit, Issued	2,535,927	0
Preferred Unit, Outstanding	2,535,927	0
Common Units [Member]	'	'
Members’ equity	'	'
Common Unit, Issued	78,337,259	58,706,282
Common Unit, Outstanding	78,337,259	58,706,282
Class B Units [Member]	'	'
Members’ equity	'	'
Common Unit, Issued	420,000	420,000
Common Unit, Outstanding	420,000	420,000

CONSOLIDATED_STATEMENTS_OF_MEM

CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY (USD $)	Total	Preferred Stock [Member]	Common Units [Member]	Class B Units [Member]	Accumulated Other Comprehensive Loss [Member]	Non-controlling Interest [Member]
In Thousands, except Share data, unless otherwise specified
Balance at Dec. 31, 2010	$869,393	'	$318,597	$5,166	($3,032)	$548,662
Balance (in units) at Dec. 31, 2010	'	'	29,666,000	420,000	'	'
Increase (Decrease) in Members' Equity	'	'	'	'	'	'
Issuance of common units in connection with the ENP Merger and equity offering	-2,629	'	524,697	'	'	-527,326
Issuance of common units in connection with the ENP Merger and equity offering (in units)	'	'	18,439,000	'	'	'
Partners' Capital Account, Distributions, Common Units	-69,027	'	-68,068	-959	'	'
Unit-based compensation	2,425	'	2,425	'	'	'
Unit-based compensation (in units)	'	'	215,000	'	'	'
Net income (loss)	88,130	'	62,063	'	'	26,067
Options exercised	3,032	'	'	'	3,032	'
Net loss	-47,403	'	'	'	'	-47,403
Balance at Dec. 31, 2011	843,921	'	839,714	4,207	0	0
Balance (in units) at Dec. 31, 2011	'	'	48,320,000	420,000	'	'
Increase (Decrease) in Members' Equity	'	'	'	'	'	'
Issuance of units, net of offering costs	'	'	321,900	'	'	'
Issuance of units, net of offering costs (in units)	'	'	12,149,000	'	'	'
Partners' Capital Account, Distributions, Common Units	-152,190	'	-151,021	-1,169	'	'
Issuance of Common units, net of offering costs of $415	-52,480	'	-52,480	'	'	'
Partners' Capital Account, Units, Converted	'	'	-1,900,000	'	'	'
Unit-based compensation	4,178	'	4,178	'	'	'
Unit-based compensation (in units)	'	'	87,000	'	'	'
Exercised options granted to officers	950	'	950	'	'	'
Options exercised (in units)	175,000	'	50,000	'	'	'
Net income (loss)	-168,815	'	-168,815	'	'	'
Balance at Dec. 31, 2012	797,464	'	794,426	3,038	'	'
Balance (in units) at Dec. 31, 2012	'	'	58,706,000	420,000	'	'
Increase (Decrease) in Members' Equity	'	'	'	'	'	'
Partners' Capital Account, Acquisitions	29,992	'	29,992	'	'	'
Partners' Capital Account, Units, Acquisitions	'	'	1,075,000	'	'	'
Issuance of units, net of offering costs	'	61,021	498,360	'	'	'
Issuance of units, net of offering costs (in units)	'	2,536,000	18,377,000	'	'	'
Partners' Capital Account, Distributions, Preferred Units	-2,634	'	-2,634	'	'	'
Partners' Capital Account, Distributions, Common Units	-181,926	'	-180,891	-1,035	'	'
Unit-based compensation	6,547	'	6,547	'	'	'
Unit-based compensation (in units)	'	'	179,000	'	'	'
Net income (loss)	59,511	'	59,511	'	'	'
Balance at Dec. 31, 2013	$1,268,335	$61,021	$1,205,311	$2,003	'	'
Balance (in units) at Dec. 31, 2013	'	2,536,000	78,337,000	420,000	'	'

CONSOLIDATED_STATEMENTS_OF_MEM1

CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2013
			Preferred Stock [Member]	Common Units [Member]
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs	$1,109	$126	$402	$415
Net merger costs in connection with merger and equity offering	'	$2,503	'	'

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating activities	'	'	'
Net income (loss)	$59,511	($168,815)	$88,130
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	'	'	'
Depreciation, depletion, amortization and accretion	167,535	104,542	84,857
Impairment of oil and natural gas properties	0	247,722	0
Amortization of deferred financing costs	3,715	2,925	4,208
Amortization of debt discount	248	172	0
Unit-based compensation	4,206	4,178	2,557
Non-cash compensation associated with phantom units granted to officers	1,725	1,243	469
Net (gains) losses on commodity and interest rate derivative contracts	-11,160	-29,854	-1,773
Cash settlements on matured commodity derivative contracts	30,905	39,102	18,720
Cash settlements paid on matured interest rate derivative contracts	-3,888	-2,515	-2,874
Net (gain) loss on acquisitions of oil and natural gas properties	5,591	11,111	-367
Changes in operating assets and liabilities:	'	'	'
Trade accounts receivable	-22,065	3,778	-15,085
Payables to affiliates	217	-1,647	50
Premiums paid on commodity derivative contracts	-204	-8,158	-1,621
Other current assets	-603	-318	-202
Accounts payable and oil and natural gas revenue payable	16,426	8,604	2,972
Accrued expenses and other current liabilities	18,855	14,375	-4,440
Other assets	1,133	267	-3
Net cash provided by operating activities	260,965	204,490	176,332
Investing activities	'	'	'
Additions to property and equipment	-1,975	-721	-935
Additions to oil and natural gas properties	-56,661	-50,405	-34,096
Acquisitions of oil and natural gas properties and derivative contracts	-272,057	-783,355	-205,222
Proceeds from the sale of oil and natural gas properties	0	5,522	5,231
Deposits and prepayments of oil and natural gas properties	-67,284	-10,285	-1,328
Net cash used in investing activities	-397,977	-839,244	-236,350
Financing activities	'	'	'
Proceeds from long-term debt	589,500	1,477,459	1,073,500
Repayment of debt	-829,500	-1,001,000	-888,000
Proceeds from Issuance of Preferred Limited Partners Units	61,021	0	0
Proceeds from common unit offerings, net	498,360	321,900	0
Payments of Ordinary Dividends, Preferred Stock and Preference Stock	-2,426	0	0
Distributions to Common and Class B members	-177,555	-140,271	-69,027
ENP distributions to non-controlling interest	0	0	-47,403
Financing fees	-2,133	-15,572	-5,282
Exercised options granted to officers	0	950	0
Prepaid offering costs	0	0	-2,747
Net cash provided by financing activities	137,267	643,466	61,041
Net increase in cash and cash equivalents	255	8,712	1,023
Cash and cash equivalents, beginning of year	11,563	2,851	1,828
Cash and cash equivalents, end of year	11,818	11,563	2,851
Supplemental cash flow information:	'	'	'
Cash paid for interest	57,067	27,625	25,021
Non-cash financing and investing activities:	'	'	'
Asset retirement obligations	22,692	26,365	4,934
Noncash or Part Noncash Acquisition, Units Issued	29,992	0	0
Common units received in exchange for the Appalachian Basin properties	0	52,480	0
Issuance of common units for the ENP Merger	$0	$0	$527,326

Description_of_the_Business

Description of the Business	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Description of Business	'
	Description of the Business:
	Vanguard Natural Resources, LLC is 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 December 31, 2013, we own properties and oil and natural gas reserves primarily located in eight operating basins:
	•	the Arkoma Basin in Arkansas and Oklahoma;
	•	the Permian Basin in West Texas and New Mexico;
	•	the Big Horn Basin in Wyoming and Montana;
	•	the Piceance Basin in Colorado;
	•	the Gulf Coast Basin in South Texas and Mississippi;
	•	the Wind River Basin in Wyoming;
	•	the Williston Basin in North Dakota and Montana; and
	•	the Powder River Basin in Wyoming.
	We were formed in October 2006 and completed our initial public offering in October 2007. On December 31, 2010, we acquired (the “ENP Purchase”) all of the member interests in Encore Energy Partners GP, LLC ("ENP GP"), the general partner of Encore Energy Partners LP ("ENP"), and  20,924,055 common units representing limited partnership interests in ENP (the “ENP Units”), together representing a 46.7% aggregate equity interest in ENP at the date of the ENP Purchase, from Denbury Resources Inc. As consideration for the purchase, we paid $300.0 million in cash and issued 3,137,255 VNR common units, valued at $93.0 million at December 31, 2010.
	On December 1, 2011, we acquired the remaining 53.4% of the ENP Units not held by us through a merger (the “ENP Merger”) with one of our wholly-owned subsidiaries. In connection with the ENP Merger, ENP’s public unitholders received 0.75 VNR common units in exchange for each ENP common unit they owned at the effective date of the ENP Merger, which resulted in the issuance of approximately 18.4 million Vanguard common units valued at $511.4 million at December 1, 2011. We refer to the ENP Purchase and ENP Merger collectively as the “ENP Acquisition.”
	References in this report to “us,” “we,” “our,” the “Company,” “Vanguard” or “VNR” are to Vanguard Natural Resources, LLC and its subsidiaries, including Vanguard Natural Gas, LLC (“VNG”), VNR Holdings, LLC (“VNRH”), Vanguard Permian, LLC (“Vanguard Permian”), Vanguard Operating, LLC ("VO"), VNR Finance Corp. (“VNRF”), Encore Energy Partners Operating LLC ("OLLC") and Encore Clear Fork Pipeline LLC. References in this report to “our operating subsidiary” or “VNG” are to Vanguard Natural Gas, LLC.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Summary of Significant Accounting Policies	'
	Summary of Significant Accounting Policies
	(a)	Basis of Presentation and Principles of Consolidation:
	The consolidated financial statements as of and for the years ended December 31, 2013, 2012 and 2011 include the accounts of VNR and its subsidiaries. As of December 31, 2010, we consolidated ENP as we had the ability to control the operating and financial decisions and policies of ENP through our ownership of ENP GP and reflected the non-controlling interest as a separate element of members’ equity on our consolidated balance sheet. On December 1, 2011, ENP became a wholly-owned subsidiary of VNG.
	Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and include the accounts of all subsidiaries after the elimination of all significant intercompany accounts and transactions. 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)	Cash Equivalents:
	The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents.
	(c)	Accounts Receivable and Allowance for Doubtful Accounts:
	Accounts receivable are customer obligations due under normal trade terms and are presented on the Consolidated Balance Sheets net of allowances for doubtful accounts. We establish provisions for losses on accounts receivable if we determine that it is likely that we will not collect all or part of the outstanding balance. We regularly review collectibility and establish or adjust our allowance as necessary using the specific identification method.
	(d)	Inventory:
	Materials, supplies and commodity inventories are valued at the lower of cost or market. The cost is determined using the first-in, first-out method. Inventories are included in other current assets in the accompanying Consolidated Balance Sheets.
	(e)	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 estimated future net cash flows from proved reserves, computed using the 12-month unweighted average of first-day-of-the-month commodity prices (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 2013 or 2011. During the year ended December 31, 2012, we recorded a non-cash ceiling test impairment of oil and natural gas properties of $247.7 million as a result of a decline in natural gas prices at the measurement dates, September 30, 2012 and December 31, 2012. Such impairment was recognized during the third and fourth quarters of 2012. The most significant factor affecting the 2012 impairment related to the properties that we acquired in the Arkoma Basin Acquisition and Rockies Acquisition (discussed below). The fair values of the properties acquired (determined using forward oil and natural gas price curves at the acquisitions dates) were higher than the discounted estimated future cash flows computed using the 12-month average prices at the impairment test measurement dates. We were able to lock in higher future selling prices for a portion of the estimated natural gas production for the Arkoma Basin Acquisition and the Rockies Acquisition by using commodity derivative contracts. However, our impairment calculations do not consider the positive impact of our commodity derivative positions as generally accepted accounting principles only allow us to consider the expected cash flows from derivatives designated as cash flow hedges. The 2012 third quarter impairment was calculated based on prices of $2.77 per MMBtu for natural gas and $95.26 per barrel of crude oil while the 2012 fourth quarter impairment was calculated based on prices of $2.76 per MMBtu for natural gas and $94.67 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.
	(f)	Goodwill and Other Intangible Assets:
	We account for goodwill and other intangible assets under the provisions of the Accounting Standards Codification (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 not amortized, but is tested for impairment annually on October 1 or whenever indicators of impairment exist. As discussed further in Note 2, all goodwill recognized in acquisitions other than the ENP Purchase has been determined to be impaired and written off. The goodwill test is performed at the reporting unit level. Beginning in 2012, the reporting unit for the goodwill recognized for the ENP Purchase represents our oil and natural gas operations in the United States. If the fair value of the reporting unit is determined to be less than its carrying value, an impairment charge is recognized for the amount by which the carrying value of goodwill exceeds its implied fair value. We utilize a market approach to determine the fair value of our reporting unit.
	On October 1, 2013, October 1, 2012 and December 1, 2011, we performed impairment tests for the goodwill recognized in the ENP Purchase and our analyses concluded that there was no impairment of goodwill as of these dates. Significant decreases in the 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.
	Intangible assets with definite useful lives are amortized over their estimated useful lives. We evaluate the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable.  An impairment loss exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount.
	We are a party to a contract allowing us to purchase a certain amount of natural gas at a below market price for use as field fuel. As of December 31, 2013, the net carrying value of this contract was $8.5 million. The carrying value is shown as Other assets on the accompanying Consolidated Balance Sheets and is amortized on a straight-line basis over the estimated life of the field. The estimated aggregate amortization expense for each of the next five fiscal years is $0.2 million per year.
	(g)	Asset Retirement Obligations:
	We record a liability for asset retirement obligations at fair value in the period in which the liability is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset’s useful life. Our recognized asset retirement obligation exclusively relates to the plugging and abandonment of oil and natural gas wells and decommissioning of our Elk Basin gas plant. Management periodically reviews the estimates of the timing of well abandonments as well as the estimated plugging and abandonment costs, which are discounted at the credit adjusted risk free rate.  These retirement costs are recorded as a long-term liability on the Consolidated Balance Sheets with an offsetting increase in oil and natural gas properties. An ongoing accretion expense is recognized for changes in the value of the liability as a result of the passage of time, which we record in depreciation, depletion, amortization and accretion expense in the Consolidated Statements of Operations.
	(h)	Revenue Recognition and Gas Imbalances:
	Sales of oil, natural gas and NGLs are recognized when oil, natural gas and NGLs have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. We sell oil, natural gas and NGLs on a monthly basis. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil, natural gas or NGLs, and prevailing supply and demand conditions, so that the price of the oil, natural gas and NGLs fluctuates to remain competitive with other available oil, natural gas and NGLs supplies. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Trade accounts receivable, net” in the accompanying Consolidated Balance Sheets.
	The Company has elected the entitlements method to account for gas production imbalances. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. The amounts of imbalances were not material at December 31, 2013 and 2012.
	(i)	Concentrations of Credit Risk:
	Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative contracts. We control our exposure to credit risk associated with these instruments by (i) placing our assets and other financial interests with credit-worthy financial institutions, (ii) maintaining policies over credit extension that include the evaluation of customers’ financial condition and monitoring payment history, although we do not have collateral requirements and (iii) netting derivative assets and liabilities for counterparties where we have a legal right of offset.
	At December 31, 2013 and 2012, the cash and cash equivalents were concentrated in one financial institution. We periodically assess the financial condition of this institution and believe that any possible credit risk is minimal.
	The following purchasers accounted for 10% or more of the Company’s oil, natural gas and NGLs sales for the years ended December 31:
			2013	2012	2011
	Marathon Oil Company		14%	21%	22%
	Plains Marketing L.P.		10%	15%	11%
	Our customers are in the energy industry and they may be similarly affected by changes in economic or other conditions.
	(j)	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, the fair value of assets and liabilities acquired in business combinations, goodwill, derivative contracts, 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.
	(k)	Price and Interest Rate Risk Management Activities:
	We have entered into derivative contracts with counterparties that are lenders under our financing arrangements 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. Our natural gas production is primarily sold under market sensitive contracts which are typically priced at a differential to the NYMEX or the published natural gas index prices for the producing area due to the natural gas quality and the proximity to major consuming markets. As for oil production, realized pricing is primarily driven by the West Texas Intermediate (“WTI”), Light Louisiana Sweet Crude, Wyoming Imperial and Flint Hills Bow River prices. NGLs pricing is based on the Oil Price Information Service postings as well as market-negotiated ethane spot prices. During 2013, our derivative transactions included the following:
	•	Fixed-price swaps - where we receive a fixed-price for our production and pay a variable market price to the contract counterparty.
	•	Basis swap contracts - which guarantee a price differential between the NYMEX prices and our physical pricing points. We receive a payment from the counterparty or make a payment to the counterparty for the difference between the settled price differential and amounts stated under the terms of the contract.
	•	Collars - where we pay the counterparty if the market price is above the ceiling price (short call) and the counterparty pays us if the market price is below the floor (long put) on a notional quantity.
	•	Three-way collar contracts - which combine a long put, a short put and a short call. The use of the long put combined with the short put allows us to sell a call at a higher price thus establishing a higher ceiling and limiting our exposure to future settlement payments while also restricting our downside risk to the difference between the long put and the short put if the price drops below the price of the short put. This allows us to settle for market plus the spread between the short put and the long put in a case where the market price has fallen below the short put fixed price.
	•	Swaption agreements - where we provide options to counterparties to extend swap contracts into subsequent years.
	•	Call options sold - a structure that may be combined with an existing swap to raise the strike price, putting us in either a higher asset position, or a lower liability position. In general, selling a call option is used to enhance an existing position or a position that we intend to enter into simultaneously.
	•	Put spread options - created when we purchase a put and sell a put simultaneously.
	•	Put options sold - a structure that may be combined with an existing swap to raise the strike price, putting us in either a higher asset position or a lower liability position. In general, selling a put option is used to enhance an existing position or a position that we intend to enter into simultaneously.
	•	Range bonus accumulators - a structure that allows us to receive a cash payment when the crude oil or natural gas settlement price remains within a predefined range on each expiry date. Depending on the terms of the contract, if the settlement price is below the floor or above the ceiling on any expiry date, we may have to sell at that level.
	We also enter into fixed LIBOR interest rate swap agreements with certain counterparties that are lenders under our financing arrangements, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates.
	Under ASC Topic 815, “Derivatives and Hedging,” all derivative instruments are recorded on the Consolidated Balance Sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date.  We net derivative assets and liabilities for counterparties where we have a legal right of offset.  Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met.  For qualifying cash flow hedges, the change in the fair value of the derivative is deferred in accumulated other comprehensive income (loss) in the equity section of the Consolidated Balance Sheets to the extent the hedge is effective. Gains and losses on cash flow hedges included in accumulated other comprehensive income (loss) are reclassified to gains (losses) on commodity cash flow hedges or gains (losses) on interest rate derivative contracts in the period that the related production is delivered or the contract settles. Gains or losses on derivative contracts that do not qualify for hedge accounting treatment are recorded in net gains (losses) on commodity derivative contracts or net gains (losses) on interest rate derivative contracts in the Consolidated Statements of Operations.
	We have elected not to designate our current portfolio of derivative contracts as hedges.  Therefore, changes in fair value of these derivative instruments are recognized in earnings and included in net gains (losses) on commodity derivative contracts or net gains (losses) on interest rate derivative contracts in the accompanying Consolidated Statements of Operations.
	Any premiums paid on derivative contracts and the fair value of derivative contracts acquired in connection with our acquisitions are capitalized as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid or the contracts are assumed. Premium payments are reflected in cash flows from operating activities in our Consolidated Statements of Cash Flows. When the consideration for an acquisition is cash, the fair value of any derivative contracts acquired in the acquisition is reflected in cash flows from investing activities. Over time, as the derivative contracts settle, the differences between the cash received and the premiums paid or fair value of contracts acquired are recognized in net gains or losses on commodity or interest rate derivate contracts, and the cash received is reflected in cash flows from operating activities in our Consolidated Statements of Cash Flows.
	(l)	Income Taxes:
	The Company is treated as a partnership for federal and state income tax purposes.  As such, it is not a taxable entity and does not directly pay federal and state income tax. Its taxable income or loss, which may vary substantially from the net income or net loss reported in the Consolidated Statements of Operations, is included in the federal and state income tax returns of each unitholder.  Accordingly, no recognition has been given to federal and state income taxes for the operations of the Company.  The aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Company does not have access to information about each unitholders’ tax attributes in the Company. However, the book basis of our net assets exceeded the net tax basis by $168.5 million at December 31, 2013 while the tax basis of our net assets exceeded the net book basis by $92.2 million at December 31, 2012.
	Legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including otherwise non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. The Company recorded a current tax liability of $0.3 million and $0.5 million as of December 31, 2013 and 2012, respectively, and a deferred tax liability of $0.4 million and deferred tax asset of $0.3 million as of December 31, 2013 and 2012, respectively. Tax provisions of $0.6 million, $0.2 million, and $0.6 million are included in our Consolidated Statements of Operations for the years ended December 31, 2013, 2012, and 2011, respectively, as a component of Selling, general and administrative expenses.

Acquisitions_and_Divestiture

Acquisitions and Divestiture	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Acquisitions and Divestiture	'
	Acquisitions and Divestiture
	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. All our acquisitions were funded with borrowings under our Reserve-Based Credit Facility (defined in Note 3), except for certain 2011 acquisitions which were funded with borrowings under financing arrangements existing at that time the acquisitions were consummated.
	2013 Acquisitions
	On April 1, 2013, we completed the acquisition of certain natural gas, oil and NGLs properties located in the Permian Basin in southeast New Mexico and West Texas for an adjusted purchase price of $266.2 million. This acquisition had an effective date of January 1, 2013.
	On June 28, 2013, we completed the acquisition of certain natural gas, oil and NGLs properties located in the Permian Basin in Texas and the San Juan and DJ-Basin in Colorado with an effective date of July 1, 2013 for an adjusted purchase price of $29.9 million. The consideration for this acquisition was paid in common equity by issuing 1,075,000 VNR common units, at an agreed price of $27.65 per common unit, valued for financial reporting purposes at the closing price of $27.90 at the closing date of the acquisition.
	We also completed other acquisitions during 2013 including the acquisition of additional working interests in previously acquired properties for an aggregate adjusted purchase price of $2.5 million.
	The following presents the values assigned to the net assets acquired in our 2013 acquisitions:
	Fair value of assets and liabilities acquired:	(in thousands)
	Oil and natural gas properties	$	317,573
	Inventory	899
	Asset retirement obligations	(11,381		)
	Oil and natural gas revenue payable and imbalance liabilities	(2,843		)
	Total fair value of assets and liabilities acquired	304,248
	Fair value of consideration transferred	298,657
	Gain on acquisition	$	5,591
	2012 Acquisitions
	On June 1, 2012, we entered into a purchase and sale agreement with Antero Resources LLC for the acquisition of natural gas and liquids properties in the Woodford Shale in Oklahoma and Fayetteville Shale in Arkansas of the Arkoma Basin. We refer to this acquisition as the “Arkoma Basin Acquisition”. We completed this acquisition on June 29, 2012 with an effective date of April 1, 2012 for an adjusted purchase price of $428.5 million. Upon closing this acquisition, we assumed natural gas swaps valued at $109.5 million on the closing date, which were restructured in July 2012 to cover the estimated natural gas production from existing producing wells in the acquired properties over the next five years. In accordance with ASC Topic 805, this acquisition resulted in a gain of $14.1 million, as reflected in the table below, primarily due to the changes in the value of derivative assets between the date the purchase and sale agreement was entered into and the closing date, which were driven by corresponding changes in natural gas prices.
	Fair value of assets and liabilities acquired:	(in thousands)
	Oil and natural gas properties	$	344,747
	Derivative assets	109,495
	Asset retirement obligations	(8,922		)
	Oil and natural gas revenue payable and imbalance liabilities	(2,653		)
	Total fair value of assets and liabilities acquired	442,667
	Fair value of consideration transferred	428,541
	Gain on acquisition	$	14,126
	On October 31, 2012, we entered into a purchase and sale agreement with Bill Barrett Corporation for the acquisition of natural gas and liquids properties in the Piceance Basin in Colorado and Powder River and Wind River Basins in Wyoming. We refer to this acquisition as the “Rockies Acquisition.” This acquisition had an effective date of October 1, 2012. With respect to the Piceance Basin properties, we have an escalating working interest wherein our working interest began at 18% and increased to 21% on January 1, 2014, and will further increase to 24% on January 1, 2015 and 26% on January 1, 2016. This structure was designed to maintain cash flow from the acquisition without the need for any capital spending until 2016. We completed this acquisition on December 31, 2012 for an adjusted purchase price of $324.7 million. This acquisition resulted in goodwill of $8.8 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 oil and 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	$	330,707
	Other assets	929
	Asset retirement obligations	(15,763		)
	Oil and natural gas revenue payable and imbalance liabilities	(41		)
	Total fair value of assets and liabilities acquired	315,832
	Fair value of consideration transferred	324,650
	Loss on acquisition	$	(8,818	)
	During 2012, we completed other smaller acquisitions of oil and natural gas properties located in our various operating regions, primarily in Wyoming and North Dakota for adjusted purchase prices aggregating to $24.8 million. One of these properties was initially included as part of a larger acquisition that we did not complete as a result of a third party exercising their preferential rights to acquire a portion of the properties. The fair value of the properties acquired in this acquisition exceeded the purchase price allocated to them in the initial agreement and thus, resulted in a gain of $6.0 million.
	2012 Divestiture
	We previously owned properties in the Appalachian Basin, which is primarily in southeast Kentucky and northeast Tennessee (the “Appalachian Basin”). On February 21, 2012, we and our 100% owned operating subsidiary entered into a Unit Exchange Agreement with Majeed S. Nami Personal Endowment Trust and Majeed S. Nami Irrevocable Trust (collectively, the “Nami Parties”) to transfer our partnership interest in Trust Energy Company, LLC and Ariana Energy, LLC, which entities operated all of our ownership interests in oil and natural gas properties in the Appalachian Basin, in exchange for 1.9 million of our common units valued at the closing price of our common units of $27.62 per unit at March 30, 2012, or $52.5 million, with an effective date of January 1, 2012 (the “Unit Exchange”). The Nami Parties are controlled by or affiliated with Majeed S. Nami who was a founding unitholder when we completed the IPO. We completed this transaction on March 30, 2012 for non-cash consideration of $52.5 million, which was offset by post-closing adjustments of $1.4 million.
	2011 Acquisitions
	During 2011, we completed acquisitions of oil and natural gas properties located in our various operating regions, primarily in the Permian Basin and the Gulf Coast Basin, for adjusted purchase prices aggregating to $202.7 million.
	ENP Acquisition
	As previously discussed, we completed the ENP Purchase on December 31, 2010. The acquisition was accounted for under the acquisition method of accounting in accordance with ASC Topic 805. The acquisition method requires the assets and liabilities acquired to be recorded at their fair values at the date of acquisition. The total consideration for the ENP Purchase amounted to $941.7 million, which resulted in a goodwill of $421.0 million. Also as previously discussed, we completed the ENP Merger on December 1, 2011. The ENP Merger was accounted for as an equity transaction in accordance with ASC Topic 810 Subtopic 10, “Consolidations - Capital Changes of Subsidiaries” (“ASC Topic 810-10”). In accordance with ASC Topic 810-10, the difference of $16.0 million between the value of Vanguard common units issued for the exchange and the carrying amount of the non-controlling interest of $527.3 million at December 1, 2011 was recognized in equity.
	Pro Forma Operating Results (Unaudited)
	In accordance with ASC Topic 805, presented below are unaudited pro forma results for the years ended December 31, 2013, 2012 and 2011 which reflect the effect on our consolidated results of operations as if (i) all our acquisitions in 2013 had occurred on January 1, 2012, (ii) all our acquisitions in 2012 had occurred on January 1, 2011 and (iii) all our acquisitions in 2011 and the ENP Merger had occurred on January 1, 2010. The unaudited pro forma results also reflect the impact of the Unit Exchange, including the elimination of the results of operations from the properties we previously owned in the Appalachian Basin and the receipt of the 1.9 million common units received as consideration for the exchange, as if it had occurred on January 1, 2011.
	The pro forma results reflect the results of combining our Consolidated Statements of Operations with the revenues and direct operating expenses of the oil and gas properties acquired adjusted for (i) assumption of asset retirement obligations and accretion expense for the properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired using the acquisition method of accounting, (iii) interest expense on additional borrowings necessary to finance the acquisitions, (iv) interest expense on the Senior Notes (defined in Note 3), including the amortization of discount, (v) the impact of the common units issued in the acquisition of properties completed on June 28, 2013, and (vi) the impact of the additional units issued in the ENP Acquisition. As discussed in Note 3 of our consolidated financial statements, we used a portion of the net proceeds from the Senior Notes offering to repay all indebtedness outstanding under our second lien term loan, then outstanding, and applied the balance of the net proceeds to outstanding borrowings under our Reserve-Based Credit Facility. The repayment therefore resulted in an increase in the amount available for borrowing under our Reserve-Based Credit Facility. The pro forma results reflect the fact that the increase in borrowing capacity provided us available funding for the Arkoma Basin Acquisition. The net gain (loss) on acquisition of oil and natural gas properties were excluded from the pro forma results for the years ended December 31, 2013, 2012 and 2011. The pro forma information is based upon these assumptions, and is not necessarily indicative of future results of operations:
		Year Ended December 31,
		2013			2012			2011
		(in thousands, except per unit amounts) (Pro forma)
	Total revenues	$	470,834		$	557,802		$	676,685
	Net income (loss) available to Common and Class B unitholders	$	54,158		$	(174,187	)	$	146,783
	Net income (loss) available to Common and Class B unitholders, per unit:
	Basic	$	0.7		$	(3.18	)	$	3.14
	Diluted	$	0.69		$	(3.18	)	$	3.14
	The amount of revenues and excess of revenues over direct operating expenses that were eliminated to reflect the impact of the Unit Exchange in the pro forma results presented above are as follows (in thousands):
		Year Ended December 31,
		2012			2011
	Revenues	$	3,267		$	20,017
	Net income (loss)	$	(400	)	$	6,041
	Post-Acquisition Operating Results
	The results of operations of the properties acquired during 2011 through 2013, as described above, have been included in our consolidated financial statements from the closing dates of the acquisitions forward. The table below presents the amounts of revenues and excess of revenues over direct operating expenses included in our 2013, 2012 and 2011 Consolidated Statements of Operations for the Arkoma Basin Acquisition, Rockies Acquisition and all of our other acquisitions, except the ENP Acquisition, as described above. Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes.
		Year Ended December 31,
		2013			2012			2011
		(in thousands)
	Arkoma Basin Acquisition
Revenues	$	55,468		$	24,673		$	—
Excess of revenues over direct operating expenses	$	45,090		$	19,971		$	—
Rockies Acquisition
Revenues	$	63,652		$	220		$	—
Excess of revenues over direct operating expenses	$	41,583		$	164		$	—
All other acquisitions
Revenues	$	80,349		$	38,366		$	18,298
Excess of revenues over direct operating expenses	$	49,025		$	21,626		$	11,572

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Debt	'
	Long-Term Debt
	Our financing arrangements consisted of the following:
							Amount Outstanding December 31,
	Description		Interest Rate		Maturity Date		2013				2012
							(in thousands)
	Senior Secured Reserve-Based Credit Facility		Variable (1)		April 16, 2018		$	460,000			$	700,000
	Senior Notes		7.875% (2)		April 1, 2020		550,000				550,000
							$	1,010,000			$	1,250,000
	Unamortized discount on Senior Notes						(2,121		)		(2,369		)
	Total long-term debt						$	1,007,879			$	1,247,631
	-1	Variable interest rate was 1.92% and 2.22% at December 31, 2013 and 2012, respectively.
	-2	Effective interest rate is 8.0%.
	Senior Secured Reserve-Based Credit Facility
	The Company's Third Amended and Restated Credit Agreement (the “Credit Agreement”) provides a maximum credit facility of $1.5 billion and an initial borrowing base of $1.3 billion (the “Reserve-Based Credit Facility”). On December 31, 2013, there were $460.0 million of outstanding borrowings and $838.2 million of borrowing capacity under the Reserve-Based Credit Facility, including a $1.8 million reduction in availability for letters of credit (discussed below).
	On April 17, 2013, we entered into the Fourth Amendment to the Credit Agreement, which provided for, among other things, (i) the extension of the maturity date to April 16, 2018, (ii) the increase of our borrowing base from $1.2 billion to $1.3 billion and (iii) increased hedging flexibility. Under this amendment, we were only committed to and paying for a borrowing utilization of $1.2 billion, but we had the flexibility to request the additional $100.0 million of availability as needed. We entered into the Fifth Amendment to the Credit Agreement effective on November 5, 2013 to reaffirm our borrowing base of $1.3 billion, to increase our commitment to $1.3 billion and to add two new lenders to the credit facility.
	Interest rates under the Reserve-Based Credit Facility are based on Euro-Dollars (LIBOR) or ABR (Prime) indications, plus a margin. Interest is generally payable quarterly for ABR loans and at the applicable maturity date for LIBOR loans. At December 31, 2013, the applicable margin and other fees increase as the utilization of the borrowing base increases as follows:
	Borrowing Base Utilization Grid
	Borrowing Base Utilization Percentage		<25%			>25% <50%			>50% <75%			>75% <90%		>90%
	Eurodollar Loans Margin		1.5	%		1.75	%		2	%		2.25	%	2.5	%
	ABR Loans Margin		0.5	%		0.75	%		1	%		1.25	%	1.5	%
	Commitment Fee Rate		0.5	%		0.5	%		0.375	%		0.375	%	0.375	%
	Letter of Credit Fee		0.5	%		0.75	%		1	%		1.25	%	1.5	%
	Our Reserve-Based Credit Facility contains a number of customary covenants that require us to maintain certain financial ratios, limit our ability to incur indebtedness, enter into commodity and interest rate derivatives, grant certain liens, make certain loans, acquisitions, capital expenditures and investments, merge or consolidate, or engage in certain asset dispositions, including a sale of all or substantially all of our assets. At December 31, 2013, we were in compliance with all of our debt covenants.
	Our Reserve-Based Credit Facility requires us to enter into commodity price hedge positions establishing certain minimum fixed prices for anticipated future production. See Note 4 for further discussion.
	Letters of Credit
	At December 31, 2013, we had unused irrevocable standby letters of credit of approximately $1.8 million. The letters are being maintained as security for performance on long-term transportation contracts. Borrowing availability for the letters of credit is provided under our Reserve-Based Credit Facility. The fair value of these letters of credit approximates contract values based on the nature of the fee arrangements with the issuing banks.
	Senior Notes
	We have $550.0 million outstanding in aggregate principal amount of 7.875% senior notes due 2020 (the "Senior Notes"). The issuers of the Senior Notes are VNR and our 100% owned finance subsidiary, VNRF. VNR has no independent assets or operations. Under the indenture governing the Senior Notes (the “Indenture”), all of our existing subsidiaries (other than VNRF), all of which are 100% owned, and certain of our future subsidiaries (the “Subsidiary Guarantors”) have unconditionally guaranteed, jointly and severally, on an unsecured basis, the Senior Notes, subject to release under certain of the following circumstances: (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 December 31, 2013, based on the most restrictive covenants of the Indenture, the Company's cash balance and the borrowings available under the Reserve-Based Credit Facility, $286.8 million of members' equity is available for distributions to unitholders, while the remainder is restricted.
	Interest on the Senior Notes is payable on April 1 and October 1 of each year. We may redeem some or all of the Senior Notes at any time on or after April 1, 2016 at redemption prices of 103.93750% of the aggregate principal amount of the Senior Notes as of April 1, 2016, declining to 100% on April 1, 2018 and thereafter. We may also redeem some or all of the Senior Notes at any time prior to April 1, 2016 at a redemption price equal to 100% of the aggregate principal amount of the Senior Notes thereof, plus a "make-whole" premium. In addition, before April 1, 2015, we may redeem up to 35% of the aggregate principal amount of the Senior Notes at a redemption price equal to 107.875% of the aggregate principal amount of the Senior Notes thereof, with the proceeds of certain equity offerings, provided that 65% of the aggregate principal amount of the Senior Notes remain outstanding immediately after any such redemption and the redemption occurs within 180 days of such equity offering. If we sell certain of our assets or experience certain changes of control, we may be required to repurchase all or a portion of the Senior Notes at a price equal to 100% and 101% of the aggregate principal amount of the Senior Notes, respectively.

Price_and_Interest_Rate_Risk_M

Price and Interest Rate Risk Management Activities	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Price and Interest Rate Risk Management Activities	'
	Price and Interest Rate Risk Management Activities
	We have entered into derivative contracts with counterparties that are lenders under our Reserve-Based Credit Facility to hedge price risk associated with a portion of our oil, natural gas and NGLs production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated which has, and could, result in overhedged volumes. Pricing for these derivative contracts are based on certain market indexes and prices at our primary sales points. During the year ended December 31, 2013, our derivative transactions included fixed-price swaps, basis swap contracts, collars, three-way collars, swaptions, call options sold, put spread options, put options sold and range bonus accumulators.
	We also enter into fixed LIBOR interest rate swap agreements with certain counterparties that are lenders under our Reserve-Based Credit Facility, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates.
	At December 31, 2013, the Company had open commodity derivative contracts covering our anticipated future production as follows:
	Fixed-Price Swaps
			Gas							Oil						NGLs
	Contract Period		MMBtu			Weighted				Bbls			Weighted Average WTI			Bbls	Weighted Average Fixed Price
						Average							Price
						Fixed Price
	January 1, 2014 – December 31, 2014		47,885,225			$	4.51			1,815,875			$	90.59		273,750	$	40.87
	January 1, 2015 – December 31, 2015		53,107,500			$	4.46			692,000			$	91.18		91,250	$	42
	January 1, 2016 – December 31, 2016		49,593,000			$	4.5			146,400			$	89.98		—	$	—
	January 1, 2017 – December 31, 2017		22,202,000			$	4.34			73,000			$	86.6		—	$	—
	Swaptions and Call Options Sold
	Calls were sold or options were provided to counterparties under swaption agreements to extend the swap into subsequent years as follows:
			Oil
	Contract Period		Bbls			Weighted
						Average
						Fixed Price
	January 1, 2014 – December 31, 2014		492,750			$	117.22
	January 1, 2015 – December 31, 2015		508,445			$	105.98
	January 1, 2016 – December 31, 2016		622,200			$	125
	Basis Swaps
			Gas
	Contract Period		MMBtu			Weighted Avg. Basis				Pricing Index
						Differential
						($/MMBtu)
	January 1, 2014 – December 31, 2014		11,845,000			$	(0.21	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2014 – December 31, 2014		452,500			$	(0.32	)		Rocky Mountain CIG and NYMEX Henry Hub Basis Differential
	January 1, 2015 – December 31, 2015		12,775,000			$	(0.29	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
			Oil
	Contract Period		Bbls			Weighted Avg. Basis				Pricing Index
						Differential ($/Bbl)
	January 1, 2014 – December 31, 2014		584,000			$	(0.84	)		WTI Midland and WTI Cushing Basis Differential
	January 1, 2014 – December 31, 2014		328,500			$	(1.05	)		West Texas Sour and WTI Cushing Basis Differential
	January 1, 2014 – December 31, 2014		182,500			$	(3.95	)		Light Louisiana Sweet Crude and Brent Basis Differential
	January 1, 2015 – December 31, 2015		365,000			$	(0.90	)		WTI Midland and WTI Cushing Basis Differential
	Collars
			Oil
	Contract Period		Bbls		Floor				Ceiling
	January 1, 2014 - December 31, 2014		12,000		$	100			$	116.2
	Three-Way Collars
			Oil
	Contract Period		Bbls			Floor				Ceiling				Put Sold
	January 1, 2014 – December 31, 2014		1,313,850			$	93.47			$	101.25			$	72.57
	January 1, 2015 – December 31, 2015		924,055			$	92.1			$	101.54			$	72.04
	January 1, 2016 – December 31, 2016		549,000			$	90			$	95			$	70
	Put Options Sold
			Oil
	Contract Period		Bbls			Put Sold ($/Bbl)
	January 1, 2014 – December 31, 2014		73,000			$	75
	January 1, 2015 – December 31, 2015		692,000			$	72.36
	January 1, 2016 – December 31, 2016		146,400			$	75
	January 1, 2017 – December 31, 2017		73,000			$	75
	Put Spread Options
			Oil
	Contract Period		Bbls			Floor				Put Sold
	January 1, 2015 – December 31, 2015		255,500			$	100			$	75
	Range Bonus Accumulators
			Gas
	Contract Period		MMBtu			Bonus				Range Ceiling				Range Floor
	January 1, 2014 – December 31, 2014		1,460,000			$	0.2			$	4.75			$	3.25
	January 1, 2015 – December 31, 2015		1,460,000			$	0.2			$	4.75			$	3.25
		Oil
Contract Period		Bbls			Bonus				Range Ceiling				Range Floor
January 1, 2014 – December 31, 2014		912,500			$	4.94			$	103.2			$	70.5
Interest Rate Swaps
We may from time to time enter into interest rate swap agreements based on LIBOR to minimize the effect of fluctuations in interest rates. These interest rate swap agreements require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates. If LIBOR is lower than the fixed rate in the contract, we are required to pay the counterparty the difference, and conversely, the counterparty is required to pay us if LIBOR is higher than the fixed rate in the contract. We do not designate interest rate swap agreements as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.
At December 31, 2013, the Company had open interest rate derivative contracts as follows (in thousands):
		Notional Amount				Fixed Libor Rates
Period:
January 1, 2014 to December 10, 2016		$	20,000			2.17	%
January 1, 2014 to October 31, 2016		$	40,000			1.65	%
January 1, 2014 to August 5, 2015 (1)		$	30,000			2.25	%
January 1, 2014 to August 6, 2016		$	25,000			1.8	%
January 1, 2014 to October 31, 2016		$	20,000			1.78	%
January 1, 2014 to September 23, 2016		$	75,000			1.15	%
January 1, 2014 to March 7, 2016		$	75,000			1.08	%
January 1, 2014 to September 7, 2016		$	25,000			1.25	%
January 1, 2014 to December 10, 2015 (2)		$	50,000			0.21	%
Total		$	360,000
-1	The counterparty has the option to extend the termination date of this contract at 2.25% to August 5, 2018.
-2	The counterparty has the option to require Vanguard to pay a fixed rate of 0.91% from December 10, 2015 to December 10, 2017.
Balance Sheet Presentation
Our commodity derivatives and interest rate swap derivatives are presented on a net basis in “derivative assets” and “derivative liabilities” on the Consolidated Balance Sheets. The following table summarizes the gross fair values of our derivative instruments and the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets for the periods indicated (in thousands):
		December 31, 2013
Offsetting Derivative Assets:		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts		$	107,307			$	(25,617	)		$	81,690
Interest rate derivative contracts		98				—				98
Total derivative instruments		$	107,405			$	(25,617	)		$	81,788
Offsetting Derivative Liabilities:		Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts		$	(33,825	)		$	25,617			$	(8,208	)
Interest rate derivative contracts		(6,869		)		—				(6,869		)
Total derivative instruments		$	(40,694	)		$	25,617			$	(15,077	)
		December 31, 2012
Offsetting Derivative Assets:		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts		$	134,905			$	(35,001	)		$	99,904
Interest rate derivative contracts		132				(106		)		26
Total derivative instruments		$	135,037			$	(35,107	)		$	99,930
Offsetting Derivative Liabilities:		Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts		$	(41,775	)		$	35,001			$	(6,774	)
Interest rate derivative contracts		(10,694		)		106				(10,588		)
Total derivative instruments		$	(52,469	)		$	35,107			$	(17,362	)
By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. Our counterparties are participants in our Reserve-Based Credit Facility (see Note 3 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 $107.4 million at December 31, 2013. 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 December 31, 2013. We minimize the credit risk in derivative instruments by: (i) entering into derivative instruments only with counterparties that are also lenders in our Reserve-Based Credit Facility and (ii) monitoring the creditworthiness of our counterparties on an ongoing basis.
The change in fair value of our commodity and interest rate derivatives for the years ended December 31, 2013, 2012 and 2011 is as follows:
	2013				2012				2011
	(in thousands)
Derivative asset (liability) at January 1, net	$	82,568			$	(29,889	)		$	(18,591	)
Purchases
Fair value of derivatives acquired through business combinations	—				109,495				—
Premiums and fees paid or deferred (received) for derivative contracts during the period	—				9,695				(257		)
Net gains on commodity and interest rate derivative contracts	11,160				29,854				1,773
Settlements
Cash settlements received on matured commodity derivative contracts	(30,905		)		(39,102		)		(18,720		)
Cash settlements paid on matured interest rate derivative contracts	3,888				2,515				2,874
Change in other comprehensive income	—				—				3,032
Derivative asset (liability) at December 31, net	$	66,711			$	82,568			$	(29,889	)

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements	'
	Fair Value Measurements
	We estimate the fair values of financial and non-financial assets and liabilities under ASC Topic 820 “Fair Value Measurements and Disclosures” (“ASC Topic 820”). ASC Topic 820 provides a framework for consistent measurement of fair value for those assets and liabilities already measured at fair value under other accounting pronouncements. Certain specific fair value measurements, such as those related to share-based compensation, are not included in the scope of ASC Topic 820. Primarily, ASC Topic 820 is applicable to assets and liabilities related to financial instruments, to some long-term investments and liabilities, to initial valuations of assets and liabilities acquired in a business combination, 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 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 December 31, 2013, the fair value of our Senior Notes was estimated to be $583.0 million. We consider the inputs to the valuation of our Senior Notes to be Level 1, as fair value was estimated based on prices quoted from a third-party financial institution.
	Derivative instruments. Our commodity derivative instruments consist of fixed-price swaps, basis swap contracts, collars, three-way collars, swaptions, call options sold, put spread options, put options sold and range bonus accumulators. We account for our commodity derivatives and interest rate derivatives at fair value on a recurring basis. We estimate the fair values of the fixed-price swaps, basis swap contracts and swaptions based on published forward commodity price curves for the underlying commodities as of the date of the estimate. We estimate the option values of the contract floors, ceilings, collars and three-way collars using an option pricing model which takes into account market volatility, market prices and contract parameters. The discount rates used in the discounted cash flow projections are based on published LIBOR rates, Eurodollar futures rates and interest swap rates. In order to estimate the fair values 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 estimates for these derivative instruments as a Level 2 input. We estimate the values 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 valuations 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 estimates 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):
		31-Dec-13
		Fair Value Measurements Using									Assets/Liabilities at Fair Value
		Level 1			Level 2			Level 3
		(in thousands)
	Assets:
	Commodity price derivative contracts	$	—		$	81,124		$	566		$	81,690
	Interest rate derivative contracts	—			98			—			98
	Total derivative instruments	$	—		$	81,222		$	566		$	81,788
	Liabilities:
	Commodity price derivative contracts	$	—		$	(8,208	)	$	—		$	(8,208	)
	Interest rate derivative contracts	—			(6,869		)	—			(6,869		)
	Total derivative instruments	$	—		$	(15,077	)	$	—		$	(15,077	)
		31-Dec-12
		Fair Value Measurements Using									Assets/Liabilities
		Level 1			Level 2			Level 3			at Fair value
		(in thousands)
	Assets:
	Commodity price derivative contracts	$	—		$	99,904		$	—		$	99,904
	Interest rate derivative contracts	—			26			—			26
	Total derivative instruments	$	—		$	99,930		$	—		$	99,930
	Liabilities:
	Commodity price derivative contracts	$	—		$	(6,276	)	$	(498	)	$	(6,774	)
	Interest rate derivative contracts	—			(10,588		)	—			(10,588		)
	Total derivative instruments	$	—		$	(16,864	)	$	(498	)	$	(17,362	)
	The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:
		2013			2012
		(in thousands)
	Unobservable inputs at January 1,	$	(498	)	$	—
	Total losses	(134		)	(498		)
	Settlements	1,198			—
	Unobservable inputs at December 31,	$	566		$	(498	)
	Change in fair value included in earnings related to derivatives still held as of December 31,	$	1,126		$	(498	)
	still held as of December 31, 2013
	During periods of market disruption, including periods of volatile oil and natural gas prices, there may be certain asset classes that were in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments, other than the range bonus accumulators, may fall to Level 3 and thus require more subjectivity and management judgment. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition.
	We apply the provisions of ASC Topic 350 “Intangibles-Goodwill and Other.” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is assessed for impairment annually on October 1 or whenever indicators of impairment exist. The goodwill test is performed at the reporting unit level, which represents our oil and natural gas operations in the United States. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. We utilize a market approach to determine the fair value of our reporting unit. Any sharp prolonged decreases in the prices of oil and natural gas or any significant negative reserve adjustments from the December 31, 2013 assessment could change our estimates of the fair value of our reporting unit and could result in an impairment charge.
	Our nonfinancial assets and liabilities that are initially measured at fair value are comprised primarily of assets acquired in business combinations and asset retirement costs and obligations.  These assets and liabilities are recorded at fair value when acquired/incurred but not re-measured at fair value in subsequent periods. We classify such initial measurements as Level 3 since certain significant unobservable inputs are utilized in their determination. A reconciliation of the beginning and ending balance of our asset retirement obligations is presented in Note 6, in accordance with ASC Topic 410-20 “Asset Retirement Obligations.” During the year ended December 31, 2013, in connection with oil and natural gas properties acquired in all 2013 acquisitions, and as well as new wells drilled during the year, we incurred and recorded asset retirement obligations totaling $11.7 million at fair value. We also recorded an $11.0 million change in estimate as a result of revisions to the timing or the amount of our original undiscounted estimated asset retirement costs. During the year ended December 31, 2012, in connection with oil and natural gas properties acquired in all of our acquisitions, and as well as new wells drilled during the year, we incurred and recorded asset retirement obligations totaling $26.4 million at fair value. The fair value of additions to the asset retirement obligation liability and certain changes in the estimated fair value of the liability are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount.  Inputs to the valuation include: (1) estimated plug and abandonment cost per well based on our experience; (2) estimated remaining life per well based on average reserve life per field; (3) our credit-adjusted risk-free interest rate ranging between 4.9% and 5.7%; and (4) the average inflation factor (2.4%). These inputs require significant judgments and estimates by the Company's management at the time of the valuation and are the most sensitive and subject to change.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation [Abstract]	'
Asset Retirement Obligations	'
	Asset Retirement Obligations
	The asset retirement obligations as of December 31, reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the year ended December 31, were as follows:
		2013			2012
		(in thousands)
	Asset retirement obligation at January 1,	$	63,114		$	35,920
	Liabilities added during the current period	11,738			26,365
	Accretion expense	2,789			1,305
	Change in estimate	10,954			—
	Retirements	(628		)	(476		)
	Total asset retirement obligation at December 31,	87,967			63,114
	Less: current obligations	(5,759		)	(3,018		)
	Long-term asset retirement obligation at December 31,	$	82,208		$	60,096
	Accretion expense for the years ended December 31, 2013, 2012 and 2011 was $2.8 million, $1.3 million and $0.9 million, respectively. Each year we review, and to the extent necessary, revise our asset retirement obligation estimates. During 2013, we reviewed the actual abandonment costs with previous estimates and, as a result, increased our estimates of future asset retirement obligations by a net $11.0 million to reflect increased costs incurred for plugging and abandonment.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	Related Party Transactions
	We previously owned oil and natural gas properties in the Appalachian Basin. On February 21, 2012, we and our 100% owned subsidiary, VNG, entered into the Unit Exchange with the Nami Parties to transfer our partnership interest in Trust Energy Company, LLC and Ariana Energy, LLC, which entities controlled all of our ownership interests in oil and natural gas properties in the Appalachian Basin, in exchange for 1.9 million of our common units valued at the closing price of our common units of $27.62 per unit at March 30, 2012, or $52.5 million, with an effective date of January 1, 2012. The Nami Parties are controlled by or affiliated with Majeed S. Nami who was a founding unitholder when we completed the IPO. We completed this transaction on March 30, 2012 for non-cash consideration of $52.5 million which was offset by post-closing adjustments of $1.4 million.
	Prior to the completion of the Unit Exchange, we relied on Vinland Energy Eastern, LLC (“Vinland”) to execute our drilling program, operate our wells and gather our natural gas in the Appalachian Basin. We reimbursed Vinland $60.00 per well per month (in addition to normal third-party operating costs) for operating our current natural gas and oil properties in the Appalachian Basin under a Management Services Agreement (“MSA”) which costs were reflected in our lease operating expenses. Under a Gathering and Compression Agreement (“GCA”), Vinland received a $0.55 per Mcf transportation fee on any new wells drilled after December 31, 2006 within the area of mutual interest or “AMI.” In June 2010, we began discussions with Vinland regarding an amendment to the GCA to go into effect beginning on July 1, 2010. The amended agreement would provide gathering and compression services based upon actual costs plus a margin of $.055 per mcf. We and Vinland agreed in principle to this change effective July 1, 2010 and jointly operated on this basis, however, no formal agreement between us and Vinland was signed. Under the GCA, the transportation fee that we paid to Vinland only encompassed transporting the natural gas to third- party pipelines at which point additional transportation fees to natural gas markets applied. These transportation fees were outlined in the GCA and are reflected in our lease operating expenses. For the years ended December 31, 2012 and 2011, costs incurred under the MSA were $0.6 million and $1.9 million, respectively, and costs incurred under the GCA were $0.4 million and $1.8 million, respectively. As a result of the Unit Exchange, the MSA and GCA were terminated.
	In connection with closing of the ENP Purchase, VNG entered into a Second Amended and Restated Administrative Services Agreement, dated December 31, 2010, with ENP, ENP GP, Encore Operating, L.P. (“Encore Operating”), OLLC and Denbury (the “Services Agreement”).  The Services Agreement was amended solely to add VNG as a party and provide for VNG to assume the rights and obligations of Encore Operating and Denbury under the previous administrative services agreement going forward.
	Pursuant to the Services Agreement, as amended, VNG provided certain general and administrative services to ENP, ENP GP and OLLC (collectively, the “ENP Group”) in exchange for a quarterly fee of $2.06 per BOE of the ENP Group’s total net oil and gas production for the most recently-completed quarter, which fee was paid by ENP (the “Administrative Fee”). The Administrative Fee was subject to certain index-related adjustments on an annual basis. Effective April 1, 2011, the Administrative Fee decreased from $2.06 per BOE of ENP’s production to $2.05 per BOE as the Council of Petroleum Accountants Societies (“COPAS”) Wage Index Adjustment decreased 0.7 percent. ENP was also obligated to reimburse VNG for all third-party expenses it incurred on behalf of the ENP Group. These terms were identical to the terms under which Denbury and Encore Operating provided administrative services to the ENP Group prior to the second amendment and restatement of the Services Agreement. During the year ended December 31, 2011, VNG received administrative fees amounting to $6.1 million, COPAS recovery amounting to $5.1 million and reimbursements of third-party expenses amounting to $5.8 million. In December 2011, the Services Agreement was terminated pursuant to the ENP Merger.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	Commitments and Contingencies
	Transportation Demand Charges
	As of December 31, 2013, we have contracts that provide firm transportation capacity on pipeline systems. The remaining terms on these contracts range from one to six years and require us to pay transportation demand charges regardless of the amount of pipeline capacity we utilize.
	The values in the table below represent gross future minimum transportation demand charges we are obligated to pay as of December 31, 2013. However, our financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property.
		(in thousands)
	2014	$	12,625
	2015	8,069
	2016	5,655
	2017	4,106
	2018	3,527
	Thereafter	3,597
	Total	$	37,579
	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 were also a party to a litigation related to the ENP Merger (the “ENP Litigation”) discussed below. In addition, 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.
	On April 5, 2011, Stephen Bushansky, a purported unitholder of ENP, filed a putative class action complaint in the Delaware Court of Chancery on behalf of the unitholders of ENP. Another purported unitholder of ENP, William Allen, filed a similar action in the same court on April 14, 2011. The Bushansky and Allen actions have been consolidated under the caption In re: Encore Energy Partners LP Unitholder Litigation, C.A. No. 6347-VCP (the “Delaware State Court Action”). On December 28, 2011, those plaintiffs jointly filed their second amended consolidated class action complaint naming as defendants ENP, Scott W. Smith, Richard A. Robert, Douglas Pence, W. Timothy Hauss, John E. Jackson, David C. Baggett, Martin G. White, and Vanguard. That putative class action complaint alleged, among other things, that defendants breached the partnership agreement by recommending a transaction that was not fair and reasonable. Plaintiffs sought compensatory damages. Vanguard filed a motion to dismiss this lawsuit. On August 31, 2012, the Chancery Court entered an order granting Vanguard's motion to dismiss the complaint for failure to state a claim and dismissing the Delaware State Court Action with prejudice. On September 27, 2012, Mr. Allen filed a notice of appeal of the dismissal of his lawsuit. On July 22, 2013, the Delaware Supreme Court affirmed the dismissal of the lawsuit.

Common_Units_and_Net_Income_Lo

Common Units and Net Income (Loss) per Unit	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Common Units and Net Income (Loss) per Unit	'
	Common Units and Net Income (Loss) per Common and Class B Unit
	Basic net income per common and Class B unit is computed in accordance with ASC Topic 260 “Earnings Per Share” (“ASC Topic 260”) by dividing net income available to common and Class B unitholders by the weighted average number of units outstanding during the period. Diluted net income per common and Class B unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. We use the treasury stock method to determine the dilutive effect. As of December 31, 2013, we have three classes of units outstanding: (i) units representing limited liability company interests (“common units”), (ii) Class B units, granted to executive officers and an employee and (iii) Series A Cumulative Redeemable Perpetual Preferred Units representing preferred equity company interests ("Series A Preferred Units"). The Class B units participate in distributions; therefore, all Class B units were considered in the computation of basic net income per unit. Series A Preferred Units have no participation rights and accordingly are excluded from the computation of basic net income per unit.
	For the year ended December 31, 2013, the 562,384 phantom units granted to officers, board members and employees from 2010 to date under the Vanguard Natural Resources, LLC Long-Term Incentive Plan (“VNR LTIP”) have been included in the computation of diluted income per common and Class B unit as 347,826 additional common units would have been issued and outstanding under the treasury stock method assuming the phantom units had been exercised at the beginning of the period. Of the 562,384 phantom units granted to date, 522,500 of them were granted to officers prior to December 31, 2012 and 85,000 were granted to officers prior to December 31, 2011 and have been excluded in the computation of net income per common and Class B unit for the years ended December 31, 2012 and 2011 as they had no dilutive effect.
	The 175,000 options granted to officers under our long-term incentive plan had a dilutive effect for the year ended December 31, 2011; therefore, they have been included in the computation of diluted earnings per unit. During the year ended December 31, 2012, all the options were exercised by the officers.
	The Series A Preferred Units rank senior to our common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up. The Series A Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by us or converted into our common units, at our option, in connection with a change of control. At any time on or after June 15, 2023, we may redeem the Series A Preferred Units, in whole or in part, out of amounts legally available therefore, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. We may also redeem the Series A Preferred Units in the event of a change of control. Holders of Series A Preferred Units will have no voting rights except for limited voting rights if we fail to pay dividends for eighteen or more monthly periods (whether or not consecutive) and in certain other limited circumstances or as required by law. The Series A Preferred Units have a liquidation preference which is equal to the redemption price described above.
	Distributions Declared
	Distributions on the Series A Preferred Units are cumulative from the date of original issue and are 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 pay cumulative distributions in cash on the Series A Preferred Units on a monthly basis at a monthly rate of $0.1641 per preferred unit, or 7.875% of the liquidation preference of $25.00 per preferred unit, per year. The initial prorated monthly distribution of $0.1422 on the Series A Preferred Units was paid on July 15, 2013. Subsequent to the initial distribution, monthly distributions were declared and paid to preferred unitholders at the monthly rate of $0.1641 per preferred unit.
	The following table shows the distribution amount per common and Class B unit, declared date, record date and payment date of the cash distributions we paid on each of our common and Class B units that were declared during each of the three years in the period ended December 31, 2013. 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. The payment of our distributions was changed from quarterly to monthly commencing with the July 2012 distribution.
		Cash Distributions
	Distribution	Per Unit		Declared Date	Record Date	Payment Date
	2013
	Fourth Quarter
	November	$	0.2075	December 17, 2013	January 2, 2014	January 15, 2014
	October	$	0.2075	November 19, 2013	December 2, 2013	December 13, 2013
	Third Quarter
	September	$	0.2075	October 21, 2013	November 1, 2013	November 14, 2013
	August	$	0.2075	September 12, 2013	October 1, 2013	October 15, 2013
	July	$	0.2075	August 20, 2013	September 3, 2013	September 13, 2013
	Second Quarter
	June	$	0.205	July 18, 2013	August 1, 2013	August 14, 2013
	May	$	0.205	June 20, 2013	July 1, 2013	July 15, 2013
	April	$	0.205	April 30, 2013	June 3, 2013	June 14, 2013
	First Quarter
	March	$	0.2025	April 19, 2013	May 1, 2013	May 15, 2013
	February	$	0.2025	March 21, 2013	April 1, 2013	April 12, 2013
	January	$	0.2025	February 18, 2013	March 1, 2013	March 15, 2013
	2012
	Fourth Quarter
	December	$	0.2025	January 25, 2013	February 4, 2013	February 14, 2013
	November	$	0.2025	December 19, 2012	January 2, 2013	January 14, 2013
	October	$	0.2025	November 16, 2012	December 3, 2012	December 14, 2012
	Third Quarter
	September	$	0.2	October 18, 2012	November 1, 2012	November 14, 2012
	August	$	0.2	September 17, 2012	October 1, 2012	October 15, 2012
	July	$	0.2	August 20, 2012	September 4, 2012	September 14, 2012
	Second Quarter	$	0.6	July 23, 2012	August 7, 2012	August 14, 2012
	First Quarter	$	0.5925	April 24, 2012	May 8, 2012	May 15, 2012
	2011
	Fourth Quarter	$	0.5875	January 18, 2012	February 7, 2012	February 14, 2012
	Third Quarter	$	0.5775	October 27, 2011	November 7, 2011	November 14, 2011
	Second Quarter	$	0.575	July 26, 2011	August 5, 2011	August 12, 2011
	First Quarter	$	0.57	April 28, 2011	May 6, 2011	May 13, 2011
	2010
	Fourth Quarter	$	0.56	January 27, 2011	February 7, 2011	February 14, 2011

UnitBased_Compensation

Unit-Based Compensation	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Unit-Based Compensation	'
	Unit-Based Compensation
	Unit Options
	In October 2007, two officers were granted options to purchase an aggregate of 175,000 units under the Vanguard Natural Resources, LLC Long-Term Incentive Plan (the “VNR LTIP”) with an exercise price equal to the initial public offering price of $19.00, which vested immediately upon being granted and had a fair value of $0.1 million on the date of grant. These options were to expire on October 29, 2012. The grant date fair value for these option awards was calculated in accordance with ASC Topic 718, “Compensation-Stock Compensation” (“ASC Topic 718”) by calculating the Black-Scholes value of each option, using a volatility rate of 12.18%, an expected dividend yield of 8.95% and a discount rate of 5.12%, and multiplying the Black-Scholes value by the number of options awarded. In determining a volatility rate of 12.18%, we, due to a lack of historical data regarding our common units, used the historical volatility of the Citigroup MLP Index over the 365 day period prior to the date of grant. In September 2012, one of the officers exercised the option to purchase 50,000 of our common units at $19.00. The remaining options were settled in October 2012 and additional compensation expense of $1.3 million was recorded, representing the excess of the settlement payment over the fair value of the options at grant date. The additional compensation expense was recognized in the Selling, general and administrative expenses line item in the Consolidated Statement of Operations.
	Executive Employment Agreements and Annual Bonus
	In June and July 2013, we and VNRH entered into new amended and restated executive employment agreements (the "Amended Agreements") with each of our three executive officers, Messrs. Smith, Robert and Pence. The Amended Agreements were effective January 1, 2013 and the initial term of the Amended Agreements ends on January 1, 2016, with a subsequent twelve-month term extension automatically commencing on January 1, 2016 and each successive January 1 thereafter, provided that neither VNRH nor the executives deliver a timely non-renewal notice prior to a term expiration date.
	The Amended Agreements provide for an annual base salary and eligibility to receive an annual performance-based cash bonus award. The annual bonus will be calculated based upon three Company performance components: absolute target distribution growth, adjusted EBITDA growth and relative unit performance to peer group, as well as a fourth component determined solely in the discretion of our board of directors. Each of the four components will be weighted equally in calculating the respective executive officer's annual bonus. The annual bonus does not require a minimum payout, although the maximum payout may not exceed two (2) times the executive's respective annual base salary. As of December 31, 2013, an accrued liability was recognized and compensation expense of $1.6 million was recorded related to these bonus arrangements, which was classified in the selling, general and administrative expenses line item in the Consolidated Statement of Operations.
	In the event of the Company's Change in Control, as defined in the VNR LTIP, the executives are entitled to certain change in control payments and benefits, consisting of: (i) an amount equal to two (2) times their then-current base salary and annual bonus and (ii) accelerated vesting of any outstanding restricted units, phantom units, or any other awards granted under the VNR LTIP held by the executives at the time of the change of control, with any settlement of these awards being made according to the terms of the VNR LTIP and the applicable individual award agreement.
	The executives are entitled to severance payments and benefits upon certain qualifying terminations. Upon a termination by VNRH without "Cause" (as such term is defined in the Amended Agreements) or termination by either executive for "Good Reason" (as such term is defined in the Amended Agreements), the executive is entitled to (i) an amount equal to three (3) times the executive's then-current base salary and (ii) accelerated vesting of any outstanding restricted units, phantom units, or any other awards granted under the VNR LTIP held by the executives at the time of such termination, with any settlement of these awards being made according to the terms of the VNR LTIP. Upon an executive's termination by "Disability" (as such term is defined in the Amended Agreements) or death, the executive is entitled to (a) an amount equal to one times the executive's then-current base salary and (b) accelerated vesting of any outstanding restricted units, phantom units, or any other awards granted under the VNR LTIP held by the executives at the time of such termination, with any settlement of these awards being made according to the terms of the VNR LTIP. As a condition to receiving any of the severance payments and benefits heretofore described, the terminated executive (or his legal representative, as applicable) must execute and not revoke a customary severance and release agreement, including a waiver of all claims.
	The Amended Agreements also provide that the executives are eligible to participate in the benefit programs generally available to senior executives of VNRH. The Amended Agreements also contain standard non-competition, non-solicitation and confidentiality provisions.
	Restricted and Phantom Units
	Under the Amended Agreements, the executives are also eligible to receive annual equity-based compensation awards, consisting of restricted units and/or phantom units granted under the VNR LTIP. Each of the executives are eligible to receive annual equity-based compensation awards having an aggregate fair market value equal to the executive's then-current annual base salary times a set multiplier, which such multiplier is five (5) times in the case of Mr. Smith, three and a half (3.5) times in the case of Mr. Robert, and two and three-quarters (2.75) times in the case of Mr. Pence.
	The restricted units are subject to a three-year vesting period. One-third of the aggregate number of the units vest on each one-year anniversary of the date of grant so long as the executive remains continuously employed with the Company. The restricted units include a tandem grant of distribution equivalent rights (“DERs”), which entitle the executives to receive the value of any dividends made by us on our units generally with respect to the number of restricted units that the executives received pursuant to the grant. In the event the executive is terminated without “Cause”, or the executive resigns for “Good Reason”, or the executive is terminated due to his death or Disability, all unvested outstanding restricted units shall receive accelerated vesting. If the executive is terminated for Cause, all unvested restricted units are forfeited. Upon the occurrence of a Change of Control, all unvested outstanding restricted units shall receive accelerated vesting.
	The phantom units are also subject to a three-year vesting period. One-third of the aggregate number of the units vest on each one-year anniversary of the date of grant so long as the executive remains continuously employed with the Company. The phantom units include a tandem grant of DERs, which entitle the executives to receive the value of any dividends made by the Company on its units generally with respect to the number of phantom units that the executives received pursuant to the grant. In the event the executive is terminated without Cause, or the executive resigns for Good Reason, or the executive is terminated due to his death or Disability, all unvested outstanding phantom units shall receive accelerated vesting. If the executive is terminated for Cause, all unvested restricted units are forfeited. Upon the occurrence of a Change of Control, all unvested outstanding restricted units shall receive accelerated vesting.
	The restricted units and the phantom units are subject to all the terms and conditions of the VNR LTIP as well as the individual award agreements which govern the awards. Neither the restricted units nor the phantom units are transferable, other than by will or the laws of descent and distribution. The Company shall withhold from the settlement or payment of the awards, as applicable, any amounts or units necessary to satisfy the Company's withholding obligations.
	On August 1, 2012, three of our executives were granted a total of 390,000 phantom units. These phantom unit grants were made under the VNR LTIP and are subject to vesting in five equal annual installments, with the first vesting date being May 18, 2013, and each subsequent vesting date occurring on each annual anniversary of the first vesting date.
	On November 15, 2013, two of our executives were awarded a total of 87,500 restricted units as retention grants. These restricted units are accompanied by DERs and will vest at the end of three years after the grant date.
	During the year ended December 31, 2013, our four independent board members were granted a total of 18,684 phantom units which will vest one year from the date of grant and VNR employees were granted a total of 70,104 phantom units. The phantom units are accompanied by DERs, which entitle the board members and VNR employees to receive the value of any distributions made by us on our units generally with respect to the number of phantom shares that the board members and the VNR employees received pursuant to these grants.
	As of December 31, 2013, an accrued liability of $1.3 million has been recorded related to phantom units granted to executive officers, board members and employees and non-cash unit-based compensation expense of $1.7 million, $1.2 million and $0.5 million has been recognized in the selling, general and administrative expense line item in the Consolidated Statements of Operations for the years ended December 31, 2013, 2012, and 2011, respectively.
	Non-Vested Restricted Unit Grants
	Historically, we have granted restricted common units to employees as partial consideration for services to be performed and have accounted for these grants under ASC Topic 718. The fair value of restricted units issued is determined based on the fair market value of common units on the date of the grant. This value is amortized over the vesting period as referenced above.
	As of December 31, 2013, a summary of the status of the non-vested units under the VNR LTIP is presented below:
		Number of		Weighted Average
		Non-vested Restricted Units		Grant Date Fair Value
	Non-vested units at December 31, 2012	289,813		$	27.97
	Granted	89,500		$	28.7
	Forfeited	(6,507	)	$	29.07
	Vested	(124,195	)	$	27.24
	Non-vested units at December 31, 2013	248,611		$	28.57
	At December 31, 2013, there was approximately $5.3 million of unrecognized compensation cost related to non-vested restricted units.  The cost is expected to be recognized over an average period of approximately 1.9 years. Our Consolidated Statements of Operations reflects non-cash compensation of $5.9 million, $5.4 million and $3.0 million in the Selling, general and administrative expenses line item for the years ended December 31, 2013, 2012 and 2011, respectively.
	ENP Long-Term Incentive Plan
	As a result of the ENP Merger, on December 1, 2011, all obligations under ENP 's Long-Term Incentive Plan (the "ENP LTIP") were assumed by VNR and all of the 143,266 non-vested units under the ENP LTIP were substituted with 107,449 Vanguard common units based on an exchange ratio of 0.75 Vanguard common unit for each ENP non-vested unit. During the eleven months ended November 30, 2011, $0.8 million of non-cash unit-based compensation expense were recorded related to units granted under the ENP LTIP.

Shelf_Registration_Statements

Shelf Registration Statements	12 Months Ended
	Dec. 31, 2013
Shelf Registration Statement [Abstract]	'
Shelf Registration Statement	'
	Shelf Registration Statements
	During the third quarter 2009, we filed a registration statement with the SEC which registered offerings of up to $300.0 million (the “2009 Shelf Registration Statement”) of any combination of debt securities, common units and guarantees of debt securities by our subsidiaries. The 2009 Shelf Registration Statement expired in August 2012. In July 2010, we filed a registration statement with the SEC which registered offerings of up to $800.0 million (the “2010 Shelf Registration Statement”) of any combination of debt securities, common units and guarantees of debt securities by our subsidiaries. The 2010 Shelf Registration Statement expired in July 2013.
	In January 2012, we filed a registration statement (the “2012 Shelf Registration Statement”) with the SEC, which registered offerings of approximately 3.1 million common units held by certain selling unitholders. By means of the same registration statement, we also registered an indeterminate amount of common units, debt securities and guarantees of debt securities, which may be offered by us. In the future, we may issue additional debt and equity securities pursuant to a prospectus supplement to the 2012 Shelf Registration Statement. On June 12, 2013, we filed a post-effective amendment to the 2012 Shelf Registration Statement with the SEC, which registered an indeterminate amount of Series A Cumulative Redeemable Perpetual Preferred Units representing preferred equity interests in the Company.
	Net proceeds, terms and pricing of each offering of securities issued under the 2012 Shelf Registration Statement are determined at the time of such offerings. The 2012 Shelf Registration Statement does not provide assurance that we will or could sell any such securities. Our ability to utilize the 2012 Shelf Registration Statement for the purpose of issuing, from time to time, any combination of debt securities, common units or preferred units will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us.
	On September 9, 2011, we entered into an amended and restated Equity Distribution Program Distribution Agreement (the “2011 Distribution Agreement”) which extended, for an additional three years, the agreement we had with our sales agent to act as our exclusive distribution agent with respect to the issuance and sale of our common units up to an aggregate gross sales price of $200.0 million. Of the $200.0 million common units provided for under the 2011 Distribution Agreement, approximately $4.0 million of our common units were issued and sold under a prospectus supplement to our 2009 Shelf Registration Statement, which expired in August 2012. Subsequent offerings of our common units under the 2011 Distribution Agreement were made pursuant to a new prospectus supplement to the 2012 Shelf Registration Statement. On November 22, 2013, we terminated the 2011 Distribution Agreement. Total net proceeds received under the 2011 Distribution Agreement during 2013 through the termination of the agreement were approximately $31.5 million, after commissions, from the sales of 1,103,499 common units.
	On November 26, 2013, we entered into an Equity Distribution Agreement (the “2013 Distribution Agreement”) with respect to the issuance and sale of our securities. Pursuant to the terms of the 2013 Distribution Agreement, we may sell from time to time through our sales agents, a combination of or either (1) our common units up to an aggregate gross sales price of $500,000,000 or (2) our Series A Preferred Units up to an aggregate gross sales price of $250,000,000. The common units and Series A Preferred Units to be sold under the 2013 Distribution Agreement are registered under the 2012 Registration Statement. During 2013, total net proceeds received under the 2013 Distribution Agreement were approximately $21.2 million, after commissions, from the sales of 748,100 common units and $0.4 million, after commissions, from the sales of 15,927 Series A Preferred Units.
	Equity Offerings
	Common Units
	On February 5, 2013, we completed a public offering of 9,200,000 of our common units at a price of $27.85 per unit, which includes 1,200,000 common units purchased pursuant to the underwriters' over-allotment option. Offers were made pursuant to a prospectus supplement to the 2012 Shelf Registration Statement. We received proceeds of approximately $246.1 million from this offering, after deducting underwriting discounts of $10.0 million and offering costs of $0.1 million. We used the net proceeds from this offering to repay indebtedness outstanding under our Reserve-Based Credit Facility.
	On June 4, 2013, we completed a public offering of 7,000,000 of our common units at a price of $28.35 per unit. Offers were made pursuant to a prospectus supplement to the 2012 Shelf Registration Statement. We received proceeds of approximately $190.9 million from this offering, after deducting underwriting discounts of $7.4 million and offering costs of $0.1 million. We used the net proceeds from this offering to repay indebtedness outstanding under our Reserve-Based Credit Facility. In July 2013, we received additional proceeds of $8.9 million from the sale of an additional 325,000 of our common units that were purchased by the underwriters to cover over-allotments.
	Preferred Units
	On June 19, 2013, we completed a public offering of 2,520,000 7.875% Series A Preferred Units at a price of $25.00 per unit. The total of 2,520,000 Series A Preferred Units includes 320,000 Series A Preferred Units purchased pursuant to the underwriters' over-allotment option. Offers were made pursuant to a prospectus supplement to the 2012 Shelf Registration Statement. We received proceeds of approximately $60.6 million from this offering, after deducting discounts of $2.0 million and offering costs of $0.4 million. We used the net proceeds from this offering to repay indebtedness outstanding under our Reserve-Based Credit Facility.
	Subsidiary Guarantors
	We and VNR Finance Corp., our wholly-owned finance subsidiary, may co-issue securities pursuant to the 2012 Shelf 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, and any subsidiaries of Vanguard that do not guarantee the securities will be minor.

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2013
Subsequent Events [Abstract]	'
Subsequent Event	'
	Subsequent Events
	Distributions
	On January 16, 2014, our board of directors declared a cash distribution attributable to the month of December 2013 of $0.2075 per common unit that was paid on February 14, 2014 to unitholders of record as of the close of business on February 3, 2014. Also, on January 16, 2014 our board of directors declared a cash distribution for our preferred unitholders of $0.1641 per preferred unit that was paid on February 14, 2014 to Vanguard preferred unitholders of record on February 3, 2014.
	On February 20, 2014, our board of directors declared a cash distribution attributable to the month of January 2014 of $0.2075 per common unit to be paid on March 17, 2014 to unitholders of record as of the close of business on March 3, 2014. Also on February 20, 2014, our board of directors declared a cash distribution for our preferred unitholders of $0.1641 per preferred unit expected to be paid on March 14, 2014 to Vanguard preferred unitholders of record on March 3, 2014.
	In addition, on February 26, 2014, our board of directors approved an increase to our monthly cash distribution from $0.2075 to $0.21 per common unit (from $2.49 to $2.52 on an annualized basis) effective with our February 2014 distribution expected to be paid on April 14, 2014 to unitholders of record as of the close of business on April 1, 2014.
	Acquisitions
	On December 23, 2013, we entered into a purchase and sale agreement to acquire natural gas and oil properties in the Pinedale and Jonah fields of Southwestern Wyoming. We refer to this acquisition as the "Pinedale Acquisition." We completed this acquisition on January 31, 2014 for an adjusted purchase price of $549.1 million, subject to additional customary post-closing adjustments to be determined. Upon closing of this acquisition, we assumed development commitments of approximately $36.6 million for the drilling and completion of vertical natural gas wells in the Pinedale field. The purchase price was funded with borrowings under our Reserve-Based Credit Facility.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Basis of Presentation and Principles of Consolidation	'
	The consolidated financial statements as of and for the years ended December 31, 2013, 2012 and 2011 include the accounts of VNR and its subsidiaries. As of December 31, 2010, we consolidated ENP as we had the ability to control the operating and financial decisions and policies of ENP through our ownership of ENP GP and reflected the non-controlling interest as a separate element of members’ equity on our consolidated balance sheet. On December 1, 2011, ENP became a wholly-owned subsidiary of VNG.
	Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and include the accounts of all subsidiaries after the elimination of all significant intercompany accounts and transactions. 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.
Cash Equivalents	'
	The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents.
Accounts Receivable and Allowance for Doubtful Accounts	'
	Accounts receivable are customer obligations due under normal trade terms and are presented on the Consolidated Balance Sheets net of allowances for doubtful accounts. We establish provisions for losses on accounts receivable if we determine that it is likely that we will not collect all or part of the outstanding balance. We regularly review collectibility and establish or adjust our allowance as necessary using the specific identification method.
Inventory	'
	Materials, supplies and commodity inventories are valued at the lower of cost or market. The cost is determined using the first-in, first-out method. Inventories are included in other current assets in the accompanying Consolidated Balance Sheets.
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 estimated future net cash flows from proved reserves, computed using the 12-month unweighted average of first-day-of-the-month commodity prices (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 2013 or 2011. During the year ended December 31, 2012, we recorded a non-cash ceiling test impairment of oil and natural gas properties of $247.7 million as a result of a decline in natural gas prices at the measurement dates, September 30, 2012 and December 31, 2012. Such impairment was recognized during the third and fourth quarters of 2012. The most significant factor affecting the 2012 impairment related to the properties that we acquired in the Arkoma Basin Acquisition and Rockies Acquisition (discussed below). The fair values of the properties acquired (determined using forward oil and natural gas price curves at the acquisitions dates) were higher than the discounted estimated future cash flows computed using the 12-month average prices at the impairment test measurement dates. We were able to lock in higher future selling prices for a portion of the estimated natural gas production for the Arkoma Basin Acquisition and the Rockies Acquisition by using commodity derivative contracts. However, our impairment calculations do not consider the positive impact of our commodity derivative positions as generally accepted accounting principles only allow us to consider the expected cash flows from derivatives designated as cash flow hedges. The 2012 third quarter impairment was calculated based on prices of $2.77 per MMBtu for natural gas and $95.26 per barrel of crude oil while the 2012 fourth quarter impairment was calculated based on prices of $2.76 per MMBtu for natural gas and $94.67 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.
Goodwill and Other Intangible Assets	'
	We account for goodwill and other intangible assets under the provisions of the Accounting Standards Codification (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 not amortized, but is tested for impairment annually on October 1 or whenever indicators of impairment exist. As discussed further in Note 2, all goodwill recognized in acquisitions other than the ENP Purchase has been determined to be impaired and written off. The goodwill test is performed at the reporting unit level. Beginning in 2012, the reporting unit for the goodwill recognized for the ENP Purchase represents our oil and natural gas operations in the United States. If the fair value of the reporting unit is determined to be less than its carrying value, an impairment charge is recognized for the amount by which the carrying value of goodwill exceeds its implied fair value. We utilize a market approach to determine the fair value of our reporting unit.
	On October 1, 2013, October 1, 2012 and December 1, 2011, we performed impairment tests for the goodwill recognized in the ENP Purchase and our analyses concluded that there was no impairment of goodwill as of these dates. Significant decreases in the 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.
	Intangible assets with definite useful lives are amortized over their estimated useful lives. We evaluate the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable.  An impairment loss exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount.
	We are a party to a contract allowing us to purchase a certain amount of natural gas at a below market price for use as field fuel. As of December 31, 2013, the net carrying value of this contract was $8.5 million. The carrying value is shown as Other assets on the accompanying Consolidated Balance Sheets and is amortized on a straight-line basis over the estimated life of the field. The estimated aggregate amortization expense for each of the next five fiscal years is $0.2 million per year.
Asset Retirement Obligations	'
	We record a liability for asset retirement obligations at fair value in the period in which the liability is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset’s useful life. Our recognized asset retirement obligation exclusively relates to the plugging and abandonment of oil and natural gas wells and decommissioning of our Elk Basin gas plant. Management periodically reviews the estimates of the timing of well abandonments as well as the estimated plugging and abandonment costs, which are discounted at the credit adjusted risk free rate.  These retirement costs are recorded as a long-term liability on the Consolidated Balance Sheets with an offsetting increase in oil and natural gas properties. An ongoing accretion expense is recognized for changes in the value of the liability as a result of the passage of time, which we record in depreciation, depletion, amortization and accretion expense in the Consolidated Statements of Operations.
Revenue Recognition	'
	Sales of oil, natural gas and NGLs are recognized when oil, natural gas and NGLs have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. We sell oil, natural gas and NGLs on a monthly basis. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil, natural gas or NGLs, and prevailing supply and demand conditions, so that the price of the oil, natural gas and NGLs fluctuates to remain competitive with other available oil, natural gas and NGLs supplies. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Trade accounts receivable, net” in the accompanying Consolidated Balance Sheets.
Gas Imbalances	'
	The Company has elected the entitlements method to account for gas production imbalances. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable.
Concentrations of Credit Risk	'
	Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative contracts. We control our exposure to credit risk associated with these instruments by (i) placing our assets and other financial interests with credit-worthy financial institutions, (ii) maintaining policies over credit extension that include the evaluation of customers’ financial condition and monitoring payment history, although we do not have collateral requirements and (iii) netting derivative assets and liabilities for counterparties where we have a legal right of offset.
	At December 31, 2013 and 2012, the cash and cash equivalents were concentrated in one financial institution. We periodically assess the financial condition of this institution and believe that any possible credit risk is minimal.
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, the fair value of assets and liabilities acquired in business combinations, goodwill, derivative contracts, 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.
Price and Interest Rate Risk Management Activities	'
	We have entered into derivative contracts with counterparties that are lenders under our financing arrangements 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. Our natural gas production is primarily sold under market sensitive contracts which are typically priced at a differential to the NYMEX or the published natural gas index prices for the producing area due to the natural gas quality and the proximity to major consuming markets. As for oil production, realized pricing is primarily driven by the West Texas Intermediate (“WTI”), Light Louisiana Sweet Crude, Wyoming Imperial and Flint Hills Bow River prices. NGLs pricing is based on the Oil Price Information Service postings as well as market-negotiated ethane spot prices. During 2013, our derivative transactions included the following:
	•	Fixed-price swaps - where we receive a fixed-price for our production and pay a variable market price to the contract counterparty.
	•	Basis swap contracts - which guarantee a price differential between the NYMEX prices and our physical pricing points. We receive a payment from the counterparty or make a payment to the counterparty for the difference between the settled price differential and amounts stated under the terms of the contract.
	•	Collars - where we pay the counterparty if the market price is above the ceiling price (short call) and the counterparty pays us if the market price is below the floor (long put) on a notional quantity.
	•	Three-way collar contracts - which combine a long put, a short put and a short call. The use of the long put combined with the short put allows us to sell a call at a higher price thus establishing a higher ceiling and limiting our exposure to future settlement payments while also restricting our downside risk to the difference between the long put and the short put if the price drops below the price of the short put. This allows us to settle for market plus the spread between the short put and the long put in a case where the market price has fallen below the short put fixed price.
	•	Swaption agreements - where we provide options to counterparties to extend swap contracts into subsequent years.
	•	Call options sold - a structure that may be combined with an existing swap to raise the strike price, putting us in either a higher asset position, or a lower liability position. In general, selling a call option is used to enhance an existing position or a position that we intend to enter into simultaneously.
	•	Put spread options - created when we purchase a put and sell a put simultaneously.
	•	Put options sold - a structure that may be combined with an existing swap to raise the strike price, putting us in either a higher asset position or a lower liability position. In general, selling a put option is used to enhance an existing position or a position that we intend to enter into simultaneously.
	•	Range bonus accumulators - a structure that allows us to receive a cash payment when the crude oil or natural gas settlement price remains within a predefined range on each expiry date. Depending on the terms of the contract, if the settlement price is below the floor or above the ceiling on any expiry date, we may have to sell at that level.
	We also enter into fixed LIBOR interest rate swap agreements with certain counterparties that are lenders under our financing arrangements, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates.
	Under ASC Topic 815, “Derivatives and Hedging,” all derivative instruments are recorded on the Consolidated Balance Sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date.  We net derivative assets and liabilities for counterparties where we have a legal right of offset.  Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met.  For qualifying cash flow hedges, the change in the fair value of the derivative is deferred in accumulated other comprehensive income (loss) in the equity section of the Consolidated Balance Sheets to the extent the hedge is effective. Gains and losses on cash flow hedges included in accumulated other comprehensive income (loss) are reclassified to gains (losses) on commodity cash flow hedges or gains (losses) on interest rate derivative contracts in the period that the related production is delivered or the contract settles. Gains or losses on derivative contracts that do not qualify for hedge accounting treatment are recorded in net gains (losses) on commodity derivative contracts or net gains (losses) on interest rate derivative contracts in the Consolidated Statements of Operations.
	We have elected not to designate our current portfolio of derivative contracts as hedges.  Therefore, changes in fair value of these derivative instruments are recognized in earnings and included in net gains (losses) on commodity derivative contracts or net gains (losses) on interest rate derivative contracts in the accompanying Consolidated Statements of Operations.
	Any premiums paid on derivative contracts and the fair value of derivative contracts acquired in connection with our acquisitions are capitalized as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid or the contracts are assumed. Premium payments are reflected in cash flows from operating activities in our Consolidated Statements of Cash Flows. When the consideration for an acquisition is cash, the fair value of any derivative contracts acquired in the acquisition is reflected in cash flows from investing activities. Over time, as the derivative contracts settle, the differences between the cash received and the premiums paid or fair value of contracts acquired are recognized in net gains or losses on commodity or interest rate derivate contracts, and the cash received is reflected in cash flows from operating activities in our Consolidated Statements of Cash Flows.
Income Taxes	'
	The Company is treated as a partnership for federal and state income tax purposes.  As such, it is not a taxable entity and does not directly pay federal and state income tax. Its taxable income or loss, which may vary substantially from the net income or net loss reported in the Consolidated Statements of Operations, is included in the federal and state income tax returns of each unitholder.  Accordingly, no recognition has been given to federal and state income taxes for the operations of the Company.  The aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Company does not have access to information about each unitholders’ tax attributes in the Company. However, the book basis of our net assets exceeded the net tax basis by $168.5 million at December 31, 2013 while the tax basis of our net assets exceeded the net book basis by $92.2 million at December 31, 2012.
	Legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including otherwise non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. The Company recorded a current tax liability of $0.3 million and $0.5 million as of December 31, 2013 and 2012, respectively, and a deferred tax liability of $0.4 million and deferred tax asset of $0.3 million as of December 31, 2013 and 2012, respectively. Tax provisions of $0.6 million, $0.2 million, and $0.6 million are included in our Consolidated Statements of Operations for the years ended December 31, 2013, 2012, and 2011, respectively, as a component of Selling, general and administrative expenses.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Schedule of purchasers accounting for 10% or more of the Company's oil, natural gas and NGLs sales	'
	The following purchasers accounted for 10% or more of the Company’s oil, natural gas and NGLs sales for the years ended December 31:
		2013	2012	2011
	Marathon Oil Company	14%	21%	22%
	Plains Marketing L.P.	10%	15%	11%

Acquisitions_and_Divestiture_T

Acquisitions and Divestiture (Tables)	12 Months Ended
	Dec. 31, 2013
Business Acquisition [Line Items]	'
Pro forma operating results from acquisitions	'
	The pro forma information is based upon these assumptions, and is not necessarily indicative of future results of operations:
		Year Ended December 31,
		2013			2012			2011
		(in thousands, except per unit amounts) (Pro forma)
	Total revenues	$	470,834		$	557,802		$	676,685
	Net income (loss) available to Common and Class B unitholders	$	54,158		$	(174,187	)	$	146,783
	Net income (loss) available to Common and Class B unitholders, per unit:
	Basic	$	0.7		$	(3.18	)	$	3.14
	Diluted	$	0.69		$	(3.18	)	$	3.14
Impact of Unit Exchange in Pro Forma Results	'
	The amount of revenues and excess of revenues over direct operating expenses that were eliminated to reflect the impact of the Unit Exchange in the pro forma results presented above are as follows (in thousands):
		Year Ended December 31,
		2012			2011
	Revenues	$	3,267		$	20,017
	Net income (loss)	$	(400	)	$	6,041
Revenues and Excess of Revenues Over Direct Operating Expenses	'
	The table below presents the amounts of revenues and excess of revenues over direct operating expenses included in our 2013, 2012 and 2011 Consolidated Statements of Operations for the Arkoma Basin Acquisition, Rockies Acquisition and all of our other acquisitions, except the ENP Acquisition, as described above. Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes.
		Year Ended December 31,
		2013			2012			2011
		(in thousands)
	Arkoma Basin Acquisition
	Revenues	$	55,468		$	24,673		$	—
	Excess of revenues over direct operating expenses	$	45,090		$	19,971		$	—
	Rockies Acquisition
	Revenues	$	63,652		$	220		$	—
	Excess of revenues over direct operating expenses	$	41,583		$	164		$	—
	All other acquisitions
	Revenues	$	80,349		$	38,366		$	18,298
	Excess of revenues over direct operating expenses	$	49,025		$	21,626		$	11,572
Other Acquistions [Member]	'
Business Acquisition [Line Items]	'
Fair Value of Assets and Liabilities Acquired	'
	The following presents the values assigned to the net assets acquired in our 2013 acquisitions:
	Fair value of assets and liabilities acquired:	(in thousands)
	Oil and natural gas properties	$	317,573
	Inventory	899
	Asset retirement obligations	(11,381		)
	Oil and natural gas revenue payable and imbalance liabilities	(2,843		)
	Total fair value of assets and liabilities acquired	304,248
	Fair value of consideration transferred	298,657
	Gain on acquisition	$	5,591
Arkoma Basin Acquisition [Member]	'
Business Acquisition [Line Items]	'
Fair Value of Assets and Liabilities Acquired	'
	In accordance with ASC Topic 805, this acquisition resulted in a gain of $14.1 million, as reflected in the table below, primarily due to the changes in the value of derivative assets between the date the purchase and sale agreement was entered into and the closing date, which were driven by corresponding changes in natural gas prices.
	Fair value of assets and liabilities acquired:	(in thousands)
	Oil and natural gas properties	$	344,747
	Derivative assets	109,495
	Asset retirement obligations	(8,922		)
	Oil and natural gas revenue payable and imbalance liabilities	(2,653		)
	Total fair value of assets and liabilities acquired	442,667
	Fair value of consideration transferred	428,541
	Gain on acquisition	$	14,126
Rockies Acquisition [Member]	'
Business Acquisition [Line Items]	'
Fair Value of Assets and Liabilities Acquired	'
	The loss resulted primarily from the changes in oil and 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	$	330,707
	Other assets	929
	Asset retirement obligations	(15,763		)
	Oil and natural gas revenue payable and imbalance liabilities	(41		)
	Total fair value of assets and liabilities acquired	315,832
	Fair value of consideration transferred	324,650
	Loss on acquisition	$	(8,818	)

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Financing Arrangements	'
	Our financing arrangements consisted of the following:
							Amount Outstanding December 31,
	Description		Interest Rate		Maturity Date		2013				2012
							(in thousands)
	Senior Secured Reserve-Based Credit Facility		Variable (1)		April 16, 2018		$	460,000			$	700,000
	Senior Notes		7.875% (2)		April 1, 2020		550,000				550,000
							$	1,010,000			$	1,250,000
	Unamortized discount on Senior Notes						(2,121		)		(2,369		)
	Total long-term debt						$	1,007,879			$	1,247,631
	-1	Variable interest rate was 1.92% and 2.22% at December 31, 2013 and 2012, respectively.
	-2	Effective interest rate is 8.0%.
Borrowing Base Utilization Grid	'
	At December 31, 2013, the applicable margin and other fees increase as the utilization of the borrowing base increases as follows:
	Borrowing Base Utilization Grid
	Borrowing Base Utilization Percentage		<25%			>25% <50%			>50% <75%			>75% <90%		>90%
	Eurodollar Loans Margin		1.5	%		1.75	%		2	%		2.25	%	2.5	%
	ABR Loans Margin		0.5	%		0.75	%		1	%		1.25	%	1.5	%
	Commitment Fee Rate		0.5	%		0.5	%		0.375	%		0.375	%	0.375	%
	Letter of Credit Fee		0.5	%		0.75	%		1	%		1.25	%	1.5	%

Price_and_Interest_Rate_Risk_M1

Price and Interest Rate Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Commodity Derivative Contracts Covering Anticipated Future Production	'
	At December 31, 2013, the Company had open commodity derivative contracts covering our anticipated future production as follows:
	Fixed-Price Swaps
			Gas							Oil						NGLs
	Contract Period		MMBtu			Weighted				Bbls			Weighted Average WTI			Bbls	Weighted Average Fixed Price
						Average							Price
						Fixed Price
	January 1, 2014 – December 31, 2014		47,885,225			$	4.51			1,815,875			$	90.59		273,750	$	40.87
	January 1, 2015 – December 31, 2015		53,107,500			$	4.46			692,000			$	91.18		91,250	$	42
	January 1, 2016 – December 31, 2016		49,593,000			$	4.5			146,400			$	89.98		—	$	—
	January 1, 2017 – December 31, 2017		22,202,000			$	4.34			73,000			$	86.6		—	$	—
	Swaptions and Call Options Sold
	Calls were sold or options were provided to counterparties under swaption agreements to extend the swap into subsequent years as follows:
			Oil
	Contract Period		Bbls			Weighted
						Average
						Fixed Price
	January 1, 2014 – December 31, 2014		492,750			$	117.22
	January 1, 2015 – December 31, 2015		508,445			$	105.98
	January 1, 2016 – December 31, 2016		622,200			$	125
	Basis Swaps
			Gas
	Contract Period		MMBtu			Weighted Avg. Basis				Pricing Index
						Differential
						($/MMBtu)
	January 1, 2014 – December 31, 2014		11,845,000			$	(0.21	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2014 – December 31, 2014		452,500			$	(0.32	)		Rocky Mountain CIG and NYMEX Henry Hub Basis Differential
	January 1, 2015 – December 31, 2015		12,775,000			$	(0.29	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
			Oil
	Contract Period		Bbls			Weighted Avg. Basis				Pricing Index
						Differential ($/Bbl)
	January 1, 2014 – December 31, 2014		584,000			$	(0.84	)		WTI Midland and WTI Cushing Basis Differential
	January 1, 2014 – December 31, 2014		328,500			$	(1.05	)		West Texas Sour and WTI Cushing Basis Differential
	January 1, 2014 – December 31, 2014		182,500			$	(3.95	)		Light Louisiana Sweet Crude and Brent Basis Differential
	January 1, 2015 – December 31, 2015		365,000			$	(0.90	)		WTI Midland and WTI Cushing Basis Differential
	Collars
			Oil
	Contract Period		Bbls		Floor				Ceiling
	January 1, 2014 - December 31, 2014		12,000		$	100			$	116.2
	Three-Way Collars
			Oil
	Contract Period		Bbls			Floor				Ceiling				Put Sold
	January 1, 2014 – December 31, 2014		1,313,850			$	93.47			$	101.25			$	72.57
	January 1, 2015 – December 31, 2015		924,055			$	92.1			$	101.54			$	72.04
	January 1, 2016 – December 31, 2016		549,000			$	90			$	95			$	70
	Put Options Sold
			Oil
	Contract Period		Bbls			Put Sold ($/Bbl)
	January 1, 2014 – December 31, 2014		73,000			$	75
	January 1, 2015 – December 31, 2015		692,000			$	72.36
	January 1, 2016 – December 31, 2016		146,400			$	75
	January 1, 2017 – December 31, 2017		73,000			$	75
	Put Spread Options
			Oil
	Contract Period		Bbls			Floor				Put Sold
	January 1, 2015 – December 31, 2015		255,500			$	100			$	75
	Range Bonus Accumulators
			Gas
	Contract Period		MMBtu			Bonus				Range Ceiling				Range Floor
	January 1, 2014 – December 31, 2014		1,460,000			$	0.2			$	4.75			$	3.25
	January 1, 2015 – December 31, 2015		1,460,000			$	0.2			$	4.75			$	3.25
			Oil
	Contract Period		Bbls			Bonus				Range Ceiling				Range Floor
	January 1, 2014 – December 31, 2014		912,500			$	4.94			$	103.2			$	70.5
Interest Rate Derivative Contracts	'
	At December 31, 2013, the Company had open interest rate derivative contracts as follows (in thousands):
			Notional Amount				Fixed Libor Rates
	Period:
	January 1, 2014 to December 10, 2016		$	20,000			2.17	%
	January 1, 2014 to October 31, 2016		$	40,000			1.65	%
	January 1, 2014 to August 5, 2015 (1)		$	30,000			2.25	%
	January 1, 2014 to August 6, 2016		$	25,000			1.8	%
	January 1, 2014 to October 31, 2016		$	20,000			1.78	%
	January 1, 2014 to September 23, 2016		$	75,000			1.15	%
	January 1, 2014 to March 7, 2016		$	75,000			1.08	%
	January 1, 2014 to September 7, 2016		$	25,000			1.25	%
	January 1, 2014 to December 10, 2015 (2)		$	50,000			0.21	%
	Total		$	360,000
	-1	The counterparty has the option to extend the termination date of this contract at 2.25% to August 5, 2018.
	-2	The counterparty has the option to require Vanguard to pay a fixed rate of 0.91% from December 10, 2015 to December 10, 2017.
Fair Value of Derivatives Outstanding	'
	The following table summarizes the gross fair values of our derivative instruments and the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets for the periods indicated (in thousands):
			December 31, 2013
	Offsetting Derivative Assets:		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
	Commodity price derivative contracts		$	107,307			$	(25,617	)		$	81,690
	Interest rate derivative contracts		98				—				98
	Total derivative instruments		$	107,405			$	(25,617	)		$	81,788
	Offsetting Derivative Liabilities:		Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
	Commodity price derivative contracts		$	(33,825	)		$	25,617			$	(8,208	)
	Interest rate derivative contracts		(6,869		)		—				(6,869		)
	Total derivative instruments		$	(40,694	)		$	25,617			$	(15,077	)
			December 31, 2012
	Offsetting Derivative Assets:		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
	Commodity price derivative contracts		$	134,905			$	(35,001	)		$	99,904
	Interest rate derivative contracts		132				(106		)		26
	Total derivative instruments		$	135,037			$	(35,107	)		$	99,930
	Offsetting Derivative Liabilities:		Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
	Commodity price derivative contracts		$	(41,775	)		$	35,001			$	(6,774	)
	Interest rate derivative contracts		(10,694		)		106				(10,588		)
	Total derivative instruments		$	(52,469	)		$	35,107			$	(17,362	)
Reported Gains and Losses on Derivative Instruments	'
	The change in fair value of our commodity and interest rate derivatives for the years ended December 31, 2013, 2012 and 2011 is as follows:
		2013				2012				2011
		(in thousands)
	Derivative asset (liability) at January 1, net	$	82,568			$	(29,889	)		$	(18,591	)
	Purchases
	Fair value of derivatives acquired through business combinations	—				109,495				—
	Premiums and fees paid or deferred (received) for derivative contracts during the period	—				9,695				(257		)
	Net gains on commodity and interest rate derivative contracts	11,160				29,854				1,773
	Settlements
	Cash settlements received on matured commodity derivative contracts	(30,905		)		(39,102		)		(18,720		)
	Cash settlements paid on matured interest rate derivative contracts	3,888				2,515				2,874
	Change in other comprehensive income	—				—				3,032
	Derivative asset (liability) at December 31, net	$	66,711			$	82,568			$	(29,889	)

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Financial Assets and Financial Liabilities Measured at Fair Value on a Recurring Basis	'
	Financial assets and financial liabilities measured at fair value on a recurring basis are summarized below (in thousands):
		31-Dec-13
		Fair Value Measurements Using									Assets/Liabilities at Fair Value
		Level 1			Level 2			Level 3
		(in thousands)
	Assets:
	Commodity price derivative contracts	$	—		$	81,124		$	566		$	81,690
	Interest rate derivative contracts	—			98			—			98
	Total derivative instruments	$	—		$	81,222		$	566		$	81,788
	Liabilities:
	Commodity price derivative contracts	$	—		$	(8,208	)	$	—		$	(8,208	)
	Interest rate derivative contracts	—			(6,869		)	—			(6,869		)
	Total derivative instruments	$	—		$	(15,077	)	$	—		$	(15,077	)
		31-Dec-12
		Fair Value Measurements Using									Assets/Liabilities
		Level 1			Level 2			Level 3			at Fair value
		(in thousands)
	Assets:
	Commodity price derivative contracts	$	—		$	99,904		$	—		$	99,904
	Interest rate derivative contracts	—			26			—			26
	Total derivative instruments	$	—		$	99,930		$	—		$	99,930
	Liabilities:
	Commodity price derivative contracts	$	—		$	(6,276	)	$	(498	)	$	(6,774	)
	Interest rate derivative contracts	—			(10,588		)	—			(10,588		)
	Total derivative instruments	$	—		$	(16,864	)	$	(498	)	$	(17,362	)
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3	'
	The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:
		2013			2012
		(in thousands)
	Unobservable inputs at January 1,	$	(498	)	$	—
	Total losses	(134		)	(498		)
	Settlements	1,198			—
	Unobservable inputs at December 31,	$	566		$	(498	)
	Change in fair value included in earnings related to derivatives still held as of December 31,	$	1,126		$	(498	)
	still held as of December 31, 2013

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation [Abstract]	'
Changes in Asset Retirement Obligations	'
	The asset retirement obligations as of December 31, reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the year ended December 31, were as follows:
		2013			2012
		(in thousands)
	Asset retirement obligation at January 1,	$	63,114		$	35,920
	Liabilities added during the current period	11,738			26,365
	Accretion expense	2,789			1,305
	Change in estimate	10,954			—
	Retirements	(628		)	(476		)
	Total asset retirement obligation at December 31,	87,967			63,114
	Less: current obligations	(5,759		)	(3,018		)
	Long-term asset retirement obligation at December 31,	$	82,208		$	60,096

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Schedule of gross future minimum transportation demand	'
	The values in the table below represent gross future minimum transportation demand charges we are obligated to pay as of December 31, 2013. However, our financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property.
		(in thousands)
	2014	$	12,625
	2015	8,069
	2016	5,655
	2017	4,106
	2018	3,527
	Thereafter	3,597
	Total	$	37,579

Common_Units_and_Net_Income_Lo1

Common Units and Net Income (Loss) per Unit (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Distributions Declared	'
	The following table shows the distribution amount per common and Class B unit, declared date, record date and payment date of the cash distributions we paid on each of our common and Class B units that were declared during each of the three years in the period ended December 31, 2013. 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. The payment of our distributions was changed from quarterly to monthly commencing with the July 2012 distribution.
		Cash Distributions
	Distribution	Per Unit		Declared Date	Record Date	Payment Date
	2013
	Fourth Quarter
	November	$	0.2075	December 17, 2013	January 2, 2014	January 15, 2014
	October	$	0.2075	November 19, 2013	December 2, 2013	December 13, 2013
	Third Quarter
	September	$	0.2075	October 21, 2013	November 1, 2013	November 14, 2013
	August	$	0.2075	September 12, 2013	October 1, 2013	October 15, 2013
	July	$	0.2075	August 20, 2013	September 3, 2013	September 13, 2013
	Second Quarter
	June	$	0.205	July 18, 2013	August 1, 2013	August 14, 2013
	May	$	0.205	June 20, 2013	July 1, 2013	July 15, 2013
	April	$	0.205	April 30, 2013	June 3, 2013	June 14, 2013
	First Quarter
	March	$	0.2025	April 19, 2013	May 1, 2013	May 15, 2013
	February	$	0.2025	March 21, 2013	April 1, 2013	April 12, 2013
	January	$	0.2025	February 18, 2013	March 1, 2013	March 15, 2013
	2012
	Fourth Quarter
	December	$	0.2025	January 25, 2013	February 4, 2013	February 14, 2013
	November	$	0.2025	December 19, 2012	January 2, 2013	January 14, 2013
	October	$	0.2025	November 16, 2012	December 3, 2012	December 14, 2012
	Third Quarter
	September	$	0.2	October 18, 2012	November 1, 2012	November 14, 2012
	August	$	0.2	September 17, 2012	October 1, 2012	October 15, 2012
	July	$	0.2	August 20, 2012	September 4, 2012	September 14, 2012
	Second Quarter	$	0.6	July 23, 2012	August 7, 2012	August 14, 2012
	First Quarter	$	0.5925	April 24, 2012	May 8, 2012	May 15, 2012
	2011
	Fourth Quarter	$	0.5875	January 18, 2012	February 7, 2012	February 14, 2012
	Third Quarter	$	0.5775	October 27, 2011	November 7, 2011	November 14, 2011
	Second Quarter	$	0.575	July 26, 2011	August 5, 2011	August 12, 2011
	First Quarter	$	0.57	April 28, 2011	May 6, 2011	May 13, 2011
	2010
	Fourth Quarter	$	0.56	January 27, 2011	February 7, 2011	February 14, 2011

UnitBased_Compensation_Tables

Unit-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Summary of the status of the non-vested units	'
	As of December 31, 2013, a summary of the status of the non-vested units under the VNR LTIP is presented below:
		Number of		Weighted Average
		Non-vested Restricted Units		Grant Date Fair Value
	Non-vested units at December 31, 2012	289,813		$	27.97
	Granted	89,500		$	28.7
	Forfeited	(6,507	)	$	29.07
	Vested	(124,195	)	$	27.24
	Non-vested units at December 31, 2013	248,611		$	28.57

Description_of_the_Business_De

Description of the Business (Details) (USD $)	0 Months Ended	12 Months Ended	0 Months Ended
	Jun. 28, 2013	Dec. 31, 2013	Dec. 02, 2011	Dec. 31, 2010
		operating_areas	ENP Acquisition [Member]	ENP Acquisition [Member]
Accounting Policies [Abstract]	'	'	'	'
Number of operating areas	'	8	'	'
Non-controlling Interest [Abstract]	'	'	'	'
Effective date of acquisition	'	'	'	31-Dec-10
Partners' Capital Account, Units, Acquisitions	'	'	'	20,924,055
Aggregate equity interest in ENP at the date of ENP Purchase (in hundredths)	'	'	'	46.70%
Cash paid for acquisition	'	'	'	$300,000,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	'	'	18,400,000	3,137,255
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable	29,900,000	'	511,400,000	93,000,000
Business Acquisition, Percentage of Voting Interests Acquired	'	'	53.40%	'
Number of 100% owned subsidiaries involved in merger	'	'	1	'
VNR common units received in exchange for each ENP common unit (in units)	'	'	$0.75	'

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Oil and Natural Gas Properties) (Details) (USD $)	3 Months Ended		12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	'	'	$0	$247,722	$0
Average price of natural gas used in the impairment calculation (per MMBTU)	2.76	2.77	'	'	'
Average price of crude oil used in the impairment calculation (per barrel)	94.67	95.26	'	'	'

Summary_of_Significant_Account4

Summary of Significant Accounting Policies (Other Intangible Assets) (Details) (Contract [Member], USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Estimated aggregate amortization expense for each of the next five fiscal years	'
2014	$0.20
2015	0.2
2016	0.2
2017	0.2
2018	0.2
Other assets [Member]	'
Other Intangible Assets	'
Net carrying value of contract	$8.50

Summary_of_Significant_Account5

Summary of Significant Accounting Policies (Concentrations of Credit Risk) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenue, Major Purchasers	'	'	'
Concentration Risk, Number of Financial Institutions	1	1	'
Customer Concentration Risk [Member] | Sales [Member] | Marathon Oil Company [Member]	'	'	'
Revenue, Major Purchasers	'	'	'
Major purchasers, percent of sales	14.00%	21.00%	22.00%
Customer Concentration Risk [Member] | Sales [Member] | Plains Marketing L.P. [Member]	'	'	'
Revenue, Major Purchasers	'	'	'
Major purchasers, percent of sales	10.00%	15.00%	11.00%

Summary_of_Significant_Account6

Summary of Significant Accounting Policies (Income Taxes) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revised Texas Franchise Tax	'	'	'
Amount tax basis of net assets exceeds net book basis	$168.50	$92.20	'
Texas [Member]	'	'	'
Revised Texas Franchise Tax	'	'	'
Current tax liability	-0.3	-0.5	'
Deferred tax liability	-0.4	'	'
Deferred tax asset	'	0.3	'
Tax provisions	$0.60	$0.20	$0.60

Acquisitions_and_Divestiture_D

Acquisitions and Divestiture (Details) (USD $)

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

Jun. 28, 2013

Mar. 30, 2012

Dec. 31, 2012

Dec. 31, 2013

Jun. 28, 2013

Apr. 02, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jun. 30, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 02, 2011

Dec. 31, 2010

Other Acquistions [Member]

Other Acquistions [Member]

Other Acquistions [Member]

Other Acquistions [Member]

Other Acquistions [Member]

Arkoma Basin Acquisition [Member]

Rockies Acquisition [Member]

Other smaller acquisitions [Member]

ENP Acquisition [Member]

ENP Acquisition [Member]

Business Acquisition [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Date definitive agreement entered

'

'

'

'

'

'

'

'

'

1-Jun-12

31-Oct-12

'

'

'

Purchase price of acquired entity

'

'

'

'

'

$266,200,000

$298,657,000

$24,800,000

$203,000,000

$428,541,000

$324,650,000

$2,500,000

'

'

Value of derivatives assumed

'

'

'

'

'

'

'

'

'

109,495,000

'

'

'

'

Coverage period of estimated natural gas production by assumed natural gas swaps (in years)

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

Gain on acquisition

'

'

'

'

'

'

5,591,000

6,000,000

'

14,126,000

'

'

'

'

Effective date of acquisition

'

'

'

'

1-Jul-13

1-Jan-13

'

'

'

1-Apr-12

1-Oct-12

'

'

31-Dec-10

Purchase price of acquired entity paid in common equity

29,900,000

'

'

'

'

'

'

'

'

'

'

'

511,400,000

93,000,000

Number of shares issued

'

'

'

'

1,075,000

'

'

'

'

'

'

'

18,400,000

3,137,255

Shares issued, agreed share price

'

'

'

'

$27.65

'

'

'

'

'

'

'

'

'

Shares issued, closing price

'

'

'

'

$27.90

'

'

'

'

'

'

'

'

'

Working interest 2013

'

'

'

'

'

'

'

'

'

'

18.00%

'

'

'

Working interest 2014

'

'

'

'

'

'

'

'

'

'

21.00%

'

'

'

Working interest 2015

'

'

'

'

'

'

'

'

'

'

24.00%

'

'

'

Working interest 2016

'

'

'

'

'

'

'

'

'

'

26.00%

'

'

'

Goodwill

'

'

420,955,000

420,955,000

'

'

'

'

'

'

8,818,000

'

'

420,955,000

Partners' Capital Account, Units, Converted

'

1,900,000

'

'

'

'

'

'

'

'

'

'

'

'

Closing price of common unit (in dollars per unit)

'

$27.62

'

'

'

'

'

'

'

'

'

'

'

'

Issuance of Common units

'

52,480,000

-52,480,000

'

'

'

'

'

'

'

'

'

'

'

Noncash Consideration After Closing Adjustments

'

52,500,000

'

'

'

'

'

'

'

'

'

'

'

'

Closing Adjustment Under Unit Exchange Agreement

'

$1,400,000

'

'

'

'

'

'

'

'

'

'

'

'

Acquisitions_and_Divestiture_A

Acquisitions and Divestiture (Aggregate Values Assigned to Net Assets Acquired) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2010	Jun. 30, 2012	Dec. 31, 2012	Apr. 02, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified			ENP Acquisition [Member]	Arkoma Basin Acquisition [Member]	Rockies Acquisition [Member]	Other Acquistions [Member]	Other Acquistions [Member]	Other Acquistions [Member]	Other Acquistions [Member]
Fair value of assets and liabilities acquired:	'	'	'	'	'	'	'	'	'
Oil and natural gas properties	'	'	'	$344,747	$330,707	'	$317,573	'	'
Value of derivatives assumed	'	'	'	109,495	'	'	'	'	'
Other assets	'	'	'	'	929	'	899	'	'
Asset retirement obligations	'	'	'	-8,922	-15,763	'	-11,381	'	'
Oil and natural gas revenue payable and imbalance liabilities	'	'	'	-2,653	-41	'	-2,843	'	'
Total fair value of assets and liabilities acquired	'	'	'	442,667	315,832	'	304,248	'	'
Fair value of consideration transferred	'	'	'	-428,541	-324,650	-266,200	-298,657	-24,800	-203,000
Gain on acquisition	'	'	'	14,126	'	'	5,591	6,000	'
Loss on acquisition	($420,955)	($420,955)	($420,955)	'	($8,818)	'	'	'	'

Acquisitions_and_Divestiture_E

Acquisitions and Divestiture (ENP Acquisition) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 02, 2011	Dec. 31, 2010
			ENP Acquisition [Member]	ENP Acquisition [Member]
Business Acquisition [Line Items]	'	'	'	'
Consideration transferred	'	'	'	$941,700,000
Goodwill	420,955,000	420,955,000	'	420,955,000
Net assets acquired and liabilities assumed	'	'	16,000,000	'
Carrying amount of noncontrolling interest	'	'	$527,300,000	'

Acquisitions_and_Divestiture_P

Acquisitions and Divestiture (Pro Forma) (Details) (USD $)	0 Months Ended	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 30, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]	'	'	'	'
Partners' Capital Account, Units, Converted	1,900	'	'	'
Pro Forma Information	'	'	'	'
Total revenues	'	$470,834	$557,802	$676,685
Net income (loss)	'	54,158	-174,187	146,783
Net income (loss) available to Common and Class B unitholders, per unit:	'	'	'	'
Business Acquisition, Pro Forma Earnings Per Share, Basic	'	$0.70	($3.18)	$3.14
Business Acquisition, Pro Forma Earnings Per Share, Diluted	'	$0.69	($3.18)	$3.14
Unit Exchange [Member]	'	'	'	'
Pro Forma Information	'	'	'	'
Total revenues	'	'	3,267	20,017
Net income (loss)	'	'	($400)	$6,041

Acquisitions_and_Divestiture_A1

Acquisitions and Divestiture (Acquiree Earnings) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Arkoma Basin Acquisition [Member]	'	'	'
Business Acquisition [Line Items]	'	'	'
Revenues	$55,468	$24,673	$0
Excess of revenues over direct operating expenses	45,090	19,971	0
Rockies Acquisition [Member]	'	'	'
Business Acquisition [Line Items]	'	'	'
Revenues	63,652	220	0
Excess of revenues over direct operating expenses	41,583	164	0
Other Acquistions [Member]	'	'	'
Business Acquisition [Line Items]	'	'	'
Revenues	80,349	38,366	18,298
Excess of revenues over direct operating expenses	$49,025	$21,626	$11,572

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)	12 Months Ended			12 Months Ended				12 Months Ended
	Dec. 31, 2013	Nov. 05, 2013	Dec. 31, 2012	Dec. 31, 2013	Apr. 17, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012
				Line of Credit [Member]	Line of Credit [Member]	Line of Credit [Member]	Line of Credit [Member]	Senior Notes [Member]	Senior Notes [Member]
							Standby Letters of Credit [Member]
Debt Instrument [Line Items]	'	'	'	'	'	'	'	'	'
Maximum facility size	'	'	'	$1,500,000,000	'	'	'	'	'
Borrowing base	'	'	'	1,300,000,000	1,200,000,000	'	1,800,000	'	'
Maturity date	'	'	'	16-Apr-18	'	'	'	1-Apr-20	'
Number of lenders added by amendment	'	2	'	'	'	'	'	'	'
Debt amount outstanding	1,010,000,000	'	1,250,000,000	460,000,000	'	700,000,000	'	550,000,000	550,000,000
Remaining borrowing capacity	'	'	'	838,200,000	'	'	'	'	'
Maximum line of credit utilization	'	'	'	1,200,000,000	'	'	'	'	'
Line of Credit Facility, Potential Increase in Borrowing Capacity	'	'	'	100,000,000	'	'	'	'	'
Senior Notes [Abstract]	'	'	'	'	'	'	'	'	'
Percentage of ownership (in hundredths)	100.00%	'	'	'	'	'	'	'	'
Stated interest rate (in hundredths)	'	'	'	'	'	'	'	7.88%	'
Authorized distribution to unitholders	'	'	'	$286,800,000	'	'	'	'	'
Redemption price of aggregate principal amount of senior notes on or after April 1, 2016 (in hundredths)	'	'	'	'	'	'	'	103.94%	'
Redemption price of aggregate principal amount of senior notes on April 1, 2018 and thereafter (in hundredths)	'	'	'	'	'	'	'	100.00%	'
Redemption price of aggregate principal amount of senior notes at any time prior to April 1, 2016 (in hundredths)	'	'	'	'	'	'	'	100.00%	'
Percentage of aggregate principal amount of senior notes that can be redeemed (in hundredths)	'	'	'	'	'	'	'	35.00%	'
Redemption price of aggregate principal amount of senior notes before April 1, 2015 (in hundredths)	'	'	'	'	'	'	'	107.88%	'
Percentage of aggregate principal amount of senior notes remained outstanding (in hundredths)	'	'	'	'	'	'	'	65.00%	'
Period of redemption of senior notes within equity offering (in days)	'	'	'	'	'	'	'	'180 days	'
Required repurchase price of aggregate principal amount of senior notes, lower range (in hundredths)	'	'	'	'	'	'	'	100.00%	'
Required repurchase price of aggregate principal amount of senior notes, upper range (in hundredths)	'	'	'	'	'	'	'	101.00%	'

LongTerm_Debt_Financing_Arrang

Long-Term Debt (Financing Arrangements) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]	'	'
Debt amount outstanding	$1,010,000	$1,250,000
Unamortized discount on Senior Notes	-2,121	-2,369
Total debt	1,007,879	1,247,631
Line of Credit [Member]	'	'
Debt Instrument [Line Items]	'	'
Interest rate description	'Variable (1)	'
Maturity date	16-Apr-18	'
Debt amount outstanding	460,000	700,000
Variable interest rate (in hundredths)	1.92%	2.22%
Senior Notes [Member]	'	'
Debt Instrument [Line Items]	'	'
Stated interest rate (in hundredths)	7.88%	'
Maturity date	1-Apr-20	'
Debt amount outstanding	$550,000	$550,000
Effective interest rate (in hundredths)	8.00%	'

LongTerm_Debt_Borrowing_Base_U

Long-Term Debt (Borrowing Base Utilization Grid) (Details)	12 Months Ended
	Dec. 31, 2013
Borrowing Base Utilization Less Than 25% [Member]	'
Debt Instrument [Line Items]	'
Commitment fee rate (in hundredths)	0.50%
Letter of credit fee (in hundredths)	0.50%
Borrowing Base Utilization Less Than 25% [Member] | Eurodollar Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	1.50%
Borrowing Base Utilization Less Than 25% [Member] | ABR Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	0.50%
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50% [Member]	'
Debt Instrument [Line Items]	'
Commitment fee rate (in hundredths)	0.50%
Letter of credit fee (in hundredths)	0.75%
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50% [Member] | Eurodollar Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	1.75%
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50% [Member] | ABR Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	0.75%
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75% [Member]	'
Debt Instrument [Line Items]	'
Commitment fee rate (in hundredths)	0.38%
Letter of credit fee (in hundredths)	1.00%
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75% [Member] | Eurodollar Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	2.00%
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75% [Member] | ABR Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	1.00%
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90% [Member]	'
Debt Instrument [Line Items]	'
Commitment fee rate (in hundredths)	0.38%
Letter of credit fee (in hundredths)	1.25%
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90% [Member] | Eurodollar Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	2.25%
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90% [Member] | ABR Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	1.25%
Borrowing Base Utilization Equal To Or Greater Than 90% [Member]	'
Debt Instrument [Line Items]	'
Commitment fee rate (in hundredths)	0.38%
Letter of credit fee (in hundredths)	1.50%
Borrowing Base Utilization Equal To Or Greater Than 90% [Member] | Eurodollar Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	2.50%
Borrowing Base Utilization Equal To Or Greater Than 90% [Member] | ABR Loans Margin [Member]	'
Debt Instrument [Line Items]	'
Loans margin (in hundredths)	1.50%

Price_and_Interest_Rate_Risk_M2

Price and Interest Rate Risk Management Activities (Derivative Contracts Covering Aniticipated Future Production) (Details)	12 Months Ended
	Dec. 31, 2013
	bbl
Fixed-Price Swaps [Member] | Natural Gas [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	47,885,225
Weighted average price of derivative (in dollars per unit)	4.51
Fixed-Price Swaps [Member] | Natural Gas [Member] | January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	53,107,500
Weighted average price of derivative (in dollars per unit)	4.46
Fixed-Price Swaps [Member] | Natural Gas [Member] | January 1, 2016 - December 31, 2016 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	49,593,000
Weighted average price of derivative (in dollars per unit)	4.5
Fixed-Price Swaps [Member] | Natural Gas [Member] | January 1, 2017 - December 31, 2017 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	22,202,000
Weighted average price of derivative (in dollars per unit)	4.34
Fixed-Price Swaps [Member] | Oil [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Weighted average price of derivative (in dollars per unit)	90.59
Anticipated future oil production (in units)	1,815,875
Fixed-Price Swaps [Member] | Oil [Member] | January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Weighted average price of derivative (in dollars per unit)	91.18
Anticipated future oil production (in units)	692,000
Fixed-Price Swaps [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Weighted average price of derivative (in dollars per unit)	89.98
Anticipated future oil production (in units)	146,400
Fixed-Price Swaps [Member] | Oil [Member] | January 1, 2017 - December 31, 2017 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Weighted average price of derivative (in dollars per unit)	86.6
Anticipated future oil production (in units)	73,000
Fixed-Price Swaps [Member] | Natural Gas Liquids [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Weighted average price of derivative (in dollars per unit)	40.87
Anticipated future oil production (in units)	273,750
Fixed-Price Swaps [Member] | Natural Gas Liquids [Member] | January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Weighted average price of derivative (in dollars per unit)	42
Anticipated future oil production (in units)	91,250
Fixed-Price Swaps [Member] | Natural Gas Liquids [Member] | January 1, 2016 - December 31, 2016 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Weighted average price of derivative (in dollars per unit)	0
Anticipated future oil production (in units)	0
Fixed-Price Swaps [Member] | Natural Gas Liquids [Member] | January 1, 2017 - December 31, 2017 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Weighted average price of derivative (in dollars per unit)	0
Anticipated future oil production (in units)	0
Swaptions [Member] | Oil [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Weighted average price of derivative (in dollars per unit)	117.22
Anticipated future oil production (in units)	492,750
Swaptions [Member] | Oil [Member] | January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Weighted average price of derivative (in dollars per unit)	105.98
Anticipated future oil production (in units)	508,445
Swaptions [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Weighted average price of derivative (in dollars per unit)	125
Anticipated future oil production (in units)	622,200
Collars [Member] | Oil [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	12,000
Floor (in dollars per unit)	100
Ceiling (in dollars per unit)	116.2
Three-Way Collars [Member] | Oil [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	1,313,850
Floor (in dollars per unit)	93.47
Ceiling (in dollars per unit)	101.25
Derivative, Average Price Risk Option Strike Price	72.57
Three-Way Collars [Member] | Oil [Member] | January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	924,055
Floor (in dollars per unit)	92.1
Ceiling (in dollars per unit)	101.54
Derivative, Average Price Risk Option Strike Price	72.04
Three-Way Collars [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	549,000
Floor (in dollars per unit)	90
Ceiling (in dollars per unit)	95
Derivative, Average Price Risk Option Strike Price	70
Put Option [Member] | Oil [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	73,000
Derivative, Average Price Risk Option Strike Price	75
Put Option [Member] | Oil [Member] | January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	692,000
Derivative, Average Price Risk Option Strike Price	72.36
Put Option [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	146,400
Derivative, Average Price Risk Option Strike Price	75
Put Option [Member] | Oil [Member] | January 1, 2017 - December 31, 2017 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	73,000
Derivative, Average Price Risk Option Strike Price	75
Put Spreads [Member] | Oil [Member] | January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	255,500
Floor (in dollars per unit)	100
Derivative, Average Price Risk Option Strike Price	75
Range Bonus Accumulators [Member] | Natural Gas [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Notional Volume (Bbls)	1,460,000
Bonus (in dollars per unit)	0.2
Derivative, Average Cap Price	4.75
Derivative, Average Floor Price	3.25
Range Bonus Accumulators [Member] | Natural Gas [Member] | January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Notional Volume (Bbls)	1,460,000
Bonus (in dollars per unit)	0.2
Derivative, Average Cap Price	4.75
Derivative, Average Floor Price	3.25
Range Bonus Accumulators [Member] | Oil [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Notional Volume (Bbls)	912,500
Bonus (in dollars per unit)	4.94
Derivative, Average Cap Price	103.2
Derivative, Average Floor Price	70.5
NW Rocky Mt-Henry Hub Index [Member] | Basis Swaps [Member] | Natural Gas [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	11,845,000
Weighted average basis differential (in dollars per unit)	-0.21
NW Rocky Mt-Henry Hub Index [Member] | Basis Swaps [Member] | Natural Gas [Member] | January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	12,775,000
Weighted average basis differential (in dollars per unit)	-0.29
NYMEX-Henry Hub Index [Member] | Basis Swaps [Member] | Natural Gas [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future gas production (in units)	452,500
Weighted average basis differential (in dollars per unit)	-0.32
Midland-Cushing Index [Member] | Basis Swaps [Member] | Oil [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	584,000
Weighted average basis differential (in dollars per unit)	-0.84
Midland-Cushing Index [Member] | Basis Swaps [Member] | Oil [Member] | January 1, 2015 - December 31, 2015 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	365,000
Weighted average basis differential (in dollars per unit)	-0.9
Midland-WTS Index [Member] | Basis Swaps [Member] | Oil [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	328,500
Weighted average basis differential (in dollars per unit)	-1.05
LLS-Brent Index [Member] | Basis Swaps [Member] | Oil [Member] | January 1, 2014 - December 31, 2014 [Member]	'
Commodity derivative contracts covering our anticipated future production [Abstract]	'
Anticipated future oil production (in units)	182,500
Weighted average basis differential (in dollars per unit)	-3.95

Price_and_Interest_Rate_Risk_M3

Price and Interest Rate Risk Management Activities (Interest Rate Swaps) (Details) (Interest rate swaps [Member], USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative [Line Items]	'
Notional amount	$360,000
January 1, 2014 to December 10, 2016 [Member]	'
Derivative [Line Items]	'
Notional amount	20,000
Fixed Libor Rates (in hundredths)	2.17%
January 1, 2014 to October 31, 2016 Swap A [Member]	'
Derivative [Line Items]	'
Notional amount	40,000
Fixed Libor Rates (in hundredths)	1.65%
January 1, 2014 to August 5, 2015 [Member]	'
Derivative [Line Items]	'
Notional amount	30,000
Fixed Libor Rates (in hundredths)	2.25%
January 1, 2014 to August 6, 2016 [Member]	'
Derivative [Line Items]	'
Notional amount	25,000
Fixed Libor Rates (in hundredths)	1.80%
January 1, 2014 to October 31, 2016 Swap B [Member]	'
Derivative [Line Items]	'
Notional amount	20,000
Fixed Libor Rates (in hundredths)	1.78%
January 1, 2014 to September 23, 2016 [Member]	'
Derivative [Line Items]	'
Notional amount	75,000
Fixed Libor Rates (in hundredths)	1.15%
January 1, 2014 to March 7, 2016 [Member]	'
Derivative [Line Items]	'
Notional amount	75,000
Fixed Libor Rates (in hundredths)	1.08%
January 1, 2014 to September 7, 2016 [Member]	'
Derivative [Line Items]	'
Notional amount	25,000
Fixed Libor Rates (in hundredths)	1.25%
January 1, 2014 to December 10, 2015 [Member]	'
Derivative [Line Items]	'
Notional amount	$50,000	[1]
Fixed Libor Rates (in hundredths)	0.21%	[1]
December 10, 2015 - December 10, 2017 [Member]	'
Derivative [Line Items]	'
Fixed Libor Rates (in hundredths)	0.91%
[1]	The counterparty has the option to require Vanguard to pay a fixed rate of 0.91% from December 10, 2015 to December 10, 2017.

Price_and_Interest_Rate_Risk_M4

Price and Interest Rate Risk Management Activities (Balance Sheet Presentation) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	$107,405	$135,037
Derivative Asset, Fair Value, Gross Liability	-25,617	-35,107
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	81,788	99,930
Derivative Liability, Fair Value, Gross Liability	-40,694	-52,469
Derivative Liability, Fair Value, Gross Asset	25,617	35,107
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-15,077	-17,362
Commodity Contract [Member]	'	'
Derivative [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	107,307	134,905
Derivative Asset, Fair Value, Gross Liability	-25,617	-35,001
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	81,690	99,904
Derivative Liability, Fair Value, Gross Liability	-33,825	-41,775
Derivative Liability, Fair Value, Gross Asset	25,617	35,001
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-8,208	-6,774
Interest Rate Contract [Member]	'	'
Derivative [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	98	132
Derivative Asset, Fair Value, Gross Liability	0	-106
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	98	26
Derivative Liability, Fair Value, Gross Liability	-6,869	-10,694
Derivative Liability, Fair Value, Gross Asset	0	106
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	($6,869)	($10,588)

Price_and_Interest_Rate_Risk_M5

Price and Interest Rate Risk Management Activities Price and Interest Rate Risk Management Activities (Additional Disclosures) (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Maximum potential loss due to credit risk	$107.40

Price_and_Interest_Rate_Risk_M6

Price and Interest Rate Risk Management Activities Price and Interest Rate Risk Management Activities (Change in Fair Value of Derivatives) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Net Derivative Asset (Liability), Reconciliation [Roll Forward]	'	'	'
Derivative asset/(liability) at beginning of year, net	$82,568	($29,889)	($18,591)
Fair value of derivative contracts acquired through business combinations	0	109,495	0
Premiums and fees paid or deferred for derivative contracts during the period	0	9,695	-257
Net (gains) losses on commodity and interest rate derivative contracts	11,160	29,854	1,773
Cash settlements received on matured commodity derivative contracts	-30,905	-39,102	-18,720
Cash settlements paid on matured interest rate derivative contracts	3,888	2,515	2,874
Change in other comprehensive income	'	'	3,032
Derivative asset/(liability) at end of year, net	$66,711	$82,568	($29,889)

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Debt Instrument, Fair Value Disclosure	$583,000,000	'
Liabilities:	'	'
Asset retirement obligations incurred during the current period	11,738,000	26,365,000
Asset Retirement Obligation, Revision of Estimate	10,954,000	0
Average inflation rate (in hundredths)	2.40%	'
Minimum [Member]	'	'
Liabilities:	'	'
Credit-adjusted risk-free interest rate (in hundredths)	4.85%	'
Maximum [Member]	'	'
Liabilities:	'	'
Credit-adjusted risk-free interest rate (in hundredths)	5.71%	'
Fair Value Measured on a Recurring Basis [Member]	'	'
Assets:	'	'
Commodity price derivative contracts	81,690,000	99,904,000
Interest rate derivative contracts	98,000	26,000
Total derivative instruments	81,788,000	99,930,000
Liabilities:	'	'
Commodity price derivative contracts	-8,208,000	-6,774,000
Interest rate derivative contracts	-6,869,000	-10,588,000
Total derivative instruments	-15,077,000	-17,362,000
Fair Value Measured on a Recurring Basis [Member] | Fair Value Measurements Using Level 1 [Member]	'	'
Assets:	'	'
Commodity price derivative contracts	0	0
Interest rate derivative contracts	0	0
Total derivative instruments	0	0
Liabilities:	'	'
Commodity price derivative contracts	0	0
Interest rate derivative contracts	0	0
Total derivative instruments	0	0
Fair Value Measured on a Recurring Basis [Member] | Fair Value Measurements Using Level 2 [Member]	'	'
Assets:	'	'
Commodity price derivative contracts	81,124,000	99,904,000
Interest rate derivative contracts	98,000	26,000
Total derivative instruments	81,222,000	99,930,000
Liabilities:	'	'
Commodity price derivative contracts	-8,208,000	-6,276,000
Interest rate derivative contracts	-6,869,000	-10,588,000
Total derivative instruments	-15,077,000	-16,864,000
Fair Value Measured on a Recurring Basis [Member] | Fair Value, Inputs, Level 3 [Member]	'	'
Assets:	'	'
Commodity price derivative contracts	566,000	0
Interest rate derivative contracts	0	0
Total derivative instruments	566,000	0
Liabilities:	'	'
Commodity price derivative contracts	0	-498,000
Interest rate derivative contracts	0	0
Total derivative instruments	$0	($498,000)

Fair_Value_Measurements_Fair_V

Fair Value Measurements Fair Value Measurements - Unobservable Inputs Reconciliation (Details) (Details) (Fair Value, Inputs, Level 3 [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Inputs, Level 3 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]	'	'
Unobservable inputs at beginning of year	($498)	$0
Total losses	-134	-498
Settlements	1,198	0
Unobservable inputs at end of year	566	-498
Change in fair value included in earnings related to derivatives still held as of end of year	$1,126	($498)

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in asset retirement obligations [Abstract]	'	'	'
Asset retirement obligation at January 1,	$63,114	$35,920	'
Liabilities added during the current period	11,738	26,365	'
Accretion expense	2,789	1,305	900
Asset Retirement Obligation, Revision of Estimate	10,954	0	'
Retirements	-628	-476	'
Total asset retirement obligation at December 31,	87,967	63,114	35,920
Less: current obligations	-5,759	-3,018	'
Long-term asset retirement obligation at December 31,	$82,208	$60,096	'

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	0 Months Ended		1 Months Ended	12 Months Ended				0 Months Ended			12 Months Ended
Share data in Thousands, except Per Share data, unless otherwise specified	Mar. 30, 2012	Apr. 02, 2011	Jun. 30, 2010	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2011	Apr. 02, 2011	Dec. 31, 2010	Dec. 31, 2010	Dec. 31, 2011
							COPAS [Member]	ENP Group [Member]	ENP Group [Member]	ENP Group [Member]	ENP Group [Member]
Related Party Transaction [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Partners' Capital Account, Units, Converted	1,900	'	'	'	'	'	'	'	'	'	'
Closing price of common unit (in dollars per unit)	$27.62	'	'	'	'	'	'	'	'	'	'
Issuance of Common units	$52,480,000	'	'	'	($52,480,000)	'	'	'	'	'	'
Noncash consideration after closing adjustments	52,500,000	'	'	'	'	'	'	'	'	'	'
Closing adjustment under unit exchange agreement	1,400,000	'	'	'	'	'	'	'	'	'	'
Monthly operating cost per well (in dollars per well)	'	'	'	60	'	'	'	'	'	'	'
Transportation fee on new wells (in dollars per mcf)	'	'	'	0.55	'	'	'	'	'	'	'
Transportation fee charged above actual cost under amended agreement (in dollars per mcf)	'	'	0.055	'	'	'	'	'	'	'	'
Cost incurred under MSA	'	'	'	'	600,000	1,900,000	'	'	'	'	'
Cost incurred under GCA	'	'	'	'	400,000	1,800,000	'	'	'	'	'
Quarterly fee (per BOE) of ENP Group's total net oil and gas production	'	'	'	'	'	'	'	2.05	2.06	2.06	'
Decrease in Wage Index Adjustment	'	0.70%	'	'	'	'	'	'	'	'	'
Administrative fees received	'	'	'	'	'	'	'	'	'	'	6,100,000
Other reimbursements from related parties	'	'	'	'	'	'	$5,100,000	'	'	'	$5,800,000

Commitments_and_Contingencies_1

Commitments and Contingencies (Transportation Demand Charges) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Gross future minimum transportation demand	'
2014	12,625
2015	8,069
2016	5,655
2017	4,106
2018	3,527
Thereafter	3,597
Total	37,579
Minimum [Member]	'
Oil and Gas Delivery Commitments and Contracts	'
Remaining term of contracts	'1 year
Maximum [Member]	'
Oil and Gas Delivery Commitments and Contracts	'
Remaining term of contracts	'6 years

Common_Units_and_Net_Income_Lo2

Common Units and Net Income (Loss) per Unit (Cash Distributions) (Details) (USD $)

0 Months Ended

12 Months Ended

1 Months Ended

3 Months Ended

Jul. 15, 2013

Dec. 31, 2013

Nov. 30, 2013

Oct. 31, 2013

Sep. 30, 2013

Aug. 31, 2013

Jul. 31, 2013

Jun. 30, 2013

31-May-13

Apr. 30, 2013

Mar. 31, 2013

Feb. 28, 2013

Jan. 31, 2013

Dec. 31, 2012

Nov. 30, 2012

Oct. 31, 2012

Sep. 30, 2012

Aug. 31, 2012

Jul. 31, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2010

Series A Preferred Stock [Member]

Series A Preferred Stock [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Preferred Unit, Distribution Rate, Per-Dollar-Amount

$0.14

$0.16

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred Unit, Distribution Rate, Percentage

'

7.88%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred Unit, Redemption Price Per Share

'

$25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Distributions Declared [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash Distributions Per Unit (in dollars per share)

'

'

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.20

$0.20

$0.20

$0.20

$0.20

$0.20

$0.20

$0.20

$0.20

$0.60

$0.59

$0.59

$0.58

$0.57

$0.57

$0.56

Cash Distributions Declared Date

'

'

17-Dec-13

19-Nov-13

21-Oct-13

12-Sep-13

20-Aug-13

18-Jul-13

20-Jun-13

30-Apr-13

19-Apr-13

21-Mar-13

18-Feb-13

25-Jan-13

19-Dec-12

16-Nov-12

18-Oct-12

17-Sep-12

20-Aug-12

23-Jul-12

24-Apr-12

18-Jan-12

27-Oct-11

26-Jul-11

28-Apr-11

27-Jan-11

Cash Distributions Record Date

'

'

2-Jan-14

2-Dec-13

1-Nov-13

1-Oct-13

3-Sep-13

1-Aug-13

1-Jul-13

3-Jun-13

1-May-13

1-Apr-13

1-Mar-13

4-Feb-13

2-Jan-13

3-Dec-12

1-Nov-12

1-Oct-12

4-Sep-12

7-Aug-12

8-May-12

7-Feb-12

7-Nov-11

5-Aug-11

6-May-11

7-Feb-11

Cash Distributions Payment Date

'

'

15-Jan-14

13-Dec-13

14-Nov-13

15-Oct-13

13-Sep-13

14-Aug-13

15-Jul-13

14-Jun-13

15-May-13

12-Apr-13

15-Mar-13

14-Feb-13

14-Jan-13

14-Dec-12

14-Nov-12

15-Oct-12

14-Sep-12

14-Aug-12

15-May-12

14-Feb-12

14-Nov-11

12-Aug-11

13-May-11

14-Feb-11

Common_Units_and_Net_Income_Lo3

Common Units and Net Income (Loss) per Unit (Antidilutive Securities) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012
	class		Phantom Share Units (PSUs) [Member]	Phantom Share Units (PSUs) [Member]	Phantom Share Units (PSUs) [Member]	Options [Member]
Antidilutive securities	'	'	'	'	'	'
Number of class of units outstanding	3	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures	562,384	'	'	'	'	175,000
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	'	'	522,500	85,000	'	'
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	'	'	'	'	347,826	'
Options exercised (in units)	'	175,000	'	'	'	'

UnitBased_Compensation_Details

Unit-Based Compensation (Details) (USD $)

0 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

11 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

Nov. 15, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Aug. 02, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Oct. 31, 2012

Oct. 31, 2007

Dec. 31, 2013

Dec. 31, 2012

Aug. 02, 2012

Sep. 30, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Nov. 30, 2011

Dec. 02, 2011

Nov. 15, 2013

Nov. 15, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 02, 2011

Dec. 02, 2011

Executive - C [Member]

Board Member [Member]

Executive - B [Member]

Executive A [Member]

Executive [Member]

Restricted Stock Units (RSUs) [Member]

Phantom Share Units (PSUs) [Member]

Phantom Share Units (PSUs) [Member]

Phantom Share Units (PSUs) [Member]

VNR LTIP [Member]

VNR LTIP [Member]

VNR LTIP [Member]

VNR LTIP [Member]

VNR LTIP [Member]

VNR LTIP [Member]

Amended Agreements [Member]

Amended Agreements [Member]

Amended Agreements [Member]

ENP LTIP [Member]

ENP LTIP [Member]

Retention Grant [Member]

Retention Grant [Member]

Selling, General and Administrative Expenses [Member]

Selling, General and Administrative Expenses [Member]

Selling, General and Administrative Expenses [Member]

Selling, General and Administrative Expenses [Member]

Selling, General and Administrative Expenses [Member]

Selling, General and Administrative Expenses [Member]

ENP Acquisition [Member]

ENP Acquisition [Member]

board_member

board_member

Board Member [Member]

Employee [Member]

officer

multipiler

Board Member [Member]

First Officer [Member]

agreement

Restricted Stock Units (RSUs) [Member]

Phantom Share Units (PSUs) [Member]

Restricted Stock Units (RSUs) [Member]

Restricted Stock Units (RSUs) [Member]

Phantom Share Units (PSUs) [Member]

Phantom Share Units (PSUs) [Member]

Phantom Share Units (PSUs) [Member]

ENP LTIP [Member]

installment

officer

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of officers under compensation plan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of units options granted under VNR LTIP (in units)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

175,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Exercise price of units under VNR LTIP (in dollars per unit)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$19

'

'

'

$19

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Additional compensation expense

'

'

'

'

'

'

'

'

'

'

'

'

'

$1,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Grant date fair value of vested units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Options expiration date

'

'

'

'

'

'

'

'

'

'

'

'

'

'

29-Oct-12

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Volatility rate (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12.18%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected dividend Yield (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8.95%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Discount rate (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.12%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of days historical volatility index

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'365 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Options exercised (in units)

'

'

175,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of executives in amended agreements

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of times executive annual base salary may not be exceeded by maximum payout

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

390,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Phantom units granted, numbers of executives

'

'

'

'

'

4

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Vesting period

'

'

'

'

'

'

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'3 years

'3 years

'

'

'

'3 years

'

'

'

'

'

'

'

'

Number of company performance elements related to annual bonus

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Ratio of aggregate restricted units that will vest on each one-year anniversary

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

33.33%

33.33%

'

'

'

'

'

'

'

'

'

'

'

'

Accrued liability

'

'

'

'

'

'

'

'

'

'

1,300,000

'

'

'

'

'

'

'

'

1,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-cash compensation

'

4,206,000

4,178,000

2,557,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5,900,000

5,400,000

3,000,000

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

18,684

70,104

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of annual installments

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrecognized compensation cost related to non-vested restricted units

'

'

'

'

'

'

'

'

'

5,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrecognized compensation cost recognition period (in years)

'

'

'

'

'

'

'

'

'

'1 year 11 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-vested units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

248,611

289,813

'

'

'

'

'

'

143,266

'

'

'

'

'

'

'

'

'

'

Stock Issued During Period, Shares, Acquisitions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

107,449

Exchange ratio

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.75

'

'

'

'

'

'

'

'

0.75

'

Non-cash unit-based compensation expense

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$800,000

'

'

'

'

'

'

$1,700,000

$1,200,000

$500,000

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Change in Control Payments and Benefits, Annual Salary and Bonus Multiplier

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of times executive salary may not be exceeded by the amount of compensation to be received upon termination without cause or for good reason

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Equity-based Compensation Awards, Annual Salary Multiplier

'

'

'

'

5

'

3.5

2.75

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Restricted units granted, number of executives

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Share based compensation number of restricted units granted to executives

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

87,500

'

'

'

'

'

'

'

'

'

UnitBased_Compensation_Summary

Unit-Based Compensation (Summary of Non-Vested Units) (Details) (VNR LTIP [Member], USD $)	12 Months Ended
	Dec. 31, 2013
VNR LTIP [Member]	'
Number of Non-vested Units	'
Non-vested units at beginning of year (in units)	289,813
Granted (in units)	89,500
Forfeited (in units)	-6,507
Vested (in units)	-124,195
Non-vested units at end of year (in units)	248,611
Weighted Average Grant Date Fair Value	'
Non-vested units at beginning of year (in dollars per unit)	$27.97
Granted (in dollars per unit)	$28.70
Forfeited (in dollars per unit)	$29.07
Vested (in dollars per unit)	$27.24
Non-vested units at end of year (in dollars per unit)	$28.57

Shelf_Registration_Statements_

Shelf Registration Statements (Details) (USD $)

12 Months Ended

0 Months Ended

12 Months Ended

3 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Sep. 09, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Sep. 30, 2009

Sep. 09, 2011

Jul. 31, 2010

Jan. 31, 2012

Jun. 04, 2013

Feb. 05, 2013

Jul. 31, 2013

Jun. 19, 2013

Dec. 31, 2013

Dec. 31, 2013

Series A Preferred Stock [Member]

Distribution Agreement 2011 [Member]

Distribution Agreement 2011 [Member]

Distribution Agreement 2013 [Member]

Distribution Agreement 2013 [Member]

Shelf Registration Statement 2009 [Member]

Shelf Registration Statement 2009 [Member]

Shelf Registration Statement 2010 [Member]

Shelf Registration Statement 2012 [Member]

Shelf Registration Statement 2012 [Member]

Shelf Registration Statement 2012 [Member]

Shelf Registration Statement 2012 [Member]

Shelf Registration Statement 2012 [Member]

Common Units [Member]

Series A Preferred Stock [Member]

Common Units [Member]

Series A Preferred Stock [Member]

Distribution Agreement 2011 [Member]

Primary Units [Member]

Common Units [Member]

Common Units [Member]

Common Units [Member]

Series A Preferred Stock [Member]

Distribution Agreement 2013 [Member]

Distribution Agreement 2013 [Member]

Shelf Registration Statements [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Registered offerings under registration statement

'

'

'

'

'

'

'

'

$300,000,000

'

$800,000,000

'

'

'

'

'

'

'

Net proceeds received under distribution agreement

'

'

'

'

'

'

'

'

'

'

'

'

190,900,000

246,100,000

8,900,000

'

'

'

Number of years extension of distribution agreement

'

'

'

'

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

Common units issued under public offerings (in units)

'

'

'

'

'

1,103,499

'

'

'

'

'

3,100,000

7,000,000

9,200,000

'

2,520,000

748,100

15,927

Preferred Unit, Distribution Rate, Percentage

'

'

'

7.88%

'

'

'

'

'

'

'

'

'

'

'

7.88%

'

'

Proceeds from issuance of units

'

'

'

'

'

31,500,000

'

'

'

4,000,000

'

'

'

'

'

'

21,200,000

400,000

Underwriter discount

'

'

'

'

'

'

'

'

'

'

'

'

7,400,000

10,000,000

'

2,000,000

'

'

Offering costs

0

0

2,747,000

'

'

'

'

'

'

'

'

'

100,000

100,000

'

400,000

'

'

Shares Issued, Price Per Share

'

'

'

'

'

'

'

'

'

'

'

'

$28.35

$27.85

'

$25

'

'

Units issued related to underwriter's overallotment option

'

'

'

'

'

'

'

'

'

'

'

'

'

1,200,000

325,000

320,000

'

'

Proceeds from Issuance of Preferred Limited Partners Units

61,021,000

0

0

'

'

'

'

'

'

'

'

'

'

'

'

60,600,000

'

'

Maximum offering under equity distribution agreement

'

'

'

'

$200,000,000

'

$500,000,000

$250,000,000

'

'

'

'

'

'

'

'

'

'

Subsequent_Events_Details

Subsequent Events (Details) (USD $)	Dec. 31, 2013	Feb. 26, 2014	Feb. 20, 2014	Jan. 16, 2014	Dec. 31, 2014	Dec. 31, 2013	Feb. 20, 2014	Jan. 16, 2014	Jan. 31, 2014
In Thousands, except Per Share data, unless otherwise specified		Common Units [Member]	Common Units [Member]	Common Units [Member]	Common Units [Member]	Common Units [Member]	Preferred Stock [Member]	Preferred Stock [Member]	Pinedale Acquisition [Member]
		Subsequent Event [Member]	Subsequent Event [Member]	Subsequent Event [Member]	Subsequent Event [Member]	Subsequent Event [Member]	Subsequent Event [Member]	Subsequent Event [Member]	Subsequent Event [Member]
Subsequent Event [Line Items]	'	'	'	'	'	'	'	'	'
Cash Distributions Declared Date	'	26-Feb-14	20-Feb-14	16-Jan-14	'	'	20-Feb-14	16-Jan-14	'
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit	'	$0.21	$0.21	$0.21	'	'	$0.16	$0.16	'
Distribution Made to Limited Liability Company (LLC) Member, Distributions Declared, Per Unit, Annualized Basis	'	'	'	'	$2.52	$2.49	'	'	'
Purchase price of acquired entity	'	'	'	'	'	'	'	'	$549,100
Contractual Obligation	$37,579	'	'	'	'	'	'	'	$36,600