Grizzly Energy (GRZZP) 10-K 2 Mar 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 25, 2015	Jun. 30, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	Vanguard Natural Resources, LLC
Entity Central Index Key	1384072
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$2,599,585,338
Entity Common Stock, Shares Outstanding		83,709,271
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Document Type	10-K
Document Period End Date	31-Dec-14
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, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Oil sales	$268,685	$268,922	$233,153
Natural gas sales	285,439	124,513	47,270
Natural gas liquids sales	70,489	49,813	29,933
Net gains on commodity derivative contracts	163,452	11,256	36,846
Total revenues	788,065	454,504	347,202
Production:
Lease operating expenses	132,515	105,502	74,366
Production and other taxes	61,874	40,430	29,369
Depreciation, depletion, amortization and accretion	226,937	167,535	104,542
Impairment of oil and natural gas properties	234,434	0	247,722
Selling, general and administrative expenses	30,839	25,942	22,466
Total costs and expenses	686,599	339,409	478,465
Income (loss) from operations	101,466	115,095	-131,263
Other income (expense):
Interest expense	-69,765	-61,148	-41,891
Net losses on interest rate derivative contracts	-1,933	-96	-6,992
Net gain on acquisitions of oil and natural gas properties	34,523	5,591	11,111
Other	54	69	220
Total other expense	-37,121	-55,584	-37,552
Net income (loss)	64,345	59,511	-168,815
Less: Distributions to Preferred unitholders	-18,197	-2,634	0
Net income (loss) available to Common and Class B unitholders	$46,148	$56,877	($168,815)
Net income (loss) per Common and Class B unit:
Earnings Per Share, Basic	$0.56	$0.78	($3.11)
Earnings Per Share, Diluted	$0.55	$0.77	($3.11)
Weighted average units outstanding:
Weighted average units outstanding - basic	82,031	73,064	54,197
Weighted average units outstanding - diluted	82,459	73,412	54,197
Common Units [Member]
Weighted average units outstanding:
Weighted average units outstanding - basic	81,611	72,644	53,777
Weighted average units outstanding - diluted	82,039	72,992	53,777
Class B Units [Member]
Weighted average units outstanding:
Weighted average units outstanding - basic and diluted	420	420	420

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets
Cash and cash equivalents	$0	$11,818
Trade accounts receivable, net	140,017	70,109
Derivative assets	142,114	21,314
Other currents assets	4,102	2,916
Total current assets	286,233	106,157
Oil and natural gas properties, at cost	4,140,527	2,523,671
Accumulated depletion, amortization and impairment	-1,164,721	-713,154
Oil and natural gas properties evaluated, net – full cost method	2,975,806	1,810,517
Other assets
Goodwill	420,955	420,955
Derivative assets	83,583	60,474
Other assets	27,015	91,538
Total assets	3,793,592	2,489,641
Accounts payable:
Trade	15,118	9,824
Affiliates	823	249
Accrued liabilities:
Lease operating	19,822	12,882
Developmental capital	24,706	10,543
Interest	11,517	11,989
Production and other taxes	29,981	16,251
Derivative liabilities	3,583	10,992
Oil and natural gas revenue payable	40,117	23,245
Distributions payable	18,640	16,499
Other	14,297	12,929
Total current liabilities	178,604	125,403
Long-term debt	1,932,816	1,007,879
Derivative liabilities	1,380	4,085
Asset retirement obligations	146,676	82,208
Other long-term liabilities	0	1,731
Total liabilities	2,259,476	1,221,306
Commitments and contingencies (Note 8)
Members’ equity
Members' Equity	1,534,116	1,268,335
Total liabilities and members’ equity	3,793,592	2,489,641
Cumulative Preferred units
Members’ equity
Members' Equity	335,444	61,021
Common Units [Member]
Members’ equity
Members' Equity	1,191,057	1,199,699
Class B Units [Member]
Members’ equity
Members' Equity	$7,615	$7,615

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical)	Dec. 31, 2014	Dec. 31, 2013
Members’ equity
Preferred units, outstanding	13,881,873	2,535,927
Cumulative Preferred units
Members’ equity
Preferred Unit, Issued	13,881,873	2,535,927
Preferred units, outstanding	13,881,873	2,535,927
Common Units [Member]
Members’ equity
Common Unit, Issued	83,451,746	78,337,259
Common Unit, Outstanding	83,451,746	78,337,259
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	Common Units [Member]	Cumulative Preferred units	Cumulative Preferred units	Class B Units [Member]
In Thousands, unless otherwise specified		Member Units [Member]		Member Units [Member]	Member Units [Member]
Balance at Dec. 31, 2011	$843,921	$836,306			$7,615
Increase (Decrease) in Members' Equity
Issuance of units, net of offering costs	321,900	321,900
Partners' Capital Account, Distributions, Common Units	-152,190	-152,190
Partners' Capital Account, Exchanges and Conversions	-52,480	-52,480
Unit-based compensation	4,178	4,178
Options exercised	950	950
Net income (loss)	-168,815	-168,815
Balance at Dec. 31, 2012	797,464	789,849			7,615
Increase (Decrease) in Members' Equity
Issuance of units, net of offering costs	498,360	498,360	61,021	61,021
Partners' Capital Account, Distributions, Common Units	-181,926	-181,926
Partners' Capital Account, Distributions, Preferred Units			-2,634	-2,634
Unit-based compensation	6,547	6,547
Partners' Capital Account, Acquisitions	29,992	29,992
Net income (loss)	59,511	59,511
Balance at Dec. 31, 2013	1,268,335	1,199,699		61,021	7,615
Increase (Decrease) in Members' Equity
Issuance of units, net of offering costs	147,814	147,814	274,423	274,423
Stock Repurchased During Period, Value	-2,498	-2,498
Partners' Capital Account, Distributions, Common Units	-207,883	-207,883
Partners' Capital Account, Distributions, Preferred Units			-18,197	-18,197
Unit-based compensation	7,777	7,777
Net income (loss)	64,345	64,345
Balance at Dec. 31, 2014	$1,534,116	$1,191,057		$335,444	$7,615

CONSOLIDATED_STATEMENTS_OF_MEM1

CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY (Parenthetical) (Member Units [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cumulative Preferred units
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs	$371	$402
Common Units [Member]
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs	$88	$415	$1,109

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	operating_areas
Operating activities
Net income (loss)	$64,345	$59,511	($168,815)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	226,937	167,535	104,542
Impairment of oil and natural gas properties	234,434	0	247,722
Amortization of deferred financing costs	3,516	3,715	2,925
Amortization of debt discount	269	248	172
Compensation related items	10,706	5,931	5,421
Net gains on commodity and interest rate derivative contracts	-161,519	-11,160	-29,854
Net cash settlements received on matured commodity derivative contracts	10,187	30,905	39,102
Net cash settlements paid on matured interest rate derivative contracts	-4,035	-3,888	-2,515
Net gain on acquisitions of oil and natural gas properties	-34,523	-5,591	-11,111
Changes in operating assets and liabilities:
Trade accounts receivable	-69,908	-22,065	3,778
Payables to affiliates	574	217	-1,647
Premiums paid on commodity derivative contracts	0	-204	-8,158
Other current assets	-1,669	-603	-318
Accounts payable and oil and natural gas revenue payable	22,166	16,426	8,604
Accrued expenses and other current liabilities	29,377	18,855	14,375
Other assets	8,895	1,133	267
Net cash provided by operating activities	339,752	260,965	204,490
Investing activities
Additions to property and equipment	-1,356	-1,975	-721
Additions to oil and natural gas properties	-142,015	-56,661	-50,405
Acquisitions of oil and natural gas properties and derivative contracts	-1,302,568	-272,057	-783,355
Proceeds from the sale of oil and natural gas properties	4,973	0	5,522
Deposits and prepayments of oil and natural gas properties	-5,236	-67,284	-10,285
Net cash used in investing activities	-1,446,202	-397,977	-839,244
Financing activities
Proceeds from long-term debt	1,388,000	589,500	1,477,459
Repayment of debt	-488,000	-829,500	-1,001,000
Proceeds from preferred unit offerings, net	274,423	61,021	0
Proceeds from common unit offerings, net	147,814	498,360	321,900
Repurchase of units under the common unit buyback program	-2,498	0	0
Distributions to Preferred unitholders	-17,290	-2,426	0
Distributions to Common and Class B members	-206,649	-177,555	-140,271
Financing fees	-1,168	-2,133	-15,572
Exercised options granted to officers	0	0	950
Net cash provided by financing activities	1,094,632	137,267	643,466
Net increase (decrease) in cash and cash equivalents	-11,818	255	8,712
Cash and cash equivalents, beginning of year	11,818	11,563
Cash and cash equivalents, end of year	0	11,818	11,563
Supplemental cash flow information:
Cash paid for interest	66,434	57,067	27,625
Non-cash financing and investing activities:
Asset retirement obligations	56,947	22,692	26,365
Assets acquired under financing obligations	31,502	0	0
Common units issued for the acquisition of oil and gas properties	0	29,992	0
Common units received in exchange for the Appalachian Basin properties	$0	$0	$52,480
Number of operating areas	9

Description_of_the_Business

Description of the Business	12 Months Ended
	Dec. 31, 2014
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, 2014, we own properties and oil and natural gas reserves primarily located in nine operating basins:
	•	the Green River Basin in Wyoming;
	•	the Piceance Basin in Colorado;
	•	the Permian Basin in West Texas and New Mexico;
	•	the Gulf Coast Basin in Texas, Louisiana and Mississippi;
	•	the Big Horn Basin in Wyoming and Montana;
	•	the Arkoma Basin in Arkansas and Oklahoma;
	•	the Williston Basin in North Dakota and Montana;
	•	the Wind River Basin in Wyoming; and
	•	the Powder River Basin in Wyoming.
	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, 2014
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:
	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)	New Pronouncement Issued But Not Yet Adopted:
	In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU No. 2014-09”), which amends the FASB ASC by adding new FASB ASC Topic 606, Revenue from Contracts with Customers, and superseding the revenue recognition requirements in FASB ASC 605, Revenue Recognition, and in most industry-specific topics. The standard provides new guidance concerning recognition and measurement of revenue and requires additional disclosures about the nature, timing and uncertainty of revenue and cash flows arising from contracts with customers. ASU No. 2014-09 is effective for annual periods beginning after December 15, 2016, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are evaluating the impact of the pending adoption of ASU No. 2014-09 on our financial position and results of operations and have not yet determined the method by which it will adopt the standard in 2017.
	(c)	Cash Equivalents:
	The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents.
	(d)	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.
	(e)	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.
	(f)	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 natural gas liquids (“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.
	We recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2014 of $234.4 million as a result of a decline in realized oil and natural gas prices at the measurement date, December 31, 2014. Such impairment was recognized during the fourth quarter of 2014. The most significant factor affecting the 2014 impairment related to the properties that we acquired in the Piceance Acquisition. The fair value of the properties acquired (determined using forward oil and natural gas price curves at the acquisitions dates) was higher than the discounted estimated future cash flows computed using the 12-month average prices at the impairment test measurement dates. However, the impairment calculations did not consider the positive impact of our commodity derivative positions as generally accepted accounting principles only allow the inclusion of derivatives designated as cash flow hedges. The fourth quarter 2014 impairment was calculated based on prices of $4.36 per MMBtu for natural gas and $94.87 per barrel of crude oil. No ceiling test impairment was required during 2013.
	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.
	(g)	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 using a two-step process. The goodwill test is performed at the reporting unit level, which represents our oil and natural gas operations in the United States. The first step involves a comparison of the estimated fair value of a reporting unit to its net book value, which is its carrying amount, including goodwill. In performing the first step, we determine the fair value of the reporting unit using the market approach. Determining fair value requires the exercise of significant judgment, including judgments about market prices and other relevant information generated by market transactions involving identical or comparable assets, liabilities, or a group of assets and liabilities, such as a business. If the estimated fair value of the reporting unit exceeds its net book value, goodwill of the reporting unit is not impaired and the second step of the impairment test is not necessary. If the net book value of the reporting unit exceeds its fair value, the second step of the goodwill impairment test will be performed to measure the amount of impairment loss, if any. The second step of the goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination. In other words, the estimated fair value of the reporting unit is allocated to all of the assets and liabilities of that unit (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination and the fair value of the reporting unit was the purchase price paid. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess.
	We performed our annual impairment tests during 2014, 2013 and 2012 and our analyses concluded that there was no impairment of goodwill as of these dates. However, due to the current decline in the prices of oil and natural gas as well as deteriorating market conditions, we performed an interim impairment test at December 31, 2014. Based on our estimates, the fair value of our reporting unit exceeded its carrying value by 8% at December 31, 2014 and therefore the second step of the impairment test was not necessary. We believe this difference between the fair value and the net book value is appropriate (in the context of assessing whether a goodwill impairment may exist) when a market-based control premium is taken into account and in light of the recent volatility in the equity markets.
	While no goodwill impairment was recognized at December 31, 2014, any further significant decline in the prices of oil and natural gas as well as any continued declines in the quoted market price of the Company’s units 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, 2014, the net carrying value of this contract was $8.3 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.
	(h)	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 and Fairway gas plants. 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.
	(i)	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, 2014 and 2013.
	(j)	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, 2014 and 2013, 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:
			2014	2013	2012
	Anadarko Petroleum Corporation		19%	1%	—%
	Marathon Oil Company		12%	14%	21%
	Plains Marketing L.P.		7%	10%	15%
	Our customers are in the energy industry and they may be similarly affected by changes in economic or other conditions.
	(k)	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.
	(l)	Price and Interest Rate Risk Management Activities:
	We have entered into derivative contracts primarily with counterparties that are also 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 2014, 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.
	(m)	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 tax basis of our net assets exceeded the net book basis by $187.0 million at December 31, 2014 while the book basis of our net assets exceeded the net tax basis by $168.5 million at December 31, 2013.
	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 $0.2 million and $0.3 million as of December 31, 2014 and 2013, respectively, and a deferred tax asset of $0.3 million and deferred tax liability of $0.4 million as of December 31, 2014 and 2013, respectively. A benefit of $0.6 million and tax provisions of $0.6 million and $0.2 million are included in our Consolidated Statements of Operations for the years ended December 31, 2014, 2013, and 2012, respectively, as a component of Selling, general and administrative expenses.

Acquisitions_and_Divestiture

Acquisitions and Divestiture	12 Months Ended
	Dec. 31, 2014
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 acquisitions, in which the Company issued shares or exchanged assets as described below.
	2014 Acquisitions
	Pinedale Acquisition
	On January 31, 2014, we completed the acquisition of natural gas and oil properties in the Pinedale and Jonah fields of Southwestern Wyoming for approximately $555.6 million in cash with an effective date of October 1, 2013. We refer to this acquisition as the “Pinedale Acquisition.” In accordance with ASC Topic 805, this acquisition resulted in a gain of $32.1 million, as reflected in the table below, primarily due to the increase in natural gas prices between the date the purchase and sale agreement was entered into and the closing date.
	Fair value of assets and liabilities acquired		(in thousands)
	Oil and natural gas properties		$	600,123
	Inventory		244
	Asset retirement obligations		(12,404		)
	Imbalance liabilities		(171		)
	Other		(125		)
	Total fair value of assets and liabilities acquired		587,667
	Fair value of consideration transferred		555,553
	Gain on acquisition		$	32,114
	Piceance Acquisition
	On September 30, 2014, we completed the acquisition of natural gas, oil and NGLs assets in the Piceance Basin in Colorado for approximately $502.1 million in cash. We refer to this acquisition as the “Piceance Acquisition.” Through this acquisition, we acquired additional interests in the same properties previously acquired in the Rockies Acquisition as defined below. The purchase price is subject to additional customary post-closing adjustments to be determined based on an effective date of July 1, 2014. In accordance with ASC Topic 805, this acquisition resulted in goodwill of $0.4 million, as reflected in the table below, which was immediately impaired and recorded as a loss in current period earnings. The loss resulted primarily from the changes in natural gas prices between the date the purchase and sale agreement was entered into and the closing date, which were used to value the reserves acquired.
	Fair value of assets and liabilities acquired		(in thousands)
	Oil and natural gas properties		$	521,401
	Asset retirement obligations		(19,452		)
	Imbalance and suspense liabilities		(236		)
	Total fair value of assets and liabilities acquired		501,713
	Fair value of consideration transferred		502,140
	Loss on acquisition		$	(427	)
	Other Acquisitions
	On May 1, 2014, we completed an asset exchange transaction with Marathon Oil Company in which we acquired natural gas and NGLs properties in the Wamsutter natural gas field in Wyoming in exchange for 75% of our working interests in the Gooseberry Field properties in Wyoming. The total consideration for this transaction was the mutual exchange and assignment of interests in the properties and net cash consideration of $6.8 million paid to Marathon Oil Company. The cash consideration was funded with borrowings under our existing Reserve-Based Credit Facility and is subject to customary final post-closing adjustments to be determined based on an effective date of January 1, 2014.
	On August 29, 2014, we completed the acquisition of certain natural gas, oil and NGLs properties located in North Louisiana and East Texas for an adjusted purchase price of $269.9 million, subject to additional customary post-closing adjustments to be determined based on an effective date of June 1, 2014.
	During the year ended December 31, 2014, we completed other smaller acquisitions of certain natural gas, oil and NGLs properties located in the Permian Basin and Powder River Basin in Wyoming for an aggregate purchase price of $17.7 million.
	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 from the date the natural gas swaps were restructured. 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 had an escalating working interest wherein our working interest began at 18% and increased to 21% on January 1, 2014, and was scheduled to 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. As noted above, we acquired all of Bill Barrett Corporation’s remaining interest in these properties in the Piceance Acquisition. 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.
	Pro Forma Operating Results (Unaudited)
	In accordance with ASC Topic 805, presented below are unaudited pro forma results for the years ended December 31, 2014, 2013 and 2012 which reflect the effect on our consolidated results of operations as if (i) all our acquisitions in 2014 had occurred on January 1, 2013, (ii) all our acquisitions in 2013 had occurred on January 1, 2012 and (iii) all our acquisitions in 2012 had occurred on January 1, 2011. 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 and (v) the impact of the common units issued in the acquisition of properties completed on June 28, 2013. We used a portion of the net proceeds from our 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. The pro forma information is based upon these assumptions, and is not necessarily indicative of future results of operations:
	Year Ended December 31,
	2014				2013		2012
	(in thousands, except per unit amounts) (Pro forma)
Total revenues	$	944,246			$	841,576	$	557,802
Net income (loss) attributable to Common and Class B unitholders	$	254,345			$	161,329	$	(174,187	)
Net income (loss) attributable to Common and Class B unitholders, per unit:
Basic	$	3.1			$	2.19	$	(3.18	)
Diluted	$	3.07			$	2.17	$	(3.18	)
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
	31-Dec-12
Revenues	$	3,267
Net loss	$	(400	)
Post-Acquisition Operating Results
The results of operations of the properties acquired, 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 2014, 2013 and 2012 Consolidated Statements of Operations for our acquisitions. Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes.
	Year Ended December 31,
	2014				2013		2012
	(in thousands)
Pinedale Acquisition
Revenues	$	139,908			$	—	$	—
Excess of revenues over direct operating expenses	$	107,934			$	—	$	—
Piceance Acquisition
Revenues	$	22,642			$	—	$	—
Excess of revenues over direct operating expenses	$	15,234			$	—	$	—
Arkoma Basin Acquisition
Revenues	$	62,450			$	55,468	$	24,673
Excess of revenues over direct operating expenses	$	48,847			$	45,090	$	19,971
Rockies Acquisition
Revenues	$	67,707			$	63,652	$	220
Excess of revenues over direct operating expenses	$	40,505			$	41,583	$	164
All other acquisitions
Revenues	$	79,009			$	37,096	$	1,535
Excess of revenues over direct operating expenses	$	51,956			$	24,912	$	992

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Debt	Long-Term Debt
	Our financing arrangements consisted of the following:
							Amount Outstanding December 31,
	Description		Interest Rate		Maturity Date		2014				2013
							(in thousands)
	Senior Secured Reserve-Based Credit Facility		Variable (1)		April 16, 2018		$	1,360,000			$	460,000
	Senior Notes		7.875% (2)		April 1, 2020		550,000				550,000
	Lease Financing Obligations		4.16% (3)		August 10, 2020 (4)		28,986				—
							$	1,938,986			$	1,010,000
	Less:
	Unamortized discount on Senior Notes						(1,852		)		(2,121		)
	Current portion						(4,318		)		—
	Total long-term debt						$	1,932,816			$	1,007,879
	-1	Variable interest rate was 2.17% and 1.92% at December 31, 2014 and 2013, respectively.
	-2	Effective interest rate is 8.0%.
	-3	Effective interest rate is 6.48%.
	-4	The Lease Financing Obligations expire on August 10, 2020 except for certain obligations which expire on July 10, 2021.
	Senior Secured Reserve-Based Credit Facility
	The Company’s Third Amended and Restated Credit Agreement (the “Credit Agreement”) provides a maximum credit facility of $3.5 billion and an initial borrowing base of $2.0 billion (the “Reserve-Based Credit Facility”). On December 31, 2014, there were $1.36 billion of outstanding borrowings and $634.5 million of borrowing capacity under the Reserve-Based Credit Facility, after reflecting a $5.5 million reduction in availability for letters of credit (discussed below).
	On October 30, 2014, we entered into the Seventh Amendment to the Credit Agreement, which provided for, among others, (a) the increase in the maximum amount of debt under capital leases from $2.0 million to $35.0 million and (b) the increase in the aggregate amount of restricted payments that can be used to repurchase the Company’s units over the term of the Credit Agreement from $10.0 million to $50.0 million.
	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, 2014, the applicable margin and other fees increase as the utilization of the borrowing base increases as follows:
	Borrowing Base Utilization Grid
	Borrowing Base Utilization Percentage		<25%			>25% <50%			>50% <75%			>75% <90%		>90%
	Eurodollar Loans Margin		1.5	%		1.75	%		2	%		2.25	%	2.5	%
	ABR Loans Margin		0.5	%		0.75	%		1	%		1.25	%	1.5	%
	Commitment Fee Rate		0.5	%		0.5	%		0.375	%		0.375	%	0.375	%
	Letter of Credit Fee		0.5	%		0.75	%		1	%		1.25	%	1.5	%
	Our Reserve-Based Credit Facility contains a number of customary covenants that require us to maintain certain financial ratios. Specifically, as of the end of each fiscal quarter, we may not permit the following: (a) our current ratio to be less than 1.0 to 1.0 and (b) our total leverage ratio to be more than 4.0 to 1.0. In addition, we are subject to various other covenants including, but not limited to, those limiting our ability to incur indebtedness, enter into commodity and interest rate derivatives, grant certain liens, make certain loans, acquisitions, capital expenditures and investments, merge or consolidate, or engage in certain asset dispositions, including a sale of all or substantially all of our assets.
	At December 31, 2014, we were in compliance with all of our debt covenants. Based on projected market conditions and lower commodity prices, we currently expect that we will not be in compliance with our total leverage ratio covenant in certain future periods. We have been in discussions with certain banks in our Reserve-Based Credit Facility regarding amending our leverage ratio covenant during our next scheduled borrowing base redetermination. Based on those discussions, it is our expectation that the covenant will be changed to provide for more flexibility given lower forecasted Adjusted EBITDA due to the lower commodity price environment. Our next borrowing base redetermination is scheduled for April 2015 and we expect our borrowing base to be reduced. Absent the success of amending our leverage ratio, a resultant breach of the covenants under our Reserve-Based Credit Facility would cause a default under the reserve-based credit agreement and the lenders would be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. This, in turn, would cause a default under the senior notes due in 2020 and permit the holders of those notes to accelerate their maturity.
	Letters of Credit
	At December 31, 2014, we had unused irrevocable standby letters of credit of approximately $5.5 million. The letters are being maintained as security for performance on long-term transportation contracts. Borrowing availability for the letters of credit is provided under our Reserve-Based Credit Facility. The fair value of these letters of credit approximates contract values based on the nature of the fee arrangements with the issuing banks.
	Senior Notes
	We have $550.0 million outstanding in aggregate principal amount of 7.875% senior notes due in 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, 2014, based on the most restrictive covenants of the Indenture, the Company’s cash balance and the borrowings available under the Reserve-Based Credit Facility, $245.0 million of members’ equity is available for distributions to unitholders, while the remainder is restricted.
	Interest on the Senior Notes is payable on April 1 and October 1 of each year. We may redeem some or all of the Senior Notes at any time on or after April 1, 2016 at redemption prices of 103.93750% of the aggregate principal amount of the Senior Notes as of April 1, 2016, declining to 100% on April 1, 2018 and thereafter. We may also redeem some or all of the Senior Notes at any time prior to April 1, 2016 at a redemption price equal to 100% of the aggregate principal amount of the Senior Notes thereof, plus a “make-whole” premium. In addition, before April 1, 2015, we may redeem up to 35% of the aggregate principal amount of the Senior Notes at a redemption price equal to 107.875% of the aggregate principal amount of the Senior Notes thereof, with the proceeds of certain equity offerings, provided that 65% of the aggregate principal amount of the Senior Notes remain outstanding immediately after any such redemption and the redemption occurs within 180 days of such equity offering. If we sell certain of our assets or experience certain changes of control, we may be required to repurchase all or a portion of the Senior Notes at a price equal to 100% and 101% of the aggregate principal amount of the Senior Notes, respectively.
	Lease Financing Obligations
	On October 24, 2014, in connection with our Piceance Acquisition, we entered into an assignment and assumption agreement, whereby we acquired compressors and the related facilities, and assumed the related financing obligations (the “Lease Financing Obligations”). Certain rights, title, interest and obligations under the Lease Financing Obligations have been assigned to several lenders and are covered by separate assignment agreements, which expire on August 10, 2020 and July 10, 2021. We have the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligations also contain an early buyout option where the Company may purchase the equipment for $16.0 million on February 10, 2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 4.16%.

Price_and_Interest_Rate_Risk_M

Price and Interest Rate Risk Management Activities	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Price and Interest Rate Risk Management Activities	Price and Interest Rate Risk Management Activities
	We have entered into derivative contracts primarily with counterparties that are also lenders under our Reserve-Based Credit Facility to hedge price risk associated with a portion of our oil, natural gas and NGLs production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated which has, and could, result in overhedged volumes. Pricing for these derivative contracts are based on certain market indexes and prices at our primary sales points.
	We also enter into fixed LIBOR interest rate swap agreements with certain counterparties that are lenders under our Reserve-Based Credit Facility, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates.
	At December 31, 2014, 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, 2015 – December 31, 2015		66,795,000			$	4.4			692,000			$	91.18		246,375	$	46.34
	January 1, 2016 – December 31, 2016		55,083,000			$	4.47			146,400			$	89.98		—	$	—
	January 1, 2017 – December 31, 2017		27,677,000			$	4.32			73,000			$	86.6		—	$	—
	Call Options Sold
			Oil
	Contract Period		Bbls			Weighted
						Average
						Fixed Price
	January 1, 2015 – December 31, 2015		252,945			$	97.89
	January 1, 2016 – December 31, 2016		622,200			$	125
	Basis Swaps
			Gas
	Contract Period		MMBtu			Weighted Avg. Basis				Pricing Index
						Differential
						($/MMBtu)
	January 1, 2015 – December 31, 2015		29,200,000			$	(0.28	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2016 – December 31, 2016		18,300,000			$	(0.24	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2017 – December 31, 2017		10,950,000			$	(0.22	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
			Oil
	Contract Period		Bbls			Weighted Avg. Basis				Pricing Index
						Differential ($/Bbl)
	January 1, 2015 – December 31, 2015		511,000			$	(1.68	)		WTI Midland and WTI Cushing Basis Differential
	January 1, 2015 – December 31, 2015		146,000			$	(2.33	)		West Texas Sour and WTI Cushing Basis Differential
	Three-Way Collars
			Gas
	Contract Period		MMbtu			Floor				Ceiling				Put Sold
	January 1, 2015 – December 31, 2015		17,337,500			$	3.99			$	4.67			$	3.38
	January 1, 2016 – December 31, 2016		12,810,000			$	3.95			$	4.58			$	3.38
	January 1, 2017 – December 31, 2017		12,775,000			$	3.97			$	4.61			$	3.4
			Oil
	Contract Period		Bbls			Floor				Ceiling				Put Sold
	January 1, 2015 – December 31, 2015		1,984,055			$	92.05			$	95.74			$	74.41
	January 1, 2016 – December 31, 2016		1,061,400			$	90			$	96.18			$	73.62
	Put Options Sold
			Gas							Oil
	Contract Period		MMbtu			Put Sold ($/MMbtu)				Bbls			Put Sold ($/Bbl)
	January 1, 2015 – December 31, 2015		9,125,000			$	3.5			692,000			$	72.36
	January 1, 2016 – December 31, 2016		1,830,000			3.5				146,400			$	75
	January 1, 2017 – December 31, 2017		1,825,000			3.5				73,000			$	75
	Range Bonus Accumulators
			Gas
	Contract Period		MMBtu			Bonus				Range Ceiling				Range Floor
	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, 2015 – December 31, 2015		182,500			$	4			$	100			$	75
	January 1, 2016 – December 31, 2016		183,000			$	4			$	100			$	75
	In January 2015, we restructured our hedge portfolio to limit further downside and volatility due to the current commodity price environment. See Note 12. Subsequent Events for further discussion.
	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, 2014, the Company had open interest rate derivative contracts as follows (in thousands):
			Notional Amount				Fixed LIBOR Rates
	Period:
	January 1, 2015 to December 10, 2016		$	20,000			2.17	%
	January 1, 2015 to October 31, 2016		$	40,000			1.65	%
January 1, 2015 to August 5, 2015 (1)		$	30,000			2.25	%
January 1, 2015 to August 6, 2016		$	25,000			1.8	%
January 1, 2015 to October 31, 2016		$	20,000			1.78	%
January 1, 2015 to September 23, 2016		$	75,000			1.15	%
January 1, 2015 to March 7, 2016		$	75,000			1.08	%
January 1, 2015 to September 7, 2016		$	25,000			1.25	%
January 1, 2015 to December 10, 2015 (2)		$	50,000			0.21	%
Total		$	360,000
-1	The counterparty has the option to extend the termination date of this contract 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, 2014
Offsetting Derivative Assets:		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts		$	289,018			$	(63,321	)		$	225,697
Total derivative instruments		$	289,018			$	(63,321	)		$	225,697
Offsetting Derivative Liabilities:		Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts		$	(63,615	)		$	63,321			$	(294	)
Interest rate derivative contracts		(4,669		)		—				(4,669		)
Total derivative instruments		$	(68,284	)		$	63,321			$	(4,963	)
		December 31, 2013
Offsetting Derivative Assets:		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts		$	107,307			$	(25,617	)		$	81,690
Interest rate derivative contracts		98				—				98
Total derivative instruments		$	107,405			$	(25,617	)		$	81,788
Offsetting Derivative Liabilities:		Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts		$	(33,825	)		$	25,617			$	(8,208	)
Interest rate derivative contracts		(6,869		)		—				(6,869		)
Total derivative instruments		$	(40,694	)		$	25,617			$	(15,077	)
By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. Our counterparties are participants in our Reserve-Based Credit Facility (see Note 3 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 $289.0 million at December 31, 2014. In accordance with our standard practice, our commodity and interest rate swap derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of such loss is somewhat mitigated as of December 31, 2014. We minimize the credit risk in derivative instruments by: (i) entering into derivative instruments primarily with counterparties that are also lenders in our Reserve-Based Credit Facility and (ii) monitoring the creditworthiness of our counterparties on an ongoing basis.
The change in fair value of our commodity and interest rate derivatives for the years ended December 31, 2014, 2013 and 2012 is as follows:
	2014				2013				2012
	(in thousands)
Derivative asset (liability) at January 1, net	$	66,711			$	82,568			$	(29,889	)
Purchases
Fair value of derivatives acquired through business combinations	(1,344		)		—				109,495
Premiums and fees paid or deferred for derivative contracts during the period	—				—				9,695
Net gains on commodity and interest rate derivative contracts	161,519				11,160				29,854
Settlements
Net cash settlements received on matured commodity derivative contracts	(10,187		)		(30,905		)		(39,102		)
Net cash settlements paid on matured interest rate derivative contracts	4,035				3,888				2,515
Derivative asset at December 31, net	$	220,734			$	66,711			$	82,568

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements
	We estimate the fair values of financial and non-financial assets and liabilities under ASC Topic 820 “Fair Value Measurements and Disclosures” (“ASC Topic 820”). ASC Topic 820 provides a framework for consistent measurement of fair value for those assets and liabilities already measured at fair value under other accounting pronouncements. Certain specific fair value measurements, such as those related to share-based compensation, are not included in the scope of ASC Topic 820. Primarily, ASC Topic 820 is applicable to assets and liabilities related to financial instruments, to some long-term investments and liabilities, to initial valuations of assets and liabilities acquired in a business combination, 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 and the initial measurement of asset retirement obligations. 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. The fair value of the Lease Financing Obligations is measured using market-based parameters of comparable term secured financing instruments and therefore we estimate that the carrying value approximates its fair value. The fair value measurements for our bank borrowings and the Lease Financing Obligations represent Level 2 inputs. As of December 31, 2014, the fair value of our Senior Notes was estimated to be $485.4 million. We consider the inputs to the valuation of our Senior Notes to be Level 1, as fair value was estimated based on prices quoted from a third-party financial institution.
	Derivative instruments. As of December 31, 2014, our commodity derivative instruments consist of fixed-price swaps, basis swap contracts, three-way collars, call options sold, 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 and basis swap contracts 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-14
		Fair Value Measurements Using									Assets/Liabilities at Fair Value
		Level 1			Level 2			Level 3
		(in thousands)
	Assets:
	Commodity price derivative contracts	$	—		$	232,167		$	(6,470	)	$	225,697
	Total derivative instruments	$	—		$	232,167		$	(6,470	)	$	225,697
	Liabilities:
	Commodity price derivative contracts	$	—		$	(294	)	$	—		$	(294	)
	Interest rate derivative contracts	—			(4,669		)	—			(4,669		)
	Total derivative instruments	$	—		$	(4,963	)	$	—		$	(4,963	)
		31-Dec-13
		Fair Value Measurements Using									Assets/Liabilities
		Level 1			Level 2			Level 3			at Fair value
		(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	)
	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:
		2014			2013
		(in thousands)
	Unobservable inputs at January 1,	$	566		$	(498	)
	Total losses	(8,238		)	(134		)
	Settlements	1,202			1,198
	Unobservable inputs at December 31,	$	(6,470	)	$	566
	Change in fair value included in earnings related to derivatives still held as of December 31, 2014	$	(6,326	)	$	1,126
	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 as well as any continued declines in the quoted market price of the Company’s units 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 years ended December 31, 2014 and 2013, in connection with the oil and natural gas properties acquired in all of our acquisitions, as well as new wells drilled during each year, we incurred and recorded asset retirement obligations totaling $52.8 million and $11.7 million, respectively, at fair value. We also recorded a $4.1 million and 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 years ended December 31, 2014 and 2013, respectively. 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 4.8% and 5.6%; and (4) the average inflation factor (2.3%). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
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:
		2014			2013
		(in thousands)
	Asset retirement obligation at January 1,	$	87,967		$	63,114
	Liabilities added during the current period	52,829			11,738
	Accretion expense	5,889			2,789
	Change in estimate	4,118			10,954
	Disposition of properties	(1,291		)	—
	Retirements	(450		)	(628		)
	Total asset retirement obligation at December 31,	149,062			87,967
	Less: current obligations	(2,386		)	(5,759		)
	Long-term asset retirement obligation at December 31,	$	146,676		$	82,208
	Accretion expense for the years ended December 31, 2014, 2013 and 2012 was $5.9 million, $2.8 million and $1.3 million, respectively. Each year we review, and to the extent necessary, revise our asset retirement obligation estimates. During 2014 and 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 $4.1 million and $11.0 million, respectively, to reflect increased costs incurred for plugging and abandonment.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
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 year ended December 31, 2012, costs incurred under the MSA and the GCA were $0.6 million and $0.4 million, respectively. As a result of the Unit Exchange, the MSA and GCA were terminated.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies
	Transportation Demand Charges
	As of December 31, 2014, we have contracts that provide firm transportation capacity on pipeline systems. The remaining terms on these contracts range from one to five years and require us to pay transportation demand charges regardless of the amount of pipeline capacity we utilize.
	The values in the table below represent gross future minimum transportation demand charges we are obligated to pay as of December 31, 2014. However, our financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property.
		(in thousands)
	2015	$	17,454
	2016	13,986
	2017	11,840
	2018	11,261
	2019	9,661
	Thereafter	410
	Total	$	64,612
	Development Commitments
	We have commitments to third-party operators under joint operating agreements relating to the drilling and completion of oil and natural gas wells. Total estimated costs to be spent in 2015 is approximately $45.9 million.
	Legal Proceedings
	We are defendants in certain 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.

Members_Equity_and_Net_Income_

Members' Equity and Net Income per Common and Class B Unit	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Members' Equity Notes Disclosure [Text Block]	Members’ Equity and Net Income per Common and Class B Unit
	Cumulative Preferred Units
	The following table summarizes the Company’s Cumulative Preferred units outstanding at December 31, 2014 and 2013:
									2014					2013
			Earliest		Liquidation Preference		Distribution Rate		Units Outstanding			Carrying Value		Units Outstanding	Carrying Value
			Redemption Date		Per Share							(in thousands)			(in thousands)
	Series A		15-Jun-23		$25.00		7.88%		2,581,873			$	62,200	2,535,927	$	61,021
	Series B		15-Apr-24		$25.00		7.63%		7,000,000			$	169,265	—	$	—
	Series C		15-Oct-24		$25.00		7.75%		4,300,000			$	103,979	—	$	—
	Total Cumulative Preferred Units								13,881,873			$	335,444	2,535,927	$	61,021
	The Series A, B and C Cumulative Preferred Units (collectively the “Cumulative Preferred Units”) have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by us or converted into our common units, at our option, in connection with a change of control. The Cumulative Preferred Units can be redeemed, in whole or in part, out of amounts legally available therefore, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. We may also redeem the Cumulative Preferred Units in the event of a change of control. Holders of the Cumulative Preferred Units will have no voting rights except for limited voting rights if we fail to pay dividends for eighteen or more monthly periods (whether or not consecutive) and in certain other limited circumstances or as required by law. The Cumulative Preferred Units have a liquidation preference which is equal to the redemption price described above.
	See Note 11. Shelf Registration Statement for a discussion of the changes in our Cumulative Preferred units during the year ended December 31, 2014.
	Common and Class B Units
	The common units represent limited liability company interests. Holders of Class B units have substantially the same rights and obligations as the holders of common units.
	On October 15, 2014, our Board of Directors authorized a $10.0 million dollar common unit buyback program. The program was approved for an initial three month period and authorized us to make open market purchases pursuant to the Securities and Exchange Commission guidelines of Rule 10b-18. We intend to hold the common units to fund our VNR LTIP (defined in Note 10) as directed by the Compensation Committee. As of December 31, 2014, we have repurchased a total of 134,770 units under the common unit buyback program for an aggregate cost of $2.5 million.
	The following is a summary of the changes in our common units issued during the years ended December 31, 2014, 2013 and 2012 (in thousands):
			2014			2013			2012
	Beginning of period		78,337			58,706			48,320
	Common units received in exchange for the Appalachian Basin properties		—			—			(1,900	)
	Issuance of Common units for the acquisition of oil and natural		—			1,075			—
	gas properties
	Issuance of Common units for cash		4,864			18,377			12,149
	Repurchase of units under the common unit buyback program		(135	)		—			—
	Unit-based compensation		386			179			87
	Options exercised		—			—			50
	End of period		83,452			78,337			58,706
	There was no change in issued and outstanding Class B units during the years ended December 31, 2014, 2013 and 2012.
	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 attributable to common and Class B unitholders by the weighted average number of units outstanding during the period. Diluted net income per common and Class B unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. We use the treasury stock method to determine the dilutive effect. Class B units participate in distributions; therefore, all Class B units were considered in the computation of basic net income per unit. The Cumulative Preferred Units have no participation rights and accordingly are excluded from the computation of net income per unit.
	The net income (loss) attributable to common and Class B unitholders and the weighted average units for calculating basic and diluted net income per common and Class B unit were as follows (in thousands, except per unit data):
			2014				2013				2012(a)
	Net income (loss) attributable to Common and Class B unitholders		$	46,148			$	56,877			$	(168,815	)
	Weighted average number of Common and Class B units outstanding - basic		82,031				73,064				54,197
	Effect of dilutive securities:
	Phantom units		428				348				—
	Weighted average number of Common and Class B units outstanding - diluted		82,459				73,412				54,197
	Net income (loss) per Common and Class B unit
	Basic		$	0.56			$	0.78			$	(3.11	)
	Diluted		$	0.55			$	0.77			$	(3.11	)
	(a)	For the year ended December 31, 2012, 522,500 phantom units were excluded from the calculation of diluted earnings per unit due to their antidilutive effect as we were in a loss position.
	Distributions Declared
	The Cumulative Preferred Units rank senior to our common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up. Distributions on the Preferred Units are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, unless the 15th day falls on a weekend or holiday, in which case it will be paid on the next business day, when, as and if declared by our board of directors. We will pay cumulative distributions in cash on the Preferred Units on a monthly basis at a monthly rate of 7.875% per annum of the liquidation preference of $25.00 per Series A Cumulative Preferred Unit, a monthly rate of 7.625% per annum of the liquidation preference of $25.00 per Series B Cumulative Preferred Unit and a monthly rate of 7.75% per annum of the liquidation preference of $25.00 per Series C Cumulative Preferred Unit.
	The following table shows the distribution amount, declared date, record date and payment date of the cash distributions we paid on each of our common and Class B units for each period presented. Future distributions are at the discretion of our board of directors and will depend on business conditions, earnings, our cash requirements and other relevant factors.
	On January 22, 2015 and February 17, 2015, our board of directors declared cash distributions on the Cumulative Preferred Units and common and Class B units attributable to the month of December 2014 and January 2015, respectively. See Note 12. Subsequent Events for further discussion.
			Cash Distributions
	Distribution		Per Unit				Declared Date		Record Date		Payment Date
	2014
	Fourth Quarter
	November		$	0.21			December 16, 2014		January 2, 2015		January 14, 2015
	October		$	0.21			November 20, 2014		December 1, 2014		December 15, 2014
	Third Quarter
	September		$	0.21			October 20, 2014		November 3, 2014		November 14, 2014
	August		$	0.21			September 19, 2014		October 1, 2014		October 15, 2014
	July		$	0.21			August 19, 2014		September 2, 2014		September 12, 2014
	Second Quarter
	June		$	0.21			July 16, 2014		August 1, 2014		August 14, 2014
	May		$	0.21			June 24, 2014		July 1, 2014		July 15, 2014
	April		$	0.21			May 20, 2014		June 2, 2014		June 13, 2014
	First Quarter
	March		$	0.21			April 17, 2014		May 1, 2014		May 15, 2014
	February		$	0.21			March 17, 2014		April 1, 2014		April 14, 2014
	January		$	0.2075			February 2, 2014		March 3, 2014		March 17, 2014
	2013
	Fourth Quarter
December		$	0.2075			January 16, 2014		February 3, 2014		February 14, 2014
November		$	0.2075			December 17, 2013		January 2, 2014		January 15, 2014
October		$	0.2075			November 19, 2013		December 2, 2013		December 13, 2013
Third Quarter
September		$	0.2075			October 21, 2013		November 1, 2013		November 14, 2013
August		$	0.2075			September 12, 2013		October 1, 2013		October 15, 2013
July		$	0.2075			August 20, 2013		September 3, 2013		September 13, 2013
Second Quarter
June		$	0.205			July 18, 2013		August 1, 2013		August 14, 2013
May		$	0.205			June 20, 2013		July 1, 2013		July 15, 2013
April		$	0.205			April 30, 2013		June 3, 2013		June 14, 2013
First Quarter
March		$	0.2025			April 19, 2013		May 1, 2013		May 15, 2013
February		$	0.2025			March 21, 2013		April 1, 2013		April 12, 2013
January		$	0.2025			February 18, 2013		March 1, 2013		March 15, 2013
2012
Fourth Quarter
December		$	0.2025			January 25, 2013		February 4, 2013		February 14, 2013
November		$	0.2025			December 19, 2012		January 2, 2013		January 14, 2013
October		$	0.2025			November 16, 2012		December 3, 2012		December 14, 2012
Third Quarter
September		$	0.2			October 18, 2012		November 1, 2012		November 14, 2012
August		$	0.2			September 17, 2012		October 1, 2012		October 15, 2012
July		$	0.2			August 20, 2012		September 4, 2012		September 14, 2012
Second Quarter		$	0.6			July 23, 2012		August 7, 2012		August 14, 2012
First Quarter		$	0.5925			April 24, 2012		May 8, 2012		May 15, 2012
2011
Fourth Quarter		$	0.5875			January 18, 2012		February 7, 2012		February 14, 2012

UnitBased_Compensation

Unit-Based Compensation	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Unit-Based Compensation Notes Disclosure	Unit-Based Compensation
	Long-Term Incentive Plan
	The Vanguard Natural Resources, LLC Long-Term Incentive Plan (the “VNR LTIP”) was adopted by the Board of Directors of the Company to compensate employees, consultants, and nonemployee directors of the Company and its affiliates who perform services for the Company under the terms of the plan. The VNR LTIP is administered by the compensation committee of the board of directors (the “Compensation Committee”) and permits the grant of unrestricted units, restricted units, phantom units, unit options and unit appreciation rights.
	Unit Options
	In October 2007, two officers were granted options to purchase an aggregate of 175,000 units under 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.
	Restricted and Phantom Units
	A restricted unit is a unit grant that vests over a period of time and that during such time is subject to forfeiture. A phantom unit grant represents the equivalent of one common unit of the Company. The phantom units, once vested, are settled through the delivery of a number of common units equal to the number of such vested units, or an amount of cash equal to the fair market value of such common units on the vesting date to be paid in a single lump sum payment, as determined by the compensation committee in its discretion. The Compensation Committee may grant tandem distribution equivalent rights (“DERs”) with respect to the phantom units that entitle the holder to receive the value of any distributions made by us on our units while the phantom units are outstanding.
	The fair value of restricted unit and phantom unit awards is measured based on the fair market value of the Company units on the date of grant. The values of restricted unit grants and phantom unit grants that are required to be settled in units are recognized as expense over the vesting period of the grants with a corresponding charge to members’ equity. When the Company has the option to settle the phantom unit grants by issuing Company units or through cash settlement, the Company recognizes the value of those grants utilizing the liability method as defined under ASC Topic 718 based on the Company’s historical practice of settling phantom units predominantly in cash. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period.
	Executive Employment Agreements 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. The Amended Agreements were effective January 1, 2013 and the initial term of the Amended Agreements ends on January 1, 2016, with a subsequent twelve-month term extension automatically commencing on January 1, 2016 and each successive January 1 thereafter, provided that neither VNRH nor the executives deliver a timely non-renewal notice prior to a term expiration date.
	The Amended Agreements provide for an annual base salary and eligibility to receive an annual performance-based cash bonus award. The annual bonus will be calculated based upon three Company performance components: absolute target distribution growth, adjusted EBITDA growth and relative unit performance to peer group, as well as a fourth component determined solely in the discretion of our board of directors. As of December 31, 2014, an accrued liability was recognized and compensation expense of $1.4 million was recorded for the year ended December 31, 2014, related to these bonus arrangements, which was classified in the selling, general and administrative expenses line item in the Consolidated Statement of Operations.
	Under the Amended Agreements, the executives are also eligible to receive annual equity-based compensation awards, consisting of restricted units and/or phantom units granted under the VNR LTIP. The restricted units and phantom units granted to executives under the Amended Agreements are subject to a three-year vesting period. One-third of the aggregate number of the units vest on each one-year anniversary of the date of grant so long as the executive remains continuously employed with the Company. Both the restricted and phantom units include a tandem grant of DERs.
	Restricted Unit Grants
	On January 1, 2014, the executives were granted a total of 182,377 restricted units in accordance with the Amended Agreements.
	During the year ended December 31, 2014, our three independent board members were granted a total of 13,137 restricted units which will vest one year from the date of grant. In addition, VNR employees were granted a total of 96,310 restricted units under the VNR LTIP which will vest three years from the date of grant. The restricted units granted to the board members and VNR employees are accompanied by DERs.
	As of December 31, 2014, a summary of the status of the non-vested restricted 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, 2013	248,611		$	28.57
	Granted	291,824		$	29.02
	Forfeited	(9,047	)	$	29.54
	Vested	(91,341	)	$	28.48
	Non-vested units at December 31, 2014	440,047		$	28.87
	The weighted average grant-date fair value of restricted units granted was $28.70 and $27.95 during the years ended December 31, 2013 and 2012, respectively.
	At December 31, 2014, there was approximately $8.4 million of unrecognized compensation cost related to non-vested restricted units.  The cost is expected to be recognized over an average period of approximately 1.7 years. Our Consolidated Statements of Operations reflects non-cash compensation related to restricted unit grants of $10.7 million, $3.4 million and $4.2 million in the Selling, general and administrative expenses line item for the years ended December 31, 2014, 2013 and 2012, respectively.
	Phantom Unit Grants
	We did not grant any phantom units during the year ended December 31, 2014.
	As of December 31, 2014, a summary of the status of the non-vested phantom units under the VNR LTIP is presented below:
		Number of		Weighted Average
		Non-vested Phantom Units		Grant Date Fair Value
	Non-vested units at December 31, 2013	482,735		$	28.67
	Forfeited	(12,539	)	$	28.35
	Vested	(139,875	)	$	28.92
	Non-vested units at December 31, 2014	330,321		$	28.58
	The weighted average grant-date fair value of phantom units granted was $28.29 and $28.67 during the years ended December 31, 2013 and 2012, respectively.
	At December 31, 2014, there was approximately $9.4 million of unrecognized compensation cost related to non-vested phantom units.  The cost is expected to be recognized over an average period of approximately 1.7 years. Compensation expense related to phantom units granted to executive officers, board members and employees of $1.0 million, $2.6 million and $1.2 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, 2014, 2013, and 2012, respectively.

Shelf_Registration_Statements

Shelf Registration Statements	12 Months Ended
	Dec. 31, 2014
Shelf Registration Statement [Abstract]
Shelf Registration Statement	Shelf Registration Statements
	We have registered an indeterminate amount of Series A Cumulative Preferred Units, Series B Cumulative Preferred Units, Series C Cumulative Preferred Units, common units, debt securities and guarantees of debt securities under our shelf registration statement filed with the SEC (the “Shelf Registration Statement”), which was effective until January 2015. As discussed in Note 12. Subsequent Events, we filed a new shelf registration statement on February 13, 2015.
	Net proceeds, terms and pricing of each offering of securities issued under the Shelf Registration Statement are determined at the time of such offerings. The Shelf Registration Statement does not provide assurance that we will or could sell any such securities. Our ability to utilize the Shelf Registration Statement for the purpose of issuing, from time to time, any combination of equity or debt securities, will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us.
	We have entered into an equity distribution agreement with respect to the issuance and sale of our Series A Cumulative Preferred Units and common units (the “Equity Distribution Agreement”) under our at-the-market equity program. Pursuant to the terms of the equity distribution agreement, we may sell from time to time through our sales agents (i) our common units representing limited liability company interests having an aggregate offering price of up to $500.0 million and (ii) our Series A Cumulative Preferred Units having an aggregate offering price of up to $250.0 million. The common units and Series A Cumulative Preferred Units to be sold under the Equity Distribution Agreement are registered under our existing Shelf Registration Statement. During the year ended December 31, 2014, total net proceeds received under our at-the-market equity program were approximately $147.8 million, after commissions and fees, from the sales of 4,863,690 common units and $1.2 million, after commissions and fees, from the sales of 45,946 Series A Cumulative Preferred Units.
	Preferred Unit Equity Offerings
	On March 11, 2014, we completed a public offering of 7,000,000 7.625% Series B Cumulative Preferred Units at a price of $25.00 per unit. Offers were made pursuant to a prospectus supplement to the Shelf Registration Statement. We received proceeds of approximately $169.3 million from this offering, after deducting underwriting discounts of $5.5 million and offering costs of $0.2 million. We used the net proceeds from this offering to repay indebtedness outstanding under our Reserve-Based Credit Facility.
	On September 15, 2014, we completed a public offering of 4,000,000 7.75% Series C Cumulative Preferred Units at a price of $25.00 per unit. Offers were made pursuant to a prospectus supplement to the Shelf Registration Statement. We received proceeds of approximately $96.9 million from this offering, after deducting underwriting discounts of $3.2 million and offering costs of $0.2 million. On September 23, 2014, we received additional proceeds of approximately $7.3 million from the sale of an additional 300,000 Series C Cumulative Preferred Units that were purchased pursuant to the underwriters’ over-allotment option. We used the net proceeds from this offering to repay indebtedness outstanding under our Reserve-Based Credit Facility.
	Subsidiary Guarantors
	We and VNR Finance Corp., our wholly-owned finance subsidiary, may co-issue securities pursuant to our effective shelf registration statement. 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 guaranteed 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, 2014
Subsequent Events [Abstract]
Subsequent Event	Subsequent Events
	Distributions
	On January 22, 2015, our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of December 2014 of $0.21 per common and Class B unit ($2.52 on an annualized basis) that was paid on February 13, 2015 to Vanguard unitholders of record on February 2, 2015.
	Also on January 22, 2015, our board of directors declared a cash distribution for our preferred unitholders of $0.1641 per Series A Cumulative Preferred Unit, $0.15885 per Series B Cumulative Preferred Unit and $0.16146 per Series C Cumulative Preferred Unit to that was paid on February 13, 2015 to Vanguard preferred unitholders of record on February 2, 2015.
	On February 17, 2015, our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of January 2015 of $0.1175 per common and Class B unit, or $1.41 on an annualized basis, which will be paid on March 17, 2015 to Vanguard unitholders of record on March 2, 2015. This represents a reduction from the distribution attributable to the month of December 2014 of $0.21 per common and Class B unit, or $2.52 on an annualized basis.
	Also on February 17, 2015, our board of directors declared and maintained a cash distribution for our preferred unitholders of $0.1641 per Series A Cumulative Preferred Unit, $0.15885 per Series B Cumulative Preferred Unit and $0.16146 per Series C Cumulative Preferred Unit, which will be paid on March 16, 2015 to Vanguard preferred unitholders of record on March 2, 2015.
	Shelf Registration Statement
	On February 13, 2015, we filed a new shelf registration statement to replace our previous shelf registration statement which expired in January 2015.
	Restructured Hedge Portfolio (Unaudited)
	We have taken steps to restructure our hedge portfolio to limit further downside and volatility due to the current commodity price environment. Specifically, we have converted a significant portion of our three-way collars in 2015 to fixed-price swaps or lowered the pricing on existing short puts. We have implemented a hedging program for approximately 77% and 45% of our anticipated crude oil production in 2015 and 2016, respectively, with 88% in the form of fixed-price swaps in 2015. Approximately 82% and 67% of our natural gas production in 2015 and 2016, respectively, is hedged with 98% in the form of fixed-price swaps in 2015. NGLs production is under fixed-price swaps for approximately 9% of anticipated production in 2015.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation and Principles of Consolidation	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.
Description of New Accounting Pronouncements Not yet Adopted [Text Block]	In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU No. 2014-09”), which amends the FASB ASC by adding new FASB ASC Topic 606, Revenue from Contracts with Customers, and superseding the revenue recognition requirements in FASB ASC 605, Revenue Recognition, and in most industry-specific topics. The standard provides new guidance concerning recognition and measurement of revenue and requires additional disclosures about the nature, timing and uncertainty of revenue and cash flows arising from contracts with customers. ASU No. 2014-09 is effective for annual periods beginning after December 15, 2016, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are evaluating the impact of the pending adoption of ASU No. 2014-09 on our financial position and results of operations and have not yet determined the method by which it will adopt the standard in 2017.
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 natural gas liquids (“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.
	We recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2014 of $234.4 million as a result of a decline in realized oil and natural gas prices at the measurement date, December 31, 2014. Such impairment was recognized during the fourth quarter of 2014. The most significant factor affecting the 2014 impairment related to the properties that we acquired in the Piceance Acquisition. The fair value of the properties acquired (determined using forward oil and natural gas price curves at the acquisitions dates) was higher than the discounted estimated future cash flows computed using the 12-month average prices at the impairment test measurement dates. However, the impairment calculations did not consider the positive impact of our commodity derivative positions as generally accepted accounting principles only allow the inclusion of derivatives designated as cash flow hedges. The fourth quarter 2014 impairment was calculated based on prices of $4.36 per MMBtu for natural gas and $94.87 per barrel of crude oil. No ceiling test impairment was required during 2013.
	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 using a two-step process. The goodwill test is performed at the reporting unit level, which represents our oil and natural gas operations in the United States. The first step involves a comparison of the estimated fair value of a reporting unit to its net book value, which is its carrying amount, including goodwill. In performing the first step, we determine the fair value of the reporting unit using the market approach. Determining fair value requires the exercise of significant judgment, including judgments about market prices and other relevant information generated by market transactions involving identical or comparable assets, liabilities, or a group of assets and liabilities, such as a business. If the estimated fair value of the reporting unit exceeds its net book value, goodwill of the reporting unit is not impaired and the second step of the impairment test is not necessary. If the net book value of the reporting unit exceeds its fair value, the second step of the goodwill impairment test will be performed to measure the amount of impairment loss, if any. The second step of the goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination. In other words, the estimated fair value of the reporting unit is allocated to all of the assets and liabilities of that unit (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination and the fair value of the reporting unit was the purchase price paid. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess.
	We performed our annual impairment tests during 2014, 2013 and 2012 and our analyses concluded that there was no impairment of goodwill as of these dates. However, due to the current decline in the prices of oil and natural gas as well as deteriorating market conditions, we performed an interim impairment test at December 31, 2014. Based on our estimates, the fair value of our reporting unit exceeded its carrying value by 8% at December 31, 2014 and therefore the second step of the impairment test was not necessary. We believe this difference between the fair value and the net book value is appropriate (in the context of assessing whether a goodwill impairment may exist) when a market-based control premium is taken into account and in light of the recent volatility in the equity markets.
	While no goodwill impairment was recognized at December 31, 2014, any further significant decline in the prices of oil and natural gas as well as any continued declines in the quoted market price of the Company’s units 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, 2014, the net carrying value of this contract was $8.3 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 and Fairway gas plants. 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, 2014 and 2013, 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 primarily with counterparties that are also 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 2014, 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 tax basis of our net assets exceeded the net book basis by $187.0 million at December 31, 2014 while the book basis of our net assets exceeded the net tax basis by $168.5 million at December 31, 2013.
	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 $0.2 million and $0.3 million as of December 31, 2014 and 2013, respectively, and a deferred tax asset of $0.3 million and deferred tax liability of $0.4 million as of December 31, 2014 and 2013, respectively. A benefit of $0.6 million and tax provisions of $0.6 million and $0.2 million are included in our Consolidated Statements of Operations for the years ended December 31, 2014, 2013, and 2012, 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, 2014
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:
		2014	2013	2012
	Anadarko Petroleum Corporation	19%	1%	—%
	Marathon Oil Company	12%	14%	21%
	Plains Marketing L.P.	7%	10%	15%

Acquisitions_and_Divestiture_T

Acquisitions and Divestiture (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2014				2013		2012
		(in thousands, except per unit amounts) (Pro forma)
	Total revenues	$	944,246			$	841,576	$	557,802
	Net income (loss) attributable to Common and Class B unitholders	$	254,345			$	161,329	$	(174,187	)
	Net income (loss) attributable to Common and Class B unitholders, per unit:
	Basic	$	3.1			$	2.19	$	(3.18	)
	Diluted	$	3.07			$	2.17	$	(3.18	)
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
		31-Dec-12
	Revenues	$	3,267
	Net loss	$	(400	)
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 2014, 2013 and 2012 Consolidated Statements of Operations for our acquisitions. Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes.
		Year Ended December 31,
		2014				2013		2012
		(in thousands)
	Pinedale Acquisition
	Revenues	$	139,908			$	—	$	—
	Excess of revenues over direct operating expenses	$	107,934			$	—	$	—
	Piceance Acquisition
	Revenues	$	22,642			$	—	$	—
	Excess of revenues over direct operating expenses	$	15,234			$	—	$	—
	Arkoma Basin Acquisition
	Revenues	$	62,450			$	55,468	$	24,673
	Excess of revenues over direct operating expenses	$	48,847			$	45,090	$	19,971
	Rockies Acquisition
	Revenues	$	67,707			$	63,652	$	220
	Excess of revenues over direct operating expenses	$	40,505			$	41,583	$	164
	All other acquisitions
	Revenues	$	79,009			$	37,096	$	1,535
	Excess of revenues over direct operating expenses	$	51,956			$	24,912	$	992
Pinedale 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 $32.1 million, as reflected in the table below, primarily due to the increase in natural gas prices between the date the purchase and sale agreement was entered into and the closing date.
	Fair value of assets and liabilities acquired		(in thousands)
	Oil and natural gas properties		$	600,123
	Inventory		244
	Asset retirement obligations		(12,404		)
	Imbalance liabilities		(171		)
	Other		(125		)
	Total fair value of assets and liabilities acquired		587,667
	Fair value of consideration transferred		555,553
	Gain on acquisition		$	32,114
Piceance Acquisition [Member]
Business Acquisition [Line Items]
Fair Value of Assets and Liabilities Acquired	In accordance with ASC Topic 805, this acquisition resulted in goodwill of $0.4 million, as reflected in the table below, which was immediately impaired and recorded as a loss in current period earnings. The loss resulted primarily from the changes in natural gas prices between the date the purchase and sale agreement was entered into and the closing date, which were used to value the reserves acquired.
	Fair value of assets and liabilities acquired		(in thousands)
	Oil and natural gas properties		$	521,401
	Asset retirement obligations		(19,452		)
	Imbalance and suspense liabilities		(236		)
	Total fair value of assets and liabilities acquired		501,713
	Fair value of consideration transferred		502,140
	Loss on acquisition		$	(427	)
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	)
Series of Individually Immaterial Business Acquisitions [Member]
Business Acquisition [Line Items]
Fair Value of Assets and Liabilities Acquired	The following presents the values assigned to the net assets acquired in our 2013 acquisitions:
	Fair value of assets and liabilities acquired:	(in thousands)
	Oil and natural gas properties	$	317,573
	Inventory	899
	Asset retirement obligations	(11,381		)
	Oil and natural gas revenue payable and imbalance liabilities	(2,843		)
	Total fair value of assets and liabilities acquired	304,248
	Fair value of consideration transferred	298,657
	Gain on acquisition	$	5,591

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Financing Arrangements	Our financing arrangements consisted of the following:
							Amount Outstanding December 31,
	Description		Interest Rate		Maturity Date		2014				2013
							(in thousands)
	Senior Secured Reserve-Based Credit Facility		Variable (1)		April 16, 2018		$	1,360,000			$	460,000
	Senior Notes		7.875% (2)		April 1, 2020		550,000				550,000
	Lease Financing Obligations		4.16% (3)		August 10, 2020 (4)		28,986				—
							$	1,938,986			$	1,010,000
	Less:
	Unamortized discount on Senior Notes						(1,852		)		(2,121		)
	Current portion						(4,318		)		—
	Total long-term debt						$	1,932,816			$	1,007,879
	-1	Variable interest rate was 2.17% and 1.92% at December 31, 2014 and 2013, respectively.
	-2	Effective interest rate is 8.0%.
	-3	Effective interest rate is 6.48%.
	-4	The Lease Financing Obligations expire on August 10, 2020 except for certain obligations which expire on July 10, 2021.
Borrowing Base Utilization Grid	At December 31, 2014, the applicable margin and other fees increase as the utilization of the borrowing base increases as follows:
	Borrowing Base Utilization Grid
	Borrowing Base Utilization Percentage		<25%			>25% <50%			>50% <75%			>75% <90%		>90%
	Eurodollar Loans Margin		1.5	%		1.75	%		2	%		2.25	%	2.5	%
	ABR Loans Margin		0.5	%		0.75	%		1	%		1.25	%	1.5	%
	Commitment Fee Rate		0.5	%		0.5	%		0.375	%		0.375	%	0.375	%
	Letter of Credit Fee		0.5	%		0.75	%		1	%		1.25	%	1.5	%

Price_and_Interest_Rate_Risk_M1

Price and Interest Rate Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivative Contracts Covering Anticipated Future Production	At December 31, 2014, 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, 2015 – December 31, 2015		66,795,000			$	4.4			692,000			$	91.18		246,375	$	46.34
	January 1, 2016 – December 31, 2016		55,083,000			$	4.47			146,400			$	89.98		—	$	—
	January 1, 2017 – December 31, 2017		27,677,000			$	4.32			73,000			$	86.6		—	$	—
	Call Options Sold
			Oil
	Contract Period		Bbls			Weighted
						Average
						Fixed Price
	January 1, 2015 – December 31, 2015		252,945			$	97.89
	January 1, 2016 – December 31, 2016		622,200			$	125
	Basis Swaps
			Gas
	Contract Period		MMBtu			Weighted Avg. Basis				Pricing Index
						Differential
						($/MMBtu)
	January 1, 2015 – December 31, 2015		29,200,000			$	(0.28	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2016 – December 31, 2016		18,300,000			$	(0.24	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
	January 1, 2017 – December 31, 2017		10,950,000			$	(0.22	)		Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
			Oil
	Contract Period		Bbls			Weighted Avg. Basis				Pricing Index
						Differential ($/Bbl)
	January 1, 2015 – December 31, 2015		511,000			$	(1.68	)		WTI Midland and WTI Cushing Basis Differential
	January 1, 2015 – December 31, 2015		146,000			$	(2.33	)		West Texas Sour and WTI Cushing Basis Differential
	Three-Way Collars
			Gas
	Contract Period		MMbtu			Floor				Ceiling				Put Sold
	January 1, 2015 – December 31, 2015		17,337,500			$	3.99			$	4.67			$	3.38
	January 1, 2016 – December 31, 2016		12,810,000			$	3.95			$	4.58			$	3.38
	January 1, 2017 – December 31, 2017		12,775,000			$	3.97			$	4.61			$	3.4
			Oil
	Contract Period		Bbls			Floor				Ceiling				Put Sold
	January 1, 2015 – December 31, 2015		1,984,055			$	92.05			$	95.74			$	74.41
	January 1, 2016 – December 31, 2016		1,061,400			$	90			$	96.18			$	73.62
	Put Options Sold
			Gas							Oil
	Contract Period		MMbtu			Put Sold ($/MMbtu)				Bbls			Put Sold ($/Bbl)
	January 1, 2015 – December 31, 2015		9,125,000			$	3.5			692,000			$	72.36
	January 1, 2016 – December 31, 2016		1,830,000			3.5				146,400			$	75
	January 1, 2017 – December 31, 2017		1,825,000			3.5				73,000			$	75
	Range Bonus Accumulators
			Gas
	Contract Period		MMBtu			Bonus				Range Ceiling				Range Floor
	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, 2015 – December 31, 2015		182,500			$	4			$	100			$	75
	January 1, 2016 – December 31, 2016		183,000			$	4			$	100			$	75
Interest Rate Derivative Contracts	At December 31, 2014, the Company had open interest rate derivative contracts as follows (in thousands):
			Notional Amount				Fixed LIBOR Rates
	Period:
	January 1, 2015 to December 10, 2016		$	20,000			2.17	%
	January 1, 2015 to October 31, 2016		$	40,000			1.65	%
	January 1, 2015 to August 5, 2015 (1)		$	30,000			2.25	%
	January 1, 2015 to August 6, 2016		$	25,000			1.8	%
	January 1, 2015 to October 31, 2016		$	20,000			1.78	%
	January 1, 2015 to September 23, 2016		$	75,000			1.15	%
	January 1, 2015 to March 7, 2016		$	75,000			1.08	%
	January 1, 2015 to September 7, 2016		$	25,000			1.25	%
	January 1, 2015 to December 10, 2015 (2)		$	50,000			0.21	%
	Total		$	360,000
	-1	The counterparty has the option to extend the termination date of this contract 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, 2014
	Offsetting Derivative Assets:		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
	Commodity price derivative contracts		$	289,018			$	(63,321	)		$	225,697
	Total derivative instruments		$	289,018			$	(63,321	)		$	225,697
	Offsetting Derivative Liabilities:		Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
	Commodity price derivative contracts		$	(63,615	)		$	63,321			$	(294	)
	Interest rate derivative contracts		(4,669		)		—				(4,669		)
	Total derivative instruments		$	(68,284	)		$	63,321			$	(4,963	)
			December 31, 2013
	Offsetting Derivative Assets:		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
	Commodity price derivative contracts		$	107,307			$	(25,617	)		$	81,690
	Interest rate derivative contracts		98				—				98
	Total derivative instruments		$	107,405			$	(25,617	)		$	81,788
	Offsetting Derivative Liabilities:		Gross Amounts of Recognized Liabilities				Gross Amounts Offset in the Consolidated Balance Sheets				Net Amounts Presented in the Consolidated Balance Sheets
	Commodity price derivative contracts		$	(33,825	)		$	25,617			$	(8,208	)
	Interest rate derivative contracts		(6,869		)		—				(6,869		)
	Total derivative instruments		$	(40,694	)		$	25,617			$	(15,077	)
Reported Gains and Losses on Derivative Instruments	The change in fair value of our commodity and interest rate derivatives for the years ended December 31, 2014, 2013 and 2012 is as follows:
		2014				2013				2012
		(in thousands)
	Derivative asset (liability) at January 1, net	$	66,711			$	82,568			$	(29,889	)
	Purchases
	Fair value of derivatives acquired through business combinations	(1,344		)		—				109,495
	Premiums and fees paid or deferred for derivative contracts during the period	—				—				9,695
	Net gains on commodity and interest rate derivative contracts	161,519				11,160				29,854
	Settlements
	Net cash settlements received on matured commodity derivative contracts	(10,187		)		(30,905		)		(39,102		)
	Net cash settlements paid on matured interest rate derivative contracts	4,035				3,888				2,515
	Derivative asset at December 31, net	$	220,734			$	66,711			$	82,568

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Financial Assets and Financial Liabilities Measured at Fair Value on a Recurring Basis	Financial assets and financial liabilities measured at fair value on a recurring basis are summarized below (in thousands):
		31-Dec-14
		Fair Value Measurements Using									Assets/Liabilities at Fair Value
		Level 1			Level 2			Level 3
		(in thousands)
	Assets:
	Commodity price derivative contracts	$	—		$	232,167		$	(6,470	)	$	225,697
	Total derivative instruments	$	—		$	232,167		$	(6,470	)	$	225,697
	Liabilities:
	Commodity price derivative contracts	$	—		$	(294	)	$	—		$	(294	)
	Interest rate derivative contracts	—			(4,669		)	—			(4,669		)
	Total derivative instruments	$	—		$	(4,963	)	$	—		$	(4,963	)
		31-Dec-13
		Fair Value Measurements Using									Assets/Liabilities
		Level 1			Level 2			Level 3			at Fair value
		(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	)
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:
		2014			2013
		(in thousands)
	Unobservable inputs at January 1,	$	566		$	(498	)
	Total losses	(8,238		)	(134		)
	Settlements	1,202			1,198
	Unobservable inputs at December 31,	$	(6,470	)	$	566
	Change in fair value included in earnings related to derivatives still held as of December 31, 2014	$	(6,326	)	$	1,126

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
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:
		2014			2013
		(in thousands)
	Asset retirement obligation at January 1,	$	87,967		$	63,114
	Liabilities added during the current period	52,829			11,738
	Accretion expense	5,889			2,789
	Change in estimate	4,118			10,954
	Disposition of properties	(1,291		)	—
	Retirements	(450		)	(628		)
	Total asset retirement obligation at December 31,	149,062			87,967
	Less: current obligations	(2,386		)	(5,759		)
	Long-term asset retirement obligation at December 31,	$	146,676		$	82,208

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014. However, our financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property.
		(in thousands)
	2015	$	17,454
	2016	13,986
	2017	11,840
	2018	11,261
	2019	9,661
	Thereafter	410
	Total	$	64,612

Members_Equity_and_Net_Income_1

Members' Equity and Net Income per Common and Class B Unit (Tables)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Cumulative Preferred Units	The following table summarizes the Company’s Cumulative Preferred units outstanding at December 31, 2014 and 2013:
								2014					2013
		Earliest		Liquidation Preference		Distribution Rate		Units Outstanding			Carrying Value		Units Outstanding	Carrying Value
		Redemption Date		Per Share							(in thousands)			(in thousands)
	Series A	15-Jun-23		$25.00		7.88%		2,581,873			$	62,200	2,535,927	$	61,021
	Series B	15-Apr-24		$25.00		7.63%		7,000,000			$	169,265	—	$	—
	Series C	15-Oct-24		$25.00		7.75%		4,300,000			$	103,979	—	$	—
	Total Cumulative Preferred Units							13,881,873			$	335,444	2,535,927	$	61,021
Common and Class B Units outstanding	The following is a summary of the changes in our common units issued during the years ended December 31, 2014, 2013 and 2012 (in thousands):
		2014			2013			2012
	Beginning of period	78,337			58,706			48,320
	Common units received in exchange for the Appalachian Basin properties	—			—			(1,900	)
	Issuance of Common units for the acquisition of oil and natural	—			1,075			—
	gas properties
	Issuance of Common units for cash	4,864			18,377			12,149
	Repurchase of units under the common unit buyback program	(135	)		—			—
	Unit-based compensation	386			179			87
	Options exercised	—			—			50
	End of period	83,452			78,337			58,706
Schedule of Earnings per unit, basic and diluted	The net income (loss) attributable to common and Class B unitholders and the weighted average units for calculating basic and diluted net income per common and Class B unit were as follows (in thousands, except per unit data):
		2014				2013				2012(a)
	Net income (loss) attributable to Common and Class B unitholders	$	46,148			$	56,877			$	(168,815	)
	Weighted average number of Common and Class B units outstanding - basic	82,031				73,064				54,197
	Effect of dilutive securities:
	Phantom units	428				348				—
	Weighted average number of Common and Class B units outstanding - diluted	82,459				73,412				54,197
	Net income (loss) per Common and Class B unit
	Basic	$	0.56			$	0.78			$	(3.11	)
	Diluted	$	0.55			$	0.77			$	(3.11	)
Distributions Declared
		Cash Distributions
	Distribution	Per Unit				Declared Date		Record Date		Payment Date
	2014
	Fourth Quarter
	November	$	0.21			December 16, 2014		January 2, 2015		January 14, 2015
	October	$	0.21			November 20, 2014		December 1, 2014		December 15, 2014
	Third Quarter
	September	$	0.21			October 20, 2014		November 3, 2014		November 14, 2014
	August	$	0.21			September 19, 2014		October 1, 2014		October 15, 2014
	July	$	0.21			August 19, 2014		September 2, 2014		September 12, 2014
	Second Quarter
	June	$	0.21			July 16, 2014		August 1, 2014		August 14, 2014
	May	$	0.21			June 24, 2014		July 1, 2014		July 15, 2014
	April	$	0.21			May 20, 2014		June 2, 2014		June 13, 2014
	First Quarter
	March	$	0.21			April 17, 2014		May 1, 2014		May 15, 2014
	February	$	0.21			March 17, 2014		April 1, 2014		April 14, 2014
	January	$	0.2075			February 2, 2014		March 3, 2014		March 17, 2014
	2013
	Fourth Quarter
	December	$	0.2075			January 16, 2014		February 3, 2014		February 14, 2014
	November	$	0.2075			December 17, 2013		January 2, 2014		January 15, 2014
	October	$	0.2075			November 19, 2013		December 2, 2013		December 13, 2013
	Third Quarter
	September	$	0.2075			October 21, 2013		November 1, 2013		November 14, 2013
	August	$	0.2075			September 12, 2013		October 1, 2013		October 15, 2013
	July	$	0.2075			August 20, 2013		September 3, 2013		September 13, 2013
	Second Quarter
	June	$	0.205			July 18, 2013		August 1, 2013		August 14, 2013
	May	$	0.205			June 20, 2013		July 1, 2013		July 15, 2013
	April	$	0.205			April 30, 2013		June 3, 2013		June 14, 2013
	First Quarter
	March	$	0.2025			April 19, 2013		May 1, 2013		May 15, 2013
	February	$	0.2025			March 21, 2013		April 1, 2013		April 12, 2013
	January	$	0.2025			February 18, 2013		March 1, 2013		March 15, 2013
	2012
	Fourth Quarter
	December	$	0.2025			January 25, 2013		February 4, 2013		February 14, 2013
	November	$	0.2025			December 19, 2012		January 2, 2013		January 14, 2013
	October	$	0.2025			November 16, 2012		December 3, 2012		December 14, 2012
	Third Quarter
	September	$	0.2			October 18, 2012		November 1, 2012		November 14, 2012
	August	$	0.2			September 17, 2012		October 1, 2012		October 15, 2012
	July	$	0.2			August 20, 2012		September 4, 2012		September 14, 2012
	Second Quarter	$	0.6			July 23, 2012		August 7, 2012		August 14, 2012
	First Quarter	$	0.5925			April 24, 2012		May 8, 2012		May 15, 2012
	2011
	Fourth Quarter	$	0.5875			January 18, 2012		February 7, 2012		February 14, 2012

UnitBased_Compensation_UnitBas

Unit-Based Compensation Unit-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Nonvested Restricted Units Activity [Table Text Block]	As of December 31, 2014, a summary of the status of the non-vested restricted 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, 2013	248,611		$	28.57
	Granted	291,824		$	29.02
	Forfeited	(9,047	)	$	29.54
	Vested	(91,341	)	$	28.48
	Non-vested units at December 31, 2014	440,047		$	28.87
Schedule of Nonvested Phantom Units, Activity [Table Text Block]	As of December 31, 2014, a summary of the status of the non-vested phantom units under the VNR LTIP is presented below:
		Number of		Weighted Average
		Non-vested Phantom Units		Grant Date Fair Value
	Non-vested units at December 31, 2013	482,735		$	28.67
	Forfeited	(12,539	)	$	28.35
	Vested	(139,875	)	$	28.92
	Non-vested units at December 31, 2014	330,321		$	28.58

Description_of_the_Business_De

Description of the Business (Details)	3 Months Ended			12 Months Ended
	Dec. 31, 2014	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2014
				operating_areas
Accounting Policies [Abstract]
Average price of crude oil used in the impairment calculation (per barrel)	94.87	94.67	95.26
Number of operating areas				9

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, 2014	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Discount rate used in determining limitation of capitalized costs				10.00%
Impairment of oil and natural gas properties				$234,434	$0	$247,722
Average price of natural gas used in the impairment calculation	4.36	2.76	2.77
Average price of crude oil used in the impairment calculation (per barrel)	94.87	94.67	95.26

Summary_of_Significant_Account4

Summary of Significant Accounting Policies (Other Intangible Assets) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Other Intangible Assets
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount	0.00%
Contract [Member]
Estimated aggregate amortization expense for each of the next five fiscal years
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	0.2
Finite-Lived Intangible Assets, Amortization Expense, Year Two	0.2
Finite-Lived Intangible Assets, Amortization Expense, Year Three	0.2
Finite-Lived Intangible Assets, Amortization Expense, Year Four	0.2
Finite-Lived Intangible Assets, Amortization Expense, Year Five	0.2
Contract [Member] | Other assets [Member]
Other Intangible Assets
Net carrying value of contract	8.3

Summary_of_Significant_Account5

Summary of Significant Accounting Policies (Concentrations of Credit Risk) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenue, Major Purchasers
Concentration Risk, Number of Financial Institutions	1	1
Customer Concentration Risk [Member] | Sales [Member] | Anadarko Petroleum Corporation [Member]
Revenue, Major Purchasers
Major purchasers, percent of sales	19.00%	1.00%	0.00%
Customer Concentration Risk [Member] | Sales [Member] | Marathon Oil Company [Member]
Revenue, Major Purchasers
Major purchasers, percent of sales	0.00%	14.00%	21.00%
Customer Concentration Risk [Member] | Sales [Member] | Plains Marketing L.P. [Member]
Revenue, Major Purchasers
Major purchasers, percent of sales	0.00%	10.00%	15.00%

Summary_of_Significant_Account6

Summary of Significant Accounting Policies (Income Taxes) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revised Texas Franchise Tax
Entity Not Subject to Income Taxes, Differences in Bases, Amount	$187	$168.50
Texas [Member]
Revised Texas Franchise Tax
Current tax liability	-0.2	-0.3
Deferred tax asset	0.3
Deferred tax liability		-0.4
Tax provisions	$0.60	$0.60	$0.20

Acquisitions_and_Divestiture_D

Acquisitions and Divestiture (Details) (USD $)

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

Mar. 30, 2012

Dec. 31, 2012

Jan. 31, 2014

Sep. 30, 2014

2-May-14

Aug. 29, 2014

Jun. 28, 2013

Apr. 02, 2013

Dec. 31, 2014

Dec. 31, 2013

Jun. 30, 2012

Dec. 31, 2012

Business Acquisition [Line Items]

Goodwill

$420,955,000

$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

52,500,000

-52,480,000

Noncash Consideration After Closing Adjustments

52,500,000

Closing Adjustment Under Unit Exchange Agreement

1,400,000

Pinedale Acquisition [Member]

Business Acquisition [Line Items]

Purchase price of acquired entity

555,553,000

Gain on acquisition

32,114,000

Effective date of acquisition

1-Oct-13

Piceance Acquisition [Member]

Business Acquisition [Line Items]

Purchase price of acquired entity

502,140,000

Effective date of acquisition

1-Jul-14

Goodwill

427,000

Wamsutter Property Acquisition [Member]

Business Acquisition [Line Items]

Purchase price of acquired entity

6,800,000

Effective date of acquisition

1-Jan-14

Ownership interest conveyed

75.00%

Gulf Coast Acquisition [Member]

Business Acquisition [Line Items]

Purchase price of acquired entity

269,900,000

Effective date of acquisition

1-Jun-14

Series of Individually Immaterial Business Acquisitions [Member]

Business Acquisition [Line Items]

Purchase price of acquired entity

24,800,000

266,200,000

17,700,000

298,657,000

Gain on acquisition

5,591,000

6,000,000

Effective date of acquisition

1-Jul-13

1-Jan-13

Purchase price of acquired entity paid in common equity

29,900,000

Number of shares issued

1,075,000

Shares issued, agreed share price

$27.65

Shares issued, closing price

$27.90

Other smaller acquisitions [Member]

Business Acquisition [Line Items]

Purchase price of acquired entity

2,500,000

Arkoma Basin Acquisition [Member]

Business Acquisition [Line Items]

Date definitive agreement entered

1-Jun-12

Purchase price of acquired entity

428,541,000

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

14,126,000

Effective date of acquisition

1-Apr-12

Rockies Acquisition [Member]

Business Acquisition [Line Items]

Date definitive agreement entered

31-Oct-12

Purchase price of acquired entity

324,650,000

Effective date of acquisition

1-Oct-12

Working interest 2013

18.00%

Working interest 2014

21.00%

Working interest 2015

24.00%

Working interest 2016

26.00%

Goodwill

$8,818,000

Acquisitions_and_Divestiture_A

Acquisitions and Divestiture (Aggregate Values Assigned to Net Assets Acquired) (Details) (USD $)	0 Months Ended	12 Months Ended			0 Months Ended
In Thousands, unless otherwise specified	Apr. 02, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2014	Jan. 31, 2014	Jun. 30, 2012	Dec. 31, 2012
Fair value of assets and liabilities acquired:
Loss on acquisition		($420,955)	($420,955)
Series of Individually Immaterial Business Acquisitions [Member]
Fair value of assets and liabilities acquired:
Oil and natural gas properties		317,573
Other assets		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	-266,200	-17,700	-298,657	-24,800
Gain on acquisition		5,591	6,000
Piceance Acquisition [Member]
Fair value of assets and liabilities acquired:
Oil and natural gas properties					521,401
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other					-236
Asset retirement obligations					-19,452
Total fair value of assets and liabilities acquired					501,713
Fair value of consideration transferred					-502,140
Loss on acquisition					-427
Pinedale Acquisition [Member]
Fair value of assets and liabilities acquired:
Oil and natural gas properties						600,123
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory						244
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other						-171
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable						-125
Asset retirement obligations						-12,404
Total fair value of assets and liabilities acquired						587,667
Fair value of consideration transferred						-555,553
Gain on acquisition						32,114
Arkoma Basin Acquisition [Member]
Fair value of assets and liabilities acquired:
Oil and natural gas properties							344,747
Value of derivatives assumed							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]
Fair value of assets and liabilities acquired:
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)

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Partners' Capital Account, Units, Converted	1,900
Pro Forma Information
Total revenues		$944,246	$841,576	$557,802
Net income (loss)		254,345	161,329	-174,187
Net income (loss) attributable to Common and Class B unitholders, per unit:
Business Acquisition, Pro Forma Earnings Per Share, Basic		$3.10	$2.19	($3.18)
Business Acquisition, Pro Forma Earnings Per Share, Diluted		$3.07	$2.17	($3.18)
Unit Exchange [Member]
Pro Forma Information
Total revenues			3,267
Net income (loss)			($400)

Acquisitions_and_Divestiture_A1

Acquisitions and Divestiture (Acquiree Earnings) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pinedale Acquisition [Member]
Business Acquisition [Line Items]
Revenues	$139,908	$0	$0
Excess of revenues over direct operating expenses	107,934	0	0
Piceance Acquisition [Member]
Business Acquisition [Line Items]
Revenues	22,642	0	0
Excess of revenues over direct operating expenses	15,234	0	0
Arkoma Basin Acquisition [Member]
Business Acquisition [Line Items]
Revenues	62,450	55,468	24,673
Excess of revenues over direct operating expenses	48,847	45,090	19,971
Rockies Acquisition [Member]
Business Acquisition [Line Items]
Revenues	67,707	63,652	220
Excess of revenues over direct operating expenses	40,505	41,583	164
Series of Individually Immaterial Business Acquisitions [Member]
Business Acquisition [Line Items]
Revenues	79,009	37,096	1,535
Excess of revenues over direct operating expenses	$51,956	$24,912	$992

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Oct. 30, 2014	Sep. 30, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Debt amount outstanding	$1,938,986,000			$1,010,000,000
Purchase of equipment at early buyout date	16,000,000
Maximum amount of restricted payment for unit repurchase allowed under the credit agreement		50,000,000	10,000,000
Senior Notes [Abstract]
Percentage of ownership (in hundredths)	100.00%
Line of Credit [Member]
Debt Instrument [Line Items]
Maximum facility size	3,500,000,000
Borrowing base	2,000,000,000
Maturity date	16-Apr-18
Debt amount outstanding	1,360,000,000			460,000,000
Remaining borrowing capacity	634,500,000
Senior Notes [Abstract]
Authorized distribution to unitholders	245,000,000
Line of Credit [Member] | Standby Letters of Credit [Member]
Debt Instrument [Line Items]
Borrowing base	5,500,000
Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Effective Percentage	8.00%
Maturity date	1-Apr-20
Debt amount outstanding	550,000,000			550,000,000
Senior Notes [Abstract]
Stated interest rate (in hundredths)	7.88%
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%
Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Effective Percentage	6.48%
Maximum facility size		35,000,000	2,000,000
Maturity date	10-Aug-20
Debt amount outstanding	$28,986,000			$0
Senior Notes [Abstract]
Stated interest rate (in hundredths)	4.16%

LongTerm_Debt_Financing_Arrang

Long-Term Debt (Financing Arrangements) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Debt amount outstanding	$1,938,986	$1,010,000
Unamortized discount on Senior Notes	-1,852	-2,121
Short-term Debt	-4,318	0
Total long-term debt	1,932,816	1,007,879
Line of Credit [Member]
Debt Instrument [Line Items]
Interest rate description	Variable (1)
Maturity date	16-Apr-18
Debt amount outstanding	1,360,000	460,000
Variable interest rate (in hundredths)	2.17%	1.92%
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
Debt Instrument, Interest Rate, Effective Percentage	8.00%
Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Stated interest rate (in hundredths)	4.16%
Maturity date	10-Aug-20
Debt amount outstanding	$28,986	$0
Debt Instrument, Interest Rate, Effective Percentage	6.48%

LongTerm_Debt_Borrowing_Base_U

Long-Term Debt (Borrowing Base Utilization Grid) (Details)	12 Months Ended
	Dec. 31, 2014
Borrowing Base Utilization Less Than 25% [Member]
Debt Instrument [Line Items]
Commitment fee rate (in hundredths)	0.50%
Letter of credit fee (in hundredths)	0.50%
Borrowing Base Utilization Less Than 25% [Member] | Eurodollar Loans Margin [Member]
Debt Instrument [Line Items]
Loans margin (in hundredths)	1.50%
Borrowing Base Utilization Less Than 25% [Member] | ABR Loans Margin [Member]
Debt Instrument [Line Items]
Loans margin (in hundredths)	0.50%
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50% [Member]
Debt Instrument [Line Items]
Commitment fee rate (in hundredths)	0.50%
Letter of credit fee (in hundredths)	0.75%
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50% [Member] | Eurodollar Loans Margin [Member]
Debt Instrument [Line Items]
Loans margin (in hundredths)	1.75%
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50% [Member] | ABR Loans Margin [Member]
Debt Instrument [Line Items]
Loans margin (in hundredths)	0.75%
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75% [Member]
Debt Instrument [Line Items]
Commitment fee rate (in hundredths)	0.38%
Letter of credit fee (in hundredths)	1.00%
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75% [Member] | Eurodollar Loans Margin [Member]
Debt Instrument [Line Items]
Loans margin (in hundredths)	2.00%
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75% [Member] | ABR Loans Margin [Member]
Debt Instrument [Line Items]
Loans margin (in hundredths)	1.00%
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90% [Member]
Debt Instrument [Line Items]
Commitment fee rate (in hundredths)	0.38%
Letter of credit fee (in hundredths)	1.25%
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90% [Member] | Eurodollar Loans Margin [Member]
Debt Instrument [Line Items]
Loans margin (in hundredths)	2.25%
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90% [Member] | ABR Loans Margin [Member]
Debt Instrument [Line Items]
Loans margin (in hundredths)	1.25%
Borrowing Base Utilization Equal To Or Greater Than 90% [Member]
Debt Instrument [Line Items]
Commitment fee rate (in hundredths)	0.38%
Letter of credit fee (in hundredths)	1.50%
Borrowing Base Utilization Equal To Or Greater Than 90% [Member] | Eurodollar Loans Margin [Member]
Debt Instrument [Line Items]
Loans margin (in hundredths)	2.50%
Borrowing Base Utilization Equal To Or Greater Than 90% [Member] | ABR Loans Margin [Member]
Debt Instrument [Line Items]
Loans margin (in hundredths)	1.50%

Price_and_Interest_Rate_Risk_M2

Price and Interest Rate Risk Management Activities (Derivative Contracts Covering Aniticipated Future Production) (Details)	12 Months Ended
	Dec. 31, 2014
	MMBTU
Fixed-Price Swaps [Member] | Oil [Member] | January 1, 2015 - December 31, 2015 [Member]
Derivative [Line Items]
Weighted average price of derivative (in dollars per unit)	91.18
Portion of Future Oil and Gas Production Being Hedged	692,000
Fixed-Price Swaps [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member]
Derivative [Line Items]
Weighted average price of derivative (in dollars per unit)	89.98
Portion of Future Oil and Gas Production Being Hedged	146,400
Fixed-Price Swaps [Member] | Oil [Member] | January 1, 2017 - December 31, 2017 [Member]
Derivative [Line Items]
Weighted average price of derivative (in dollars per unit)	86.6
Portion of Future Oil and Gas Production Being Hedged	73,000
Fixed-Price Swaps [Member] | Natural Gas [Member] | January 1, 2015 - December 31, 2015 [Member]
Derivative [Line Items]
Anticipated future gas production (in units)	66,795,000
Weighted average price of derivative (in dollars per unit)	4.4
Fixed-Price Swaps [Member] | Natural Gas [Member] | January 1, 2016 - December 31, 2016 [Member]
Derivative [Line Items]
Anticipated future gas production (in units)	55,083,000
Weighted average price of derivative (in dollars per unit)	4.47
Fixed-Price Swaps [Member] | Natural Gas [Member] | January 1, 2017 - December 31, 2017 [Member]
Derivative [Line Items]
Anticipated future gas production (in units)	27,677,000
Weighted average price of derivative (in dollars per unit)	4.32
Fixed-Price Swaps [Member] | Natural Gas Liquids [Member] | January 1, 2015 - December 31, 2015 [Member]
Derivative [Line Items]
Weighted average price of derivative (in dollars per unit)	46.34
Portion of Future Oil and Gas Production Being Hedged	246,375
Fixed-Price Swaps [Member] | Natural Gas Liquids [Member] | January 1, 2016 - December 31, 2016 [Member]
Derivative [Line Items]
Weighted average price of derivative (in dollars per unit)	0
Portion of Future Oil and Gas Production Being Hedged	0
Fixed-Price Swaps [Member] | Natural Gas Liquids [Member] | January 1, 2017 - December 31, 2017 [Member]
Derivative [Line Items]
Weighted average price of derivative (in dollars per unit)	0
Portion of Future Oil and Gas Production Being Hedged	0
Call Option [Member] | Oil [Member] | January 1, 2015 - December 31, 2015 [Member]
Derivative [Line Items]
Weighted average price of derivative (in dollars per unit)	97.89
Portion of Future Oil and Gas Production Being Hedged	252,945
Call Option [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member]
Derivative [Line Items]
Weighted average price of derivative (in dollars per unit)	125
Portion of Future Oil and Gas Production Being Hedged	622,200
Three-Way Collars [Member] | Oil [Member] | January 1, 2015 - December 31, 2015 [Member]
Derivative [Line Items]
Floor (in dollars per unit)	92.05
Ceiling (in dollars per unit)	95.74
Derivative, Average Price Risk Option Strike Price	74.41
Portion of Future Oil and Gas Production Being Hedged	1,984,055
Three-Way Collars [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member]
Derivative [Line Items]
Floor (in dollars per unit)	90
Ceiling (in dollars per unit)	96.18
Derivative, Average Price Risk Option Strike Price	73.62
Portion of Future Oil and Gas Production Being Hedged	1,061,400
Three-Way Collars [Member] | Natural Gas [Member] | January 1, 2015 - December 31, 2015 [Member]
Derivative [Line Items]
Anticipated future gas production (in units)	17,337,500
Floor (in dollars per unit)	3.99
Ceiling (in dollars per unit)	4.67
Derivative, Average Price Risk Option Strike Price	3.38
Three-Way Collars [Member] | Natural Gas [Member] | January 1, 2016 - December 31, 2016 [Member]
Derivative [Line Items]
Anticipated future gas production (in units)	12,810,000
Floor (in dollars per unit)	3.95
Ceiling (in dollars per unit)	4.58
Derivative, Average Price Risk Option Strike Price	3.38
Three-Way Collars [Member] | Natural Gas [Member] | January 1, 2017 - December 31, 2017 [Member]
Derivative [Line Items]
Anticipated future gas production (in units)	12,775,000
Floor (in dollars per unit)	3.97
Ceiling (in dollars per unit)	4.61
Derivative, Average Price Risk Option Strike Price	3.4
Put Option Sold [Member] | Oil [Member] | January 1, 2015 - December 31, 2015 [Member]
Derivative [Line Items]
Derivative, Average Price Risk Option Strike Price	72.36
Portion of Future Oil and Gas Production Being Hedged	692,000
Put Option Sold [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member]
Derivative [Line Items]
Derivative, Average Price Risk Option Strike Price	75
Portion of Future Oil and Gas Production Being Hedged	146,400
Put Option Sold [Member] | Oil [Member] | January 1, 2017 - December 31, 2017 [Member]
Derivative [Line Items]
Derivative, Average Price Risk Option Strike Price	75
Portion of Future Oil and Gas Production Being Hedged	73,000
Put Option Sold [Member] | Natural Gas [Member] | January 1, 2015 - December 31, 2015 [Member]
Derivative [Line Items]
Notional Volume (Bbls)	9,125,000
Derivative, Average Price Risk Option Strike Price	3.5
Put Option Sold [Member] | Natural Gas [Member] | January 1, 2016 - December 31, 2016 [Member]
Derivative [Line Items]
Notional Volume (Bbls)	1,830,000
Derivative, Average Price Risk Option Strike Price	3.5
Put Option Sold [Member] | Natural Gas [Member] | January 1, 2017 - December 31, 2017 [Member]
Derivative [Line Items]
Notional Volume (Bbls)	1,825,000
Derivative, Average Price Risk Option Strike Price	3.5
Range Bonus Accumulators [Member] | Oil [Member] | January 1, 2015 - December 31, 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	182,500
Bonus (in dollars per unit)	4
Derivative, Average Cap Price	100
Derivative, Average Floor Price	75
Range Bonus Accumulators [Member] | Oil [Member] | January 1, 2016 - December 31, 2016 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	183,000
Bonus (in dollars per unit)	4
Derivative, Average Cap Price	100
Derivative, Average Floor Price	75
Range Bonus Accumulators [Member] | Natural Gas [Member] | January 1, 2015 - December 31, 2015 [Member]
Derivative [Line Items]
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
NW Rocky Mt-Henry Hub Index [Member] | Basis Swaps [Member] | Natural Gas [Member] | January 1, 2015 - December 31, 2015 [Member]
Derivative [Line Items]
Anticipated future gas production (in units)	29,200,000
Weighted average basis differential (in dollars per unit)	-0.28
NW Rocky Mt-Henry Hub Index [Member] | Basis Swaps [Member] | Natural Gas [Member] | January 1, 2016 - December 31, 2016 [Member]
Derivative [Line Items]
Anticipated future gas production (in units)	18,300,000
Weighted average basis differential (in dollars per unit)	-0.24
NW Rocky Mt-Henry Hub Index [Member] | Basis Swaps [Member] | Natural Gas [Member] | January 1, 2017 - December 31, 2017 [Member]
Derivative [Line Items]
Anticipated future gas production (in units)	10,950,000
Weighted average basis differential (in dollars per unit)	-0.22
Midland-Cushing Index [Member] | Basis Swaps [Member] | Oil [Member] | January 1, 2015 - December 31, 2015 [Member]
Derivative [Line Items]
Weighted average basis differential (in dollars per unit)	-1.68
Portion of Future Oil and Gas Production Being Hedged	511,000
Midland-WTS Index [Member] | Basis Swaps [Member] | Oil [Member] | January 1, 2015 - December 31, 2015 [Member]
Derivative [Line Items]
Weighted average basis differential (in dollars per unit)	-2.33
Portion of Future Oil and Gas Production Being Hedged	146,000

Price_and_Interest_Rate_Risk_M3

Price and Interest Rate Risk Management Activities (Interest Rate Swaps) (Details) (Interest rate swaps [Member], USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Derivative [Line Items]
Notional amount	$360,000
January 1, 2015 to December 10, 2016 [Member]
Derivative [Line Items]
Notional amount	20,000
Fixed Libor Rates (in hundredths)	2.17%
January 1, 2015 to October 31, 2016 Swap A [Member]
Derivative [Line Items]
Notional amount	40,000
Fixed Libor Rates (in hundredths)	1.65%
January 1, 2015 to August 5, 2015 [Member]
Derivative [Line Items]
Notional amount	30,000	[1]
Fixed Libor Rates (in hundredths)	2.25%	[1]
January 1, 2015 to August 6, 2016 [Member]
Derivative [Line Items]
Notional amount	25,000
Fixed Libor Rates (in hundredths)	1.80%
January 1, 2015 to October 31, 2016 Swap B [Member]
Derivative [Line Items]
Notional amount	20,000
Fixed Libor Rates (in hundredths)	1.78%
January 1, 2015 to September 23, 2016 [Member]
Derivative [Line Items]
Notional amount	75,000
Fixed Libor Rates (in hundredths)	1.15%
January 1, 2015 to March 7, 2016 [Member]
Derivative [Line Items]
Notional amount	75,000
Fixed Libor Rates (in hundredths)	1.08%
January 1, 2015 to September 7, 2016 [Member]
Derivative [Line Items]
Notional amount	25,000
Fixed Libor Rates (in hundredths)	1.25%
January 1, 2015 to December 10, 2015 [Member]
Derivative [Line Items]
Notional amount	$50,000	[2]
Fixed Libor Rates (in hundredths)	0.21%	[2]
December 10, 2015 - December 10, 2017 [Member]
Derivative [Line Items]
Fixed Libor Rates (in hundredths)	0.91%
[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.

Price_and_Interest_Rate_Risk_M4

Price and Interest Rate Risk Management Activities (Balance Sheet Presentation) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$289,018	$107,405
Derivative Asset, Fair Value, Gross Liability	-63,321	-25,617
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	225,697	81,788
Derivative Liability, Fair Value, Gross Liability	-68,284	-40,694
Derivative Liability, Fair Value, Gross Asset	63,321	25,617
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-4,963	-15,077
Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	289,018	107,307
Derivative Asset, Fair Value, Gross Liability	-63,321	-25,617
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	225,697	81,690
Derivative Liability, Fair Value, Gross Liability	-63,615	-33,825
Derivative Liability, Fair Value, Gross Asset	63,321	25,617
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-294	-8,208
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset		98
Derivative Asset, Fair Value, Gross Liability		0
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		98
Derivative Liability, Fair Value, Gross Liability	-4,669	-6,869
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	($4,669)	($6,869)

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, 2014
In Thousands, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Maximum potential loss due to credit risk	$289,000

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Net Derivative Asset (Liability), Reconciliation [Roll Forward]
Derivative asset/(liability) at beginning of year, net	$66,711	$82,568	($29,889)
Fair value of derivative contracts acquired through business combinations	-1,344	0	109,495
Premiums and fees paid or deferred for derivative contracts during the period	0	0	9,695
Net (gains) losses on commodity and interest rate derivative contracts	161,519	11,160	29,854
Cash settlements received on matured commodity derivative contracts	-10,187	-30,905	-39,102
Cash settlements paid on matured interest rate derivative contracts	4,035	3,888	2,515
Derivative asset/(liability) at end of year, net	$220,734	$66,711	$82,568

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	$485,400,000
Liabilities:
Asset retirement obligations incurred during the current period	52,829,000	11,738,000
Asset Retirement Obligation, Revision of Estimate	4,118,000	10,954,000
Average inflation rate (in hundredths)	2.30%
Minimum [Member]
Liabilities:
Credit-adjusted risk-free interest rate (in hundredths)	4.75%
Maximum [Member]
Liabilities:
Credit-adjusted risk-free interest rate (in hundredths)	5.61%
Fair Value Measured on a Recurring Basis [Member]
Assets:
Commodity price derivative contracts	225,697,000	81,690,000
Interest rate derivative contracts		98,000
Total derivative instruments	225,697,000	81,788,000
Liabilities:
Commodity price derivative contracts	-294,000	-8,208,000
Interest rate derivative contracts	-4,669,000	-6,869,000
Total derivative instruments	-4,963,000	-15,077,000
Fair Value Measured on a Recurring Basis [Member] | Fair Value Measurements Using Level 1 [Member]
Assets:
Commodity price derivative contracts	0	0
Interest rate derivative contracts		0
Total derivative instruments	0	0
Liabilities:
Commodity price derivative contracts	0	0
Interest rate derivative contracts	0	0
Total derivative instruments	0	0
Fair Value Measured on a Recurring Basis [Member] | Fair Value Measurements Using Level 2 [Member]
Assets:
Commodity price derivative contracts	232,167,000	81,124,000
Interest rate derivative contracts		98,000
Total derivative instruments	232,167,000	81,222,000
Liabilities:
Commodity price derivative contracts	-294,000	-8,208,000
Interest rate derivative contracts	-4,669,000	-6,869,000
Total derivative instruments	-4,963,000	-15,077,000
Fair Value Measured on a Recurring Basis [Member] | Fair Value, Inputs, Level 3 [Member]
Assets:
Commodity price derivative contracts		566,000
Interest rate derivative contracts		0
Total derivative instruments		566,000
Liabilities:
Commodity price derivative contracts	-6,470,000	0
Interest rate derivative contracts		0
Total derivative instruments	($6,470,000)	$0

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, 2014	Dec. 31, 2013
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	$566	($498)
Total losses	-8,238	-134
Settlements	1,202	1,198
Unobservable inputs at end of year	-6,470	566
Change in fair value included in earnings related to derivatives still held as of end of year	($6,326)	$1,126

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Changes in asset retirement obligations [Abstract]
Asset retirement obligation at January 1,	$87,967	$63,114
Liabilities added during the current period	52,829	11,738
Accretion expense	5,889	2,789	1,300
Asset Retirement Obligation, Revision of Estimate	4,118	10,954
Asset Retirement Obligations Disposition Of Properties	-1,291	0
Retirements	-450	-628
Total asset retirement obligation at December 31,	149,062	87,967	63,114
Less: current obligations	-2,386	-5,759
Long-term asset retirement obligation at December 31,	$146,676	$82,208

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	0 Months Ended	1 Months Ended	12 Months Ended
Share data in Millions, except Per Share data, unless otherwise specified	Mar. 30, 2012	Jun. 30, 2010	Dec. 31, 2012
Related Party Transaction [Line Items]
Partners' Capital Account, Units, Converted	1.9
Closing price of common unit (in dollars per unit)	$27.62
Issuance of Common units	$52,500,000		($52,480,000)
Noncash consideration after closing adjustments	52,500,000
Closing adjustment under unit exchange agreement	1,400,000
Monthly operating cost per well (in dollars per well)			60
Transportation fee on new wells (in dollars per mcf)			0.55
Transportation fee charged above actual cost under amended agreement (in dollars per mcf)		0.055
Cost incurred under MSA			600,000
Cost incurred under GCA			$400,000

Commitments_and_Contingencies_1

Commitments and Contingencies (Transportation Demand Charges) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014
Gross future minimum transportation demand
2015	17,454
2016	13,986
2017	11,840
2018	11,261
2019	9,661
Thereafter	410
Total	64,612
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	5 years

Commitments_and_Contingencies_2

Commitments and Contingencies Commitments and contingencies - Development Commitment (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Commitments and Contingencies Disclosure [Abstract]
Development Commitment, Remaining Minimum Amount Committed	$45.90

Members_Equity_and_Net_Income_2

Members' Equity and Net Income per Common and Class B Unit Members' Equity and Net Income per Common and Class B Unit - Preferred Units Outstanding (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Preferred Stock, Liquidation Preference Per Share	$25
Preferred units, outstanding	13,881,873	2,535,927
Limited Liability Company (LLC) Preferred Unit, Issuance Value	$335,444	$61,021
Series A Preferred Units [Member]
Preferred Stock, Liquidation Preference Per Share	$25
Preferred Unit, Distribution Rate, Percentage	7.88%
Preferred units, outstanding	2,581,873	2,535,927
Limited Liability Company (LLC) Preferred Unit, Issuance Value	62,200	61,021
Series B Preferred Units [Member]
Preferred Stock, Liquidation Preference Per Share	$25
Preferred Unit, Distribution Rate, Percentage	7.63%
Preferred units, outstanding	7,000,000	0
Limited Liability Company (LLC) Preferred Unit, Issuance Value	169,265	0
Series C Preferred Units [Member]
Preferred Stock, Liquidation Preference Per Share	$25
Preferred Unit, Distribution Rate, Percentage	7.75%
Preferred units, outstanding	4,300,000	0
Limited Liability Company (LLC) Preferred Unit, Issuance Value	$103,979	$0

Members_Equity_and_Net_Income_3

Members' Equity and Net Income per Common and Class B Unit Members' Equity and Net Income per Common and Class B Unit - Common and Class B Units Rollforward (Details) (USD $)	0 Months Ended		12 Months Ended
	Oct. 15, 2014	Mar. 30, 2012	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2013
Class of Stock [Line Items]
Stock Repurchase Program, Authorized Amount	$10,000,000
Treasury Stock, Carrying Basis			$2,500,000
Stock Repurchased During Period, Shares			134,770
Increase (Decrease) in Common Units [Roll Forward]
Partners' Capital Account, Units, Converted		-1,900,000
Treasury Stock, Shares, Acquired			-135,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period				50,000
Common Units [Member]
Increase (Decrease) in Common Units [Roll Forward]
Partners' Capital Account, Units			78,337,000	48,320,000	58,706,000
Partners' Capital Account, Units, Converted				-1,900,000
Partners' Capital Account, Units, Acquisitions					1,075,000
Partners' Capital Account, Units, Sale of Units			4,864,000	12,149,000	18,377,000
Partners' Capital Account, Units, Unit-based Compensation			386,000	87,000	179,000
Partners' Capital Account, Units			83,452,000	58,706,000	78,337,000

Members_Equity_and_Net_Income_4

Members' Equity and Net Income per Common and Class B Unit - Net Income (Loss) per Common and Class B Unit (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Antidilutive securities
Net Income (Loss) Available to Common and class b unitholders, Basic	$46,148	$56,877	($168,815)
Weighted Average Number of Shares Outstanding, Basic	82,031,000	73,064,000	54,197,000
Weighted average units outstanding - diluted	82,459,000	73,412,000	54,197,000
Earnings Per Share, Basic	$0.56	$0.78	($3.11)
Earnings Per Share, Diluted	$0.55	$0.77	($3.11)
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount			522,500
Phantom Share Units (PSUs) [Member]
Antidilutive securities
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	428,000	348,000	0

Members_Equity_and_Net_Income_5

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

12 Months Ended

1 Months Ended

3 Months Ended

Dec. 31, 2014

Nov. 30, 2014

Oct. 31, 2014

Sep. 30, 2014

Aug. 31, 2014

Jul. 31, 2014

Jun. 30, 2014

31-May-14

Apr. 30, 2014

Mar. 31, 2014

Feb. 28, 2014

Jan. 31, 2014

Dec. 31, 2013

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

Preferred Stock, Liquidation Preference Per Share

$25

Series A Preferred Units [Member]

Preferred Unit, Distribution Rate, Percentage

7.88%

Preferred Stock, Liquidation Preference Per Share

$25

Series B Preferred Units [Member]

Preferred Unit, Distribution Rate, Percentage

7.63%

Preferred Stock, Liquidation Preference Per Share

$25

Series C Preferred Units [Member]

Preferred Unit, Distribution Rate, Percentage

7.75%

Preferred Stock, Liquidation Preference Per Share

$25

Common Units [Member]

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

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.21

$0.20

$0.20

$0.20

$0.20

$0.20

$0.20

$0.20

$0.20

$0.20

$0.60

$0.59

$0.59

Cash Distributions Declared Date

16-Dec-14

20-Nov-14

20-Oct-14

19-Sep-14

19-Aug-14

16-Jul-14

24-Jun-14

20-May-14

17-Apr-14

17-Mar-14

2-Feb-14

16-Jan-14

17-Dec-13

19-Nov-13

21-Oct-13

12-Sep-13

20-Aug-13

18-Jul-13

20-Jun-13

30-Apr-13

19-Apr-13

21-Mar-13

18-Feb-13

25-Jan-13

19-Dec-12

16-Nov-12

18-Oct-12

17-Sep-12

20-Aug-12

23-Jul-12

24-Apr-12

18-Jan-12

Cash Distributions Record Date

2-Jan-15

1-Dec-14

3-Nov-14

1-Oct-14

2-Sep-14

1-Aug-14

1-Jul-14

2-Jun-14

1-May-14

1-Apr-14

3-Mar-14

3-Feb-14

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

Cash Distributions Payment Date

14-Jan-15

15-Dec-14

14-Nov-14

15-Oct-14

12-Sep-14

14-Aug-14

15-Jul-14

13-Jun-14

15-May-14

14-Apr-14

17-Mar-14

14-Feb-14

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

UnitBased_Compensation_Details

Unit-Based Compensation (Details) (USD $)	12 Months Ended		0 Months Ended	1 Months Ended			12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2014	Jan. 01, 2014	Oct. 31, 2012	Oct. 31, 2007	Sep. 30, 2012	Dec. 31, 2013
					officer	officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options exercised (in units)	50,000
Accrued liability		$1.40
Board Member [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom units granted, numbers of executives		3
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to non-vested restricted units		8.4
Unrecognized compensation cost recognition period (in years)		1 year 8 months
Restricted Stock Units (RSUs) [Member] | Board Member [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		1 year
Common units granted to VNR employees and board member (in units)		13,137
Restricted Stock Units (RSUs) [Member] | Employee [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		3 years
Common units granted to VNR employees and board member (in units)		96,310
Restricted Stock Units (RSUs) [Member] | Executive [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common units granted to VNR employees and board member (in units)			182,377
Phantom Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to non-vested restricted units		9.4
Unrecognized compensation cost recognition period (in years)		1 year 8 months
VNR LTIP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of officers under compensation plan					2
Number of units options granted under VNR LTIP (in units)					175,000
Exercise price of units under VNR LTIP (in dollars per unit)					$19
Additional compensation expense				1.3
Grant date fair value of vested units					0.1
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
VNR LTIP [Member] | Officer, First [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of officers under compensation plan						1
Exercise price of units under VNR LTIP (in dollars per unit)						$19
Options exercised (in units)						50,000
VNR LTIP [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in dollars per unit)	27.95	$29.02					$28.70
VNR LTIP [Member] | Phantom Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in dollars per unit)	28.67						$28.29
Amended Agreements [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		3 years
Ratio of aggregate restricted units that will vest on each one-year anniversary		33.33%
Amended Agreements [Member] | Phantom Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Ratio of aggregate restricted units that will vest on each one-year anniversary		33.33%
Selling, General and Administrative Expenses [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash unit-based compensation expense	4.2	10.7					3.4
Selling, General and Administrative Expenses [Member] | Phantom Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash unit-based compensation expense	1.2	1					2.6
Selling, General and Administrative Expenses [Member] | Amended Agreements [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash unit-based compensation expense		$1.40

UnitBased_Compensation_Summary

Unit-Based Compensation - Summary of Non-Vested Restricted Units (Details) (Restricted Stock Units (RSUs) [Member], USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost recognition period (in years)	1 year 8 months
VNR LTIP [Member]
Number of Non-vested Units
Non-vested units, beginning of year (in units)	248,611
Granted (in units)	291,824
Forfeited (in units)	-9,047
Vested (in units)	-91,341
Non-vested units, end of year (in units)	440,047	248,611
Weighted Average Grant Date Fair Value
Non-vested units at beginning of year (in dollars per unit)	$28.57
Granted (in dollars per unit)	$29.02	$28.70	$27.95
Forfeited (in dollars per unit)	$29.54
Vested (in dollars per unit)	$28.48
Non-vested units at end of year (in dollars per unit)	$28.87	$28.57

UnitBased_Compensation_UnitBas1

Unit-Based Compensation Unit-Based Compensation - Summary of Non-Vested Phantom Units (Details) (Phantom Share Units (PSUs) [Member], VNR Long Term Incentive Plan [Member], USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Phantom Share Units (PSUs) [Member] | VNR Long Term Incentive Plan [Member]
Granted (in dollars per unit)		$28.29	$28.67
Number of Non-vested Units
Non-vested units, beginning of year (in units)	482,735
Forfeited (in units)	-12,539
Vested (in units)	-139,875
Non-vested units, end of year (in units)	330,321	482,735
Weighted Average Grant Date Fair Value
Non-vested units at beginning of year (in dollars per unit)	$28.67
Forfeited (in dollars per unit)	$28.35
Vested (in dollars per unit)	$28.92
Non-vested units at end of year (in dollars per unit)	$28.58	$28.67

Shelf_Registration_Statements_

Shelf Registration Statements (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 11, 2014	Sep. 23, 2014	Sep. 15, 2014
Shelf Registration Statements [Line Items]
Proceeds from preferred unit offerings, net	$274,423,000	$61,021,000	$0
Series A Preferred Units [Member]
Shelf Registration Statements [Line Items]
Preferred Unit, Distribution Rate, Percentage	7.88%
Series B Preferred Units [Member]
Shelf Registration Statements [Line Items]
Preferred Unit, Distribution Rate, Percentage	7.63%
Series C Preferred Units [Member]
Shelf Registration Statements [Line Items]
Preferred Unit, Distribution Rate, Percentage	7.75%
Distribution Agreement 2013 [Member] | Common Units [Member]
Shelf Registration Statements [Line Items]
Maximum offering under equity distribution agreement	500,000,000
Proceeds from Issuance or Sale of Equity	147,800,000
Units issued under public offerings (in units)	4,863,690
Distribution Agreement 2013 [Member] | Series A Preferred Units [Member]
Shelf Registration Statements [Line Items]
Maximum offering under equity distribution agreement	250,000,000
Proceeds from preferred unit offerings, net	1,200,000
Units issued under public offerings (in units)	45,946
Shelf Registration Statement 2012 [Member] | Series B Preferred Units [Member]
Shelf Registration Statements [Line Items]
Proceeds from preferred unit offerings, net				169,300,000
Units issued under public offerings (in units)				7,000,000
Preferred Unit, Distribution Rate, Percentage				7.63%
Underwriter discount				5,500,000
Offering costs				200,000
Shares Issued, Price Per Share				$25
Shelf Registration Statement 2012 [Member] | Series C Preferred Units [Member]
Shelf Registration Statements [Line Items]
Proceeds from preferred unit offerings, net					7,300,000	96,900,000
Units issued under public offerings (in units)						4,000,000
Preferred Unit, Distribution Rate, Percentage						7.75%
Underwriter discount						3,200,000
Offering costs						$200,000
Shares Issued, Price Per Share						$25
Units issued related to underwriter's overallotment option					300,000

Subsequent_Events_Details

Subsequent Events (Details) (USD $)

1 Months Ended

3 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

Nov. 30, 2014

Oct. 31, 2014

Sep. 30, 2014

Aug. 31, 2014

Jul. 31, 2014

Jun. 30, 2014

31-May-14

Apr. 30, 2014

Mar. 31, 2014

Feb. 28, 2014

Jan. 31, 2014

Dec. 31, 2013

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

Dec. 31, 2014

Feb. 17, 2015

Jan. 22, 2015

Dec. 31, 2015

Jan. 31, 2015

Subsequent Event [Member] | Oil [Member] | Contract Period January 1, 2015 to December 31, 2015 [Member]

Subsequent Event [Line Items]

Portion of future oil and gas production hedged

77.00%

Subsequent Event [Member] | Oil [Member] | Contract Period January 1, 2016 to December, 31 2016 [Member]

Subsequent Event [Line Items]

Portion of future oil and gas production hedged

45.00%

Subsequent Event [Member] | Oil [Member] | Fixed-Price Swaps [Member] | Contract Period January 1, 2015 to December 31, 2015 [Member]

Subsequent Event [Line Items]

Portion of future oil and gas production hedged

88.00%

Subsequent Event [Member] | Natural Gas [Member] | Contract Period January 1, 2015 to December 31, 2015 [Member]

Subsequent Event [Line Items]

Portion of future oil and gas production hedged

82.00%

Subsequent Event [Member] | Natural Gas [Member] | Contract Period January 1, 2016 to December, 31 2016 [Member]

Subsequent Event [Line Items]

Portion of future oil and gas production hedged

67.00%

Subsequent Event [Member] | Natural Gas [Member] | Fixed-Price Swaps [Member] | Contract Period January 1, 2015 to December 31, 2015 [Member]

Subsequent Event [Line Items]

Portion of future oil and gas production hedged

98.00%

Subsequent Event [Member] | Natural Gas Liquids [Member] | Contract Period January 1, 2015 to December 31, 2015 [Member]

Subsequent Event [Line Items]

Portion of future oil and gas production hedged

9.00%

Common Units [Member]

Subsequent Event [Line Items]

Cash Distributions Declared Date

16-Dec-14

20-Nov-14

20-Oct-14

19-Sep-14

19-Aug-14

16-Jul-14

24-Jun-14

20-May-14

17-Apr-14

17-Mar-14

2-Feb-14

16-Jan-14

17-Dec-13

19-Nov-13

21-Oct-13

12-Sep-13

20-Aug-13

18-Jul-13

20-Jun-13

30-Apr-13

19-Apr-13

21-Mar-13

18-Feb-13

25-Jan-13

19-Dec-12

16-Nov-12

18-Oct-12

17-Sep-12

20-Aug-12

23-Jul-12

24-Apr-12

18-Jan-12

Distribution Made to Limited Liability Company (LLC) Member, Distributions Declared, Per Unit, Annualized Basis

$2.52

Common Units [Member] | Subsequent Event [Member]

Subsequent Event [Line Items]

Cash Distributions Declared Date

17-Feb-15

22-Jan-15

Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit

$0.12

$0.21

Distribution Made to Limited Liability Company (LLC) Member, Distributions Declared, Per Unit, Annualized Basis

$1.41

Series A Preferred Units [Member] | Subsequent Event [Member]

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit

$0.16

$0.16

Series B Preferred Units [Member] | Subsequent Event [Member]

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit

$0.16

$0.16

Series C Preferred Units [Member] | Subsequent Event [Member]

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit

$0.16

$0.16

Cumulative Preferred units | Subsequent Event [Member]

Subsequent Event [Line Items]

Cash Distributions Declared Date

17-Feb-15

22-Jan-15