Grizzly Energy (GRZZP) 10-Q 9 Nov 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Nov. 05, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	Vanguard Natural Resources, LLC
Entity Central Index Key	1,384,072
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		130,464,658

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Revenues:
Oil sales	$ 33,624	$ 69,034	$ 113,425	$ 211,197
Natural gas sales	50,851	67,827	146,502	201,175
NGLs sales	6,352	16,766	25,635	55,514
Net gains (losses) on commodity derivative contracts	64,328	83,311	102,561	(11,125)
Total revenues	155,155	236,938	388,123	456,761
Production:
Lease operating expenses	34,169	31,011	101,247	95,726
Production and other taxes	9,082	15,130	31,262	46,693
Depreciation, depletion, amortization, and accretion	52,428	55,680	182,443	150,798
Impairment of oil and natural gas properties	491,487	0	1,357,462	0
Selling, general and administrative expenses	8,046	7,140	26,239	23,042
Total costs and expenses	595,212	108,961	1,698,653	316,259
Income (loss) from operations	(440,057)	127,977	(1,310,530)	140,502
Other income (expense):
Interest expense	(21,130)	(16,721)	(61,693)	(49,529)
Net gains (losses) on interest rate derivative contracts	(807)	511	(2,291)	(1,068)
Net gains (losses) on acquisitions of oil and natural gas properties	(284)	2,409	(284)	34,523
Other	1	(77)	46	54
Total other income (expense), net	(22,220)	(13,878)	(64,222)	(16,020)
Net income (loss)	(462,277)	114,099	(1,374,752)	124,482
Distributions to Preferred unitholders	(6,690)	(4,949)	(20,070)	(11,507)
Net income (loss) attributable to Common and Class B unitholders	$ (468,967)	$ 109,150	$ (1,394,822)	$ 112,975
Earnings Per Share, Basic	$ (5.39)	$ 1.31	$ (16.25)	$ 1.39
Earnings Per Share, Diluted	$ (5.39)	$ 1.30	$ (16.25)	$ 1.38
Weighted Average Number of Shares Outstanding, Basic	87,012	83,525	85,834	81,377
Weighted Average Number of Shares Outstanding, Diluted	87,012	83,753	85,834	81,651
Common Units
Other income (expense):
Weighted Average Number of Shares Outstanding, Basic	86,592	83,105	85,414	80,957
Weighted Average Number of Shares Outstanding, Diluted	86,592	83,333	85,414	81,231
Class B Units
Other income (expense):
Weighted Average Number of Shares Outstanding, Basic and Diluted (shares)	420	420	420	420

CONSOLIDATED BALANCE SHEETS (Un

CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 19,490	$ 0
Trade accounts receivable, net	66,200	140,017
Derivative assets	139,901	142,114
Other currents assets	11,119	4,102
Total current assets	236,710	286,233
Oil and natural gas properties, at cost	4,257,859	4,140,527
Accumulated depletion, amortization and impairment	(2,695,554)	(1,164,721)
Oil and natural gas properties evaluated, net - full cost method	1,562,305	2,975,806
Other assets
Goodwill	420,955	420,955
Derivative assets	62,890	83,583
Other assets	30,529	27,015
Total assets	2,313,389	3,793,592
Accounts payable:
Trade	17,682	15,118
Affiliates	1,512	823
Accrued liabilities:
Lease operating	13,152	19,822
Developmental capital	9,274	24,706
Interest	21,987	11,517
Production and other taxes	47,155	29,981
Derivative liabilities	636	3,583
Oil and natural gas revenue payable	22,192	40,117
Distribution payable	11,241	18,640
Other	20,770	14,297
Total current liabilities	165,601	178,604
Long-term debt	1,889,674	1,932,816
Derivative liabilities	473	1,380
Asset retirement obligations, net of current portion	173,898	146,676
Other long-term liabilities	730	0
Total liabilities	$ 2,230,376	$ 2,259,476
Commitments and contingencies
Members' equity
Members' Equity	$ 83,013	$ 1,534,116
Total liabilities and members' equity	2,313,389	3,793,592
Cumulative Preferred Units
Members' equity
Members' Equity	335,444	335,444
Common Units
Members' equity
Members' Equity	(260,046)	1,191,057
Class B Units
Members' equity
Members' Equity	$ 7,615	$ 7,615

CONSOLIDATED BALANCE SHEETS (U4

CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - shares	Sep. 30, 2015	Dec. 31, 2014
Members' equity
Preferred units, issued (shares)	13,881,873	13,881,873
Preferred units, outstanding (shares)	13,881,873	13,881,873
Common Units
Members' equity
Common units, issued (shares)	86,597,301	83,451,746
Common units, outstanding (shares)	86,597,301	83,451,746
Class B Units
Members' equity
Common units, issued (shares)	420,000	420,000
Common units, outstanding (shares)	420,000	420,000

CONSOLIDATED STATEMENTS OF MEMB

CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY (Unaudited) - USD ($) $ in Thousands	Total	Member Units	Cumulative Preferred unitsMember Units	Common UnitsMember Units	Class B UnitsMember Units
Balance at Dec. 31, 2013		$ 1,268,335	$ 61,021	$ 1,199,699	$ 7,615
Increase (Decrease) in Members' Equity [Roll Forward]
Issuance of units, net of offering costs			274,423	147,814
Repurchase of units under the common unit buyback program		(2,498)		(2,498)
Distributions to Preferred unitholders		(18,197)		(18,197)
Distributions to Common and Class B unitholders		(207,883)		(207,883)
Unit-based compensation		7,777		7,777
Net income (loss)		64,345		64,345
Balance at Dec. 31, 2014		1,534,116	335,444	1,191,057	7,615
Increase (Decrease) in Members' Equity [Roll Forward]
Issuance of units, net of offering costs		35,549		35,549
Repurchase of units under the common unit buyback program		(2,399)		(2,399)
Distributions to Preferred unitholders		(20,070)		(20,070)
Distributions to Common and Class B unitholders		(99,163)		(99,163)
Unit-based compensation		9,732		9,732
Net income (loss)	$ (1,374,752)	(1,374,752)		(1,374,752)
Balance at Sep. 30, 2015		$ 83,013	$ 335,444	$ (260,046)	$ 7,615

CONSOLIDATED STATEMENTS OF MEM6

CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY (Unaudited) (Parenthetical) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Common Units
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs	$ 600
Common Units | Member Units
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs	$ 589	$ 88
Cumulative Preferred units | Member Units
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs		$ 371

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Operating activities
Net income (loss)	$ (1,374,752)	$ 124,482
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization, and accretion	182,443	150,798
Impairment of oil and natural gas properties	1,357,462	0
Amortization of deferred financing costs	3,058	2,586
Amortization of debt discount	216	199
Compensation related items	9,732	5,437
Net (gains) losses on commodity and interest rate derivative contracts	(100,270)	12,193
Cash settlements received (paid) on matured commodity derivative contracts	125,988	(13,347)
Cash settlements paid on matured interest rate derivative contracts	(2,968)	(3,026)
Net (gains) losses on acquisitions of oil and natural gas properties	284	(34,523)
Changes in operating assets and liabilities:
Trade accounts receivable	73,817	(32,248)
Other current assets	(7,012)	(1,991)
Premiums paid on commodity derivative contracts	(794)	0
Accounts payable and oil and natural gas revenue payable	(15,360)	8,449
Payable to affiliates	689	331
Accrued expenses and other current liabilities	4,716	26,733
Other assets	8,070	(384)
Net cash provided by operating activities	265,319	245,689
Investing activities
Additions to property and equipment	(329)	(1,148)
Additions to oil and natural gas properties	(80,213)	(79,514)
Acquisitions of oil and natural gas properties	(13,004)	(1,303,035)
Deposits and prepayments of oil and natural gas properties	(13,419)	(4,957)
Proceeds from Sale of Oil and Gas Property and Equipment	0	1,950
Net cash used in investing activities	(106,965)	(1,386,704)
Financing activities
Proceeds from long-term debt	117,500	1,321,000
Repayment of long-term debt	(160,721)	(406,000)
Proceeds from preferred unit offerings, net	0	274,521
Proceeds from Common unit offerings, net	35,549	147,841
Repurchase of units under the Common unit buyback program	(2,399)	0
Distributions to Preferred unitholders	(20,070)	(10,600)
Distributions to Common and Class B unitholders	(106,562)	(153,410)
Payments of Financing Costs	(2,161)	(199)
Net cash provided by (used in) financing activities	(138,864)	1,173,153
Net increase cash and cash equivalents	19,490	32,138
Cash and cash equivalents, beginning of period	0	11,818
Cash and cash equivalents, end of period	19,490	43,956
Supplemental cash flow information:
Cash paid for interest	47,718	36,143
Non-cash financing and investing activities:
Asset retirement obligations	24,300	51,081
Noncash or Part Noncash Acquisition, Value of Assets Acquired	31,421	0
Noncash gain on termination of derivative contracts	$ 28,517	$ 0

Description of the Business

Description of the Business	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Description of Business	Description of the Business: We are a publicly traded limited liability company focused on the acquisition and development of mature, long-lived oil and natural gas properties in the United States. Our primary business objective is to generate stable cash flows allowing us to make monthly cash distributions to our unitholders and, over time, increase our monthly cash distributions through the acquisition of additional mature, long-lived oil and natural gas properties. Through our operating subsidiaries, as of September 30, 2015 , we own properties and oil and natural gas reserves primarily located in nine operating areas: • the Green River Basin in Wyoming; • the Piceance Basin in Colorado; • the Permian Basin in West Texas and New Mexico; • the Gulf Coast Basin in Texas, Louisiana and Mississippi; • the Big Horn Basin in Wyoming and Montana; • the Arkoma Basin in Arkansas and Oklahoma; • the Williston Basin in North Dakota and Montana; • the Wind River Basin in Wyoming; and • the Powder River Basin in Wyoming. We were formed in October 2006 and completed our initial public offering in October 2007. Our common units are listed on the NASDAQ Global Select Market (“NASDAQ”), an exchange of the NASDAQ OMX Group Inc. (Nasdaq: NDAQ), under the symbol “VNR.” Our Series A, Series B and Series C Cumulative Preferred units are also listed on the NASDAQ under the symbols “VNRAP”, “VNRBP” and “VNRCP,” respectively.

Summary of Significant Accounti

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies The accompanying consolidated financial statements are unaudited and were prepared from our records. We derived the Consolidated Balance Sheet as of December 31, 2014 , from the audited financial statements contained in our 2014 Annual Report. Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by generally accepted accounting principles in the United States (“GAAP”). You should read this Quarterly Report on Form 10-Q along with our 2014 Annual Report, which contains a summary of our significant accounting policies and other disclosures. In our opinion, we have made all adjustments which are of a normal, recurring nature to fairly present our interim period results. Information for interim periods may not be indicative of our operating results for the entire year. As of September 30, 2015 , our significant accounting policies are consistent with those discussed in Note 1 of our consolidated financial statements contained in our 2014 Annual Report. (a) Basis of Presentation and Principles of Consolidation: The consolidated financial statements as of September 30, 2015 and December 31, 2014 and for the three and nine months ended September 30, 2015 and 2014 include our accounts and those of our subsidiaries. We present our financial statements in accordance with GAAP. All intercompany transactions and balances have been eliminated upon consolidation. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income (loss) or members’ equity. (b) Oil and Natural Gas Properties: The full cost method of accounting is used to account for oil and natural gas properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil, natural gas and NGLs reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and subject to ceiling test limitations as discussed below. Capitalized costs associated with proved reserves are amortized over the life of the reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated, which occurs on a quarterly basis. Specifically, costs are transferred to the amortizable base when properties are determined to have proved reserves. In addition, we transfer unproved property costs to the amortizable base when unproved properties are evaluated as being impaired and as exploratory wells are determined to be unsuccessful. Additionally, the amortizable base includes estimated future development costs, dismantlement, restoration and abandonment costs net of estimated salvage values. Capitalized costs are limited to a ceiling based on the present value of future net revenues, computed using the 12-month unweighted average of first-day-of-the-month historical price, the “12-month average price” discounted at 10% , plus the lower of cost or fair market value of unproved properties. If the ceiling is less than the total capitalized costs, we are required to write-down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write-downs are included in the Consolidated Statements of Operations as an impairment charge. We recorded a non-cash ceiling test impairment of oil and natural gas properties for the nine months ended September 30, 2015 of $1.4 billion as a result of a decline in oil and natural gas prices at the measurement dates, March 31, 2015 , June 30, 2015 and September 30, 2015 . The impairment for the first quarter of 2015 was $132.6 million and was calculated based on the 12-month average price of $3.91 per MMBtu for natural gas and $82.62 per barrel of crude oil. The impairment for the second quarter of 2015 was $733.4 million and was calculated based on the 12-month average price of $3.44 per MMBtu for natural gas and $71.51 per barrel of crude oil. The impairment for the third quarter of 2015 was $491.5 million and was calculated based on the 12-month average price of $3.11 per MMBtu for natural gas and $59.23 per barrel of crude oil. No ceiling test impairment was required during the nine months ended September 30, 2014 . When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties. (c) New Pronouncement Issued But Not Yet Adopted: In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU No. 2014-09”), which amends the FASB ASC by adding new FASB ASC Topic 606, Revenue from Contracts with Customers, and superseding the revenue recognition requirements in FASB ASC 605, Revenue Recognition, and in most industry-specific topics. 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). In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date (“ASU No. 2014-14”) to defer the effective date of ASU No. 2014-09 by one year. Public business entities should apply the guidance in ASU 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. 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 we will adopt the standard in 2018. In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (“ASU No. 2015-16”) to simplify the accounting for adjustments made to provisional amounts recognized in a business combination by eliminating the requirement to retrospectively account for those adjustments. The amendments under ASU No. 2015-16 require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Further, the amendments in this ASU require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments under ASU No. 2015-16 also require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. For public business entities, the amendments are effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The amendments should be applied prospectively to adjustments to provisional amounts that occur after the effective date with earlier application permitted for financial statements that have not been issued. The only disclosures required at transition should be the nature of and reason for the change in accounting principle. An entity should disclose that information in the first annual period of adoption and in the interim periods within the first annual period if there is a measurement-period adjustment during the first annual period in which the changes are effective. We do not expect the adoption of ASU No. 2015-16 will have a material impact on our consolidated financial statements. (d) Use of Estimates: The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related cash flow estimates used in impairment tests of oil and natural gas properties and goodwill, the acquisition of oil and natural gas properties, the fair value of derivative contracts and asset retirement obligations, accrued oil, natural gas and NGLs revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ from those estimates.

Acquisitions

Acquisitions	9 Months Ended
	Sep. 30, 2015
Business Combinations [Abstract]
Acquisitions	Acquisitions Our acquisitions are accounted for under the acquisition method of accounting in accordance with ASC Topic 805, “Business Combinations” (“ASC Topic 805”). An acquisition may result in the recognition of a gain or goodwill based on the measurement of the fair value of the assets acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. Any such gain or any loss resulting from the impairment of goodwill is recognized in current period earnings and classified in other income and expense in the accompanying Consolidated Statements of Operations. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of the properties acquired in our acquisitions have been included in the consolidated financial statements since the closing dates of the acquisitions. On July 31, 2015, we completed the acquisition of additional interests in the same properties located in the Pinedale field of Southwestern Wyoming that were previously acquired in the Pinedale Acquisition in 2014 for an adjusted purchase price of $11.4 million , subject to additional customary post-closing adjustments to be determined based on an effective date of April 1, 2015. The acquisition was funded with borrowings under our existing Reserve-Based Credit Facility. 2015 Mergers On October 5, 2015, Vanguard completed the transactions contemplated by the Purchase Agreement and Plan of Merger, dated as of April 20, 2015, pursuant to which a subsidiary of Vanguard merged into LRR Energy, L.P. and, at the same time, Vanguard acquired LRE GP, LLC, the general partner of LRR Energy, L.P. See Note 11. Subsequent Events for further discussion. On October 8, 2015, Vanguard completed the merger with Eagle Rock Energy Partners, L.P. (“Eagle Rock”) and pursuant the terms of the merger agreement, Eagle Rock has become a wholly-owned indirect subsidiary of Vanguard. See Note 11. Subsequent Events for further discussion. 2014 Acquisitions Pinedale Acquisition On January 31, 2014, we completed the acquisition of natural gas and oil properties in the Pinedale and Jonah fields of Southwestern Wyoming for approximately $555.6 million in cash with an effective date of October 1, 2013 . We refer to this acquisition as the “Pinedale Acquisition.” The purchase price was funded with borrowings under our Reserve-Based Credit Facility (as defined below). In accordance with ASC Topic 805, this acquisition resulted in a gain of $32.1 million , as reflected in the table below, primarily due to the increase in natural gas prices between the date the purchase and sale agreement was entered into and the closing date. Fair value of assets and liabilities acquired (in thousands) Oil and natural gas properties $ 600,123 Inventory 244 Asset retirement obligations (12,404 ) Imbalance liabilities (171 ) Other (125 ) Total fair value of assets and liabilities acquired 587,667 Fair value of consideration transferred 555,553 Gain on acquisition $ 32,114 Piceance Acquisition On September 30, 2014, we completed the acquisition of natural gas, oil and NGLs assets in the Piceance Basin in Colorado for approximately $496.4 million in cash with an effective date of July 1, 2014 . We refer to this acquisition as the “Piceance Acquisition.” The purchase price was funded with borrowings under our Reserve-Based Credit Facility. In accordance with ASC Topic 805, this acquisition resulted in goodwill of $0.4 million , as reflected in the table below, which was immediately impaired and recorded as a loss in current period earnings. The loss resulted primarily from the changes in natural gas prices between the date the purchase and sale agreement was entered into and the closing date, which were used to value the reserves acquired. Fair value of assets and liabilities acquired (in thousands) Oil and natural gas properties $ 523,537 Asset retirement obligations (19,452 ) Production and ad valorem taxes payable (7,552 ) Suspense liabilities (445 ) Other (124 ) Total fair value of assets and liabilities acquired 495,964 Fair value of consideration transferred 496,391 Loss on acquisition $ (427 ) Other Acquisitions On May 1, 2014, we completed an asset exchange transaction with Marathon Oil Company in which we acquired natural gas and NGLs properties in the Wamsutter natural gas field in Wyoming in exchange for 75% of our working interests in the Gooseberry Field properties in Wyoming. The total consideration for this transaction was the mutual exchange and assignment of interests in the properties and cash consideration of $6.8 million paid to Marathon Oil Company. The cash consideration was funded with borrowings under our existing Reserve-Based Credit Facility. The effective date of the acquisition is January 1, 2014 . On August 29, 2014, we completed the acquisition of certain natural gas, oil and NGLs properties located in North Louisiana and East Texas for an adjusted purchase price of $265.1 million . We refer to this acquisition as the “Gulf Coast Acquisition.” The purchase price was funded with borrowings under our existing Reserve-Based Credit Facility. The effective date of the acquisition is June 1, 2014 . During the year ended December 31, 2014, we completed other smaller acquisitions of certain natural gas, oil and NGLs properties located in the Permian Basin and Powder River Basin in Wyoming for an aggregate purchase price of $17.7 million which was funded with borrowings under our existing Reserve-Based Credit Facility. Pro Forma Operating Results In accordance with ASC Topic 805, presented below are unaudited pro forma results for the three and nine months ended September 30, 2014 to show the effect on our consolidated results of operations as if our acquisitions completed in 2014 had occurred on January 1, 2013 . The pro forma results reflect the results of combining our statement of operations with the results of operations from the oil and natural gas properties acquired during 2014 , adjusted for (i) the assumption of asset retirement obligations and accretion expense for the properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired, and (iii) interest expense on additional borrowings necessary to finance the acquisitions. The net gains on acquisitions of oil and natural gas properties was excluded from the pro forma results for the three and nine months ended September 30, 2014 . The pro forma information is based upon these assumptions and is not necessarily indicative of future results of operations: Pro forma Three Months Ended September 30, 2014 Nine Months Ended September 30, 2014 (in thousands, except per unit data) Total revenues $ 275,547 $ 613,584 Net income attributable to Common and Class B unitholders $ 118,458 $ 134,928 Net income per Common and Class B unit: Basic $ 1.42 $ 1.66 Diluted $ 1.41 $ 1.65 Post-Acquisition Operating Results The amount of revenues and excess of revenues over direct operating expenses included in the accompanying Consolidated Statements of Operations for our 2014 acquisitions are shown in the table that follows. Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes. Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 (in thousands) Pinedale Acquisition Revenues $ 22,098 $ 36,947 $ 66,445 $ 106,163 Excess of revenues over direct operating expenses $ 14,694 $ 29,423 $ 44,598 $ 82,709 Piceance Acquisition Revenues $ 9,081 $ 283 $ 28,811 $ 283 Excess of revenues over direct operating expenses $ 4,310 $ 227 $ 15,237 $ 227 Other acquisitions Revenues $ 9,987 $ 8,671 $ 28,720 $ 11,831 Excess of revenues over direct operating expenses $ 5,522 $ 5,868 $ 15,836 $ 7,970

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2015
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Our financing arrangements consisted of the following as of the date indicated: Amount Outstanding Description Interest Rate Maturity Date September 30, 2015 December 31, 2014 (in thousands) Senior Secured Reserve-Based Credit Facility Variable (1) April 16, 2018 $ 1,320,000 $ 1,360,000 Senior Notes 7.875% (2) April 1, 2020 550,000 550,000 Lease Financing Obligation 4.16% August 10, 2020 (3) $ 25,764 28,986 $ 1,895,764 $ 1,938,986 Less: Unamortized discount on Senior Notes (1,636 ) (1,852 ) Current portion of Lease Financing Obligation (4,454 ) (4,318 ) Total long-term debt $ 1,889,674 $ 1,932,816 (1) Variable interest rate was 2.45% and 2.17% at September 30, 2015 and December 31, 2014 , respectively. (2) Effective interest rate was 8.0% . (3) The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021. Senior Secured Reserve-Based Credit Facility The Company’s Third Amended and Restated Credit Agreement (the “Credit Agreement”) provides a maximum credit facility of $3.5 billion and an initial borrowing base of $1.6 billion (the “Reserve-Based Credit Facility”). As of September 30, 2015 , there were approximately $1.32 billion of outstanding borrowings and $275.5 million of borrowing capacity under the Reserve-Based Credit Facility, after consideration of a $4.5 million reduction in availability for letters of credit (discussed below). On June 3, 2015, the Company entered into the Eighth Amendment to the Credit Agreement which decreased its borrowing base from $2.0 billion to $1.6 billion . However, the Eighth Amendment provided for an automatic increase in the borrowing base of $200.0 million which became effective upon closing of the LRE Merger on October 5, 2015. In addition, the Eighth Amendment includes, among other provisions, an amendment of the debt to “Last Twelve Months Adjusted EBITDA” covenant whereby the Company shall not permit such ratio to be greater than 5.5 to 1.0 in 2015, 5.25 to 1.0 in 2016 and 4.5 to 1.0 starting in 2017 and beyond. On November 6, 2015 , we completed our semi-annual borrowing base redetermination and entered into the Fourth Amended and Restated Credit Agreement (“Restated Credit Agreement”). See Note 11. Subsequent Events for further discussion. Interest rates under the Reserve-Based Credit Facility are based on Eurodollar (LIBOR) or ABR (Prime) indications, plus a margin. Interest is generally payable quarterly for ABR loans and at the applicable maturity date for LIBOR loans. At September 30, 2015 , the applicable margin and other fees increase as the utilization of the borrowing base increases as follows: Borrowing Base Utilization Grid Borrowing Base Utilization Percentage <25% > 25% <50% > 50% <75% > 75% <90% > 90% Eurodollar Loans Margin 1.50 % 1.75 % 2.00 % 2.25 % 2.50 % ABR Loans Margin 0.50 % 0.75 % 1.00 % 1.25 % 1.50 % Commitment Fee Rate 0.50 % 0.50 % 0.375 % 0.375 % 0.375 % Letter of Credit Fee 0.50 % 0.75 % 1.00 % 1.25 % 1.50 % 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 5.5 to 1.0 in 2015, 5.25 to 1.0 in 2016 and 4.5 to 1.0 starting in 2017 and beyond. 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 September 30, 2015 , we were in compliance with all of our debt covenants. Letters of Credit At September 30, 2015 , we have unused irrevocable standby letters of credit of approximately $4.5 million . The letters are being maintained as security for performance on long-term transportation contracts. Borrowing availability for the letters of credit is provided under our Reserve-Based Credit Facility. The fair value of these letters of credit approximates contract values based on the nature of the fee arrangements with the issuing banks. Senior Notes We have $550.0 million outstanding in aggregate principal amount of 7.875% senior notes due 2020 (the “Senior Notes”). The issuers of the Senior Notes are VNR and our 100% owned finance subsidiary, VNRF. VNR has no independent assets or operations. Under the indenture governing the Senior Notes (the “Indenture”), all of our existing subsidiaries (other than VNRF), all of which are 100% owned, and certain of our future subsidiaries (the “Subsidiary Guarantors”) have unconditionally guaranteed, jointly and severally, on an unsecured basis, the Senior Notes, subject to certain customary release provisions, including: (i) upon the sale or other disposition of all or substantially all of the subsidiary’s properties or assets; (ii) upon the sale or other disposition of our equity interests in the subsidiary; (iii) upon designation of the subsidiary as an unrestricted subsidiary in accordance with the terms of the Indenture; (iv) upon legal defeasance or covenant defeasance or the discharge of the Indenture; (v) upon the liquidation or dissolution of the subsidiary; (vi) upon the subsidiary ceasing to guarantee any other of our indebtedness and to be an obligor under any of our credit facilities; or (vii) upon such subsidiary dissolving or ceasing to exist after consolidating with, merging into or transferring all of its properties or assets to us. The Indenture also contains covenants that will limit our ability to (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) make distributions on, purchase or redeem our common units or purchase or redeem subordinated indebtedness; (iv) make investments; (v) restrict dividends, loans or other asset transfers from our restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of our properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; (viii) enter into transactions with affiliates; or (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the Senior Notes achieve an investment grade rating from each of Standard & Poor’s Rating Services and Moody’s Investors Services, Inc. and no default under the Indenture exists, many of the foregoing covenants will terminate. At September 30, 2015 , based on the most restrictive covenants of the Indenture, the Company’s cash balance and the borrowings available under the Reserve-Based Credit Facility, approximately $234.5 million of members’ equity is available for distributions to unitholders, while the remainder is restricted. Interest on the Senior Notes is payable on April 1 and October 1 of each year. We may redeem some or all of the Senior Notes at any time on or after April 1, 2016 at redemption prices of 103.93750% of the aggregate principal amount of the Senior Notes as of April 1, 2016, declining to 100% on April 1, 2018 and thereafter. We may also redeem some or all of the Senior Notes at any time prior to April 1, 2016 at a redemption price equal to 100% of the aggregate principal amount of the Senior Notes thereof, plus a “make-whole” premium. If we sell certain of our assets or experience certain changes of control, we may be required to repurchase all or a portion of the Senior Notes at a price equal to 100% and 101% of the aggregate principal amount of the Senior Notes, respectively. Lease Financing Obligations On October 24, 2014, in connection with our Piceance Acquisition, we entered into an assignment and assumption agreement, whereby we acquired compressors and related facilities and assumed the related financing obligations (the “Lease Financing Obligations”). Certain rights, title, interest and obligations under the Lease Financing Obligations have been assigned to several lenders and are covered by separate assignment agreements, which expire on August 10, 2020 and July 10, 2021. We have the option to purchase the equipment at the end of the lease term for the current fair market value. The Lease Financing Obligations also contain an early buyout option whereby the Company may purchase the equipment for $16.0 million on February 10, 2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 4.16% .

Price and Interest Rate Risk Ma

Price and Interest Rate Risk Management Activities	9 Months Ended
	Sep. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Price and Interest Rate Risk Management Activities	Price and Interest Rate Risk Management Activities We have entered into derivative contracts primarily with counterparties that are also lenders under our Reserve-Based Credit Facility to hedge price risk associated with a portion of our oil, natural gas and NGLs production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated which has, and could, result in overhedged volumes. Pricing for these derivative contracts is based on certain market indexes and prices at our primary sales points. We also enter into fixed LIBOR interest rate swap agreements with certain counterparties that are lenders under our Reserve-Based Credit Facility, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates. At September 30, 2015 , the Company had open commodity derivative contracts covering our anticipated future production as follows: Fixed-Price Swaps Gas Oil NGLs Contract Period MMBtu Weighted Average Fixed Price Bbls Weighted Average WTI Price Bbls Weighted Average October 1, 2015 – December 31, 2015 22,436,000 $ 4.26 602,600 $ 71.94 62,100 $ 46.34 January 1, 2016 – December 31, 2016 55,083,000 $ 4.47 329,400 $ 76.10 567,300 29.96 January 1, 2017 – December 31, 2017 24,027,000 $ 4.35 — $ — — $ — Call Options Sold Gas Oil Contract Period MMBtu Weighted Average Fixed Price Bbls Weighted Average Fixed Price October 1, 2015 – December 31, 2015 — — 18,400 $ 105.00 January 1, 2016 – December 31, 2016 9,150,000 $ 4.25 622,200 $ 125.00 January 1, 2017 – December 31, 2017 9,125,000 $ 4.50 365,000 $ 95.00 Swaptions Gas Contract Period MMBtu Weighted Average Fixed Price October 1, 2015 – December 31, 2015 610,000 $ 3.50 January 1, 2016 – December 31, 2016 910,000 $ 3.50 Basis Swaps Gas Contract Period MMBtu Weighted Avg. Basis Differential ($/MMBtu) Pricing Index October 1, 2015 – December 31, 2015 7,360,000 $ (0.28 ) Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential January 1, 2016 – December 31, 2016 21,960,000 $ (0.23 ) 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 Differential ($/Bbl) Pricing Index October 1, 2015 – December 31, 2015 128,800 $ (1.68 ) WTI Midland and WTI Cushing Basis Differential January 1, 2016 – December 31, 2016 512,400 $ (0.94 ) WTI Midland and WTI Cushing Basis Differential October 1, 2015 – December 31, 2015 36,800 $ (2.33 ) West Texas Sour and WTI Cushing Basis Differential January 1, 2016 – December 31, 2016 219,600 $ (0.43 ) West Texas Sour and WTI Cushing Basis Differential October 1, 2015 – December 31, 2015 184,000 $ (14.50 ) WTI and West Canadian Select Basis Differential Three-Way Collars Gas Contract Period MMBtu Floor Ceiling Put Sold January 1, 2016 – December 31, 2016 12,810,000 $ 3.95 $ 4.25 $ 3.00 January 1, 2017 – December 31, 2017 16,425,000 $ 3.92 $ 4.23 $ 3.37 Oil Contract Period Bbls Floor Ceiling Put Sold October 1, 2015 – December 31, 2015 69,000 $ 90.00 $ 99.13 $ 76.67 January 1, 2016 – December 31, 2016 1,061,400 $ 90.00 $ 96.18 $ 73.62 Put Options Sold Gas Oil Contract Period MMBtu Put Sold ($/MMBtu) Bbls Put Sold ($/Bbl) October 1, 2015 – December 31, 2015 6,670,000 $ 3.16 128,800 $ 71.43 January 1, 2016 – December 31, 2016 1,830,000 $ 3.00 146,400 $ 75.00 January 1, 2017 – December 31, 2017 1,825,000 $ 3.50 73,000 $ 75.00 Range Bonus Accumulators Gas Contract Period MMBtu Bonus Range Ceiling Range Floor October 1, 2015 – December 31, 2015 368,000 $ 0.16 $ 4.00 $ 2.50 Oil Contract Period Bbls Bonus Range Ceiling Range Floor October 1, 2015 – December 31, 2015 46,000 $ 4.00 $ 100.00 $ 75.00 January 1, 2016 – December 31, 2016 183,000 $ 4.00 $ 100.00 $ 75.00 Collars Oil Contract Period Bbls Floor Price ($/Bbl) Ceiling Price ($/Bbl) October 1, 2015 – December 31, 2015 46,000 $ 50.00 $ 58.45 Call Spreads Oil Contract Period Bbls Call Price ($/Bbl) Short Call Price ($/Bbl) October 1, 2015 – December 31, 2015 473,800 $ 70.00 $ 85.00 Puts Oil Contract Period Bbls Put Price ($/Bbl) January 1, 2016 – December 31, 2016 366,000 $ 60.00 Interest Rate Swaps At September 30, 2015 , we had open interest rate derivative contracts as follows (in thousands): Period Notional Amount Fixed LIBOR Rates October 1, 2015 to December 10, 2016 $ 20,000 2.17 % October 1, 2015 to October 31, 2016 $ 40,000 1.65 % October 1, 2015 to August 5, 2018 $ 30,000 2.25 % October 1, 2015 to August 6, 2016 $ 25,000 1.80 % October 1, 2015 to October 31, 2016 $ 20,000 1.78 % October 1, 2015 to September 23, 2016 $ 75,000 1.15 % October 1, 2015 to March 7, 2016 $ 75,000 1.08 % October 1, 2015 to September 7, 2016 $ 25,000 1.25 % October 1, 2015 to December 10, 2015 (1) $ 50,000 0.21 % Total $ 360,000 (1) The counterparty has the option to require Vanguard to pay a fixed rate of 0.91% from December 10, 2015 to December 10, 2017. 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 as governed by the International Swaps and Derivatives Association Master Agreement with each of the counterparties. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets for the periods indicated (in thousands): September 30, 2015 Offsetting Derivative Assets: Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts $ 230,500 $ (24,175 ) $ 206,325 Interest rate derivative contracts — (3,534 ) (3,534 ) Total derivative instruments $ 230,500 $ (27,709 ) $ 202,791 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 $ (24,827 ) $ 24,175 $ (652 ) Interest rate derivative contracts (3,991 ) 3,534 (457 ) Total derivative instruments $ (28,818 ) $ 27,709 $ (1,109 ) December 31, 2014 Offsetting Derivative Assets: Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts $ 289,018 $ (63,321 ) $ 225,697 Total derivative instruments $ 289,018 $ (63,321 ) $ 225,697 Offsetting Derivative Liabilities: Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts $ (63,615 ) $ 63,321 $ (294 ) Interest rate derivative contracts (4,669 ) — (4,669 ) Total derivative instruments $ (68,284 ) $ 63,321 $ (4,963 ) By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. Our counterparties are participants in our Reserve-Based Credit Facility (see Note 3. Long-Term Debt for further discussion), which is secured by our oil and natural gas properties; therefore, we are not required to post any collateral. The maximum amount of loss due to credit risk that we would incur if our counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $230.5 million at September 30, 2015 . In accordance with our standard practice, our commodity and interest rate swap derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of such loss is somewhat mitigated as of September 30, 2015 . We minimize the credit risk in derivative instruments by: (i) entering into derivative instruments primarily with counterparties that are also lenders in our Reserve-Based Credit Facility and (ii) monitoring the creditworthiness of our counterparties on an ongoing basis. Changes in fair value of our commodity and interest rate derivatives for the nine months ended September 30, 2015 and the year ended December 31, 2014 are as follows: Nine Months Ended September 30, 2015 Year Ended December 31, 2014 (in thousands) Derivative asset at beginning of period, net $ 220,734 $ 66,711 Purchases Fair value of derivatives acquired 35,643 (1,344 ) Net gains on commodity and interest rate derivative contracts 100,270 161,519 Settlements Cash settlements received on matured commodity derivative contracts (125,988 ) (10,187 ) Cash settlements paid on matured interest rate derivative contracts 2,968 4,035 Termination of derivative contracts (31,945 ) — Derivative asset at end of period, net $ 201,682 $ 220,734

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements We estimate the fair values of financial and non-financial assets and liabilities under ASC Topic 820 “Fair Value Measurements and Disclosures” (“ASC Topic 820”). ASC Topic 820 provides a framework for consistent measurement of fair value for those assets and liabilities already measured at fair value under other accounting pronouncements. Certain specific fair value measurements, such as those related to share-based compensation, are not included in the scope of ASC Topic 820. Primarily, ASC Topic 820 is applicable to assets and liabilities related to financial instruments, to some long-term investments and liabilities, to initial valuations of assets and liabilities acquired in a business combination, recognition of asset retirement obligations and to long-lived assets written down to fair value when they are impaired. It does not apply to oil and natural gas properties accounted for under the full cost method, which are subject to impairment based on SEC rules. ASC Topic 820 applies to assets and liabilities carried at fair value on the Consolidated Balance Sheets, as well as to supplemental information about the fair values of financial instruments not carried at fair value. We have applied the provisions of ASC Topic 820 to assets and liabilities measured at fair value on a recurring basis, which includes our commodity and interest rate derivatives contracts, and on a nonrecurring basis, which includes goodwill, acquisitions of oil and natural gas properties and other intangible assets. ASC Topic 820 provides a definition of fair value and a framework for measuring fair value, as well as expanding disclosures regarding fair value measurements. The framework requires fair value measurement techniques to include all significant assumptions that would be made by willing participants in a market transaction. ASC Topic 820 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. ASC Topic 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to the “levels” described below. The hierarchy is based on the reliability of the inputs used in estimating fair value and requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The framework for fair value measurement assumes that transparent “observable” (Level 1) inputs generally provide the most reliable evidence of fair value and should be used to measure fair value whenever available. The classification of a fair value measurement is determined based on the lowest level (with Level 3 as the lowest) of significant input to the fair value estimation process. The standard describes three levels of inputs that may be used to measure fair value: Level 1 Quoted prices for identical instruments in active markets. Level 2 Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets. Level 3 Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used. As required by ASC Topic 820, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: Financing arrangements. The carrying amounts of our bank borrowings outstanding approximate fair value because our current borrowing rates do not materially differ from market rates for similar bank borrowings. We consider this fair value estimate as a Level 2 input. As of September 30, 2015 , the fair value of our Senior Notes was estimated to be $319.8 million . We consider the inputs to the valuation of our Senior Notes to be Level 1 as fair value was estimated based on prices quoted from a third-party financial institution. Derivative instruments. Our commodity derivative instruments consist of fixed-price swaps, basis swaps, call options sold, swaptions, put options sold, call spreads, call options, put options, three-way collars and range bonus accumulators. We account for our commodity derivatives and interest rate derivatives at fair value on a recurring basis. We estimate the fair values of the fixed-price swaps and basis-swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate. We estimate the option value of the contract floors, ceilings and three-way collars using an option pricing model which takes into account market volatility, market prices and contract parameters. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. In order to estimate the fair value of our interest rate swaps, we use a yield curve based on money market rates and interest rate swaps, extrapolate a forecast of future interest rates, estimate each future cash flow, derive discount factors to value the fixed and floating rate cash flows of each swap, and then discount to present value all known (fixed) and forecasted (floating) swap cash flows. We consider the fair value estimate for these derivative instruments as a Level 2 input. We estimate the value of the range bonus accumulators using an option pricing model for both Asian Range Digital options and Asian Put options that takes into account market volatility, market prices and contract parameters. Range bonus accumulators are complex in structure requiring sophisticated valuation methods and greater subjectivity. As such, range bonus accumulators valuation may include inputs and assumptions that are less observable or require greater estimation, thereby resulting in valuations with less certainty. We consider the fair value estimate for range bonus accumulators as a Level 3 input. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Management validates the data provided by third parties by understanding the pricing models used, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to our commodity derivatives and interest rate derivatives. Financial assets and financial liabilities measured at fair value on a recurring basis are summarized below (in thousands): September 30, 2015 Fair Value Measurements Using Assets/Liabilities Level 1 Level 2 Level 3 at Fair value Assets: Commodity price derivative contracts $ — $ 212,394 $ (6,069 ) $ 206,325 Interest rate derivative contracts — (3,534 ) — (3,534 ) Total derivative instruments $ — $ 208,860 $ (6,069 ) $ 202,791 Liabilities: Commodity price derivative contracts $ — $ (652 ) $ — $ (652 ) Interest rate derivative contracts — (457 ) — (457 ) Total derivative instruments $ — $ (1,109 ) $ — $ (1,109 ) December 31, 2014 Fair Value Measurements Using Assets/Liabilities Level 1 Level 2 Level 3 at Fair value Assets: Commodity price derivative contracts $ — $ 232,167 $ (6,470 ) $ 225,697 Total derivative instruments $ — $ 232,167 $ (6,470 ) $ 225,697 Liabilities: Commodity price derivative contracts $ — $ (294 ) $ — $ (294 ) Interest rate derivative contracts — (4,669 ) — (4,669 ) Total derivative instruments $ — $ (4,963 ) $ — $ (4,963 ) The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 (unobservable inputs) in the fair value hierarchy: Nine Months Ended September 30, 2015 2014 (in thousands) Unobservable inputs, beginning of period $ (6,470 ) $ 566 Total gains 3,525 798 Settlements (3,124 ) (184 ) Unobservable inputs, end of period $ (6,069 ) $ 1,180 Change in fair value included in earnings related to derivatives still held as of September 30, $ (2,254 ) $ 1,132 During periods of market disruption, including periods of volatile oil and natural gas prices, there may be certain asset classes that were in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments, other than the range bonus accumulators, may fall to Level 3 and thus require more subjectivity and management judgment. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition. We apply the provisions of ASC Topic 350 “ Intangibles-Goodwill and Other .” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is assessed for impairment annually on October 1 or whenever indicators of impairment exist. The goodwill test is performed at the reporting unit level, which represents our oil and natural gas operations in the United States. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. We utilize a market approach to determine the fair value of our reporting unit. While no goodwill impairment was recognized at September 30, 2015 , any further significant decline in prices of oil and natural gas or significant negative reserve adjustments could change our estimate of the fair value of the reporting unit and could result in an impairment charge. Our nonfinancial assets and liabilities that are initially measured at fair value are comprised primarily of assets acquired in business combinations and asset retirement costs and obligations. These assets and liabilities are recorded at fair value when acquired/incurred but not re-measured at fair value in subsequent periods. We classify such initial measurements as Level 3 since certain significant unobservable inputs are utilized in their determination. A reconciliation of the beginning and ending balance of our asset retirement obligations is presented in Note 6, in accordance with ASC Topic 410-20 “ Asset Retirement Obligations. ” During the nine months ended September 30, 2015 and the year ended December 31, 2014 , in connection with new wells drilled and wells acquired during the period, we incurred and recorded asset retirement obligations totaling $ 2.0 million and $52.8 million , respectively, at fair value. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Inputs to the valuation include: (1) estimated plug and abandonment cost per well based on our experience; (2) estimated remaining life per well based on average reserve life per field; (3) our credit-adjusted risk-free interest rate ranging between 4.6% and 5.2% ; 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	9 Months Ended
	Sep. 30, 2015
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The asset retirement obligations as of September 30, 2015 and December 31, 2014 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the nine months ended September 30, 2015 and the year ended December 31, 2014 were as follows: September 30, 2015 December 31, 2014 (in thousands) Asset retirement obligations, beginning of period $ 149,062 $ 87,967 Liabilities added during the current period 1,971 52,829 Accretion expense 5,537 5,889 Retirements (692 ) (450 ) Disposition of properties — (1,291 ) Change in estimate 22,329 4,118 Asset retirement obligation, end of period 178,207 149,062 Less: current obligations (4,309 ) (2,386 ) Long-term asset retirement obligation, end of period $ 173,898 $ 146,676 Each year the Company reviews and, to the extent necessary, revises its asset retirement obligation estimates. During 2015 and 2014 , the Company reviewed actual abandonment costs with previous estimates and, as a result, increased its estimates of future asset retirement obligations by $22.3 million and $4.1 million , respectively, to reflect increased costs incurred for plugging and abandonment costs.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Transportation Demand Charges As of September 30, 2015 , we have contracts that provide firm transportation capacity on pipeline systems. The remaining terms on these contracts range from nine months 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 September 30, 2015 . However, our financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property. September 30, 2015 (in thousands) October 1, 2015 - December 31, 2015 $ 4,194 2016 15,442 2017 12,512 2018 11,696 2019 9,661 Thereafter 410 Total $ 53,915 Legal Proceedings We are defendants in legal proceedings arising in the normal course of our business. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management does not believe that it is probable that the outcome of these actions will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flow. We are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject. We are also a party to separate legal proceedings relating to each of the LRE Merger and the Eagle Rock Merger (these proceedings are together referred to as the “Merger Litigation”). Please see Part II-Item 1-Legal Proceedings in this Quarterly Report for a detailed discussion of the Merger Litigation.

Members' Equity and Net Income

Members' Equity and Net Income per Common and Class B Unit	9 Months Ended
	Sep. 30, 2015
Equity [Abstract]
Members' Equity and Net Income per Common and Class B Unit	Members’ Equity and Net Income per Common and Class B Unit Cumulative Preferred Units The following table summarizes the Company’s Cumulative Preferred units outstanding at September 30, 2015 and December 31, 2014 : September 30, 2015 December 31, 2014 Earliest Redemption Date Liquidation Preference Per Share Distribution Rate Units Outstanding Carrying Value Units Outstanding Carrying Value Series A June 15, 2023 $25.00 7.875% 2,581,873 $ 62,200 2,581,873 $ 62,200 Series B April 15, 2024 $25.00 7.625% 7,000,000 $ 169,265 7,000,000 $ 169,265 Series C October 15, 2024 $25.00 7.75% 4,300,000 $ 103,979 4,300,000 $ 103,979 Total Cumulative Preferred Units 13,881,873 $ 335,444 13,881,873 $ 335,444 The Cumulative Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by us or converted into our common units, at our option, commencing on the redemptions dates as stated above. The Cumulative Preferred Units can be redeemed, in whole or in part, out of amounts legally available therefore, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. Upon the occurrence of a change of control, each holder of Cumulative Preferred Units will have the right to convert some or all of their Cumulative Preferred Units into our common units unless prior to the change of control, we provide notice of our election to redeem the Cumulative Preferred Units or we exercise any of our redemption rights relating to the units prior to the change of control conversion date as set by our board of directors. Also upon the occurrence of a change of control we may, at our option and subject to certain restrictions, redeem the Cumulative Preferred Units by paying $25.00 per unit, plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. Holders of the Cumulative Preferred Units will have no voting rights except for limited voting rights if we fail to pay dividends for eighteen or more monthly periods (whether or not consecutive) and in certain other limited circumstances or as required by law. The Cumulative Preferred Units have a liquidation preference which is equal to the redemption price described above. Common and Class B Units The common units represent limited liability company interests. Holders of Class B units have substantially the same rights and obligations as the holders of common units. The following is a summary of the changes in our common units issued during the nine months ended September 30, 2015 and the year ended December 31, 2014 (in thousands): September 30, 2015 December 31, 2014 Beginning of period 83,452 78,337 Issuance of Common units for cash 2,430 4,864 Repurchase of units under the Common unit buyback program (157 ) (135 ) Reissuance of Common units for restricted unit grants 288 — Unit-based compensation 584 386 End of period 86,597 83,452 There was no change in issued and outstanding Class B units during the nine months ended September 30, 2015 or the year ended December 31, 2014 . 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 basic net income per unit. The net income (loss) attributable to common and Class B unitholders and the weighted average units for calculating basic and diluted net income (loss) per common and Class B unit were as follows (in thousands, except per unit data): Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 (in thousands, except per unit amounts) Net income (loss) attributable to Common and Class B unitholders $ (468,967 ) $ 109,150 $ (1,394,822 ) $ 112,975 Weighted average number of Common and Class B units outstanding - basic 87,012 83,525 85,834 81,377 Effect of dilutive securities: Phantom units (a) — 228 — 274 Weighted average number of Common and Class B units outstanding - diluted 87,012 83,753 85,834 81,651 Net income (loss) per Common and Class B unit Basic $ (5.39 ) $ 1.31 $ (16.25 ) $ 1.39 Diluted $ (5.39 ) $ 1.30 $ (16.25 ) $ 1.38 (a) For the three and nine months ended September 30, 2015 , 47,626 and 166,331 phantom units were excluded from the calculation of diluted earnings per unit, respectively, due to their antidilutive effect as we were in a loss position. Distributions Declared The Cumulative Preferred Units rank senior to our common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up. Distributions on the Preferred Units are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by our board of directors. We will pay cumulative distributions in cash on the Preferred Units on a monthly basis at a monthly rate of 7.875% per annum of the liquidation preference of $25.00 per Series A Cumulative Preferred Unit, a monthly rate of 7.625% per annum of the liquidation preference of $25.00 per Series B Cumulative Preferred Unit and a monthly rate of 7.75% per annum of the liquidation preference of $25.00 per Series C Cumulative Preferred Unit. The following table shows the distribution amount, declared date, record date and payment date of the cash distributions we paid on each of our common and Class B units for each period presented. Future distributions are at the discretion of our board of directors and will depend on business conditions, earnings, our cash requirements and other relevant factors. On October 19, 2015 , our board of directors declared a cash distribution on the Cumulative Preferred Units and common and Class B units attributable to the month of September 2015. See Note 11. Subsequent Events for further discussion. Cash Distributions Distribution Per Unit Declared Date Record Date Payment Date 2015 Third Quarter August $ 0.1175 September 21, 2015 October 1, 2015 October 15, 2015 July $ 0.1175 August 20, 2015 September 1, 2015 September 14, 2015 Second Quarter June $ 0.1175 July 16, 2015 August 3, 2015 August 14, 2015 May $ 0.1175 June 18, 2015 July 1, 2015 July 15, 2015 April $ 0.1175 May 19, 2015 June 1, 2015 June 12, 2015 First Quarter March $ 0.1175 April 15, 2015 May 1, 2015 May 15, 2015 February $ 0.1175 March 18, 2015 April 1, 2015 April 14, 2015 January $ 0.1175 February 17, 2015 March 2, 2015 March 17, 2015 2014 Fourth Quarter December $ 0.2100 January 22, 2015 February 2, 2015 February 13, 2015 November $ 0.2100 December 16, 2014 January 2, 2015 January 14, 2015 October $ 0.2100 November 20, 2014 December 1, 2014 December 15, 2014 Third Quarter September $ 0.2100 October 20, 2014 November 3, 2014 November 14, 2014 August $ 0.2100 September 19, 2014 October 1, 2014 October 15, 2014 July $ 0.2100 August 19, 2014 September 2, 2014 September 12, 2014 Second Quarter June $ 0.2100 July 16, 2014 August 1, 2014 August 14, 2014 May $ 0.2100 June 24, 2014 July 1, 2014 July 15, 2014 April $ 0.2100 May 20, 2014 June 2, 2014 June 13, 2014 First Quarter March $ 0.2100 April 17, 2014 May 1, 2014 May 15, 2014 February $ 0.2100 March 17, 2014 April 1, 2014 April 14, 2014 January $ 0.2075 February 20, 2014 March 3, 2014 March 17, 2014 2013 Fourth Quarter December $ 0.2075 January 16, 2014 February 3, 2014 February 14, 2014

Unit-Based Compensation

Unit-Based Compensation	9 Months Ended
	Sep. 30, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Unit-Based Compensation	Unit-Based Compensation Long-Term Incentive Plan The Vanguard Natural Resources, LLC Long-Term Incentive Plan (the “VNR LTIP”) was adopted by the Board of Directors of the Company to compensate employees and nonemployee directors of the Company and its affiliates who perform services for the Company under the terms of the plan. The VNR LTIP is administered by the compensation committee of the board of directors (the “Compensation Committee”) and permits the grant of unrestricted units, restricted units, phantom units, unit options and unit appreciation rights. Restricted and Phantom Units A restricted unit is a unit grant that vests over a period of time and that during such time is subject to forfeiture. A phantom unit grant represents the equivalent of one common unit of the Company. The phantom units, once vested, are settled through the delivery of a number of common units equal to the number of such vested units, or an amount of cash equal to the fair market value of such common units on the vesting date to be paid in a single lump sum payment, as determined by the compensation committee in its discretion. The Compensation Committee may grant tandem distribution equivalent rights (“DERs”) with respect to the phantom units that entitle the holder to receive the value of any distributions made by us on our units while the phantom units are outstanding. The fair value of restricted unit and phantom unit awards is measured based on the fair market value of the Company units on the date of grant. The values of restricted unit grants and phantom unit grants that are required to be settled in units are recognized as expense over the vesting period of the grants with a corresponding charge to members’ equity. When the Company has the option to settle the phantom unit grants by issuing Company units or through cash settlement, the Company recognizes the value of those grants utilizing the liability method as defined under ASC Topic 718 based on the Company’s historical practice of settling phantom units predominantly in cash. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period. Executive Employment Agreements In June and July 2013, we and VNRH entered into amended and restated executive employment agreements (the “Amended Agreements”) with each of our three executive officers, Messrs. Smith, Robert and Pence. The Amended Agreements were effective January 1, 2013 and the initial term of the Amended Agreements ends on January 1, 2016, with a subsequent twelve-month term extension automatically commencing on January 1, 2016 and each successive January 1 thereafter, provided that neither VNRH nor the executives deliver a timely non-renewal notice prior to a term expiration date. The Amended Agreements provide for an annual base salary and eligibility to receive an annual performance-based cash bonus award. The annual bonus will be calculated based upon three Company performance components: absolute target distribution growth, adjusted EBITDA growth and relative unit performance to peer group, as well as a fourth component determined solely in the discretion of our board of directors. As of September 30, 2015 , an accrued liability was recognized and compensation expense of $1.1 million was recorded for the nine months ended September 30, 2015 related to these arrangements, which was classified in the selling, general and administrative expenses line item in the Consolidated Statement of Operations. Under the Amended Agreements, the executives are also eligible to receive annual equity-based compensation awards, consisting of restricted units and/or phantom units granted under the VNR LTIP. Any restricted units and phantom units granted to executives under the Amended Agreements are subject to a three-year vesting period. One-third of the aggregate number of the units vest on each one-year anniversary of the date of grant so long as the executive remains continuously employed with the Company. Both the restricted and phantom units include a tandem grant of DERs. Restricted Unit Grants In January 2015, the executives were granted a total of 360,762 restricted units in accordance with the Amended Agreements. Also, during the nine months ended September 30, 2015 , our three independent board members were granted a total of 26,334 restricted units which will vest one year from the date of grant. The restricted units granted to the executives and our board members are accompanied by DERs. VNR employees were also granted a total of 169,772 restricted units under the VNR LTIP of which 1,613 restricted units vested immediately. The remaining grants have vesting periods between three to four years years from the date of grant. A summary of the status of the non-vested restricted units as of September 30, 2015 is presented below: Number of Non-vested Restricted Units Weighted Average Grant Date Fair Value Non-vested restricted units at December 31, 2014 440,047 $ 28.87 Granted 556,868 $ 15.23 Forfeited (17,670 ) $ 20.54 Vested (119,904 ) $ 29.22 Non-vested restricted units at September 30, 2015 859,341 $ 20.15 At September 30, 2015 , there was approximately $11.7 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately 1.7 years. Our Consolidated Statements of Operations reflect non-cash compensation related to restricted unit grants of $3.4 million and $1.3 million in the selling, general and administrative expenses line item for the three months ended September 30, 2015 and 2014 , respectively, and $10.4 million and $5.2 million for the nine months ended September 30, 2015 and 2014 , respectively. Phantom Unit Grants A summary of the status of the non-vested phantom units under the VNR LTIP as of September 30, 2015 is presented below: Number of Non-vested Phantom Units Weighted Average Grant Date Fair Value Non-vested phantom units at December 31, 2014 330,440 $ 21.27 Forfeited (2,979 ) $ 28.28 Vested (124,127 ) $ 21.56 Non-vested phantom units at September 30, 2015 203,334 $ 20.99 At September 30, 2015 , there was approximately $2.8 million of unrecognized compensation cost related to non-vested phantom units. The cost is expected to be recognized over an average period of approximately 1.4 years . Our Consolidated Statements of Operations reflect non-cash compensation related to phantom unit grants of $0.4 million and $0.2 million in the selling, general and administrative expense line item for the three months ended September 30, 2015 and 2014 , respectively, and $1.3 million for each of the nine months ended September 30, 2015 and 2014 .

Shelf Registration Statements

Shelf Registration Statements	9 Months Ended
	Sep. 30, 2015
Shelf Registration Statement [Abstract]
Shelf Registration Statement	Shelf Registration Statement We have registered an indeterminate amount of Series A Cumulative Preferred Units, Series B Cumulative Preferred Units, Series C Cumulative Preferred Units, common units, debt securities and guarantees of debt securities under our currently effective shelf registration statement filed with the SEC, as amended (the “Shelf Registration Statement”). In the future, we may issue additional debt and equity securities pursuant to a prospectus supplement to the Shelf Registration Statement. Net proceeds, terms and pricing of each offering of securities issued under the Shelf Registration Statement are determined at the time of such offerings. The Shelf Registration Statement does not provide assurance that we will or could sell any such securities. Our ability to utilize the Shelf Registration Statement for the purpose of issuing, from time to time, any combination of debt securities, common units or Cumulative Preferred Units will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us. We have entered into an equity distribution agreement with respect to the issuance and sale of our Series A Cumulative Preferred Units, Series B Cumulative Preferred Units, Series C Cumulative Preferred Units, and common units. Pursuant to the terms of the equity distribution agreement, we may sell from time to time through our sales agents, (i) our common units representing limited liability company interests having an aggregate offering price of up to $400.0 million , (ii) our Series A Cumulative Preferred Units having an aggregate offering price of up to $50.0 million , (iii) our Series B Cumulative Preferred Units having an aggregate offering price of up to $100.0 million or (iv) our Series C Cumulative Preferred Units having an aggregate offering price of up to $75.0 million . The common units and Preferred Units to be sold under the equity distribution agreement are registered under our existing Shelf Registration Statement. During the nine months ended September 30, 2015 , total net proceeds received under the equity distribution agreement were approximately $35.5 million , after commissions and fees of $0.6 million , from the sale of 2,430,170 common units. Subsidiary Guarantors We and VNRF, our wholly-owned finance subsidiary, may co-issue securities pursuant to the registration statement discussed above. VNR has no independent assets or operations. Debt securities that we may offer may be guaranteed by our subsidiaries. We contemplate that if we offer debt securities, the guarantees will be full and unconditional and joint and several (subject to certain customary release provisions), and any subsidiaries of VNR that do not guarantee the securities will be minor.

Subsequent Events

Subsequent Events	9 Months Ended
	Sep. 30, 2015
Subsequent Events [Abstract]
Subsequent Event	Subsequent Events Distributions On October 19, 2015 , our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of September 2015 of $0.1175 per common and Class B unit ( $1.41 on an annualized basis) expected to be paid on November 13, 2015 to Vanguard unitholders of record on November 2, 2015 , which includes unitholders who received the newly issued Vanguard Common Units as part of the LRE Merger and Eagle Rock Merger discussed below. Also on October 19, 2015 , our board of directors declared a cash distribution for our preferred unitholders of $0.1641 per Series A Cumulative Preferred Unit, $0.15885 per Series B Cumulative Preferred Unit and $0.16146 per Series C Cumulative Preferred Unit, which will be paid on November 13, 2015 to Vanguard preferred unitholders of record on November 2, 2015 . Mergers LRE Merger On October 5, 2015, Vanguard completed the transactions contemplated by the Purchase Agreement and Plan of Merger, dated as of April 20, 2015 (the “LRE Merger Agreement”), pursuant to which a subsidiary of Vanguard merged into LRR Energy, L.P. (“LRE”) and, at the same time, Vanguard acquired LRE GP, LLC (the “LRE GP”), the general partner of LRR Energy, L.P. (the “LRE Merger”). Under the terms of the LRE Merger Agreement, (i) each outstanding LRE common unit was converted into the right to receive 0.550 newly issued Vanguard common units and (ii) Vanguard purchased all of the outstanding limited liability company interests in LRE GP in exchange for 12,320 newly issued Vanguard common units. Further, in connection with the LRE Merger Agreement, each award of restricted LRE common units issued under LRE’s long-term incentive plan that was subject to time-based vesting and that was outstanding and unvested immediately prior to the effective time of the LRE Merger became fully vested and was deemed to be a LRE common unit with the right to receive Vanguard common units. As consideration for the LRE Merger, Vanguard issued approximately 15.4 million common units valued at $121.3 million based on the closing price per Vanguard common unit of $7.86 at October 5, 2015 and assumed $290.0 million in debt. The LRE Merger was completed following approval, at a Special Meeting of LRE unitholders on October 5, 2015, of the LRE Merger Agreement and the LRE Merger by holders of a majority of the outstanding LRE Common Units. Eagle Rock Merger On October 8, 2015, Vanguard completed the previously announced transactions contemplated by the Agreement and Plan of Merger, dated as of May 21, 2015 (the “Eagle Rock Merger Agreement”) pursuant to which Eagle Rock Energy Partners, L.P. became a wholly-owned indirect subsidiary of Vanguard (the “Eagle Rock Merger”). Under the terms of the Eagle Rock Merger Agreement, (i) each Eagle Rock common unit was converted into the right to receive 0.185 newly issued Vanguard common units. Further, in connection with the Eagle Rock Merger Agreement, Vanguard adopted Eagle Rock’s long-term incentive plan and each outstanding award of Eagle Rock common units issued under such plan was converted into a new award of restricted units based on Vanguard common units. However, any outstanding Eagle Rock common units held by employees and officers of Eagle Rock and members of the board of directors of Eagle Rock who did not receive employment offers from Vanguard accelerated upon the effective time of the Eagle Rock Merger and was converted into the right to receive newly issued Vanguard common units, with the vesting of performance-based restricted units determined based upon Eagle Rock’s actual performance through the effective time of the Eagle Rock Merger (subject to Vanguard’s good faith review). As consideration for the Eagle Rock Merger, Vanguard issued approximately 28.3 million Vanguard common units valued at $259.2 million based on the closing price per Vanguard common unit of $9.17 at October 8, 2015 and assumed $151.8 million in debt. The Eagle Rock Merger was completed following (i) approval by holders of a majority of the outstanding Eagle Rock common units, at a Special Meeting of Eagle Rock unitholders on October 5, 2015, of the Eagle Rock Merger Agreement and the Eagle Rock Merger and (ii) approval by Vanguard unitholders, at Vanguard’s 2015 Annual Meeting of Unitholders, of the issuance of Vanguard common units to be issued as Eagle Rock Merger Consideration to the holders of Eagle Rock common units in connection with the Eagle Rock Merger. Borrowing Base Redetermination On November 6, 2015 , we completed our semi-annual borrowing base redetermination and entered into the Fourth Amended and Restated Credit Agreement (“Restated Credit Agreement”), which reaffirms the Company’s $1.8 billion borrowing base. The terms of the Restated Credit Agreement also include, among other provisions, the increase in the maximum investments or capital contributions that can be made in certain entities from $5.0 million to $100.0 million . In addition, the Company is permitted to incur up to $300.0 million of junior lien indebtedness provided the borrowing base will be reduced by $0.25 cents for every dollar of junior debt issued.

Summary of Significant Accoun20

Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation and Principles of Consolidation	Basis of Presentation and Principles of Consolidation: The consolidated financial statements as of September 30, 2015 and December 31, 2014 and for the three and nine months ended September 30, 2015 and 2014 include our accounts and those of our subsidiaries. We present our financial statements in accordance with GAAP. All intercompany transactions and balances have been eliminated upon consolidation. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income (loss) or members’ equity.
Oil and Natural Gas Properties	Oil and Natural Gas Properties: The full cost method of accounting is used to account for oil and natural gas properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil, natural gas and NGLs reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and subject to ceiling test limitations as discussed below. Capitalized costs associated with proved reserves are amortized over the life of the reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated, which occurs on a quarterly basis. Specifically, costs are transferred to the amortizable base when properties are determined to have proved reserves. In addition, we transfer unproved property costs to the amortizable base when unproved properties are evaluated as being impaired and as exploratory wells are determined to be unsuccessful. Additionally, the amortizable base includes estimated future development costs, dismantlement, restoration and abandonment costs net of estimated salvage values. Capitalized costs are limited to a ceiling based on the present value of future net revenues, computed using the 12-month unweighted average of first-day-of-the-month historical price, the “12-month average price” discounted at 10% , plus the lower of cost or fair market value of unproved properties. If the ceiling is less than the total capitalized costs, we are required to write-down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write-downs are included in the Consolidated Statements of Operations as an impairment charge. We recorded a non-cash ceiling test impairment of oil and natural gas properties for the nine months ended September 30, 2015 of $1.4 billion as a result of a decline in oil and natural gas prices at the measurement dates, March 31, 2015 , June 30, 2015 and September 30, 2015 . The impairment for the first quarter of 2015 was $132.6 million and was calculated based on the 12-month average price of $3.91 per MMBtu for natural gas and $82.62 per barrel of crude oil. The impairment for the second quarter of 2015 was $733.4 million and was calculated based on the 12-month average price of $3.44 per MMBtu for natural gas and $71.51 per barrel of crude oil. The impairment for the third quarter of 2015 was $491.5 million and was calculated based on the 12-month average price of $3.11 per MMBtu for natural gas and $59.23 per barrel of crude oil. No ceiling test impairment was required during the nine months ended September 30, 2014 . When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties.
New Pronouncements Issued But Not Yet Adopted	New Pronouncement Issued But Not Yet Adopted: In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU No. 2014-09”), which amends the FASB ASC by adding new FASB ASC Topic 606, Revenue from Contracts with Customers, and superseding the revenue recognition requirements in FASB ASC 605, Revenue Recognition, and in most industry-specific topics. 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). In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date (“ASU No. 2014-14”) to defer the effective date of ASU No. 2014-09 by one year. Public business entities should apply the guidance in ASU 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. 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 we will adopt the standard in 2018. In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (“ASU No. 2015-16”) to simplify the accounting for adjustments made to provisional amounts recognized in a business combination by eliminating the requirement to retrospectively account for those adjustments. The amendments under ASU No. 2015-16 require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Further, the amendments in this ASU require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments under ASU No. 2015-16 also require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. For public business entities, the amendments are effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The amendments should be applied prospectively to adjustments to provisional amounts that occur after the effective date with earlier application permitted for financial statements that have not been issued. The only disclosures required at transition should be the nature of and reason for the change in accounting principle. An entity should disclose that information in the first annual period of adoption and in the interim periods within the first annual period if there is a measurement-period adjustment during the first annual period in which the changes are effective. We do not expect the adoption of ASU No. 2015-16 will have a material impact on our consolidated financial statements.
Use of Estimates	Use of Estimates: The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related cash flow estimates used in impairment tests of oil and natural gas properties and goodwill, the acquisition of oil and natural gas properties, the fair value of derivative contracts and asset retirement obligations, accrued oil, natural gas and NGLs revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ from those estimates.

Acquisitions (Tables)

Acquisitions (Tables)	9 Months Ended
	Sep. 30, 2015
Business Acquisition [Line Items]
Pro Forma Information	The pro forma results reflect the results of combining our statement of operations with the results of operations from the oil and natural gas properties acquired during 2014 , adjusted for (i) the assumption of asset retirement obligations and accretion expense for the properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired, and (iii) interest expense on additional borrowings necessary to finance the acquisitions. The net gains on acquisitions of oil and natural gas properties was excluded from the pro forma results for the three and nine months ended September 30, 2014 . The pro forma information is based upon these assumptions and is not necessarily indicative of future results of operations: Pro forma Three Months Ended September 30, 2014 Nine Months Ended September 30, 2014 (in thousands, except per unit data) Total revenues $ 275,547 $ 613,584 Net income attributable to Common and Class B unitholders $ 118,458 $ 134,928 Net income per Common and Class B unit: Basic $ 1.42 $ 1.66 Diluted $ 1.41 $ 1.65
Revenues and Excess of Revenues Over Direct Operating Expenses	The amount of revenues and excess of revenues over direct operating expenses included in the accompanying Consolidated Statements of Operations for our 2014 acquisitions are shown in the table that follows. Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes. Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 (in thousands) Pinedale Acquisition Revenues $ 22,098 $ 36,947 $ 66,445 $ 106,163 Excess of revenues over direct operating expenses $ 14,694 $ 29,423 $ 44,598 $ 82,709 Piceance Acquisition Revenues $ 9,081 $ 283 $ 28,811 $ 283 Excess of revenues over direct operating expenses $ 4,310 $ 227 $ 15,237 $ 227 Other acquisitions Revenues $ 9,987 $ 8,671 $ 28,720 $ 11,831 Excess of revenues over direct operating expenses $ 5,522 $ 5,868 $ 15,836 $ 7,970
Pinedale Acquisition
Business Acquisition [Line Items]
Fair value of assets and liabilities acquired	Fair value of assets and liabilities acquired (in thousands) Oil and natural gas properties $ 600,123 Inventory 244 Asset retirement obligations (12,404 ) Imbalance liabilities (171 ) Other (125 ) Total fair value of assets and liabilities acquired 587,667 Fair value of consideration transferred 555,553 Gain on acquisition $ 32,114
Piceance Acquisition
Business Acquisition [Line Items]
Fair value of assets and liabilities acquired	Fair value of assets and liabilities acquired (in thousands) Oil and natural gas properties $ 523,537 Asset retirement obligations (19,452 ) Production and ad valorem taxes payable (7,552 ) Suspense liabilities (445 ) Other (124 ) Total fair value of assets and liabilities acquired 495,964 Fair value of consideration transferred 496,391 Loss on acquisition $ (427 )

Long-Term Debt (Tables)

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2015
Debt Disclosure [Abstract]
Financing Arrangements	Our financing arrangements consisted of the following as of the date indicated: Amount Outstanding Description Interest Rate Maturity Date September 30, 2015 December 31, 2014 (in thousands) Senior Secured Reserve-Based Credit Facility Variable (1) April 16, 2018 $ 1,320,000 $ 1,360,000 Senior Notes 7.875% (2) April 1, 2020 550,000 550,000 Lease Financing Obligation 4.16% August 10, 2020 (3) $ 25,764 28,986 $ 1,895,764 $ 1,938,986 Less: Unamortized discount on Senior Notes (1,636 ) (1,852 ) Current portion of Lease Financing Obligation (4,454 ) (4,318 ) Total long-term debt $ 1,889,674 $ 1,932,816 (1) Variable interest rate was 2.45% and 2.17% at September 30, 2015 and December 31, 2014 , respectively. (2) Effective interest rate was 8.0% . (3) The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021.
Borrowing Base Utilization Grid	Borrowing Base Utilization Grid Borrowing Base Utilization Percentage <25% > 25% <50% > 50% <75% > 75% <90% > 90% Eurodollar Loans Margin 1.50 % 1.75 % 2.00 % 2.25 % 2.50 % ABR Loans Margin 0.50 % 0.75 % 1.00 % 1.25 % 1.50 % Commitment Fee Rate 0.50 % 0.50 % 0.375 % 0.375 % 0.375 % Letter of Credit Fee 0.50 % 0.75 % 1.00 % 1.25 % 1.50 %

Price and Interest Rate Risk 23

Price and Interest Rate Risk Management Activities (Tables)	9 Months Ended
	Sep. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivative Contracts Covering Anticipated Future Production	At September 30, 2015 , the Company had open commodity derivative contracts covering our anticipated future production as follows: Fixed-Price Swaps Gas Oil NGLs Contract Period MMBtu Weighted Average Fixed Price Bbls Weighted Average WTI Price Bbls Weighted Average October 1, 2015 – December 31, 2015 22,436,000 $ 4.26 602,600 $ 71.94 62,100 $ 46.34 January 1, 2016 – December 31, 2016 55,083,000 $ 4.47 329,400 $ 76.10 567,300 29.96 January 1, 2017 – December 31, 2017 24,027,000 $ 4.35 — $ — — $ — Call Options Sold Gas Oil Contract Period MMBtu Weighted Average Fixed Price Bbls Weighted Average Fixed Price October 1, 2015 – December 31, 2015 — — 18,400 $ 105.00 January 1, 2016 – December 31, 2016 9,150,000 $ 4.25 622,200 $ 125.00 January 1, 2017 – December 31, 2017 9,125,000 $ 4.50 365,000 $ 95.00 Swaptions Gas Contract Period MMBtu Weighted Average Fixed Price October 1, 2015 – December 31, 2015 610,000 $ 3.50 January 1, 2016 – December 31, 2016 910,000 $ 3.50 Basis Swaps Gas Contract Period MMBtu Weighted Avg. Basis Differential ($/MMBtu) Pricing Index October 1, 2015 – December 31, 2015 7,360,000 $ (0.28 ) Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential January 1, 2016 – December 31, 2016 21,960,000 $ (0.23 ) 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 Differential ($/Bbl) Pricing Index October 1, 2015 – December 31, 2015 128,800 $ (1.68 ) WTI Midland and WTI Cushing Basis Differential January 1, 2016 – December 31, 2016 512,400 $ (0.94 ) WTI Midland and WTI Cushing Basis Differential October 1, 2015 – December 31, 2015 36,800 $ (2.33 ) West Texas Sour and WTI Cushing Basis Differential January 1, 2016 – December 31, 2016 219,600 $ (0.43 ) West Texas Sour and WTI Cushing Basis Differential October 1, 2015 – December 31, 2015 184,000 $ (14.50 ) WTI and West Canadian Select Basis Differential Three-Way Collars Gas Contract Period MMBtu Floor Ceiling Put Sold January 1, 2016 – December 31, 2016 12,810,000 $ 3.95 $ 4.25 $ 3.00 January 1, 2017 – December 31, 2017 16,425,000 $ 3.92 $ 4.23 $ 3.37 Oil Contract Period Bbls Floor Ceiling Put Sold October 1, 2015 – December 31, 2015 69,000 $ 90.00 $ 99.13 $ 76.67 January 1, 2016 – December 31, 2016 1,061,400 $ 90.00 $ 96.18 $ 73.62 Put Options Sold Gas Oil Contract Period MMBtu Put Sold ($/MMBtu) Bbls Put Sold ($/Bbl) October 1, 2015 – December 31, 2015 6,670,000 $ 3.16 128,800 $ 71.43 January 1, 2016 – December 31, 2016 1,830,000 $ 3.00 146,400 $ 75.00 January 1, 2017 – December 31, 2017 1,825,000 $ 3.50 73,000 $ 75.00 Range Bonus Accumulators Gas Contract Period MMBtu Bonus Range Ceiling Range Floor October 1, 2015 – December 31, 2015 368,000 $ 0.16 $ 4.00 $ 2.50 Oil Contract Period Bbls Bonus Range Ceiling Range Floor October 1, 2015 – December 31, 2015 46,000 $ 4.00 $ 100.00 $ 75.00 January 1, 2016 – December 31, 2016 183,000 $ 4.00 $ 100.00 $ 75.00 Collars Oil Contract Period Bbls Floor Price ($/Bbl) Ceiling Price ($/Bbl) October 1, 2015 – December 31, 2015 46,000 $ 50.00 $ 58.45 Call Spreads Oil Contract Period Bbls Call Price ($/Bbl) Short Call Price ($/Bbl) October 1, 2015 – December 31, 2015 473,800 $ 70.00 $ 85.00 Puts Oil Contract Period Bbls Put Price ($/Bbl) January 1, 2016 – December 31, 2016 366,000 $ 60.00
Interest Rate Derivative Contracts	Interest Rate Swaps At September 30, 2015 , we had open interest rate derivative contracts as follows (in thousands): Period Notional Amount Fixed LIBOR Rates October 1, 2015 to December 10, 2016 $ 20,000 2.17 % October 1, 2015 to October 31, 2016 $ 40,000 1.65 % October 1, 2015 to August 5, 2018 $ 30,000 2.25 % October 1, 2015 to August 6, 2016 $ 25,000 1.80 % October 1, 2015 to October 31, 2016 $ 20,000 1.78 % October 1, 2015 to September 23, 2016 $ 75,000 1.15 % October 1, 2015 to March 7, 2016 $ 75,000 1.08 % October 1, 2015 to September 7, 2016 $ 25,000 1.25 % October 1, 2015 to December 10, 2015 (1) $ 50,000 0.21 % Total $ 360,000 (1) The counterparty has the option to require Vanguard to pay a fixed rate of 0.91% from December 10, 2015 to December 10, 2017.
Fair Value of Derivatives Outstanding	Our commodity derivatives and interest rate swap derivatives are presented on a net basis in “derivative assets” and “derivative liabilities” on the Consolidated Balance Sheets as governed by the International Swaps and Derivatives Association Master Agreement with each of the counterparties. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets for the periods indicated (in thousands): September 30, 2015 Offsetting Derivative Assets: Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts $ 230,500 $ (24,175 ) $ 206,325 Interest rate derivative contracts — (3,534 ) (3,534 ) Total derivative instruments $ 230,500 $ (27,709 ) $ 202,791 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 $ (24,827 ) $ 24,175 $ (652 ) Interest rate derivative contracts (3,991 ) 3,534 (457 ) Total derivative instruments $ (28,818 ) $ 27,709 $ (1,109 ) December 31, 2014 Offsetting Derivative Assets: Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts $ 289,018 $ (63,321 ) $ 225,697 Total derivative instruments $ 289,018 $ (63,321 ) $ 225,697 Offsetting Derivative Liabilities: Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts $ (63,615 ) $ 63,321 $ (294 ) Interest rate derivative contracts (4,669 ) — (4,669 ) Total derivative instruments $ (68,284 ) $ 63,321 $ (4,963 )
Reported Gains and Losses on Derivative Instruments	Changes in fair value of our commodity and interest rate derivatives for the nine months ended September 30, 2015 and the year ended December 31, 2014 are as follows: Nine Months Ended September 30, 2015 Year Ended December 31, 2014 (in thousands) Derivative asset at beginning of period, net $ 220,734 $ 66,711 Purchases Fair value of derivatives acquired 35,643 (1,344 ) Net gains on commodity and interest rate derivative contracts 100,270 161,519 Settlements Cash settlements received on matured commodity derivative contracts (125,988 ) (10,187 ) Cash settlements paid on matured interest rate derivative contracts 2,968 4,035 Termination of derivative contracts (31,945 ) — Derivative asset at end of period, net $ 201,682 $ 220,734

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2015
Fair Value Disclosures [Abstract]
Financial Assets and Financial Liabilities Measured at Fair Value on a Recurring Basis	Financial assets and financial liabilities measured at fair value on a recurring basis are summarized below (in thousands): September 30, 2015 Fair Value Measurements Using Assets/Liabilities Level 1 Level 2 Level 3 at Fair value Assets: Commodity price derivative contracts $ — $ 212,394 $ (6,069 ) $ 206,325 Interest rate derivative contracts — (3,534 ) — (3,534 ) Total derivative instruments $ — $ 208,860 $ (6,069 ) $ 202,791 Liabilities: Commodity price derivative contracts $ — $ (652 ) $ — $ (652 ) Interest rate derivative contracts — (457 ) — (457 ) Total derivative instruments $ — $ (1,109 ) $ — $ (1,109 ) December 31, 2014 Fair Value Measurements Using Assets/Liabilities Level 1 Level 2 Level 3 at Fair value Assets: Commodity price derivative contracts $ — $ 232,167 $ (6,470 ) $ 225,697 Total derivative instruments $ — $ 232,167 $ (6,470 ) $ 225,697 Liabilities: Commodity price derivative contracts $ — $ (294 ) $ — $ (294 ) Interest rate derivative contracts — (4,669 ) — (4,669 ) Total derivative instruments $ — $ (4,963 ) $ — $ (4,963 )
Reconciliation of changes in the fair value of assets and liabilities classified as Level 3	The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 (unobservable inputs) in the fair value hierarchy: Nine Months Ended September 30, 2015 2014 (in thousands) Unobservable inputs, beginning of period $ (6,470 ) $ 566 Total gains 3,525 798 Settlements (3,124 ) (184 ) Unobservable inputs, end of period $ (6,069 ) $ 1,180 Change in fair value included in earnings related to derivatives still held as of September 30, $ (2,254 ) $ 1,132

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2015
Asset Retirement Obligation [Abstract]
Changes in Asset Retirement Obligations	The asset retirement obligations as of September 30, 2015 and December 31, 2014 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the nine months ended September 30, 2015 and the year ended December 31, 2014 were as follows: September 30, 2015 December 31, 2014 (in thousands) Asset retirement obligations, beginning of period $ 149,062 $ 87,967 Liabilities added during the current period 1,971 52,829 Accretion expense 5,537 5,889 Retirements (692 ) (450 ) Disposition of properties — (1,291 ) Change in estimate 22,329 4,118 Asset retirement obligation, end of period 178,207 149,062 Less: current obligations (4,309 ) (2,386 ) Long-term asset retirement obligation, end of period $ 173,898 $ 146,676

Commitments and Contingencies (

Commitments and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
Future minimum transportation demand charges	The values in the table below represent gross future minimum transportation demand charges we are obligated to pay as of September 30, 2015 . However, our financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property. September 30, 2015 (in thousands) October 1, 2015 - December 31, 2015 $ 4,194 2016 15,442 2017 12,512 2018 11,696 2019 9,661 Thereafter 410 Total $ 53,915

Members' Equity and Net Incom27

Members' Equity and Net Income per Common and Class B Unit (Tables)	9 Months Ended
	Sep. 30, 2015
Equity [Abstract]
Cumulative Preferred Units	The following table summarizes the Company’s Cumulative Preferred units outstanding at September 30, 2015 and December 31, 2014 : September 30, 2015 December 31, 2014 Earliest Redemption Date Liquidation Preference Per Share Distribution Rate Units Outstanding Carrying Value Units Outstanding Carrying Value Series A June 15, 2023 $25.00 7.875% 2,581,873 $ 62,200 2,581,873 $ 62,200 Series B April 15, 2024 $25.00 7.625% 7,000,000 $ 169,265 7,000,000 $ 169,265 Series C October 15, 2024 $25.00 7.75% 4,300,000 $ 103,979 4,300,000 $ 103,979 Total Cumulative Preferred Units 13,881,873 $ 335,444 13,881,873 $ 335,444
Schedule of Common and Class B Units Outstanding Roll Forward	The following is a summary of the changes in our common units issued during the nine months ended September 30, 2015 and the year ended December 31, 2014 (in thousands): September 30, 2015 December 31, 2014 Beginning of period 83,452 78,337 Issuance of Common units for cash 2,430 4,864 Repurchase of units under the Common unit buyback program (157 ) (135 ) Reissuance of Common units for restricted unit grants 288 — Unit-based compensation 584 386 End of period 86,597 83,452
Schedule of Earnings Per Share, Basic and Diluted	The net income (loss) attributable to common and Class B unitholders and the weighted average units for calculating basic and diluted net income (loss) per common and Class B unit were as follows (in thousands, except per unit data): Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 (in thousands, except per unit amounts) Net income (loss) attributable to Common and Class B unitholders $ (468,967 ) $ 109,150 $ (1,394,822 ) $ 112,975 Weighted average number of Common and Class B units outstanding - basic 87,012 83,525 85,834 81,377 Effect of dilutive securities: Phantom units (a) — 228 — 274 Weighted average number of Common and Class B units outstanding - diluted 87,012 83,753 85,834 81,651 Net income (loss) per Common and Class B unit Basic $ (5.39 ) $ 1.31 $ (16.25 ) $ 1.39 Diluted $ (5.39 ) $ 1.30 $ (16.25 ) $ 1.38 (a) For the three and nine months ended September 30, 2015 , 47,626 and 166,331 phantom units were excluded from the calculation of diluted earnings per unit, respectively, due to their antidilutive effect as we were in a loss position.
Distributions Declared	The following table shows the distribution amount, declared date, record date and payment date of the cash distributions we paid on each of our common and Class B units for each period presented. Future distributions are at the discretion of our board of directors and will depend on business conditions, earnings, our cash requirements and other relevant factors. On October 19, 2015 , our board of directors declared a cash distribution on the Cumulative Preferred Units and common and Class B units attributable to the month of September 2015. See Note 11. Subsequent Events for further discussion. Cash Distributions Distribution Per Unit Declared Date Record Date Payment Date 2015 Third Quarter August $ 0.1175 September 21, 2015 October 1, 2015 October 15, 2015 July $ 0.1175 August 20, 2015 September 1, 2015 September 14, 2015 Second Quarter June $ 0.1175 July 16, 2015 August 3, 2015 August 14, 2015 May $ 0.1175 June 18, 2015 July 1, 2015 July 15, 2015 April $ 0.1175 May 19, 2015 June 1, 2015 June 12, 2015 First Quarter March $ 0.1175 April 15, 2015 May 1, 2015 May 15, 2015 February $ 0.1175 March 18, 2015 April 1, 2015 April 14, 2015 January $ 0.1175 February 17, 2015 March 2, 2015 March 17, 2015 2014 Fourth Quarter December $ 0.2100 January 22, 2015 February 2, 2015 February 13, 2015 November $ 0.2100 December 16, 2014 January 2, 2015 January 14, 2015 October $ 0.2100 November 20, 2014 December 1, 2014 December 15, 2014 Third Quarter September $ 0.2100 October 20, 2014 November 3, 2014 November 14, 2014 August $ 0.2100 September 19, 2014 October 1, 2014 October 15, 2014 July $ 0.2100 August 19, 2014 September 2, 2014 September 12, 2014 Second Quarter June $ 0.2100 July 16, 2014 August 1, 2014 August 14, 2014 May $ 0.2100 June 24, 2014 July 1, 2014 July 15, 2014 April $ 0.2100 May 20, 2014 June 2, 2014 June 13, 2014 First Quarter March $ 0.2100 April 17, 2014 May 1, 2014 May 15, 2014 February $ 0.2100 March 17, 2014 April 1, 2014 April 14, 2014 January $ 0.2075 February 20, 2014 March 3, 2014 March 17, 2014 2013 Fourth Quarter December $ 0.2075 January 16, 2014 February 3, 2014 February 14, 2014

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Share-based Compensation, Restricted Stock Units Award Activity	A summary of the status of the non-vested restricted units as of September 30, 2015 is presented below: Number of Non-vested Restricted Units Weighted Average Grant Date Fair Value Non-vested restricted units at December 31, 2014 440,047 $ 28.87 Granted 556,868 $ 15.23 Forfeited (17,670 ) $ 20.54 Vested (119,904 ) $ 29.22 Non-vested restricted units at September 30, 2015 859,341 $ 20.15
Schedule of Nonvested Phantom Units Activity	A summary of the status of the non-vested phantom units under the VNR LTIP as of September 30, 2015 is presented below: Number of Non-vested Phantom Units Weighted Average Grant Date Fair Value Non-vested phantom units at December 31, 2014 330,440 $ 21.27 Forfeited (2,979 ) $ 28.28 Vested (124,127 ) $ 21.56 Non-vested phantom units at September 30, 2015 203,334 $ 20.99

Description of the Business (De

Description of the Business (Details)	9 Months Ended
	Sep. 30, 2015operating_areas
Accounting Policies [Abstract]
Number of operating areas	9

Summary of Significant Accoun30

Summary of Significant Accounting Policies (Details) $ in Thousands	3 Months Ended				9 Months Ended
	Sep. 30, 2015USD ($)$ / bbl$ / MMBTU	Jun. 30, 2015USD ($)$ / bbl$ / MMBTU	Mar. 31, 2015USD ($)$ / bbl$ / MMBTU	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Discount rate used in determining limitation of capitalized costs (in hundredths)					10.00%
Impairment of oil and natural gas properties	$ 491,487	$ 733,400	$ 132,600	$ 0	$ 1,357,462	$ 0
Average price of natural gas used in the impairment calculation | $ / MMBTU	3.11	3.44	3.91
Average price of crude oil used in the impairment calculation | $ / bbl	59.23	71.51	82.62

Acquisitions (Details)

Acquisitions (Details) - USD ($) $ in Thousands	Sep. 30, 2014	Aug. 29, 2014	May. 02, 2014	Jan. 31, 2014	Sep. 30, 2015	Sep. 30, 2014
Pinedale Acquisition
Business Acquisition [Line Items]
Fair value of consideration transferred				$ 555,553
Effective date of acquisition				Oct. 1, 2013
Gain on acquisition of oil and natural gas properties				$ 32,114
Piceance Acquisition
Business Acquisition [Line Items]
Fair value of consideration transferred	$ 496,391
Effective date of acquisition	Jul. 1, 2014
Goodwill, Impairment Loss	$ 427
Wamsutter Property Acquisition
Business Acquisition [Line Items]
Ownership interest conveyed			75.00%
Fair value of consideration transferred			$ 6,800
Effective date of acquisition			Jan. 1, 2014
Gulf Coast Acquisition
Business Acquisition [Line Items]
Fair value of consideration transferred		$ 265,100
Effective date of acquisition		Jun. 1, 2014
Other Smaller Acquisitions
Business Acquisition [Line Items]
Fair value of consideration transferred					$ 11,400	$ 17,700

Acquisitions (Fair Value of Ass

Acquisitions (Fair Value of Assets and Liabilities Acquired) (Details) - USD ($) $ in Thousands	Sep. 30, 2014	Jan. 31, 2014	Sep. 30, 2015	Sep. 30, 2014
Pinedale Acquisition
Fair value of assets and liabilities acquired
Oil and Gas Properties		$ 600,123
Inventory		244
Asset retirement obligations		(12,404)
Imbalance and Suspense liabilities		(171)
Other		(125)
Total fair value of assets and liabilities acquired		587,667
Fair value of consideration transferred		555,553
Gain on acquisition of oil and natural gas properties		$ 32,114
Piceance Acquisition
Fair value of assets and liabilities acquired
Oil and Gas Properties	$ 523,537			$ 523,537
Asset retirement obligations	(19,452)			(19,452)
Production and ad valorem taxes payable	(7,552)			(7,552)
Imbalance and Suspense liabilities	(445)			(445)
Other	(124)			(124)
Total fair value of assets and liabilities acquired	495,964			495,964
Fair value of consideration transferred	496,391
Loss on acquisition	$ (427)
Other Smaller Acquisitions
Fair value of assets and liabilities acquired
Fair value of consideration transferred			$ 11,400	$ 17,700

Acquisitions (Pro Forma) (Detai

Acquisitions (Pro Forma) (Details) - USD ($)	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014
Business Acquisition, Pro Forma Information [Abstract]
Proforma revenues	$ 275,547,000	$ 613,584,000
Proforma Net income	$ 118,458,000	$ 134,928
Net income per Common and Class B unit:
Business Acquisition, Pro Forma Earnings Per Share, Basic	$ 1.42	$ 1.66
Business Acquisition, Pro Forma Earnings Per Share, Diluted	$ 1.41	$ 1.65

Acquisitions (Acquiree Earnings

Acquisitions (Acquiree Earnings) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Pinedale Acquisition
Business Acquisition [Line Items]
Revenues	$ 22,098	$ 36,947	$ 66,445	$ 106,163
Excess of revenues over direct operating expenses	14,694	29,423	44,598	82,709
Piceance Acquisition
Business Acquisition [Line Items]
Revenues	9,081	283	28,811	283
Excess of revenues over direct operating expenses	4,310	227	15,237	227
Other Smaller Acquisitions
Business Acquisition [Line Items]
Revenues	9,987	8,671	28,720	11,831
Excess of revenues over direct operating expenses	$ 5,522	$ 5,868	$ 15,836	$ 7,970

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Thousands		9 Months Ended
		Sep. 30, 2015	Jan. 01, 2017	Jan. 01, 2016	Oct. 05, 2015	Jun. 03, 2015	Mar. 31, 2015	Dec. 31, 2014
Senior Secured Reserve-Based Credit Facility [Abstract]
Outstanding borrowings		$ 1,895,764						$ 1,938,986
Current Ratio		100.00%
Debt to EBITDA ratio		550.00%				550.00%
Senior Notes [Abstract]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		100.00%
Members' equity available for distributions		$ 234,500
Debt Instrument, Unamortized Discount (Premium), Net		(1,636)						(1,852)
Long-term Debt, Current Maturities		4,454						4,318
Long-term Debt, Excluding Current Maturities		1,889,674						1,932,816
Senior Secured Reserve-Based Credit Facility
Senior Secured Reserve-Based Credit Facility [Abstract]
Line of Credit Facility, Maximum Borrowing Capacity		3,500,000
Line of Credit Facility, Current Borrowing Capacity		1,600,000					$ 2,000,000
Outstanding borrowings		1,320,000						1,360,000
Remaining borrowing capacity		$ 275,500
Senior Notes [Abstract]
Maturity date		Apr. 16, 2018
Senior Notes
Senior Secured Reserve-Based Credit Facility [Abstract]
Outstanding borrowings		$ 550,000						550,000
Senior Notes [Abstract]
Aggregate principal amount		$ 550,000
Stated interest rate (in hundredths)	[1]	7.875%
Maturity date		Apr. 1, 2020
Percentage of ownership in subsidiaries		100.00%
Redemption price of aggregate principal amount of senior notes on or after April 1, 2016 (in hundredths)		103.9375%
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%
Required repurchase price of aggregate principal amount of senior notes, lower range (in hundredths)		100.00%
Required repurchase price of aggregate principal amount of senior notes, upper range (in hundredths)		101.00%
Lease Financing Obligations
Senior Secured Reserve-Based Credit Facility [Abstract]
Outstanding borrowings		$ 25,764						$ 28,986
Senior Notes [Abstract]
Stated interest rate (in hundredths)		4.16%
Maturity date	[2]	Aug. 10, 2020
Aggregate Cost, Early Buyout Option to Purchase equipment		$ 16,000
Standby Letters of Credit | Senior Secured Reserve-Based Credit Facility
Senior Secured Reserve-Based Credit Facility [Abstract]
Line of Credit Facility, Current Borrowing Capacity		$ 4,500
Scenario, Forecast [Member]
Senior Secured Reserve-Based Credit Facility [Abstract]
Debt to EBITDA ratio			450.00%	525.00%
Scenario, Forecast [Member] | Senior Secured Reserve-Based Credit Facility
Senior Secured Reserve-Based Credit Facility [Abstract]
Additional borrowing capacity upon closing of the LRE merger					$ 200,000
[1]	Effective interest rate was 8.0%.
[2]	The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021.

Long-Term Debt - Financing Arra

Long-Term Debt - Financing Arrangements (Details) - USD ($) $ in Thousands		9 Months Ended
		Sep. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Outstanding borrowings		$ 1,895,764	$ 1,938,986
Senior Secured Reserve-Based Credit Facility
Debt Instrument [Line Items]
Interest rate description	[1]	Variable (1)
Maturity date		Apr. 16, 2018
Outstanding borrowings		$ 1,320,000	$ 1,360,000
Variable interest rate		2.45%	2.17%
Senior Notes
Debt Instrument [Line Items]
Stated interest rate (in hundredths)	[2]	7.875%
Maturity date		Apr. 1, 2020
Outstanding borrowings		$ 550,000	$ 550,000
Effective interest rate (in hundredths)		8.00%
Lease Financing Obligations
Debt Instrument [Line Items]
Stated interest rate (in hundredths)		4.16%
Maturity date	[3]	Aug. 10, 2020
Outstanding borrowings		$ 25,764	$ 28,986
[1]	Variable interest rate was 2.45% and 2.17% at September 30, 2015 and December 31, 2014, respectively.
[2]	Effective interest rate was 8.0%.
[3]	The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021.

Long-Term Debt - Borrowing Base

Long-Term Debt - Borrowing Base Utilization Grid (Details)	9 Months Ended
	Sep. 30, 2015
Borrowing Base Utilization Less Than 25%
Debt Instrument [Line Items]
Commitment fee rate (in hundredths)	0.50%
Letter of credit fee (in hundredths)	0.50%
Borrowing Base Utilization Less Than 25% | Eurodollar Loans Margin
Debt Instrument [Line Items]
Loans margin (in hundredths)	1.50%
Borrowing Base Utilization Less Than 25% | ABR Loans Margin
Debt Instrument [Line Items]
Loans margin (in hundredths)	0.50%
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50%
Debt Instrument [Line Items]
Commitment fee rate (in hundredths)	0.50%
Letter of credit fee (in hundredths)	0.75%
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50% | Eurodollar Loans Margin
Debt Instrument [Line Items]
Loans margin (in hundredths)	1.75%
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50% | ABR Loans Margin
Debt Instrument [Line Items]
Loans margin (in hundredths)	0.75%
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75%
Debt Instrument [Line Items]
Commitment fee rate (in hundredths)	0.375%
Letter of credit fee (in hundredths)	1.00%
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75% | Eurodollar Loans Margin
Debt Instrument [Line Items]
Loans margin (in hundredths)	2.00%
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75% | ABR Loans Margin
Debt Instrument [Line Items]
Loans margin (in hundredths)	1.00%
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90%
Debt Instrument [Line Items]
Commitment fee rate (in hundredths)	0.375%
Letter of credit fee (in hundredths)	1.25%
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90% | Eurodollar Loans Margin
Debt Instrument [Line Items]
Loans margin (in hundredths)	2.25%
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90% | ABR Loans Margin
Debt Instrument [Line Items]
Loans margin (in hundredths)	1.25%
Borrowing Base Utilization Equal To Or Greater Than 90%
Debt Instrument [Line Items]
Commitment fee rate (in hundredths)	0.375%
Letter of credit fee (in hundredths)	1.50%
Borrowing Base Utilization Equal To Or Greater Than 90% | Eurodollar Loans Margin
Debt Instrument [Line Items]
Loans margin (in hundredths)	2.50%
Borrowing Base Utilization Equal To Or Greater Than 90% | ABR Loans Margin
Debt Instrument [Line Items]
Loans margin (in hundredths)	1.50%

Price and Interest Rate Risk 38

Price and Interest Rate Risk Management Activities (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2015USD ($)MMBTU$ / bbl$ / MMBTUbbl
Fair value of derivatives [Abstract]
Maximum potential loss due to credit risk | $	$ 230,500
Fixed-Price Swaps | Gas | Contract period October 1, 2015 to December 31, 2015 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged | MMBTU	22,436,000
Weighted average fixed price (in dollars per unit) | $ / MMBTU	4.26
Fixed-Price Swaps | Gas | Contract period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged | MMBTU	55,083,000
Weighted average fixed price (in dollars per unit) | $ / MMBTU	4.47
Fixed-Price Swaps | Gas | Contract period January 1, 2017 to December 31, 2017
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged | MMBTU	24,027,000
Weighted average fixed price (in dollars per unit) | $ / MMBTU	4.35
Fixed-Price Swaps | Oil | Contract period October 1, 2015 to December 31, 2015 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	602,600
Weighted average fixed price (in dollars per unit)	71.94
Fixed-Price Swaps | Oil | Contract period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	329,400
Weighted average fixed price (in dollars per unit)	76.10
Fixed-Price Swaps | Oil | Contract period January 1, 2017 to December 31, 2017
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	0
Weighted average fixed price (in dollars per unit)	0
Fixed-Price Swaps | Natural Gas Liquids | Contract period October 1, 2015 to December 31, 2015 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	62,100
Weighted average fixed price (in dollars per unit)	46.34
Fixed-Price Swaps | Natural Gas Liquids | Contract period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	567,300
Weighted average fixed price (in dollars per unit)	29.96
Fixed-Price Swaps | Natural Gas Liquids | Contract period January 1, 2017 to December 31, 2017
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	0
Weighted average fixed price (in dollars per unit)	0
Call Option [Member] | Gas | Contract period October 1, 2015 to December 31, 2015 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged | MMBTU	0
Weighted average fixed price (in dollars per unit) | $ / MMBTU	0
Call Option [Member] | Gas | Contract period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged | MMBTU	9,150,000
Weighted average fixed price (in dollars per unit) | $ / MMBTU	4.25
Call Option [Member] | Gas | Contract period January 1, 2017 to December 31, 2017
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged | MMBTU	9,125,000
Weighted average fixed price (in dollars per unit) | $ / MMBTU	4.50
Call Option [Member] | Oil | Contract period October 1, 2015 to December 31, 2015 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	18,400
Weighted average fixed price (in dollars per unit)	105
Call Option [Member] | Oil | Contract period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	622,200
Weighted average fixed price (in dollars per unit)	125
Call Option [Member] | Oil | Contract period January 1, 2017 to December 31, 2017
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	365,000
Weighted average fixed price (in dollars per unit)	95
Swaption [Member] | Gas | Contract period October 1, 2015 to December 31, 2015 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged | MMBTU	610,000
Weighted average fixed price (in dollars per unit) | $ / MMBTU	3.50
Swaption [Member] | Gas | Contract period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged | MMBTU	910,000
Weighted average fixed price (in dollars per unit) | $ / MMBTU	3.50
Basis Swaps | Gas | Contract period October 1, 2015 to December 31, 2015 [Member] | NW Rocky Mt-Henry Hub Index
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged | MMBTU	7,360,000
Weighted average basis differential (in dollars per unit) | $ / MMBTU	(0.28)
Basis Swaps | Gas | Contract period January 1, 2016 to December, 31 2016 | NW Rocky Mt-Henry Hub Index
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged | MMBTU	21,960,000
Weighted average basis differential (in dollars per unit) | $ / MMBTU	(0.23)
Basis Swaps | Gas | Contract period January 1, 2017 to December 31, 2017 | NW Rocky Mt-Henry Hub Index
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged | MMBTU	10,950,000
Weighted average basis differential (in dollars per unit) | $ / MMBTU	(0.22)
Basis Swaps | Oil | Contract period October 1, 2015 to December 31, 2015 [Member] | Midland-Cushing Index
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	128,800
Weighted average basis differential (in dollars per unit)	(1.68)
Basis Swaps | Oil | Contract period October 1, 2015 to December 31, 2015 [Member] | WTS-Cushing Index
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	36,800
Weighted average basis differential (in dollars per unit)	(2.33)
Basis Swaps | Oil | Contract period October 1, 2015 to December 31, 2015 [Member] | WTI-WCS Index
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	184,000
Weighted average basis differential (in dollars per unit)	(14.50)
Basis Swaps | Oil | Contract period January 1, 2016 to December, 31 2016 | Midland-Cushing Index
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	512,400
Weighted average basis differential (in dollars per unit)	(0.94)
Basis Swaps | Oil | Contract period January 1, 2016 to December, 31 2016 | WTS-Cushing Index
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	219,600
Weighted average basis differential (in dollars per unit)	(0.43)
Three-Way Collars | Gas | Contract period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged | MMBTU	12,810,000
Weighted average price (in dollars per unit) | $ / MMBTU	3
Floor (in dollars per unit) | $ / MMBTU	3.95
Ceiling (in dollars per unit) | $ / MMBTU	4.25
Three-Way Collars | Gas | Contract period January 1, 2017 to December 31, 2017
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged | MMBTU	16,425,000
Weighted average price (in dollars per unit) | $ / MMBTU	3.37
Floor (in dollars per unit) | $ / MMBTU	3.92
Ceiling (in dollars per unit) | $ / MMBTU	4.23
Three-Way Collars | Oil | Contract period October 1, 2015 to December 31, 2015 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	69,000
Weighted average price (in dollars per unit)	76.67
Floor (in dollars per unit)	90
Ceiling (in dollars per unit)	99.13
Three-Way Collars | Oil | Contract period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	1,061,400
Weighted average price (in dollars per unit)	73.62
Floor (in dollars per unit)	90
Ceiling (in dollars per unit)	96.18
Put Options Sold | Gas | Contract period October 1, 2015 to December 31, 2015 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged | MMBTU	6,670,000
Weighted average price (in dollars per unit) | $ / MMBTU	3.16
Put Options Sold | Gas | Contract period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged | MMBTU	1,830,000
Weighted average price (in dollars per unit) | $ / MMBTU	3
Put Options Sold | Gas | Contract period January 1, 2017 to December 31, 2017
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged | MMBTU	1,825,000
Weighted average price (in dollars per unit) | $ / MMBTU	3.50
Put Options Sold | Oil | Contract period October 1, 2015 to December 31, 2015 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	128,800
Weighted average price (in dollars per unit)	71.43
Put Options Sold | Oil | Contract period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	146,400
Weighted average price (in dollars per unit)	75
Put Options Sold | Oil | Contract period January 1, 2017 to December 31, 2017
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	73,000
Weighted average price (in dollars per unit)	75
Range Bonus Accumulators | Gas | Contract period October 1, 2015 to December 31, 2015 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Floor (in dollars per unit) | $ / MMBTU	2.50
Ceiling (in dollars per unit) | $ / MMBTU	4
Notional amount (in MMBtu) | MMBTU	368,000
Bonus (in dollars per unit) | $ / MMBTU	0.16
Range Bonus Accumulators | Oil | Contract period October 1, 2015 to December 31, 2015 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Floor (in dollars per unit)	75
Derivative, Nonmonetary Notional Amount, Volume | bbl	46,000
Ceiling (in dollars per unit)	100
Bonus (in dollars per unit)	4
Range Bonus Accumulators | Oil | Contract period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Floor (in dollars per unit)	75
Derivative, Nonmonetary Notional Amount, Volume | bbl	183,000
Ceiling (in dollars per unit)	100
Bonus (in dollars per unit)	4
Collars | Oil | Contract period October 1, 2015 to December 31, 2015 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	46,000
Floor (in dollars per unit)	50
Ceiling (in dollars per unit)	58.45
Call Spreads | Oil | Contract period October 1, 2015 to December 31, 2015 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	473,800
Derivative, Price Risk Option Strike Price	70
Call option short call price	85
Puts | Oil | Contract period January 1, 2016 to December, 31 2016
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged | bbl	366,000
Derivative, Price Risk Option Strike Price	60
Interest Rate Swaps
Interest rate derivative contracts [Abstract]
Notional amount | $	$ 360,000
Interest Rate Swaps | Contract Period October 1, 2015 to December 10, 2016 [Member]
Interest rate derivative contracts [Abstract]
Notional amount | $	$ 20,000
Fixed Libor Rates (in hundredths)	2.17%
Interest Rate Swaps | Contract Period October 1, 2015 to October 31, 2016 Swap A [Member]
Interest rate derivative contracts [Abstract]
Notional amount | $	$ 40,000
Fixed Libor Rates (in hundredths)	1.65%
Interest Rate Swaps | Contract Period October 1, 2015 to August 5, 2015 [Member]
Interest rate derivative contracts [Abstract]
Notional amount | $	$ 30,000	[1]
Fixed Libor Rates (in hundredths)	2.25%	[1]
Interest Rate Swaps | Contract Period October 1, 2015 to August 6, 2016 [Member]
Interest rate derivative contracts [Abstract]
Notional amount | $	$ 25,000
Fixed Libor Rates (in hundredths)	1.80%
Interest Rate Swaps | Contract Period October 1, 2015 to October 31, 2016 Swap B [Member]
Interest rate derivative contracts [Abstract]
Notional amount | $	$ 20,000
Fixed Libor Rates (in hundredths)	1.78%
Interest Rate Swaps | Contract Period October 1, 2015 to September 23, 2016 [Member]
Interest rate derivative contracts [Abstract]
Notional amount | $	$ 75,000
Fixed Libor Rates (in hundredths)	1.149%
Interest Rate Swaps | Contract Period October 1, 2015 to March 7, 2016 [Member]
Interest rate derivative contracts [Abstract]
Notional amount | $	$ 75,000
Fixed Libor Rates (in hundredths)	1.08%
Interest Rate Swaps | Contract Period October 1, 2015 to September 7, 2016 [Member]
Interest rate derivative contracts [Abstract]
Notional amount | $	$ 25,000
Fixed Libor Rates (in hundredths)	1.25%
Interest Rate Swaps | Contract Period October 1, 2015 to December 10, 2015 [Member]
Interest rate derivative contracts [Abstract]
Notional amount | $	$ 50,000	[2]
Fixed Libor Rates (in hundredths)	0.21%	[2]
Interest Rate Swaps | Contract Period December 10, 2015 to December 10, 2017
Interest rate derivative contracts [Abstract]
Fixed Libor Rates (in hundredths)	0.91%
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmQzZGJkOTQ5MTg3MDRiZGRiYThhZTljMjk0NjM1NjMxfFRleHRTZWxlY3Rpb246ODIxRkVEQjAyNzJDNUY1NTIyRkUxOEZFQTdBNTAwNDIM}
[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 39

Price and Interest Rate Risk Management Activities - Balance Sheet Presentation (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Offsetting Derivative Assets:
Gross amounts of recognized assets	$ 230,500	$ 289,018
Gross amounts offset in the consolidated balance sheets	(27,709)	(63,321)
Net Amounts Presented in the Consolidated Balance Sheets	202,791	225,697
Offsetting Derivative Liabilities:
Gross amounts of recognized liabilities	(28,818)	(68,284)
Gross amounts offset in the consolidated balance sheets	27,709	63,321
Net Amounts Presented in the Consolidated Balance Sheets	(1,109)	(4,963)
Commodity Contract
Offsetting Derivative Assets:
Gross amounts of recognized assets	230,500	289,018
Gross amounts offset in the consolidated balance sheets	(24,175)	(63,321)
Net Amounts Presented in the Consolidated Balance Sheets	206,325	225,697
Offsetting Derivative Liabilities:
Gross amounts of recognized liabilities	(24,827)	(63,615)
Gross amounts offset in the consolidated balance sheets	24,175	63,321
Net Amounts Presented in the Consolidated Balance Sheets	(652)	(294)
Interest Rate Contract
Offsetting Derivative Assets:
Gross amounts of recognized assets	0
Gross amounts offset in the consolidated balance sheets	(3,534)
Net Amounts Presented in the Consolidated Balance Sheets	(3,534)
Offsetting Derivative Liabilities:
Gross amounts of recognized liabilities	(3,991)	(4,669)
Gross amounts offset in the consolidated balance sheets	3,534	0
Net Amounts Presented in the Consolidated Balance Sheets	$ (457)	$ (4,669)

Price and Interest Rate Risk 40

Price and Interest Rate Risk Management Activities - Change in Fair Value of Derivatives (Details) - USD ($) $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Fair Value, Net Derivative Asset (Liability), Reconciliation [Roll Forward]
Derivative asset at beginning of period, net	$ 220,734	$ 66,711	$ 66,711
Fair value of derivatives acquired	35,643		(1,344)
Net gains on commodity and interest rate derivative contracts	100,270	(12,193)	161,519
Cash settlement received on matured commodity derivative contracts	(125,988)	13,347	(10,187)
Cash settlements paid on matured interest rate derivative contracts	2,968	$ 3,026	4,035
Fair value of derivative contracts terminated	(31,945)		0
Derivative asset at end of period, net	$ 201,682		$ 220,734

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	$ 319,800
Liabilities:
Asset retirement obligations incurred and recorded	$ 1,971	$ 52,829
Average inflation rate (in hundredths)	2.29%
Fair Value Measured on a Recurring Basis
Assets:
Commodity price derivative contracts	$ 206,325	225,697
Interest Rate Derivative Assets, at Fair Value	(3,534)
Total derivative instruments	202,791	225,697
Liabilities:
Commodity price derivative contracts	(652)	(294)
Interest rate derivative contracts	(457)	(4,669)
Total derivative instruments	(1,109)	(4,963)
Fair Value Measured on a Recurring Basis | Fair Value Measurements Using Level 1
Assets:
Commodity price derivative contracts	0	0
Interest Rate Derivative Assets, at Fair Value	0
Total derivative instruments	0	0
Liabilities:
Commodity price derivative contracts	0	0
Interest rate derivative contracts	0	0
Total derivative instruments	0	0
Fair Value Measured on a Recurring Basis | Fair Value Measurements Using Level 2
Assets:
Commodity price derivative contracts	212,394	232,167
Interest Rate Derivative Assets, at Fair Value	(3,534)
Total derivative instruments	208,860	232,167
Liabilities:
Commodity price derivative contracts	(652)	(294)
Interest rate derivative contracts	(457)	(4,669)
Total derivative instruments	(1,109)	(4,963)
Fair Value Measured on a Recurring Basis | Fair Value Measurements Using Level 3
Assets:
Commodity price derivative contracts	(6,069)	(6,470)
Interest Rate Derivative Assets, at Fair Value	0
Total derivative instruments	(6,069)	(6,470)
Liabilities:
Commodity price derivative contracts	0	0
Interest rate derivative contracts	0	0
Total derivative instruments	$ 0	$ 0
Minimum
Liabilities:
Credit-adjusted risk-free interest rate (in hundredths)	4.60%
Maximum
Liabilities:
Credit-adjusted risk-free interest rate (in hundredths)	5.20%

Fair Value Measurements - Unobs

Fair Value Measurements - Unobservable Inputs Reconciliation (Details) - Fair Value Measurements Using Level 3 - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Unobservable inputs reconciliation
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	$ (6,470)	$ 566
Total gains	3,525	798
Settlements	(3,124)	(184)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	(6,069)	1,180
Change in fair value included in earnings related to derivatives still held as of September 30,	$ (2,254)	$ 1,132

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Changes in asset retirement obligations [Abstract]
Asset retirement obligations at beginning of period	$ 149,062	$ 87,967
Liabilities added during the current period	1,971	52,829
Accretion expense	5,537	5,889
Retirements	(692)	(450)
Disposition of properties	0	(1,291)
Change in estimate	22,329	4,118
Total asset retirement obligations at end of period	178,207	149,062
Less: current obligations	(4,309)	(2,386)
Long-term asset retirement obligation at end of period	$ 173,898	$ 146,676

Commitments and Contingencies44

Commitments and Contingencies (Transportation Demand Charges) (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2015USD ($)
Gross future minimum transportation demand
October 1, 2015 - December 31, 2015	$ 4,194
2,016	15,442
2,017	12,512
2,018	11,696
2,019	9,661
Thereafter	410
Total	$ 53,915
Minimum
Oil and Gas Delivery Commitments and Contracts
Oil and Gas Delivery Commitments and Contracts, Length of Contract	9 months
Maximum
Oil and Gas Delivery Commitments and Contracts
Oil and Gas Delivery Commitments and Contracts, Length of Contract	5 years

Members' Equity and Net Incom45

Members' Equity and Net Income per Common and Class B Unit - Preferred Units Outstanding (Details) - USD ($) $ / shares in Units, $ in Thousands	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Liquidation Preference Per Share (usd per share)	$ 25
Units Outstanding (shares)	13,881,873	13,881,873
Carrying Value	$ 335,444	$ 335,444
Series A Preferred Units
Class of Stock [Line Items]
Liquidation Preference Per Share (usd per share)	$ 25
Distribution Rate	7.875%
Units Outstanding (shares)	2,581,873	2,581,873
Carrying Value	$ 62,200	$ 62,200
Series B Preferred Unit
Class of Stock [Line Items]
Liquidation Preference Per Share (usd per share)	$ 25
Distribution Rate	7.625%
Units Outstanding (shares)	7,000,000	7,000,000
Carrying Value	$ 169,265	$ 169,265
Series C Preferred Units
Class of Stock [Line Items]
Liquidation Preference Per Share (usd per share)	$ 25
Distribution Rate	7.75%
Units Outstanding (shares)	4,300,000	4,300,000
Carrying Value	$ 103,979	$ 103,979

Members' Equity and Net Incom46

Members' Equity and Net Income per Common and Class B Unit - Common and Class B Units Rollforward (Details) - Common Units - shares shares in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Increase (Decrease) in Members' Equity [Roll Forward]
Beginning of period (shares)	83,452	78,337
Issuance of Common units for cash (shares)	2,430	4,864
Repurchase of units under the Common unit buyback program (shares)	(157)	(135)
Reissuance of Common units for restricted unit grants (shares)	288	0
Unit-based compensation (shares)	584	386
End of period (shares)	86,597	83,452

Members' Equity and Net Incom47

Members' Equity and Net Income per Common and Class B Unit - Net Income per Unit (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Dilutive Securities Included in Computation of Earnings Per Share [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic	$ (468,967)	$ 109,150	$ (1,394,822)	$ 112,975
Weighted Average Number of Shares Outstanding, Basic	87,012,000	83,525,000	85,834,000	81,377,000
Weighted Average Number of Shares Outstanding, Diluted	87,012,000	83,753,000	85,834,000	81,651,000
Antidilutive securities excluded from computation (shares)	47,626		166,331
Earnings Per Share, Basic	$ (5.39)	$ 1.31	$ (16.25)	$ 1.39
Earnings Per Share, Diluted	$ (5.39)	$ 1.30	$ (16.25)	$ 1.38
Phantom Share Units (PSUs)
Dilutive Securities Included in Computation of Earnings Per Share [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	0	228,000	0	274,000

Members' Equity and Net Incom48

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

1 Months Ended

9 Months Ended

Aug. 31, 2015

Jul. 31, 2015

Jun. 30, 2015

May. 31, 2015

Apr. 30, 2015

Mar. 31, 2015

Feb. 28, 2015

Jan. 31, 2015

Dec. 31, 2014

Nov. 30, 2014

Oct. 31, 2014

Sep. 30, 2014

Aug. 31, 2014

Jul. 31, 2014

Jun. 30, 2014

May. 31, 2014

Apr. 30, 2014

Mar. 31, 2014

Feb. 28, 2014

Jan. 31, 2014

Dec. 31, 2013

Sep. 30, 2015

Class of Stock [Line Items]

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

$ 25

Common Units

Class of Stock [Line Items]

Cash Distributions per Unit (usd per share)

$ 0.1175

$ 0.1175

$ 0.1175

$ 0.1175

$ 0.1175

$ 0.1175

$ 0.1175

$ 0.1175

$ 0.21

$ 0.21

$ 0.21

$ 0.21

$ 0.21

$ 0.21

$ 0.21

$ 0.21

$ 0.21

$ 0.21

$ 0.21

$ 0.2075

$ 0.2075

Cash distribution, declaration date

Sep. 21, 2015

Aug. 20, 2015

Jul. 16, 2015

Jun. 18, 2015

May 19, 2015

Apr. 15, 2015

Mar. 18, 2015

Feb. 17, 2015

Jan. 22, 2015

Dec. 16, 2014

Nov. 20, 2014

Oct. 20, 2014

Sep. 19, 2014

Aug. 19, 2014

Jul. 16, 2014

Jun. 24, 2014

May 20, 2014

Apr. 17, 2014

Mar. 17, 2014

Feb. 20, 2014

Jan. 16, 2014

Cash Distributions Record Date

Oct. 1, 2015

Sep. 1, 2015

Aug. 3, 2015

Jul. 1, 2015

Jun. 1, 2015

May 1, 2015

Apr. 1, 2015

Mar. 2, 2015

Feb. 2, 2015

Jan. 2, 2015

Dec. 1, 2014

Nov. 3, 2014

Oct. 1, 2014

Sep. 2, 2014

Aug. 1, 2014

Jul. 1, 2014

Jun. 2, 2014

May 1, 2014

Apr. 1, 2014

Mar. 3, 2014

Feb. 3, 2014

Cash Distributions Payment Date

Oct. 15, 2015

Sep. 14, 2015

Aug. 14, 2015

Jul. 15, 2015

Jun. 12, 2015

May 15, 2015

Apr. 14, 2015

Mar. 17, 2015

Feb. 13, 2015

Jan. 14, 2015

Dec. 15, 2014

Nov. 14, 2014

Oct. 15, 2014

Sep. 12, 2014

Aug. 14, 2014

Jul. 15, 2014

Jun. 13, 2014

May 15, 2014

Apr. 14, 2014

Mar. 17, 2014

Feb. 14, 2014

Series A Preferred Units

Class of Stock [Line Items]

Distribution Rate

7.875%

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

$ 25

Series B Preferred Unit

Class of Stock [Line Items]

Distribution Rate

7.625%

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

$ 25

Series C Preferred Units

Class of Stock [Line Items]

Distribution Rate

7.75%

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

$ 25

Unit-Based Compensation (Detail

Unit-Based Compensation (Details) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Jan. 31, 2015shares	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)officershares	Sep. 30, 2014USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Accrued liability | $		$ 1.1		$ 1.1
Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period				1 year
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested (in units)				119,904
Restricted Stock Units (RSUs) | Employee [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested (in units)				1,613
Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested (in units)				124,127
Amended Agreements
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of executives in amended agreements | officer				3
Amended Agreements | Executive Officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted (in units)	360,762
VNR Long Term Incentive Plan | Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted (in units)				26,334
VNR Long Term Incentive Plan | Employee [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted (in units)				169,772
Selling, General and Administrative Expenses | Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash compensation | $		3.4	$ 1.3	$ 10.4	$ 5.2
Selling, General and Administrative Expenses | Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash compensation | $		$ 0.4	$ 0.2	$ 1.3	$ 1.3
Minimum | Employee [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period				3 years
Maximum | Employee [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period				4 years

Unit-Based Compensation - Summa

Unit-Based Compensation - Summary of Non-Vested Restricted Units (Details) - $ / shares	1 Months Ended	9 Months Ended
	Jan. 31, 2015	Sep. 30, 2015
Board Member
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		1 year
Amended Agreements | Executive Officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted (in units)	360,762
VNR Long Term Incentive Plan | Board Member
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted (in units)		26,334
Restricted Stock Units (RSUs)
Number of Non-vested Units
Non-vested units at beginning of period (in units)	440,047	440,047
Granted (in units)		556,868
Forfeited (in units)		(17,670)
Vested (in units)		(119,904)
Non-vested units at end of period (in units)		859,341
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per unit)	$ 28.87	$ 28.87
Granted (in dollars per unit)		15.23
Forfeited (in dollars per unit)		20.54
Vested (in dollars per unit)		29.22
Non-vested units at end of period (in dollars per unit)		$ 20.15
Restricted Stock Units (RSUs) | Amended Agreements
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percent of units vesting on each one-year anniversary		33.33%
Phantom Share Units (PSUs)
Number of Non-vested Units
Non-vested units at beginning of period (in units)	330,440	330,440
Forfeited (in units)		(2,979)
Vested (in units)		(124,127)
Non-vested units at end of period (in units)		203,334
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per unit)	$ 21.27	$ 21.27
Forfeited (in dollars per unit)		28.28
Vested (in dollars per unit)		21.56
Non-vested units at end of period (in dollars per unit)		$ 20.99
Phantom Share Units (PSUs) | Amended Agreements
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percent of units vesting on each one-year anniversary		33.33%

Unit-Based Compensation - Sum51

Unit-Based Compensation - Summary of Non-Vested Phantom Units (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$ 11.7		$ 11.7
Unrecognized compensation cost recognition period (in years)			1 year 8 months
Number of Non-vested Units
Non-vested units at beginning of period (in units)			440,047
Forfeited (in units)			(17,670)
Vested (in units)			(119,904)
Non-vested units at end of period (in units)	859,341		859,341
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per unit)			$ 28.87
Forfeited (in dollars per unit)			20.54
Vested (in dollars per unit)			29.22
Non-vested units at end of period (in dollars per unit)	$ 20.15		$ 20.15
Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$ 2.8		$ 2.8
Unrecognized compensation cost recognition period (in years)			1 year 5 months
Number of Non-vested Units
Non-vested units at beginning of period (in units)			330,440
Forfeited (in units)			(2,979)
Vested (in units)			(124,127)
Non-vested units at end of period (in units)	203,334		203,334
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per unit)			$ 21.27
Forfeited (in dollars per unit)			28.28
Vested (in dollars per unit)			21.56
Non-vested units at end of period (in dollars per unit)	$ 20.99		$ 20.99
Selling, General and Administrative Expenses | Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash compensation	$ 3.4	$ 1.3	$ 10.4	$ 5.2
Selling, General and Administrative Expenses | Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash compensation	$ 0.4	$ 0.2	$ 1.3	$ 1.3

Shelf Registration Statements (

Shelf Registration Statements (Details) $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)shares
Common Units
Shelf Registration Statements [Line Items]
Maximum offering under equity distribution agreement	$ 400
Proceeds from Issuance or Sale of Equity	35.5
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs	$ 0.6
Units issued under public offerings (in units) | shares	2,430,170
Series A Preferred Units
Shelf Registration Statements [Line Items]
Maximum offering under equity distribution agreement	$ 50
Series B Preferred Unit
Shelf Registration Statements [Line Items]
Maximum offering under equity distribution agreement	100
Series C Preferred Units
Shelf Registration Statements [Line Items]
Maximum offering under equity distribution agreement	$ 75

Subsequent Events (Details)

Subsequent Events (Details) - USD ($)

Oct. 19, 2015

Oct. 08, 2015

Oct. 05, 2015

Aug. 31, 2015

Jul. 31, 2015

Jun. 30, 2015

May. 31, 2015

Apr. 30, 2015

Mar. 31, 2015

Feb. 28, 2015

Jan. 31, 2015

Dec. 31, 2014

Nov. 30, 2014

Oct. 31, 2014

Sep. 30, 2014

Aug. 31, 2014

Jul. 31, 2014

Jun. 30, 2014

May. 31, 2014

Apr. 30, 2014

Mar. 31, 2014

Feb. 28, 2014

Jan. 31, 2014

Dec. 31, 2013

Nov. 03, 2015

Sep. 30, 2015

Subsequent Event [Line Items]

Debt covenant, maximum investment in certain entities

$ 5,000,000

Subsequent Event

Subsequent Event [Line Items]

Debt covenant, maximum investment in certain entities

$ 100,000,000

Debt covenant, Reduction in borrowing capacity

25.00%

Common Units

Subsequent Event [Line Items]

Cash distribution, declaration date

Sep. 21, 2015

Aug. 20, 2015

Jul. 16, 2015

Jun. 18, 2015

May 19, 2015

Apr. 15, 2015

Mar. 18, 2015

Feb. 17, 2015

Jan. 22, 2015

Dec. 16, 2014

Nov. 20, 2014

Oct. 20, 2014

Sep. 19, 2014

Aug. 19, 2014

Jul. 16, 2014

Jun. 24, 2014

May 20, 2014

Apr. 17, 2014

Mar. 17, 2014

Feb. 20, 2014

Jan. 16, 2014

Common Units | Subsequent Event

Subsequent Event [Line Items]

Cash distribution, declaration date

Oct. 19, 2015

Cash distribution attributable, per unit

$ 0.1175

Cash distribution, annualized basis, per unit

1.41

Class B Units | Subsequent Event

Subsequent Event [Line Items]

Cash distribution attributable, per unit

0.1175

Cash distribution, annualized basis, per unit

1.41

Series A Preferred Units | Subsequent Event

Subsequent Event [Line Items]

Cash distribution attributable, per unit

0.1641

Series B Preferred Unit | Subsequent Event

Subsequent Event [Line Items]

Cash distribution attributable, per unit

0.15885

Series C Preferred Units | Subsequent Event

Subsequent Event [Line Items]

Cash distribution attributable, per unit

$ 0.16146

Cumulative Preferred units | Subsequent Event

Subsequent Event [Line Items]

Cash distribution, declaration date

Oct. 19, 2015

LRE Merger [Member] | Subsequent Event

Subsequent Event [Line Items]

Business Acquisition, Equity Interest Issued or Issuable, Exchange Ratio

55.00%

Business Combination, Consideration Transferred, Equity Interests Issued and Issuable

$ 121,300,000

Business Acquisition, Share Price

$ 7.86

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

$ 290,000,000

EROC Merger [Member] | Subsequent Event

Subsequent Event [Line Items]

Business Acquisition, Equity Interest Issued or Issuable, Exchange Ratio

18.50%

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

28,260,000

Business Combination, Consideration Transferred, Equity Interests Issued and Issuable

$ 259,200,000

Business Acquisition, Share Price

$ 9.17

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

$ 151,800,000

Interest owned by GP company [Member] | LRE Merger [Member] | Subsequent Event

Subsequent Event [Line Items]

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

12,320

Interest owned other than by GP company [Member] | LRE Merger [Member] | Subsequent Event

Subsequent Event [Line Items]

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

15,400,000

Senior Secured Reserve-Based Credit Facility

Subsequent Event [Line Items]

Line of Credit Facility, Current Borrowing Capacity

$ 2,000,000,000

$ 1,600,000,000

Senior Secured Reserve-Based Credit Facility | Subsequent Event

Subsequent Event [Line Items]

Line of Credit Facility, Current Borrowing Capacity

$ 1,800,000,000

Subordinated Debt [Member] | Subsequent Event

Subsequent Event [Line Items]

Maximum borrowing capacity

$ 300,000,000