Grizzly Energy (GRZZP) 10-Q 9 Nov 16 2016 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Nov. 07, 2016
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, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		131,024,208

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues:
Oil sales	$ 41,999	$ 33,624	$ 127,594	$ 113,425
Natural gas sales	52,454	50,851	121,756	146,502
NGLs sales	10,733	6,352	30,752	25,635
Net gains (losses) on commodity derivative contracts	21,099	64,328	(15,752)	102,561
Total revenues	126,285	155,155	264,350	388,123
Production:
Lease operating expenses	39,386	34,169	120,228	101,247
Production and other taxes	11,823	9,082	29,967	31,262
Depreciation, depletion, amortization, and accretion	32,096	52,428	118,935	182,443
Impairment of oil and natural gas properties	0	491,487	365,658	1,357,462
Impairment of goodwill	252,676	0	252,676	0
Selling, general and administrative expenses	11,454	8,046	35,884	26,239
Total costs and expenses	347,435	595,212	923,348	1,698,653
Loss from operations	(221,150)	(440,057)	(658,998)	(1,310,530)
Other income (expense):
Interest expense	(22,976)	(21,130)	(72,612)	(61,693)
Net gains (losses) on interest rate derivative contracts	764	(807)	(6,061)	(2,291)
Net loss on acquisition of oil and natural gas properties	(2,117)	(284)	(3,782)	(284)
Gain on extinguishment of debt	0	0	89,714	0
Other	111	1	363	46
Total other income (expense), net	(24,218)	(22,220)	7,622	(64,222)
Net loss	(245,368)	(462,277)	(651,376)	(1,374,752)
Less: Net income attributable to non-controlling interests	(27)	0	(91)	0
Net loss attributable to Vanguard unitholders	(245,395)	(462,277)	(651,467)	(1,374,752)
Distributions to Preferred unitholders	(6,690)	(6,690)	(20,069)	(20,070)
Net loss attributable to Common and Class B unitholders	$ (252,085)	$ (468,967)	$ (671,536)	$ (1,394,822)
Net loss per Common and Class B unit – basic and diluted (in usd per share)	$ (1.92)	$ (5.39)	$ (5.12)	$ (16.25)
Common Units
Other income (expense):
Weighted average Common units outstanding – basic & diluted (in shares)	131,040	86,592	130,862	85,414
Class B Units
Other income (expense):
Weighted average Common units outstanding – basic & diluted (in shares)	420	420	420	420

CONSOLIDATED BALANCE SHEETS (Un

CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents	$ 38,794	$ 0
Trade accounts receivable, net	100,707	115,200
Derivative assets	94,987	236,886
Other current assets	6,061	6,436
Total current assets	240,549	358,522
Oil and natural gas properties, at cost	4,705,609	4,961,218
Accumulated depletion, amortization and impairment	(3,712,323)	(3,239,242)
Oil and natural gas properties evaluated, net – full cost method	993,286	1,721,976
Other assets
Goodwill	253,370	506,046
Derivative assets	8,301	80,161
Other assets	50,379	28,887
Total assets	1,545,885	2,695,592
Accounts payable:
Trade	4,163	22,895
Affiliates	1,822	1,757
Accrued liabilities:
Lease operating	11,818	19,910
Development capital	7,752	26,726
Interest	17,728	11,958
Production and other taxes	39,803	40,472
Other	3,863	10,378
Derivative liabilities	33	356
Oil and natural gas revenue payable	27,284	44,823
Distributions payable	0	5,018
Current portion of long-term debt	31,887	0
Other current liabilities	14,958	17,715
Total current liabilities	161,111	202,008
Long-term debt, net of current portion (Note 3)	1,821,594	2,277,931
Derivative liabilities	1,671	0
Asset retirement obligations, net of current portion	258,306	262,432
Other long-term liabilities	40,022	40,656
Total liabilities	2,282,704	2,783,027
Commitments and contingencies (Note 7)
Members’ deficit (Note 8)
Total VNR members’ deficit	(743,813)	(87,435)
Non-controlling interest in subsidiary	6,994	0
Total members’ deficit	(736,819)	(87,435)
Total liabilities and members’ deficit	1,545,885	2,695,592
Cumulative Preferred Units
Members’ deficit (Note 8)
Total VNR members’ deficit	335,444	335,444
Common Units
Members’ deficit (Note 8)
Total VNR members’ deficit	(1,086,872)	(430,494)
Class B Units
Members’ deficit (Note 8)
Total VNR members’ deficit	$ 7,615	$ 7,615

CONSOLIDATED BALANCE SHEETS (U4

CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - shares	Sep. 30, 2016	Dec. 31, 2015
Members’ deficit (Note 8)
Preferred units, issued (shares)	13,881,873	13,881,873
Preferred units, outstanding (shares)	13,881,873	13,881,873
Common Units
Members’ deficit (Note 8)
Common units, issued (shares)	131,039,675	130,476,978
Common units, outstanding (shares)	131,039,675	130,476,978
Class B
Members’ deficit (Note 8)
Common units, issued (shares)	420,000	420,000
Common units, outstanding (shares)	420,000	420,000

CONSOLIDATED STATEMENTS OF MEMB

CONSOLIDATED STATEMENTS OF MEMBERS' DEFICIT (Unaudited) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Increase (Decrease) in Members' Equity [Roll Forward]
Balance		$ (87,435)	$ 1,534,116	$ 1,534,116
Issuance of common units, net of offering costs				35,544
Repurchase of units under the common unit buyback program				(2,399)
Distributions to Preferred unitholders (see Note 8)		(5,575)		(26,760)
Distributions to Common and Class B unitholders (see Note 8)		(8,014)		(134,019)
Unit-based compensation		8,850		16,874
Net income (loss)	$ (245,368)	(651,376)	(1,374,752)	(1,883,174)
Non-controlling interest in subsidiary		7,453
Potato Hills cash distribution to non-controlling interest		(550)
Balance	(736,819)	(736,819)		(87,435)
Non-controlling Interest
Increase (Decrease) in Members' Equity [Roll Forward]
Balance		0	0	0
Net income (loss)		91
Non-controlling interest in subsidiary		7,453
Potato Hills cash distribution to non-controlling interest		(550)
Balance	6,994	6,994		0
Cumulative Preferred Units | Member Units
Increase (Decrease) in Members' Equity [Roll Forward]
Balance		335,444	335,444	335,444
Balance	335,444	335,444		335,444
Common Units
Increase (Decrease) in Members' Equity [Roll Forward]
Issuance costs related to prior period equity transactions		(172)
Common Units | Member Units
Increase (Decrease) in Members' Equity [Roll Forward]
Balance		(430,494)	1,191,057	1,191,057
Issuance of common units, net of offering costs				35,544
Issuance costs related to prior period equity transactions		(172)		(593)
Repurchase of units under the common unit buyback program				(2,399)
Distributions to Preferred unitholders (see Note 8)		(5,575)		(26,760)
Distributions to Common and Class B unitholders (see Note 8)		(8,014)		(134,019)
Unit-based compensation		8,850		16,874
Net income (loss)		(651,467)		(1,883,174)
Balance	(1,086,872)	(1,086,872)		(430,494)
Class B | Member Units
Increase (Decrease) in Members' Equity [Roll Forward]
Balance		7,615	$ 7,615	7,615
Balance	$ 7,615	$ 7,615		7,615
EROC Merger | Common Units
Increase (Decrease) in Members' Equity [Roll Forward]
Issuance of common units, net of offering costs				253,068
EROC Merger | Common Units | Member Units
Increase (Decrease) in Members' Equity [Roll Forward]
Issuance of common units, net of offering costs				253,068
Issuance costs related to prior period equity transactions				(5,560)
LRE Merger | Common Units
Increase (Decrease) in Members' Equity [Roll Forward]
Issuance of common units, net of offering costs				119,315
LRE Merger | Common Units | Member Units
Increase (Decrease) in Members' Equity [Roll Forward]
Issuance of common units, net of offering costs				119,315
Issuance costs related to prior period equity transactions				$ (3,961)

CONSOLIDATED STATEMENTS OF MEM6

CONSOLIDATED STATEMENTS OF MEMBERS' DEFICIT (Unaudited) (Parenthetical) - Common Units - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Offering costs related to prior period offerings	$ (172)
Member Units
Offering costs related to prior period offerings	$ (172)	$ (593)
EROC Merger | Member Units
Offering costs related to prior period offerings		(5,560)
LRE Merger | Member Units
Offering costs related to prior period offerings		$ (3,961)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Operating activities
Net loss	$ (651,376)	$ (1,374,752)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization, and accretion	118,935	182,443
Impairment of oil and natural gas properties	365,658	1,357,462
Impairment of goodwill	252,676	0
Amortization of deferred financing costs	3,306	3,058
Amortization of debt discount	2,739	216
Compensation related items	8,850	9,732
Net (gains) losses on commodity and interest rate derivative contracts	21,813	(100,270)
Cash settlements received on matured commodity derivative contracts	198,104	125,988
Cash settlements paid on matured interest rate derivative contracts	(6,770)	(2,968)
Net loss on acquisition of oil and natural gas properties	3,782	284
Gain on extinguishment of debt	(89,714)	0
Changes in operating assets and liabilities:
Trade accounts receivable	10,482	73,817
Other current assets	(553)	(7,012)
Net premiums received (paid) on commodity derivative contracts	176	(794)
Accounts payable and oil and natural gas revenue payable	(36,296)	(15,360)
Payable to affiliates	65	689
Accrued expenses and other current liabilities	(32,497)	4,716
Other assets	10,197	8,070
Net cash provided by operating activities	179,577	265,319
Investing activities
Additions to property and equipment	(73)	(329)
Potato Hills Gas Gathering System acquisition	(7,501)	0
Additions to oil and natural gas properties	(49,117)	(80,213)
Acquisitions of oil and natural gas properties	0	(13,004)
Deposits and prepayments of oil and natural gas properties	(12,257)	(13,419)
Proceeds from the sale of oil and natural gas properties	288,483	0
Net cash provided by (used in) investing activities	219,535	(106,965)
Financing activities
Proceeds from long-term debt	93,500	117,500
Repayment of long-term debt	(430,897)	(160,721)
Proceeds from Common unit offerings, net	0	35,549
Repurchase of units under the Common unit buyback program	0	(2,399)
Distributions to Preferred unitholders	(6,690)	(20,070)
Distributions to Common and Class B unitholders	(11,917)	(106,562)
Potato Hills distribution to non-controlling interest	(550)	0
Financing fees	(3,764)	(2,161)
Net cash used in financing activities	(360,318)	(138,864)
Net increase cash and cash equivalents	38,794	19,490
Cash and cash equivalents, beginning of period	0	0
Cash and cash equivalents, end of period	38,794	19,490
Supplemental cash flow information:
Cash paid for interest	60,575	47,718
Non-cash financing and investing activity:
Asset retirement obligations, net	13,208	24,300
Noncash or Part Noncash Acquisition, Value of Assets Acquired	0	31,421
Noncash gain on termination of derivative contracts	$ 0	$ 28,517

Description of the Business

Description of the Business	9 Months Ended
	Sep. 30, 2016
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, 2016 , we own properties and oil and natural gas reserves primarily located in ten operating areas: • the Green River Basin in Wyoming; • the Permian Basin in West Texas and New Mexico; • the Gulf Coast Basin in Texas, Louisiana, Mississippi and Alabama; • the Anadarko Basin in Oklahoma and North Texas; • the Piceance Basin in Colorado; • 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 7.875% Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Cumulative Preferred Units”), 7.625% Series B Cumulative Redeemable Perpetual Preferred Units (“Series B Cumulative Preferred Units”) and 7.75% Series C Cumulative Redeemable Perpetual Preferred Units (“Series C Cumulative Preferred Units,” and, collectively with the Series A Units and Series B Units, the “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, 2016
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, 2015 , from the audited financial statements contained in our 2015 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 2015 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, 2016 , our significant accounting policies are consistent with those discussed in Note 1 of our consolidated financial statements contained in our 2015 Annual Report. (a) Basis of Presentation and Principles of Consolidation: The consolidated financial statements as of September 30, 2016 and December 31, 2015 and for the three and nine months ended September 30, 2016 and 2015 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. We consolidated Potato Hills Gas Gathering System as of the close date of the acquisition in January 2016 as we have the ability to control the operating and financial decisions and policies of the entity through our 51% ownership and reflected the non-controlling interest as a separate element in our consolidated financial statements. (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 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, 2016 of $365.7 million as a result of a decline in oil and natural gas prices at the measurement dates, March 31, 2016 and June 30, 2016 . The impairment for the first quarter of 2016 was $207.8 million and was calculated based on the 12-month average price of $2.41 per MMBtu for natural gas and $46.16 per barrel of crude oil. The impairment for the second quarter of 2016 was $157.9 million and was calculated based on the 12-month average price of $2.24 per MMBtu for natural gas and $42.91 per barrel of crude oil. No ceiling test impairment was recorded for the third quarter of 2016. For the nine months ended September 30, 2015 , we recorded a non-cash ceiling test impairment of oil and natural gas properties 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. 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) Goodwill and Other Intangible Assets: We account for goodwill under the provisions of the Accounting Standards Codification (ASC) Topic 350, “Intangibles-Goodwill and Other.” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is not amortized, but is tested for impairment annually on October 1 or whenever indicators of impairment exist using a two-step process. Due to the decline in prices of oil and natural gas as well as deteriorating market conditions, we performed an interim impairment test at September 30, 2016 as the carrying value of our reporting unit was negative. Therefore the Company was required to perform the second step of the goodwill impairment test. Based on the results of the the second step of the goodwill impairment test, we recorded a non-cash loss on impairment of goodwill of $252.7 million for the nine months ended September 30, 2016 to write the goodwill down to its estimated fair value of $253.4 million . Based on evaluation of qualitative factors, we determined that the goodwill impairment is primarily a result of the decline in the prices of oil and natural gas and the decline in the market price of our common units. Any further significant decline in the prices of oil and natural gas as well as any continued declines in the quoted market price of the Company’s units could change our estimate of the fair value of the reporting unit and could result in an additional impairment charge. (d) New Pronouncement Issued But Not Yet Adopted: 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 must 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 currently evaluating the method by which we will adopt the standard in 2018 and the impact of the pending adoption of ASU No. 2014-09 on our consolidated financial statements and do not anticipate the standard will have a material impact on our consolidated financial statements. In February 2016, the FASB issued ASU No. 2016-02, "Leases (Topic 842)", which requires lessees to recognize at the commencement date for all leases, with the exception of short-term leases, (a) a lease liability, which is a lessee‘s obligation to make lease payments arising from a lease, measured on a discounted basis, and (b) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The ASU on leases will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. We do not expect the adoption of ASU No. 2016-02 will have a material impact on our consolidated financial statements. In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. Under this ASU, the SEC Staff is rescinding certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities—Oil and Gas, effective upon adoption of Topic 606. As discussed above, Revenue from Contracts with Customers (Topic 606) is effective for public entities for fiscal years, and interim periods within the fiscal years, beginning after December 15, 2017. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU No. 2016-12”). The amendments under this ASU do not change the core revenue recognition principle in Topic 606. In addition, ASU No. 2016-12 provide clarifying guidance in certain narrow areas and add some practical expedients. These amendments are also effective at the same date that Topic 606 is effective. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) to address diversity in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The adoption of this ASU will not have any material impact on the calculation or presentation of our results of operations, cash flows or financial position. (e) 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. (f) Prior Year Financial Statement Presentation Certain prior year balances have been reclassified to conform to the current year presentation of balances as stated in this Quarterly Report on Form 10-Q. Please read Note 3. Long-Term Debt of the Notes to the Consolidated Financial Statements for further discussion regarding this reclassification.

Acquisitions and Divestitures

Acquisitions and Divestitures	9 Months Ended
	Sep. 30, 2016
Business Combinations [Abstract]
Acquisitions and Divestitures	2. Acquisitions and Divestitures Our acquisitions are accounted for under the acquisition method of accounting in accordance with ASC Topic 805, “Business Combinations” (“ASC Topic 805”). An acquisition may result in the recognition of a gain or goodwill based on the measurement of the fair value of the assets acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. Any such gain or any loss resulting from the impairment of goodwill is recognized in current period earnings and classified in other income and expense in the accompanying Consolidated Statements of Operations. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of the properties acquired in our acquisitions have been included in the consolidated financial statements since the closing dates of the acquisitions. All our acquisitions were funded with borrowings under our Reserve-Based Credit Facility (defined in Note 3. Long-Term Debt of the Notes to the Consolidated Financial Statements), except for certain acquisitions, in which the Company issued shares or exchanged assets as described below. 2016 Acquisitions and Divestitures In January 2016, we completed the acquisition of a 51% joint venture interest in Potato Hills Gas Gathering System, a gathering system located in Latimer County, Oklahoma, including the acquisition of the compression assets relating to the gathering system, for a total consideration of $7.7 million . As part of the acquisition, Vanguard also acquired the seller’s rights as manager under the related joint venture agreement. The acquisition was funded with borrowings under our existing Reserve-Based Credit Facility. In May 2016, we completed the sale of our natural gas, oil and natural gas liquids assets in the SCOOP/STACK area in Oklahoma to entities managed by Titanium Exploration Partners, LLC for $272.5 million , subject to final post-closing adjustments (the “SCOOP/STACK Divestiture”). We received net cash proceeds of $265.0 million from the sale, while $7.5 million of the total consideration is currently held in escrow. The Company used $262.9 million of the cash received to reduce borrowings under our Reserve-Based Credit Facility and $2.1 million to pay for some of the transaction fees related to the sale. During the nine months ended September 30, 2016 , we completed sales of certain of our other properties in several different counties within our operating areas for an aggregate consideration of approximately $22.2 million. All cash proceeds received from the sales of these properties were used to reduce borrowings under our Reserve-Based Credit Facility. 2015 Acquisitions and Mergers 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 based on an effective date of April 1, 2015. The acquisition was funded with borrowings under our existing Reserve-Based Credit Facility. LRE Merger On October 5, 2015, we completed the transactions contemplated by the Purchase Agreement and Plan of Merger, dated as of April 20, 2015 (the “LRE Merger Agreement”), by and among us, Lighthouse Merger Sub, LLC, our wholly owned subsidiary (“LRE Merger Sub”), Lime Rock Management LP (“LR Management”), Lime Rock Resources A, L.P. (“LRR A”), Lime Rock Resources B, L.P. (“LRR B”), Lime Rock Resources C, L.P. (“LRR C”), Lime Rock Resources II-A, L.P. (“LRR II-A”), Lime Rock Resources II-C, L.P. (“LRR II-C”), and, together with LRR A, LRR B, LRR C, LRR II-A and LR Management, the “GP Sellers”), LRR Energy, L.P. (“LRE”) and LRE GP, LLC (“LRE GP”), the general partner of LRE. Pursuant to the terms of the LRE Merger Agreement, LRE Merger Sub was merged with and into LRE, with LRE continuing as the surviving entity and as our wholly owned subsidiary (the “LRE Merger”), and, at the same time, we acquired all of the limited liability company interests in LRE GP from the GP Sellers in exchange for common units representing limited liability company interests in Vanguard. Under the terms of the LRE Merger Agreement, each common unit representing interests in LRE (the “LRE Common Units”) was converted into the right to receive 0.550 newly issued Vanguard common units. As consideration for the LRE Merger, we issued approximately 15.4 million Vanguard common units valued at $123.3 million based on the closing price per Vanguard common unit of $7.98 at October 5, 2015 and assumed $290.0 million in debt. The debt assumed was extinguished using borrowings under the Company’s Reserve-Based Credit Facility following the close of the LRE Merger. As consideration for our purchase of the limited liability company interests in LRE GP, we issued 12,320 Vanguard common units. 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. The following presents the values assigned to the net assets acquired in the LRE Merger as of the merger date (in thousands): Consideration Market value of Vanguard’s common units issued to LRE unitholders $ 123,276 Long-term debt assumed 290,000 413,276 Add: fair value of liabilities assumed Accounts payable and accrued liabilities 5,606 Other current liabilities 9,018 Asset retirement obligations 39,595 Amount attributable to liabilities assumed 54,219 Less: fair value of assets acquired Cash 11,532 Trade accounts receivable 6,822 Other current assets 4,172 Oil and natural gas properties 209,463 Derivative assets 78,725 Other assets 267 Amount attributable to assets acquired 310,981 Goodwill $ 156,514 Eagle Rock Merger On October 8, 2015, we completed the transactions contemplated by the Agreement and Plan of Merger, dated as of May 21, 2015 (the “Eagle Rock Merger Agreement”), by and among us, Talon Merger Sub, LLC, our wholly owned subsidiary (“Eagle Rock Merger Sub”), Eagle Rock Energy Partners, L.P. (“Eagle Rock”) and Eagle Rock Energy GP, L.P. (“Eagle Rock GP”). Pursuant to the terms of the Eagle Rock Merger Agreement, Eagle Rock Merger Sub was merged with and into Eagle Rock with Eagle Rock continuing as the surviving entity and as our wholly owned subsidiary (the “Eagle Rock Merger”). Under the terms of the Eagle Rock Merger Agreement, each common unit representing limited partner interests in Eagle Rock (“Eagle Rock Common Unit”) was converted into the right to receive 0.185 newly issued Vanguard common units or, in the case of fractional Vanguard common units, cash (without interest and rounded up to the nearest whole cent). As consideration for the Eagle Rock Merger, Vanguard issued approximately 27.7 million Vanguard common units valued at $258.3 million based on the closing price per Vanguard common unit of $9.31 at October 8, 2015 and assumed $156.6 million in debt. The Company extinguished $122.3 million of the debt assumed using borrowings under its Reserve-Based Credit Facility following the close of Eagle Rock Merger. 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. The following presents the values assigned to the net assets acquired in the Eagle Rock Merger as of the merger date (in thousands): Consideration Market value of Vanguard’s common units issued to Eagle Rock unitholders $ 258,282 Long-term debt assumed 156,550 Replacement unit-based payment awards attributable to pre-combination services 346 415,178 Add: fair value of liabilities assumed Accounts payable and accrued liabilities 53,255 Other current liabilities 2,206 Derivative liabilities 2,201 Asset retirement obligations 48,633 Deferred tax liability 39,327 Other long-term liabilities 1,244 Amount attributable to liabilities assumed 146,866 Less: fair value of assets acquired Cash 6,971 Trade accounts receivable 13,761 Other current assets 15,664 Oil and natural gas properties 462,715 Derivative assets 90,234 Other assets 9,734 Amount attributable to assets acquired 599,079 Bargain Purchase Gain $ (37,035 ) As a result of the consideration transferred being less than the fair value of net assets acquired, Vanguard reassessed whether it had fully identified all of the assets and liabilities obtained in the acquisition. As part of its reassessment, Vanguard also reevaluated the consideration transferred and whether there were any non-controlling interests in the acquired property. No additional assets or liabilities were identified. Vanguard also determined that there were no non-controlling interests in the Eagle Rock Merger. Vanguard determined that the bargain purchase gain was primarily attributable to unfavorable market trends between the date the parties agreed to the consideration for the Eagle Rock Merger and the date the transaction was completed, resulting in the decline of Vanguard’s unit price. Although the depressed oil and natural gas market also affected the fair value of Eagle Rock’s oil and natural gas properties, it had a more significant impact on Vanguard’s unit price compared to the resulting decrease in the fair value of those properties. As a result, the fair value of the net assets acquired in the Eagle Rock Merger, including the oil and natural gas properties, exceeded the total consideration paid. During the three and nine months ended September 30, 2016 , Vanguard made adjustments to the amounts assigned to the net assets acquired based on new information obtained about facts that existed as of the merger date. As a result, the bargain purchase gain was reduced by $3.8 million . This adjustment is included in the net loss on acquisition of oil and natural gas properties for this period. 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, 2015 to show the effect on our consolidated results of operations as if our acquisitions and mergers completed in 2015 had occurred on January 1, 2014 . The pro forma results also reflect the impact of the SCOOP/STACK Divestiture as if it had occurred on January 1, 2015. 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 2015 and eliminating the results of operations from the oil and natural gas properties divested in the SCOOP/STACK Divestiture, adjusted for (i) the assumption of asset retirement obligations and accretion expense for the properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired, (iii) interest expense on additional debt assumed in the LRE Merger and the Eagle Rock Merger, and (iv) the impact of the common units issued in the LRE Merger and the Eagle Rock Merger. 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, Nine months Ended 2015 2016 2015 (in thousands, except per unit data) Total revenues $ 176,404 $ 246,808 $ 579,159 Net loss $ (850,404 ) $ (675,349 ) $ (1,563,264 ) Net loss per unit Common and Class B units - basic and diluted $ (6.50 ) $ (5.14 ) $ (12.05 ) The amount of revenues and excess of revenues over direct operating expenses that were eliminated to reflect the impact of the SCOOP/STACK Divestiture in the pro forma results presented above are as follows (in thousands): Nine months Ended (in thousands) Revenues $ 17,542 Excess of revenues over direct operating expenses $ 15,278 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 2015 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, 2016 September 30, 2016 (in thousands) Eagle Rock Merger Revenues $ 9,160 $ 42,340 Excess of revenues over direct operating expenses $ 3,886 $ 21,605 LRE Merger Revenues $ 18,427 $ 34,767 Excess of revenues over direct operating expenses $ 12,630 $ 19,485

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2016
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, 2016 December 31, 2015 (in thousands) Senior Secured Reserve-Based Credit Facility Variable (1) April 16, 2018 $ 1,354,000 $ 1,688,000 Senior Notes due 2019 8.375% (2) June 1, 2019 51,120 51,120 Senior Notes due 2020 7.875% (3) April 1, 2020 381,830 550,000 Senior Notes due 2023 7.00% February 15, 2023 75,634 — Lease Financing Obligation 4.16% August 10, 2020 (4) 21,310 24,668 $ 1,883,894 $ 2,313,788 Less: Current portion of debt under the Reserve-Based Credit Facility (5) (31,887 ) — Unamortized discount on Senior Notes (14,174 ) (17,651 ) Unamortized deferred financing costs (6) (11,596 ) (13,705 ) Current portion of Lease Financing Obligation (4,643 ) (4,501 ) Total long-term debt $ 1,821,594 $ 2,277,931 (1) Variable interest rate was 3.02% and 2.90% at September 30, 2016 and December 31, 2015 , respectively. (2) Effective interest rate was 21.45% at September 30, 2016 and December 31, 2015 . (3) Effective interest rate was 8.00% at September 30, 2016 and December 31, 2015 . (4) The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021. (5) Represents the remaining borrowing base deficiency obligation as of September 30, 2016 payable in two equal monthly installments through November 2016. (6) In order to comply with Accounting Standards Update No. 2015-03, unamortized debt issuance costs have been reclassified from other assets to long-term debt on a retrospective basis. This reclassification had no impact on historical income from continuing operations or members’ equity. 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 . In May 2016, the lenders party to the Credit Agreement (the “First Lien Lenders”) decreased the Company’s borrowing base from $1.78 billion to $1.325 billion (the “Reserve-Based Credit Facility”) resulting in a borrowing base deficiency of approximately $103.5 million . The Company made monthly payments of $17.5 million through September 30, 2016 . As of September 30, 2016 , there were approximately $1.35 billion of outstanding borrowings and approximately $2.9 million in outstanding letters of credit resulting in a borrowing deficiency of $31.9 million under the Reserve-Based Credit Facility. On September 30, 2016, the Company entered into a waiver (the “Waiver”) to its Credit Agreement, in which the lenders thereto (the “First Lien Lenders”) agreed, among other things, subject to certain conditions, to waive any event of default, so long as the payment was made within the 30-day grace period, resulting from the Company’s election not to make the approximately $15.0 million semi-annual interest payment due on October 3, 2016 on approximately $381.8 million in aggregate principal amount of Senior Notes due 2020 (defined below). Pursuant to the Waiver, the First Lien Lenders agreed that the Company’s decision to take advantage of the applicable grace period under the indenture governing the Senior Notes due 2020 would not constitute an event of default under the Credit Agreement. A failure to pay interest on the Senior Notes due 2020 following the expiration of the 30-day grace period would have resulted in events of default under the Credit Agreement and the indenture governing the Senior Secured Second Lien Notes (defined below), which would have entitled the trustee under the indenture governing the Senior Secured Second Lien Notes and the First Lien Lenders to declare all obligations thereunder to be immediately due and payable. The Company made the $15.1 million semi-annual interest payment with respect to its Senior Notes due 2020 on October 26, 2016. On October 26, 2016, the Company entered into the Limited Waiver and Eleventh Amendment (the “Waiver and Eleventh Amendment”) to its Credit Agreement. On November 3, 2016, the Company completed its semi-annual redetermination which led to a further reduction of its borrowing base from $1.325 billion to $1.1 billion , resulting in a borrowing base deficiency of $187.5 million , after consideration of $0.3 million in outstanding letters of credit. For more information, please see Note 11. Subsequent Events of the Notes to the Consolidated Financial Statements. The Company’s failure to repay any of the installments due related to the borrowing base deficiency shall constitute an event of default under the Credit Agreement and as such, the lenders could declare all outstanding principal and interest to be due and payable, could freeze our accounts, could foreclose against the assets securing their borrowings, and we could be forced into bankruptcy or liquidation. In addition, a payment default under the Reserve Based Credit Facility could result in a cross default under our Senior Notes due 2020 and Senior Secured Second Lien Notes. In such case, we may not have sufficient assets to repay our creditors, including the holders of our Senior Notes due 2020 or Senior Notes due 2019 (defined below). As a result, there may not be any value remaining attributable to the holders of our common units and Cumulative Preferred Units. 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, 2016 , 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 other 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 5.25 to 1.0 in 2016 and 4.5 to 1.0 starting in 2017 and beyond. In addition, we are subject to various 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. We were in compliance with all of our debt covenants as of September 30, 2016 . Letters of Credit At September 30, 2016 , we have unused irrevocable standby letters of credit of approximately $2.9 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 marketing counterparties. 8.375% Senior Notes Due 2019 At September 30, 2016 , we had $51.1 million outstanding in aggregate principal amount of 8.375% senior notes due in 2019 (the “Senior Notes due 2019”). The Senior Notes due 2019 were assumed by VO in connection with the Eagle Rock Merger. Interest on the Senior Notes due 2019 is payable on June 1 and December 1 of each year. The Senior Notes due 2019 are fully and unconditionally (except for customary release provisions) and jointly and severally guaranteed on a senior unsecured basis by Vanguard and all of our existing subsidiaries, all of which are 100% owned, and certain of our future subsidiaries (the “Subsidiary Guarantors”). Prior to the Eagle Rock Merger, the parties to the indenture executed a supplemental indenture which eliminated substantially all of the restrictive covenants and certain events of default with respect to the Senior Notes due 2019. We have the option to redeem some or all of the Senior Notes due 2019 at any time at redemption prices equal to the aggregate principal amount multiplied by (i) 102.094% if such Senior Notes due 2019 are redeemed in 2016 and (ii) 100.000% if such Senior Notes due 2019 are redeemed in 2017 and thereafter. 7.875% Senior Notes Due 2020 At September 30, 2016 , we had $381.8 million outstanding in aggregate principal amount of 7.875% senior notes due in 2020 (the “Senior Notes due 2020”). The issuers of the Senior Notes due 2020 are VNR and our 100% owned finance subsidiary, VNRF. VNR has no independent assets or operations. Under the indenture governing the Senior Notes due 2020 (the “Senior Notes 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 due 2020, subject to release under certain of the following circumstances: (i) upon the sale or other disposition of all or substantially all of the subsidiary’s properties or assets, (ii) upon the sale or other disposition of our equity interests in the subsidiary, (iii) upon designation of the subsidiary as an unrestricted subsidiary in accordance with the terms of the Senior Notes Indenture, (iv) upon legal defeasance or covenant defeasance or the discharge of the Senior Notes 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 Senior Notes 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 due 2020 achieve an investment grade rating from each of Standard & Poor’s Rating Services and Moody’s Investors Services, Inc. and no default under the Senior Notes Indenture exists, many of the foregoing covenants will terminate. As of September 30, 2016 , based on the most restrictive covenants of the Senior Notes Indenture and as a result of our borrowing base deficiency, we are restricted from making distributions to our unitholders. In addition, a payment default under the Reserve Based Credit Facility could result in a cross default under Senior Notes due 2020. Interest on the Senior Notes due 2020 is payable on April 1 and October 1 of each year. We may redeem some or all of the Senior Notes due 2020 at any one or more occasions on or after April 1, 2016 at redemption prices of 103.93750% of the aggregate principal amount of the Senior Notes due 2020 as of April 1, 2016, plus accrued and unpaid interest, if any, on the Senior Notes due 2020 redeemed, declining to 100% on April 1, 2018 and thereafter. We had the option to redeem some or all of the Senior Notes due 2020 at any one or more occasions prior to April 1, 2016 at a redemption price equal to 100% of the aggregate principal amount of the Senior Notes due 2020 thereof, plus a “make-whole” premium, and accrued and unpaid interest to the redemption date. We did not redeem any of the Senior Notes due 2020 prior to April 1, 2016. If we sell certain of our assets and experience certain changes of control, we may be required to repurchase all or a portion of the Senior Notes due 2020 at a price equal to 100% and 101% of the aggregate principal amount of the Senior Notes due 2020, respectively. 7.0% Senior Secured Second Lien Notes Due 2023 On February 10, 2016, we issued approximately $75.6 million aggregate principal amount of new 7.0% Senior Secured Second Lien Notes due 2023 (the “Senior Secured Second Lien Notes”) to certain eligible holders of our outstanding 7.875% Senior Notes due 2020 in exchange for approximately $168.2 million aggregate principal amount of the Senior Notes due 2020 held by such holders. Interest on the Senior Secured Second Lien Notes is payable on February 15 and August 15 of each year. The Senior Secured Second Lien Notes will mature on (i) February 15, 2023 or (ii) December 31, 2019 if, prior to December 31, 2019, we have not repurchased, redeemed or otherwise repaid in full all of the Senior Notes due 2020 outstanding at that time in excess of $50.0 million in aggregate principal amount and, to the extent we repurchased, redeemed or otherwise repaid the Senior Notes due 2020 with proceeds of certain indebtedness, if such indebtedness has a final maturity date no earlier than the date that is 91 days after February 15, 2023. Under the indenture governing the Senior Secured Second Lien Notes (the “Senior Secured Second Lien Notes Indenture”), the Subsidiary Guarantors (other than VNRF) have unconditionally guaranteed, jointly and severally, the Senior Secured Second Lien Notes, subject to release under certain of the following circumstances: (i) upon the sale or other disposition of all or substantially all of the subsidiary’s properties or assets, (ii) upon the sale or other disposition of our equity interests in the subsidiary, (iii) upon designation of the subsidiary as an unrestricted subsidiary in accordance with the terms of the Senior Secured Second Lien Indenture, (iv) upon legal defeasance or covenant defeasance or the discharge of the Senior Secured Second Lien Notes 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 Senior Secured Second Lien Notes 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 Secured Second Lien 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 Senior Secured Second Lien Notes Indenture exists, many of the foregoing covenants will terminate. As of September 30, 2016 , based on the most restrictive covenants of the Senior Secured Second Lien Notes Indenture and as a result of our borrowing base deficiency, we are restricted from making distributions to our unitholders. In addition, a payment default under the Reserve Based Credit Facility could result in a cross default under our Senior Secured Second Lien Notes. The exchanges were accounted for as an extinguishment of debt. As a result, we recorded a gain on extinguishment of debt of $89.7 million for the nine months ended September 30, 2016 , which is the difference between the aggregate fair market value of the Senior Secured Second Lien Notes issued and the carrying amount of Senior Notes due 2020 extinguished in the exchange, net of unamortized bond discount and deferred financing costs, of $165.3 million . Lease Financing Obligations On October 24, 2014, as part of our acquisition of certain natural gas, oil and NGLs assets in the Piceance Basin, we entered into an assignment and assumption agreement with Bank of America Leasing & Capital, LLC as the lead bank, 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, 2016
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. In October 2016, in conjunction with entering into the Waiver and Eleventh Amendment, we monetized certain of our outstanding commodity price hedge agreements for total proceeds of approximately $42.3 million . The following tables summarize oil, natural gas and NGLs commodity derivative contracts in place at September 30, 2016 , and does not reflect the impact of the monetization mentioned above. Fixed-Price Swaps (NYMEX) Gas Oil NGLs Contract Period MMBtu Weighted Average Fixed Price Bbls Weighted Average WTI Price Bbls Weighted Average October 1, 2016 – December 31, 2016 18,264,472 $ 4.36 469,014 $ 84.00 227,500 $ 30.31 January 1, 2017 – December 31, 2017 55,080,260 $ 3.74 749,698 $ 85.70 — — Fixed-Price Swaps (Light Louisiana Sweet) Oil Contract Period Bbls Weighted Average Fixed Price January 1, 2017 – December 31, 2017 168,000 $ 91.25 Call Options Sold Gas Oil Contract Period MMBtu Weighted Average Fixed Price Bbls Weighted Average Fixed Price October 1, 2016 – December 31, 2016 2,300,000 $ 4.25 156,400 $ 50.00 January 1, 2017 – December 31, 2017 11,862,500 $ 3.01 365,000 $ 95.00 Swaptions Gas Contract Period MMBtu Weighted Average Fixed Price January 1, 2017 – December 31, 2017 3,437,500 $ 2.99 January 1, 2018 – December 31, 2018 675,000 $ 2.74 Basis Swaps Gas Contract Period MMBtu Weighted Avg. Basis Differential ($/MMBtu) Pricing Index October 1, 2016 – December 31, 2016 9,660,000 $ (0.20 ) Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential January 1, 2017 – December 31, 2017 21,900,000 $ (0.20 ) Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential October 1, 2016 – December 31, 2016 235,385 $ (0.08 ) Houston Ship Channel and NYMEX Henry Hub Basis Differential October 1, 2016 – December 31, 2016 69,624 $ (0.10 ) TexOk and NYMEX Henry Hub Basis Differential October 1, 2016 – December 31, 2016 390,713 $ (0.13 ) WAHA and NYMEX Henry Hub Basis Differential Oil Contract Period Bbls Weighted Avg. Basis Differential ($/Bbl) Pricing Index October 1, 2016 – December 31, 2016 243,000 $ (1.01 ) WTI Midland and WTI Cushing Basis Differential October 1, 2016 – December 31, 2016 55,200 $ (0.43 ) West Texas Sour and WTI Cushing Basis Differential October 1, 2016 – December 31, 2016 184,000 $ (14.25 ) WTI and West Canadian Select Basis Differential Three-Way Collars Gas Contract Period MMBtu Floor Ceiling Put Sold October 1, 2016 – December 31, 2016 3,220,000 $ 3.95 $ 4.25 $ 3.00 January 1, 2017 – December 31, 2017 14,600,000 $ 3.88 $ 4.15 $ 3.31 Oil Contract Period Bbls Floor Ceiling Put Sold October 1, 2016 – December 31, 2016 266,800 $ 90.00 $ 96.18 $ 73.62 Put Options Sold Gas Oil Contract Period MMBtu Put Sold ($/MMBtu) Bbls Put Sold ($/Bbl) October 1, 2016 – December 31, 2016 460,000 $ 3.00 36,800 $ 75.00 January 1, 2017 – December 31, 2017 1,825,000 $ 3.50 73,000 $ 75.00 Range Bonus Accumulators Oil Contract Period Bbls Bonus Range Ceiling Range Floor October 1, 2016 – December 31, 2016 46,000 $ 4.00 $ 100.00 $ 75.00 Collars Gas Oil Contract Period MMBtu Floor Price ($/MMBtu) Ceiling Price ($/MMBtu) Bbls Floor Price ($/Bbl) Ceiling Price ($/Bbl) October 1, 2016 – December 31, 2016 — $ — $ — 138,000 $ 45.00 $ 55.00 January 1, 2017 – December 31, 2017 450,000 $ 3.10 $ 3.45 — $ — $ — Puts Oil Contract Period Bbls Put Price ($/Bbl) October 1, 2016 – December 31, 2016 92,000 $ 60.00 Interest Rate Swaps At September 30, 2016 , we had open interest rate derivative contracts as follows (in thousands): Period Notional Amount Fixed LIBOR Rates October 1, 2016 to December 10, 2016 $ 20,000 2.17 % October 1, 2016 to October 31, 2016 $ 40,000 1.65 % October 1, 2016 to August 5, 2018 $ 30,000 2.25 % October 1, 2016 to October 31, 2016 $ 20,000 1.78 % October 1, 2016 to December 31, 2019 $ 175,000 2.32 % October 1, 2016 to February 16, 2017 $ 75,000 1.73 % October 1, 2016 to June 16, 2017 $ 70,000 1.43 % October 1, 2016 to February 16, 2017 $ 75,000 1.73 % Total $ 505,000 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, 2016 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 $ 129,235 $ (17,419 ) $ 111,816 Interest rate derivative contracts — (8,528 ) (8,528 ) Total derivative instruments $ 129,235 $ (25,947 ) $ 103,288 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 $ (17,703 ) $ 17,418 $ (285 ) Interest rate derivative contracts (9,947 ) 8,528 (1,419 ) Total derivative instruments $ (27,650 ) $ 25,946 $ (1,704 ) December 31, 2015 Offsetting Derivative Assets: Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts $ 349,281 $ (21,834 ) $ 327,447 Interest rate derivative contracts — (10,400 ) (10,400 ) Total derivative instruments $ 349,281 $ (32,234 ) $ 317,047 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 $ (21,934 ) $ 21,834 $ (100 ) Interest rate derivative contracts (10,656 ) 10,400 (256 ) Total derivative instruments $ (32,590 ) $ 32,234 $ (356 ) 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. The majority of our counterparties are participants in our Reserve-Based Credit Facility (see Note 3. Long-Term Debt of the Notes to the Consolidated Financial Statements 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 $129.2 million at September 30, 2016 . 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, 2016 . 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, 2016 and the year ended December 31, 2015 are as follows: Nine Months Ended September 30, 2016 Year Ended December 31, 2015 (in thousands) Derivative asset at beginning of period, net $ 316,691 $ 220,734 Purchases Fair value of derivatives acquired — 195,273 Net premiums and fees (received) paid or deferred for derivative contracts (1,960 ) 7,126 Net gains (losses) on commodity and interest rate derivative contracts (21,813 ) 169,569 Settlements Cash settlements received on matured commodity derivative contracts (198,104 ) (211,723 ) Cash settlements paid on matured interest rate derivative contracts 6,770 5,227 Termination of derivative contracts — (69,515 ) Derivative asset at end of period, net $ 101,584 $ 316,691

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2016
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 represent their 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, 2016 , the fair value of our Senior Notes due 2020 was estimated to be $189.1 million and our Senior Notes due 2019 was estimated to be $24.1 million . Our Senior Secured Second Lien Notes are a private debt and we estimated its fair value to be $37.5 million valued based on the prices used to estimate the fair value of our Senior Notes due 2020. 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, 2016 Fair Value Measurements Using Assets/Liabilities Level 1 Level 2 Level 3 at Fair Value Assets: Commodity price derivative contracts $ — $ 112,976 $ (1,160 ) $ 111,816 Interest rate derivative contracts — (8,528 ) — (8,528 ) Total derivative instruments $ — $ 104,448 $ (1,160 ) $ 103,288 Liabilities: Commodity price derivative contracts $ — $ (285 ) $ — $ (285 ) Interest rate derivative contracts — (1,419 ) — (1,419 ) Total derivative instruments $ — $ (1,704 ) $ — $ (1,704 ) December 31, 2015 Fair Value Measurements Using Assets/Liabilities Level 1 Level 2 Level 3 at Fair Value Assets: Commodity price derivative contracts $ — $ 333,380 $ (5,933 ) $ 327,447 Interest rate derivative contracts — (10,400 ) — (10,400 ) Total derivative instruments $ — $ 322,980 $ (5,933 ) $ 317,047 Liabilities: Commodity price derivative contracts $ — $ (99 ) $ — $ (99 ) Interest rate derivative contracts — (257 ) — (257 ) Total derivative instruments $ — $ (356 ) $ — $ (356 ) 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, 2016 2015 (in thousands) Unobservable inputs, beginning of period $ (5,933 ) $ (6,470 ) Total gains 9,381 3,525 Settlements (4,608 ) (3,124 ) Unobservable inputs, end of period $ (1,160 ) $ (6,069 ) Change in fair value included in earnings related to derivatives still held as of September 30, $ 223 $ (2,254 ) During periods of market disruption, including periods of volatile oil and natural gas prices, there may be certain asset classes that were in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments, other than the range bonus accumulators, may fall to Level 3 and thus require more subjectivity and management judgment. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition. We apply the provisions of ASC Topic 350 “ Intangibles-Goodwill and Other .” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is assessed for impairment annually on October 1 or whenever indicators of impairment exist. The goodwill test is performed at the reporting unit level, which represents our oil and natural gas operations in the United States. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. We utilize a market approach to determine the fair value of our reporting unit. Any sharp prolonged decreases in the prices of oil and natural gas as well as any continued declines in the quoted market price of the Company’s units could change our estimates of the fair value of our reporting unit and could result in an impairment charge. As of September 30, 2016 , the carrying value of our reporting unit was negative. Therefore the Company was required to perform the second step of the goodwill impairment test. The fair value amount of the assets and liabilities were calculated using a combination of a market and income approach as follows: equity and debt were valued using a market approach while the remaining balance sheet assets and liabilities were valued using an income approach. Furthermore, significant assumptions used in calculating the fair value of our oil and gas properties that were valued using an income approach include: (i) observable forward prices for commodities at September 30, 2016 and (ii) a 10% discount rate, which was comparable to discount rates on recent transactions. Based on the results of the the second step of the goodwill impairment test, we recorded a non-cash loss on impairment of goodwill of $252.7 million for the quarter ended September 30, 2016 . Based on evaluation of qualitative factors, we determined that the goodwill impairment is primarily a result of the decline in the prices of oil and natural gas and the decline in the market price of our common units. 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, 2016 , in connection with new wells drilled, we incurred and recorded asset retirement obligations totaling $0.5 million , at fair value and also recorded a $4.4 million reduction due to a change in estimate as a result of revisions to the timing or the amount of our original undiscounted estimated asset retirement costs during the nine months ended September 30, 2016 . During the year ended December 31, 2015 , in connection with the oil and natural gas properties acquired in all of our acquisitions, the LRE Merger and the Eagle Rock Merger, as well as new wells drilled, we incurred and recorded asset retirement obligations totaling $90.9 million , at fair value. In addition, we recorded a $22.3 million change in estimate as a result of revisions to the timing or the amount of our original undiscounted estimated asset retirement costs during the year ended December 31, 2015 . 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 5.5% ; and (4) the average inflation factor ( 2.0% ). 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, 2016
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The asset retirement obligations as of September 30, 2016 and December 31, 2015 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the nine months ended September 30, 2016 and the year ended December 31, 2015 were as follows: September 30, 2016 December 31, 2015 (in thousands) Asset retirement obligations, beginning of period $ 271,456 $ 149,062 Liabilities added during the current period 502 2,699 Liabilities added from the LRE Merger and the Eagle Rock Merger — 88,228 Accretion expense 9,142 10,238 Retirements (1,492 ) (838 ) Liabilities related to assets divested (9,342 ) (262 ) Change in estimate (4,368 ) 22,329 Asset retirement obligation, end of period 265,898 271,456 Less: current obligations (7,592 ) (9,024 ) Long-term asset retirement obligation, end of period $ 258,306 $ 262,432 Each year the Company reviews and, to the extent necessary, revises its asset retirement obligation estimates. During the nine months ended September 30, 2016 and year ended December 31, 2015 , the Company reviewed actual abandonment costs with previous estimates and as a result, decreased its estimates of future asset retirement obligations by $4.4 million and increased its estimates of future asset retirement obligations by $22.3 million , respectively, to reflect revised estimates to be incurred for plugging and abandonment costs.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Transportation Demand Charges As of September 30, 2016 , we have contracts that provide firm transportation capacity on pipeline systems. The remaining terms on these contracts range from one month to four 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, 2016 . 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, 2016 (in thousands) October 1, 2016 - December 31, 2016 $ 3,317 2017 12,538 2018 11,678 2019 9,661 2020 410 Total $ 37,604 Legal Proceedings We are defendants in certain legal proceedings arising in the normal course of our business. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management does not believe that it is probable that the outcome of these actions will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flow. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject. We are also a party to separate legal proceedings relating to (i) the LRE Merger, (ii) the Eagle Rock Merger and (iii) our exchange (the “Debt Exchange”) of the Senior Notes due 2020 for the Senior Secured Second Lien Notes (please read Note 3. Long-Term Debt of the Notes to the Consolidated Financial Statements for further discussion). Please read Part II, Item 1, Legal Proceedings for further discussion.

Members_ Deficit and Net Loss p

Members’ Deficit and Net Loss per Common and Class B Unit	9 Months Ended
	Sep. 30, 2016
Equity [Abstract]
Members’ Deficit and Net Loss per Common and Class B Unit	Members’ Deficit and Net Loss per Common and Class B Unit Cumulative Preferred Units The following table summarizes the Company’s Cumulative Preferred Units outstanding at September 30, 2016 and December 31, 2015 : September 30, 2016 December 31, 2015 Earliest Redemption Date Liquidation Preference Per Unit 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, in connection with a change of control. The Cumulative Preferred Units can be redeemed, in whole or in part, out of amounts legally available therefore, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. We may also redeem the Cumulative Preferred Units in the event of a change of control. Holders of the Cumulative Preferred Units will have no voting rights except for limited voting rights if we fail to pay dividends for eighteen or more monthly periods (whether or not consecutive) and in certain other limited circumstances or as required by law. The Cumulative Preferred Units have a liquidation preference which is equal to the redemption price described above. On February 25, 2016, our board of directors elected to suspend cash distributions to the holders of our common and Class B units and Cumulative Preferred Units effective with the February 2016 distribution. All preferred distributions will continue to accumulate and must be paid in full before distributions to common and Class B unitholders can resume. As of September 30, 2016 , dividends in arrears related to our Cumulative Preferred Units were $3.0 million , $7.8 million and $4.9 million , respectively. 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, 2016 and the year ended December 31, 2015 (in thousands): September 30, 2016 December 31, 2015 Beginning of period 130,477 83,452 Issuance of Common units as consideration for the Eagle Rock Merger — 27,886 Issuance of Common units as consideration for the LRE Merger — 15,448 Issuance of Common units for cash — 2,430 Repurchase of units under the Common unit buyback program — (157 ) Unit-based compensation 563 1,418 End of period 131,040 130,477 There was no change in issued and outstanding Class B units during the nine months ended September 30, 2016 or the year ended December 31, 2015 . Net 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, which reflects all accumulated distributions on Cumulative Preferred Units, including distributions in arrears, 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. For the three months ended September 30, 2016 and 2015 , 2,632,083 and 47,626 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. For the nine months ended September 30, 2016 and 2015 , 2,632,083 and 166,331 phantom units were excluded from the calculation of diluted earnings per unit, respectively, due to their antidilutive effect as we were also 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 Cumulative 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. Distributions on our Cumulative Preferred Units accumulate 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 per unit, declared date, record date and payment date of the cash distributions we paid on each of our common and Class B units attributable to 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. Our board of directors elected to suspend cash distributions to the holders of our common and Class B units and Cumulative Preferred Units effective with the February 2016 distribution. Cash Distributions Distribution Per Unit Declared Date Record Date Payment Date 2016 First Quarter January $ 0.0300 February 18, 2016 March 1, 2016 March 15, 2016 2015 Fourth Quarter December $ 0.0300 January 20, 2016 February 1, 2016 February 12, 2016 November $ 0.0300 December 18, 2015 January 4, 2016 January 14, 2016 October $ 0.1175 November 20, 2015 December 1, 2015 December 15, 2015 Third Quarter September $ 0.1175 October 19, 2015 November 2, 2015 November 13, 2015 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

Unit-Based Compensation

Unit-Based Compensation	9 Months Ended
	Sep. 30, 2016
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 On March 18, 2016, we and VNRH entered into new amended and restated executive employment agreements (the “Amended Agreements”) with each of our three executive officers, Messrs. Smith, Robert and Pence in order to set forth in writing the revised terms of each executive’s employment relationship with VNRH. The Amended Agreements were effective January 1, 2016 and the initial term of the Amended Agreements ends on January 1, 2019, with a subsequent twelve-month term extension automatically commencing on January 1, 2019 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 the executive officers an annual base salary and eligibility to receive an annual performance-based cash bonus award. The annual bonus will be calculated based upon four Company performance components: adjusted EBITDA results, production results, lease operating expenses, and cash general and administrative expenses, as well as a fifth component determined solely in the discretion of our board of directors. As of September 30, 2016 and 2015 , we recognized an accrued liability of $0.6 million and $1.1 million , respectively, related to the performance-based bonus award. In addition, compensation expense related to these arrangements of $0.6 million and $0.4 million were recorded for the three months ended September 30, 2016 and 2015 , respectively, and $1.8 million and $1.1 million for the nine months ended September 30, 2016 and 2015 , respectively, which were 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. 2016 Unit Grants In January 2016, the executives were granted a total of 2,255,033 phantom units in accordance with the Amended Agreements. Also, during the nine months ended September 30, 2016 , our three independent board members were granted a total of 125,838 phantom units which will vest one year from the date of grant. In addition, VNR employees were granted 1,331,579 phantom units under the VNR LTIP which will vest three years from the date of grant and a VNR employee was granted a total of 7,500 restricted units under the VNR LTIP of which one-third will vest on each one-year anniversary of the date of grant so long as the employee remains continuously employed with the Company. The phantom units include a tandem grant of DERs. Restricted Units A summary of the status of the non-vested restricted units as of September 30, 2016 is presented below: Number of Non-vested Restricted Units Weighted Average Grant Date Fair Value Non-vested restricted units at December 31, 2015 976,348 $ 18.29 Granted 7,500 $ 3.11 Forfeited (29,891 ) $ 13.34 Vested (259,047 ) $ 17.09 Non-vested restricted units at September 30, 2016 694,910 $ 18.84 At September 30, 2016 , there was approximately $6.1 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately 1.3 years. Our Consolidated Statements of Operations reflect non-cash compensation related to restricted unit grants of $1.5 million and $3.4 million in the selling, general and administrative expenses line item for the three months ended September 30, 2016 and 2015 , respectively, and $4.1 million and $10.4 million for the nine months ended September 30, 2016 and 2015 , respectively. Phantom Units A summary of the status of the non-vested phantom units under the VNR LTIP as of September 30, 2016 is presented below: Number of Non-vested Phantom Units Weighted Average Grant Date Fair Value Non-vested phantom units at December 31, 2015 203,221 $ 20.99 Granted 3,712,450 $ 2.56 Forfeited (30,124 ) $ 1.97 Vested (122,523 ) $ 22.23 Non-vested phantom units at September 30, 2016 3,763,024 $ 2.92 At September 30, 2016 , there was approximately $8.2 million of unrecognized compensation cost related to non-vested phantom units. The cost is expected to be recognized over an average period of approximately 1.3 years . Our Consolidated Statements of Operations reflect non-cash compensation related to phantom unit grants of $1.3 million and $0.4 million in the selling, general and administrative expense line item for the three months ended September 30, 2016 and 2015 , respectively, and $3.6 million and $1.3 million for the nine months ended September 30, 2016 and 2015 , respectively.

Shelf Registration Statements (

Shelf Registration Statements (Notes)	9 Months Ended
	Sep. 30, 2016
Shelf Registration Statements [Abstract]
Shelf Registration Statements [Text Block]	Shelf Registration Statement Under our currently effective shelf registration statement, as amended (File No. 333-210329), filed with the SEC (the “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 as shall have an aggregate initial offering price not to exceed $500.0 million . In the future, we may issue additional debt and equity securities pursuant to a prospectus supplement to the Universal Shelf Registration Statement. Net proceeds, terms and pricing of each offering of securities issued under the Shelf Registration Statement will be 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 also 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 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. Subsidiary Guarantors We and VNRF, our wholly-owned finance subsidiary, may co-issue securities pursuant to the Shelf Registration Statement discussed above. VNR has no independent assets or operations. Debt securities that we may offer may be guaranteed by our subsidiaries. We contemplate that if we offer debt securities, the guarantees will be full and unconditional and joint and several (subject to certain customary release provisions), and any subsidiaries of VNR that do not guarantee the securities will be minor.

Subsequent Events (Notes)

Subsequent Events (Notes)	9 Months Ended
	Sep. 30, 2016
Subsequent Events [Abstract]
Subsequent Events [Text Block]	11. Subsequent Events Waiver to the Credit Agreement and Borrowing Base Redetermination On October 26, 2016, the Company entered into the Limited Waiver and Eleventh Amendment to the Credit Agreement. Pursuant to the Waiver and Eleventh Amendment, the First Lien Lenders agreed, among other things, subject to certain conditions, to waive any events of default resulting from the Company’s inability to maintain liquidity in excess of $50.0 million , giving pro forma effect to the Company’s payments of (i) the $15.0 million semi-annual interest payment due on October 1, 2016 on approximately $381.8 million in aggregate principal amount of Senior Notes due 2020 and (ii) the approximately $2.1 million semi-annual interest payment due on December 1, 2016 on approximately $51.1 million in aggregate principal amount of Senior Notes due 2019. In conjunction with the Waiver and Eleventh Amendment, the Company monetized certain of its outstanding commodity price hedge agreements and used the proceeds along with cash on hand first to pre-pay the First Lien Lenders (i) $29.3 million , representing the remaining outstanding borrowing base deficiency resulting from the Company’s borrowing base redetermination in May 2016 and (ii) $37.5 million , which was applied as the first required monthly payment to the Company’s new borrowing base deficiency resulting from the November 2016 borrowing base redetermination. Also, the Company pledged to the First Lien Lenders certain unencumbered midstream assets as collateral as well as agreed to pay 100% of the net cash proceeds from any asset sale, swap or hedge monetization or other disposition to the First Lien Lenders. The borrowing base may be further reduced as a result of such disposition to the extent of the attributed value of such asset to the borrowing base. Furthermore, any incurrence of second lien debt will require the Company to prepay the First Lien Lenders equal to the net cash proceeds received by the Company from any second lien financing. On November 3, 2016, the Company completed its semi-annual redetermination of its borrowing base, resulting in a reduction from $1.325 billion to $1.1 billion . After consideration of the first $37.5 million deficiency payment already having been made pursuant to entering into the Waiver and Eleventh Amendment on October 26, 2016, the Company intends to repay the remaining borrowing base deficiency of $187.5 million in five equal monthly installments of $37.5 million beginning in January 2017. The Company anticipates that its forecasted excess cash flow from operations will not be sufficient to pay the remaining borrowing base deficiency. Refinancing or restructuring our debt, selling assets, reducing or delaying our drilling program or seeking to raise additional capital through non-traditional lending or other private sources of capital will be necessary to satisfy this requirement in order to be back in compliance under the Credit Agreement. The Company made the $15.1 million semi-annual interest payment with respect to its Senior Notes due 2020 on October 26, 2016.

Summary of Significant Accoun20

Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2016
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, 2016 and December 31, 2015 and for the three and nine months ended September 30, 2016 and 2015 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. We consolidated Potato Hills Gas Gathering System as of the close date of the acquisition in January 2016 as we have the ability to control the operating and financial decisions and policies of the entity through our 51% ownership and reflected the non-controlling interest as a separate element in our consolidated financial statements.
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 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, 2016 of $365.7 million as a result of a decline in oil and natural gas prices at the measurement dates, March 31, 2016 and June 30, 2016 . The impairment for the first quarter of 2016 was $207.8 million and was calculated based on the 12-month average price of $2.41 per MMBtu for natural gas and $46.16 per barrel of crude oil. The impairment for the second quarter of 2016 was $157.9 million and was calculated based on the 12-month average price of $2.24 per MMBtu for natural gas and $42.91 per barrel of crude oil. No ceiling test impairment was recorded for the third quarter of 2016. For the nine months ended September 30, 2015 , we recorded a non-cash ceiling test impairment of oil and natural gas properties 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. When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties.
Goodwill and Intangible Assets	(c) Goodwill and Other Intangible Assets: We account for goodwill under the provisions of the Accounting Standards Codification (ASC) Topic 350, “Intangibles-Goodwill and Other.” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is not amortized, but is tested for impairment annually on October 1 or whenever indicators of impairment exist using a two-step process. Due to the decline in prices of oil and natural gas as well as deteriorating market conditions, we performed an interim impairment test at September 30, 2016 as the carrying value of our reporting unit was negative. Therefore the Company was required to perform the second step of the goodwill impairment test. Based on the results of the the second step of the goodwill impairment test, we recorded a non-cash loss on impairment of goodwill of $252.7 million for the nine months ended September 30, 2016 to write the goodwill down to its estimated fair value of $253.4 million . Based on evaluation of qualitative factors, we determined that the goodwill impairment is primarily a result of the decline in the prices of oil and natural gas and the decline in the market price of our common units. Any further significant decline in the prices of oil and natural gas as well as any continued declines in the quoted market price of the Company’s units could change our estimate of the fair value of the reporting unit and could result in an additional impairment charge
New Pronouncements Issued But Not Yet Adopted	New Pronouncement Issued But Not Yet Adopted: 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 must 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 currently evaluating the method by which we will adopt the standard in 2018 and the impact of the pending adoption of ASU No. 2014-09 on our consolidated financial statements and do not anticipate the standard will have a material impact on our consolidated financial statements. In February 2016, the FASB issued ASU No. 2016-02, "Leases (Topic 842)", which requires lessees to recognize at the commencement date for all leases, with the exception of short-term leases, (a) a lease liability, which is a lessee‘s obligation to make lease payments arising from a lease, measured on a discounted basis, and (b) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The ASU on leases will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. We do not expect the adoption of ASU No. 2016-02 will have a material impact on our consolidated financial statements. In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. Under this ASU, the SEC Staff is rescinding certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities—Oil and Gas, effective upon adoption of Topic 606. As discussed above, Revenue from Contracts with Customers (Topic 606) is effective for public entities for fiscal years, and interim periods within the fiscal years, beginning after December 15, 2017. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU No. 2016-12”). The amendments under this ASU do not change the core revenue recognition principle in Topic 606. In addition, ASU No. 2016-12 provide clarifying guidance in certain narrow areas and add some practical expedients. These amendments are also effective at the same date that Topic 606 is effective. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) to address diversity in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The adoption of this ASU will not have any material impact on the calculation or presentation of our results of operations, cash flows or financial position.
Use of Estimates	Use of Estimates: The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related cash flow estimates used in impairment tests of oil and natural gas properties and goodwill, the acquisition of oil and natural gas properties, the fair value of derivative contracts and asset retirement obligations, accrued oil, natural gas and NGLs revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ from those estimates.
Prior Year Financial Statement Presentation	Prior Year Financial Statement Presentation Certain prior year balances have been reclassified to conform to the current year presentation of balances as stated in this Quarterly Report on Form 10-Q. Please read Note 3. Long-Term Debt of the Notes to the Consolidated Financial Statements for further discussion regarding this reclassification.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	9 Months Ended
	Sep. 30, 2016
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 2015 and eliminating the results of operations from the oil and natural gas properties divested in the SCOOP/STACK Divestiture, adjusted for (i) the assumption of asset retirement obligations and accretion expense for the properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired, (iii) interest expense on additional debt assumed in the LRE Merger and the Eagle Rock Merger, and (iv) the impact of the common units issued in the LRE Merger and the Eagle Rock Merger. 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, Nine months Ended 2015 2016 2015 (in thousands, except per unit data) Total revenues $ 176,404 $ 246,808 $ 579,159 Net loss $ (850,404 ) $ (675,349 ) $ (1,563,264 ) Net loss per unit Common and Class B units - basic and diluted $ (6.50 ) $ (5.14 ) $ (12.05 ) The amount of revenues and excess of revenues over direct operating expenses that were eliminated to reflect the impact of the SCOOP/STACK Divestiture in the pro forma results presented above are as follows (in thousands): Nine months Ended (in thousands) Revenues $ 17,542 Excess of revenues over direct operating expenses $ 15,278
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 2015 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, 2016 September 30, 2016 (in thousands) Eagle Rock Merger Revenues $ 9,160 $ 42,340 Excess of revenues over direct operating expenses $ 3,886 $ 21,605 LRE Merger Revenues $ 18,427 $ 34,767 Excess of revenues over direct operating expenses $ 12,630 $ 19,485
LRE Merger [Member]
Business Acquisition [Line Items]
Fair value of assets and liabilities acquired	Consideration Market value of Vanguard’s common units issued to LRE unitholders $ 123,276 Long-term debt assumed 290,000 413,276 Add: fair value of liabilities assumed Accounts payable and accrued liabilities 5,606 Other current liabilities 9,018 Asset retirement obligations 39,595 Amount attributable to liabilities assumed 54,219 Less: fair value of assets acquired Cash 11,532 Trade accounts receivable 6,822 Other current assets 4,172 Oil and natural gas properties 209,463 Derivative assets 78,725 Other assets 267 Amount attributable to assets acquired 310,981 Goodwill $ 156,514
EROC Merger [Member]
Business Acquisition [Line Items]
Fair value of assets and liabilities acquired	Consideration Market value of Vanguard’s common units issued to Eagle Rock unitholders $ 258,282 Long-term debt assumed 156,550 Replacement unit-based payment awards attributable to pre-combination services 346 415,178 Add: fair value of liabilities assumed Accounts payable and accrued liabilities 53,255 Other current liabilities 2,206 Derivative liabilities 2,201 Asset retirement obligations 48,633 Deferred tax liability 39,327 Other long-term liabilities 1,244 Amount attributable to liabilities assumed 146,866 Less: fair value of assets acquired Cash 6,971 Trade accounts receivable 13,761 Other current assets 15,664 Oil and natural gas properties 462,715 Derivative assets 90,234 Other assets 9,734 Amount attributable to assets acquired 599,079 Bargain Purchase Gain $ (37,035 )

Long-Term Debt (Tables)

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2016
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, 2016 December 31, 2015 (in thousands) Senior Secured Reserve-Based Credit Facility Variable (1) April 16, 2018 $ 1,354,000 $ 1,688,000 Senior Notes due 2019 8.375% (2) June 1, 2019 51,120 51,120 Senior Notes due 2020 7.875% (3) April 1, 2020 381,830 550,000 Senior Notes due 2023 7.00% February 15, 2023 75,634 — Lease Financing Obligation 4.16% August 10, 2020 (4) 21,310 24,668 $ 1,883,894 $ 2,313,788 Less: Current portion of debt under the Reserve-Based Credit Facility (5) (31,887 ) — Unamortized discount on Senior Notes (14,174 ) (17,651 ) Unamortized deferred financing costs (6) (11,596 ) (13,705 ) Current portion of Lease Financing Obligation (4,643 ) (4,501 ) Total long-term debt $ 1,821,594 $ 2,277,931 (1) Variable interest rate was 3.02% and 2.90% at September 30, 2016 and December 31, 2015 , respectively. (2) Effective interest rate was 21.45% at September 30, 2016 and December 31, 2015 . (3) Effective interest rate was 8.00% at September 30, 2016 and December 31, 2015 . (4) The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021. (5) Represents the remaining borrowing base deficiency obligation as of September 30, 2016 payable in two equal monthly installments through November 2016. (6) In order to comply with Accounting Standards Update No. 2015-03, unamortized debt issuance costs have been reclassified from other assets to long-term debt on a retrospective basis. This reclassification had no impact on historical income from continuing operations or members’ equity.
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, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivative Contracts Covering Anticipated Future Production	The following tables summarize oil, natural gas and NGLs commodity derivative contracts in place at September 30, 2016 , and does not reflect the impact of the monetization mentioned above. Fixed-Price Swaps (NYMEX) Gas Oil NGLs Contract Period MMBtu Weighted Average Fixed Price Bbls Weighted Average WTI Price Bbls Weighted Average October 1, 2016 – December 31, 2016 18,264,472 $ 4.36 469,014 $ 84.00 227,500 $ 30.31 January 1, 2017 – December 31, 2017 55,080,260 $ 3.74 749,698 $ 85.70 — — Fixed-Price Swaps (Light Louisiana Sweet) Oil Contract Period Bbls Weighted Average Fixed Price January 1, 2017 – December 31, 2017 168,000 $ 91.25 Call Options Sold Gas Oil Contract Period MMBtu Weighted Average Fixed Price Bbls Weighted Average Fixed Price October 1, 2016 – December 31, 2016 2,300,000 $ 4.25 156,400 $ 50.00 January 1, 2017 – December 31, 2017 11,862,500 $ 3.01 365,000 $ 95.00 Swaptions Gas Contract Period MMBtu Weighted Average Fixed Price January 1, 2017 – December 31, 2017 3,437,500 $ 2.99 January 1, 2018 – December 31, 2018 675,000 $ 2.74 Basis Swaps Gas Contract Period MMBtu Weighted Avg. Basis Differential ($/MMBtu) Pricing Index October 1, 2016 – December 31, 2016 9,660,000 $ (0.20 ) Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential January 1, 2017 – December 31, 2017 21,900,000 $ (0.20 ) Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential October 1, 2016 – December 31, 2016 235,385 $ (0.08 ) Houston Ship Channel and NYMEX Henry Hub Basis Differential October 1, 2016 – December 31, 2016 69,624 $ (0.10 ) TexOk and NYMEX Henry Hub Basis Differential October 1, 2016 – December 31, 2016 390,713 $ (0.13 ) WAHA and NYMEX Henry Hub Basis Differential Oil Contract Period Bbls Weighted Avg. Basis Differential ($/Bbl) Pricing Index October 1, 2016 – December 31, 2016 243,000 $ (1.01 ) WTI Midland and WTI Cushing Basis Differential October 1, 2016 – December 31, 2016 55,200 $ (0.43 ) West Texas Sour and WTI Cushing Basis Differential October 1, 2016 – December 31, 2016 184,000 $ (14.25 ) WTI and West Canadian Select Basis Differential Three-Way Collars Gas Contract Period MMBtu Floor Ceiling Put Sold October 1, 2016 – December 31, 2016 3,220,000 $ 3.95 $ 4.25 $ 3.00 January 1, 2017 – December 31, 2017 14,600,000 $ 3.88 $ 4.15 $ 3.31 Oil Contract Period Bbls Floor Ceiling Put Sold October 1, 2016 – December 31, 2016 266,800 $ 90.00 $ 96.18 $ 73.62 Put Options Sold Gas Oil Contract Period MMBtu Put Sold ($/MMBtu) Bbls Put Sold ($/Bbl) October 1, 2016 – December 31, 2016 460,000 $ 3.00 36,800 $ 75.00 January 1, 2017 – December 31, 2017 1,825,000 $ 3.50 73,000 $ 75.00 Range Bonus Accumulators Oil Contract Period Bbls Bonus Range Ceiling Range Floor October 1, 2016 – December 31, 2016 46,000 $ 4.00 $ 100.00 $ 75.00 Collars Gas Oil Contract Period MMBtu Floor Price ($/MMBtu) Ceiling Price ($/MMBtu) Bbls Floor Price ($/Bbl) Ceiling Price ($/Bbl) October 1, 2016 – December 31, 2016 — $ — $ — 138,000 $ 45.00 $ 55.00 January 1, 2017 – December 31, 2017 450,000 $ 3.10 $ 3.45 — $ — $ — Puts Oil Contract Period Bbls Put Price ($/Bbl) October 1, 2016 – December 31, 2016 92,000 $ 60.00
Interest Rate Derivative Contracts	Interest Rate Swaps At September 30, 2016 , we had open interest rate derivative contracts as follows (in thousands): Period Notional Amount Fixed LIBOR Rates October 1, 2016 to December 10, 2016 $ 20,000 2.17 % October 1, 2016 to October 31, 2016 $ 40,000 1.65 % October 1, 2016 to August 5, 2018 $ 30,000 2.25 % October 1, 2016 to October 31, 2016 $ 20,000 1.78 % October 1, 2016 to December 31, 2019 $ 175,000 2.32 % October 1, 2016 to February 16, 2017 $ 75,000 1.73 % October 1, 2016 to June 16, 2017 $ 70,000 1.43 % October 1, 2016 to February 16, 2017 $ 75,000 1.73 % Total $ 505,000
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, 2016 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 $ 129,235 $ (17,419 ) $ 111,816 Interest rate derivative contracts — (8,528 ) (8,528 ) Total derivative instruments $ 129,235 $ (25,947 ) $ 103,288 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 $ (17,703 ) $ 17,418 $ (285 ) Interest rate derivative contracts (9,947 ) 8,528 (1,419 ) Total derivative instruments $ (27,650 ) $ 25,946 $ (1,704 ) December 31, 2015 Offsetting Derivative Assets: Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Commodity price derivative contracts $ 349,281 $ (21,834 ) $ 327,447 Interest rate derivative contracts — (10,400 ) (10,400 ) Total derivative instruments $ 349,281 $ (32,234 ) $ 317,047 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 $ (21,934 ) $ 21,834 $ (100 ) Interest rate derivative contracts (10,656 ) 10,400 (256 ) Total derivative instruments $ (32,590 ) $ 32,234 $ (356 )
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, 2016 and the year ended December 31, 2015 are as follows: Nine Months Ended September 30, 2016 Year Ended December 31, 2015 (in thousands) Derivative asset at beginning of period, net $ 316,691 $ 220,734 Purchases Fair value of derivatives acquired — 195,273 Net premiums and fees (received) paid or deferred for derivative contracts (1,960 ) 7,126 Net gains (losses) on commodity and interest rate derivative contracts (21,813 ) 169,569 Settlements Cash settlements received on matured commodity derivative contracts (198,104 ) (211,723 ) Cash settlements paid on matured interest rate derivative contracts 6,770 5,227 Termination of derivative contracts — (69,515 ) Derivative asset at end of period, net $ 101,584 $ 316,691

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2016
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, 2016 Fair Value Measurements Using Assets/Liabilities Level 1 Level 2 Level 3 at Fair Value Assets: Commodity price derivative contracts $ — $ 112,976 $ (1,160 ) $ 111,816 Interest rate derivative contracts — (8,528 ) — (8,528 ) Total derivative instruments $ — $ 104,448 $ (1,160 ) $ 103,288 Liabilities: Commodity price derivative contracts $ — $ (285 ) $ — $ (285 ) Interest rate derivative contracts — (1,419 ) — (1,419 ) Total derivative instruments $ — $ (1,704 ) $ — $ (1,704 ) December 31, 2015 Fair Value Measurements Using Assets/Liabilities Level 1 Level 2 Level 3 at Fair Value Assets: Commodity price derivative contracts $ — $ 333,380 $ (5,933 ) $ 327,447 Interest rate derivative contracts — (10,400 ) — (10,400 ) Total derivative instruments $ — $ 322,980 $ (5,933 ) $ 317,047 Liabilities: Commodity price derivative contracts $ — $ (99 ) $ — $ (99 ) Interest rate derivative contracts — (257 ) — (257 ) Total derivative instruments $ — $ (356 ) $ — $ (356 )
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, 2016 2015 (in thousands) Unobservable inputs, beginning of period $ (5,933 ) $ (6,470 ) Total gains 9,381 3,525 Settlements (4,608 ) (3,124 ) Unobservable inputs, end of period $ (1,160 ) $ (6,069 ) Change in fair value included in earnings related to derivatives still held as of September 30, $ 223 $ (2,254 )

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2016
Asset Retirement Obligation [Abstract]
Changes in Asset Retirement Obligations	The asset retirement obligations as of September 30, 2016 and December 31, 2015 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the nine months ended September 30, 2016 and the year ended December 31, 2015 were as follows: September 30, 2016 December 31, 2015 (in thousands) Asset retirement obligations, beginning of period $ 271,456 $ 149,062 Liabilities added during the current period 502 2,699 Liabilities added from the LRE Merger and the Eagle Rock Merger — 88,228 Accretion expense 9,142 10,238 Retirements (1,492 ) (838 ) Liabilities related to assets divested (9,342 ) (262 ) Change in estimate (4,368 ) 22,329 Asset retirement obligation, end of period 265,898 271,456 Less: current obligations (7,592 ) (9,024 ) Long-term asset retirement obligation, end of period $ 258,306 $ 262,432

Commitments and Contingencies (

Commitments and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2016
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, 2016 . 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, 2016 (in thousands) October 1, 2016 - December 31, 2016 $ 3,317 2017 12,538 2018 11,678 2019 9,661 2020 410 Total $ 37,604

Members_ Deficit and Net Loss27

Members’ Deficit and Net Loss per Common and Class B Unit (Tables)	9 Months Ended
	Sep. 30, 2016
Equity [Abstract]
Cumulative Preferred Units	The following table summarizes the Company’s Cumulative Preferred Units outstanding at September 30, 2016 and December 31, 2015 : September 30, 2016 December 31, 2015 Earliest Redemption Date Liquidation Preference Per Unit 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, 2016 and the year ended December 31, 2015 (in thousands): September 30, 2016 December 31, 2015 Beginning of period 130,477 83,452 Issuance of Common units as consideration for the Eagle Rock Merger — 27,886 Issuance of Common units as consideration for the LRE Merger — 15,448 Issuance of Common units for cash — 2,430 Repurchase of units under the Common unit buyback program — (157 ) Unit-based compensation 563 1,418 End of period 131,040 130,477
Distributions Declared	The following table shows the distribution amount per unit, declared date, record date and payment date of the cash distributions we paid on each of our common and Class B units attributable to 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. Our board of directors elected to suspend cash distributions to the holders of our common and Class B units and Cumulative Preferred Units effective with the February 2016 distribution. Cash Distributions Distribution Per Unit Declared Date Record Date Payment Date 2016 First Quarter January $ 0.0300 February 18, 2016 March 1, 2016 March 15, 2016 2015 Fourth Quarter December $ 0.0300 January 20, 2016 February 1, 2016 February 12, 2016 November $ 0.0300 December 18, 2015 January 4, 2016 January 14, 2016 October $ 0.1175 November 20, 2015 December 1, 2015 December 15, 2015 Third Quarter September $ 0.1175 October 19, 2015 November 2, 2015 November 13, 2015 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

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2016
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, 2016 is presented below: Number of Non-vested Restricted Units Weighted Average Grant Date Fair Value Non-vested restricted units at December 31, 2015 976,348 $ 18.29 Granted 7,500 $ 3.11 Forfeited (29,891 ) $ 13.34 Vested (259,047 ) $ 17.09 Non-vested restricted units at September 30, 2016 694,910 $ 18.84
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, 2016 is presented below: Number of Non-vested Phantom Units Weighted Average Grant Date Fair Value Non-vested phantom units at December 31, 2015 203,221 $ 20.99 Granted 3,712,450 $ 2.56 Forfeited (30,124 ) $ 1.97 Vested (122,523 ) $ 22.23 Non-vested phantom units at September 30, 2016 3,763,024 $ 2.92

Description of the Business (De

Description of the Business (Details)	9 Months Ended
	Sep. 30, 2016operating_areas
Accounting Policies [Abstract]
Number of operating areas	10

Summary of Significant Accoun30

Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Goodwill	$ 253,370		$ 253,370		$ 506,046
Impairment of goodwill	$ 252,676	$ 0	$ 252,676	$ 0
Potato Hills Gas Gathering System [Member]
Ownership interest percent	51.00%		51.00%

Summary of Significant Accoun31

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Oil and Gas Properties) (Details) $ in Thousands	3 Months Ended						9 Months Ended
	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)$ / bbl$ / MMBTU	Mar. 31, 2016USD ($)$ / bbl$ / MMBTU	Sep. 30, 2015USD ($)$ / bbl$ / MMBTU	Jun. 30, 2015USD ($)$ / bbl$ / MMBTU	Mar. 31, 2015USD ($)$ / bbl$ / MMBTU	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Discount rate used in determining limitation of capitalized costs							10.00%
Impairment of oil and natural gas properties | $	$ 0	$ 157,900	$ 207,800	$ 491,487	$ 733,400	$ 132,600	$ 365,658	$ 1,357,462
Average price of natural gas used in the impairment calculation | $ / MMBTU		2.24	2.41	3.11	3.44	3.91
Average price of crude oil used in the impairment calculation | $ / bbl		42.91	46.16	59.23	71.51	82.62

Acquisitions and Divestitures -

Acquisitions and Divestitures - Acquisitions (LRE Merger) (Details) $ / shares in Units, $ in Thousands	Oct. 05, 2015USD ($)$ / sharesshares	Sep. 30, 2016USD ($)	Dec. 31, 2015USD ($)
Less: fair value of assets acquired
Goodwill		$ 253,370	$ 506,046
LRE Merger [Member]
Business Acquisition [Line Items]
Business Combination, Equity Interest Issued or Issuable, Exchange Ratio	0.550
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares	15,400,000
Share price (in USD per share) | $ / shares	$ 7.98
Business Combination, Consideration Transferred [Abstract]
Market value of Vanguard’s common units issued to LRE unitholders	$ 123,276
Long-term debt assumed	290,000
Business Combination, Consideration Transferred	413,276
Add: fair value of liabilities assumed
Accounts payable and accrued liabilities	5,606
Other current liabilities	9,018
Asset retirement obligations	39,595
Amount attributable to liabilities assumed	54,219
Less: fair value of assets acquired
Cash	11,532
Trade accounts receivable	6,822
Other current assets	4,172
Oil and natural gas properties	209,463
Derivative assets	78,725
Other assets	267
Amount attributable to assets acquired	310,981
Goodwill	$ 156,514
General Partner [Member] | LRE Merger [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares	12,320

Acquisitions and Divestitures33

Acquisitions and Divestitures - Acquisitions (Eagle Rock Merger) (Details) - EROC Merger [Member] $ / shares in Units, $ in Thousands, shares in Millions	Oct. 08, 2015USD ($)$ / sharesshares	Sep. 30, 2016USD ($)
Business Acquisition [Line Items]
Business Combination, Equity Interest Issued or Issuable, Exchange Ratio	0.185
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares	27.7
Share price (in USD per share) | $ / shares	$ 9.31
Debt extinguished subsequent to the merger	$ 122,300
Business Combination, Consideration Transferred [Abstract]
Market value of Vanguard’s common units issued to Eagle Rock unitholders	258,282
Long-term debt assumed	156,550
Replacement unit-based payment awards attributable to pre-combination services	346
Business Combination, Consideration Transferred	415,178
Add: fair value of liabilities assumed
Accounts payable and accrued liabilities	53,255
Other current liabilities	2,206
Derivative liabilities	2,201
Asset retirement obligations	48,633
Deferred tax liability	39,327
Other long-term liabilities	1,244
Amount attributable to liabilities assumed	146,866
Less: fair value of assets acquired
Cash	6,971
Trade accounts receivable	13,761
Other current assets	15,664
Oil and natural gas properties	462,715
Derivative assets	90,234
Other assets	9,734
Amount attributable to assets acquired	599,079
Bargain Purchase Gain	$ (37,035)
Adjustment to bargain purchase gain recognized		$ 3,800

Acquisitions and Divestitures34

Acquisitions and Divestitures (Details) - USD ($) $ in Thousands	May 19, 2016	Jul. 31, 2015	Sep. 30, 2016	Sep. 30, 2015
Business Acquisition [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment			$ 288,483	$ 0
Series of Individually Immaterial Business Acquisitions [Member]
Business Acquisition [Line Items]
Fair value of consideration transferred		$ 11,400
Proceeds from Sale of Oil and Gas Property and Equipment			$ 22,200
SCOOP/STACK Divestiture [Member]
Business Acquisition [Line Items]
Business acquisitions, Agreed purchase price	$ 272,500
Proceeds from Sale of Oil and Gas Property and Equipment	265,000
Amount held in escrow	7,500
Transaction fees	2,100
Potato Hills Gas Gathering System [Member]
Business Acquisition [Line Items]
Ownership interest conveyed			51.00%
Fair value of consideration transferred			$ 7,700
Senior Secured Reserve-Based Credit Facility | SCOOP/STACK Divestiture [Member]
Business Acquisition [Line Items]
Line of credit repayment	$ 262,900

Acquisitions and Divestitures35

Acquisitions and Divestitures - Pro Forma (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Proforma revenues	$ 176,404	$ 246,808	$ 579,159
Proforma Net income	$ (850,404)	$ (675,349)	$ (1,563,264)
Common and Class B units - basic and diluted (in USD per share)	$ (6.50)	$ (5.14)	$ (12.05)
SCOOP/STACK Divestiture [Member]
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Proforma revenues		$ 17,542
Excess of revenues over direct operating expenses		$ 15,278

Acquisitions and Divestitures36

Acquisitions and Divestitures - Acquiree Earnings (Details) - USD ($) $ in Thousands	May 19, 2016	Sep. 30, 2016	Sep. 30, 2016
SCOOP/STACK Divestiture [Member]
Business Acquisition [Line Items]
Business acquisitions, Agreed purchase price	$ 272,500
EROC Merger [Member]
Business Acquisition [Line Items]
Revenues		$ 9,160	$ 42,340
Excess of revenues over direct operating expenses		3,886	21,605
LRE Merger [Member]
Business Acquisition [Line Items]
Revenues		18,427	34,767
Excess of revenues over direct operating expenses		$ 12,630	$ 19,485

Long-Term Debt (Details)

Long-Term Debt (Details)		Nov. 03, 2016USD ($)	Oct. 26, 2016USD ($)	Sep. 30, 2016USD ($)payment	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)payment	Sep. 30, 2015USD ($)	Jan. 01, 2017	Dec. 01, 2016USD ($)	Oct. 03, 2016USD ($)	May 26, 2016USD ($)	Feb. 10, 2016USD ($)	Jan. 01, 2016	Dec. 31, 2015USD ($)
Senior Secured Reserve-Based Credit Facility [Abstract]
Debt amount outstanding				$ 1,883,894,000		$ 1,883,894,000								$ 2,313,788,000
Interest Paid						$ 60,575,000	$ 47,718,000
Current Ratio											1
Debt to EBITDA ratio													5.25
Senior Notes [Abstract]
Subsidiary or Equity Method Investee, Cumulative Percentage Ownership after All Transactions						100.00%
Extinguishment of Debt, Amount						$ 168,200,000
Required repurchase of aggregate amount of debt				50,000,000		50,000,000
Gains (Losses) on Extinguishment of Debt				$ 0	$ 0	$ 89,714,000	$ 0
Carrying Value of Senior Notes exchanged, Net												$ 165,300,000
Senior Secured Reserve-Based Credit Facility
Debt Instrument [Line Items]
Variable interest rate				3.02%		3.02%								2.90%
Senior Secured Reserve-Based Credit Facility [Abstract]
Number of monthly installments | payment				2		2
Line of Credit Facility, Maximum Borrowing Capacity				$ 3,500,000,000		$ 3,500,000,000
Line of Credit Facility, Current Borrowing Capacity				1,325,000,000		1,325,000,000					$ 1,780,000,000
Long-term Line of Credit, Deficiency											$ 103,500,000
Line of Credit Facility, Periodic Payment						17,500,000
Debt amount outstanding				1,354,000,000		1,354,000,000								$ 1,688,000,000
Remaining borrowing capacity				$ (31,900,000)		$ (31,900,000)
Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Effective Percentage				21.45%		21.45%
Senior Secured Reserve-Based Credit Facility [Abstract]
Debt amount outstanding				$ 51,120,000		$ 51,120,000								51,120,000
Senior Notes [Abstract]
Redemption price of aggregate principal amount of senior notes on or after April 1, 2016 (in hundredths)						102.094%
Stated interest rate (in hundredths)	[1]			8.375%		8.375%
Redemption price of aggregate principal amount of senior notes on April 1, 2018 and thereafter (in hundredths)						100.00%
Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Effective Percentage				8.00%		8.00%
Senior Secured Reserve-Based Credit Facility [Abstract]
Debt amount outstanding				$ 381,830,000		$ 381,830,000								550,000,000
Senior Notes [Abstract]
Redemption price of aggregate principal amount of senior notes on or after April 1, 2016 (in hundredths)						103.9375%
Stated interest rate (in hundredths)	[2]			7.875%		7.875%
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%
Subordinated Debt due 2023
Senior Secured Reserve-Based Credit Facility [Abstract]
Debt amount outstanding				$ 75,634,000		$ 75,634,000								0
Senior Notes [Abstract]
Stated interest rate (in hundredths)				7.00%		7.00%						7.00%
Debt Instrument, Face Amount												$ 75,600,000
Lease Financing Obligations
Senior Secured Reserve-Based Credit Facility [Abstract]
Debt amount outstanding				$ 21,310,000		$ 21,310,000								$ 24,668,000
Senior Notes [Abstract]
Stated interest rate (in hundredths)				4.16%		4.16%
Aggregate Cost, Early Buyout Option to Purchase equipment				$ 16,000,000		$ 16,000,000
Standby Letters of Credit | Senior Secured Reserve-Based Credit Facility
Senior Secured Reserve-Based Credit Facility [Abstract]
Line of Credit Facility, Current Borrowing Capacity				$ 2,900,000		$ 2,900,000
Scenario, Forecast [Member]
Senior Secured Reserve-Based Credit Facility [Abstract]
Debt to EBITDA ratio								4.5
Subsequent Event [Member]
Senior Secured Reserve-Based Credit Facility [Abstract]
Long-term Line of Credit, Deficiency		$ 187,500,000
Interest Payable										$ 15,000,000
Subsequent Event [Member] | Senior Secured Reserve-Based Credit Facility
Senior Secured Reserve-Based Credit Facility [Abstract]
Line of Credit Facility, Current Borrowing Capacity		1,100,000,000
Line of Credit Facility, Periodic Payment		37,500,000
Subsequent Event [Member] | Senior Notes due 2019 [Member]
Senior Secured Reserve-Based Credit Facility [Abstract]
Interest Payable									$ 2,100,000
Subsequent Event [Member] | Senior Notes due 2020 [Member]
Senior Secured Reserve-Based Credit Facility [Abstract]
Interest Paid			$ 15,100,000
Interest Payable										$ 15,000,000
Subsequent Event [Member] | Standby Letters of Credit | Senior Secured Reserve-Based Credit Facility
Senior Secured Reserve-Based Credit Facility [Abstract]
Line of Credit Facility, Current Borrowing Capacity		$ 300,000
[1]	Effective interest rate was 21.45% at September 30, 2016 and December 31, 2015.
[2]	Effective interest rate was 8.00% at September 30, 2016 and December 31, 2015.

Long-Term Debt - Financing Arra

Long-Term Debt - Financing Arrangements (Details) - USD ($) $ in Thousands		9 Months Ended
		Sep. 30, 2016	Feb. 10, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Debt amount outstanding		$ 1,883,894		$ 2,313,788
Current portion of debt under the Reserve-Based Credit Facility		(31,887)		0
Unamortized discount on Senior Notes		(14,174)		(17,651)
Unamortized deferred financing costs		(11,596)		(13,705)
Current portion of Lease Financing Obligation		(4,643)		(4,501)
Total long-term debt		$ 1,821,594		2,277,931
Senior Secured Reserve-Based Credit Facility
Debt Instrument [Line Items]
Interest rate description	[1]	Variable (1)
Maturity date		Apr. 16, 2018
Debt amount outstanding		$ 1,354,000		1,688,000
Current portion of debt under the Reserve-Based Credit Facility		$ (31,887)		0
Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Stated interest rate (in hundredths)	[2]	8.375%
Maturity date		Jun. 1, 2019
Debt amount outstanding		$ 51,120		51,120
Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Stated interest rate (in hundredths)	[3]	7.875%
Maturity date		Apr. 1, 2020
Debt amount outstanding		$ 381,830		550,000
Subordinated Debt due 2023
Debt Instrument [Line Items]
Stated interest rate (in hundredths)		7.00%	7.00%
Maturity date		Feb. 15, 2023
Debt amount outstanding		$ 75,634		0
Lease Financing Obligations
Debt Instrument [Line Items]
Stated interest rate (in hundredths)		4.16%
Maturity date	[4]	Aug. 10, 2020
Debt amount outstanding		$ 21,310		$ 24,668
[1]	Variable interest rate was 3.02% and 2.90% at September 30, 2016 and December 31, 2015, respectively.
[2]	Effective interest rate was 21.45% at September 30, 2016 and December 31, 2015.
[3]	Effective interest rate was 8.00% at September 30, 2016 and December 31, 2015.
[4]	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, 2016
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 40

Price and Interest Rate Risk Management Activities (Details) $ in Thousands	1 Months Ended	9 Months Ended
	Oct. 31, 2016USD ($)	Sep. 30, 2016USD ($)MMBTU$ / bbl$ / MMBTUbbl
Fair value of derivatives [Abstract]
Maximum potential loss due to credit risk | $		$ 129,200
Fixed-Price Swaps | Gas | Contract period October 1, 2016 to December 31, 2016 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged (in MMBtu) | MMBTU		18,264,472
Weighted average fixed price (in dollars per unit) | $ / MMBTU		4.36
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 (in MMBtu) | MMBTU		55,080,260
Weighted average fixed price (in dollars per unit) | $ / MMBTU		3.74
Fixed-Price Swaps | Oil | Contract period October 1, 2016 to December 31, 2016 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Weighted average fixed price (in dollars per unit) | $ / bbl		84
Portion of Future Oil and liquids Production Being Hedged (in Bbls) | bbl		469,014
Fixed-Price Swaps | Oil | Contract period January 1, 2017 to December 31, 2017
Commodity derivative contracts covering our anticipated future production [Abstract]
Weighted average fixed price (in dollars per unit) | $ / bbl		85.70
Portion of Future Oil and liquids Production Being Hedged (in Bbls) | bbl		749,698
Fixed-Price Swaps | Oil | Contract period January 1, 2017 to December 31, 2017 | Light Louisiana Sweet [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Weighted average fixed price (in dollars per unit) | $ / bbl		91.25
Portion of Future Oil and liquids Production Being Hedged (in Bbls) | bbl		168,000
Fixed-Price Swaps | Natural Gas Liquids | Contract period October 1, 2016 to December 31, 2016 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Weighted average fixed price (in dollars per unit) | $ / bbl		30.31
Portion of Future Oil and liquids Production Being Hedged (in Bbls) | bbl		227,500
Fixed-Price Swaps | Natural Gas Liquids | Contract period January 1, 2017 to December 31, 2017
Commodity derivative contracts covering our anticipated future production [Abstract]
Weighted average fixed price (in dollars per unit) | $ / bbl		0
Portion of Future Oil and liquids Production Being Hedged (in Bbls) | bbl		0
Call Option [Member] | Gas | Contract period October 1, 2016 to December 31, 2016 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged (in MMBtu) | MMBTU		2,300,000
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 (in MMBtu) | MMBTU		11,862,500
Weighted average fixed price (in dollars per unit) | $ / MMBTU		3.01
Call Option [Member] | Oil | Contract period October 1, 2016 to December 31, 2016 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Weighted average fixed price (in dollars per unit) | $ / bbl		50
Portion of Future Oil and liquids Production Being Hedged (in Bbls) | bbl		156,400
Call Option [Member] | Oil | Contract period January 1, 2017 to December 31, 2017
Commodity derivative contracts covering our anticipated future production [Abstract]
Weighted average fixed price (in dollars per unit) | $ / bbl		95
Portion of Future Oil and liquids Production Being Hedged (in Bbls) | bbl		365,000
Swaption [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 (in MMBtu) | MMBTU		3,437,500
Weighted average fixed price (in dollars per unit) | $ / MMBTU		2.99
Swaption [Member] | Gas | Contract period January 1, 2018 to December 31, 2018 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged (in MMBtu) | MMBTU		675,000
Weighted average fixed price (in dollars per unit) | $ / MMBTU		2.74
Basis Swaps | Gas | Contract period October 1, 2016 to December 31, 2016 [Member] | NW Rocky Mt-Henry Hub Index
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged (in MMBtu) | MMBTU		9,660,000
Weighted average basis differential (in dollars per unit) | $ / MMBTU		(0.20)
Basis Swaps | Gas | Contract period October 1, 2016 to December 31, 2016 [Member] | Houston Ship Channel-Henry Hub Index [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged (in MMBtu) | MMBTU		235,385
Weighted average basis differential (in dollars per unit) | $ / MMBTU		(0.08)
Basis Swaps | Gas | Contract period October 1, 2016 to December 31, 2016 [Member] | TexOk- Henry Hub Index [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged (in MMBtu) | MMBTU		69,624
Weighted average basis differential (in dollars per unit) | $ / MMBTU		(0.10)
Basis Swaps | Gas | Contract period October 1, 2016 to December 31, 2016 [Member] | WAHA - Henry Hub Index [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged (in MMBtu) | MMBTU		390,713
Weighted average basis differential (in dollars per unit) | $ / MMBTU		(0.13)
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 (in MMBtu) | MMBTU		21,900,000
Weighted average basis differential (in dollars per unit) | $ / MMBTU		(0.20)
Basis Swaps | Oil | Contract period October 1, 2016 to December 31, 2016 [Member] | Midland-Cushing Index
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged (in Bbls) | bbl		243,000
Weighted average basis differential (in dollars per unit) | $ / bbl		(1.01)
Basis Swaps | Oil | Contract period October 1, 2016 to December 31, 2016 [Member] | WTS-Cushing Index
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged (in Bbls) | bbl		55,200
Weighted average basis differential (in dollars per unit) | $ / bbl		(0.43)
Basis Swaps | Oil | Contract period October 1, 2016 to December 31, 2016 [Member] | WTI-WCS Index
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged (in Bbls) | bbl		184,000
Weighted average basis differential (in dollars per unit) | $ / bbl		(14.25)
Three-Way Collars | Gas | Contract period October 1, 2016 to December 31, 2016 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged (in MMBtu) | MMBTU		3,220,000
Weighted average price (in dollars per unit) | $ / MMBTU		3
Ceiling (in dollars per unit) | $ / MMBTU		4.25
Floor (in dollars per unit) | $ / MMBTU		3.95
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 (in MMBtu) | MMBTU		14,600,000
Weighted average price (in dollars per unit) | $ / MMBTU		3.31
Ceiling (in dollars per unit) | $ / MMBTU		4.15
Floor (in dollars per unit) | $ / MMBTU		3.88
Three-Way Collars | Oil | Contract period October 1, 2016 to December 31, 2016 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged (in Bbls) | bbl		266,800
Weighted average price (in dollars per unit) | $ / bbl		73.62
Ceiling (in dollars per unit) | $ / bbl		96.18
Floor (in dollars per unit) | $ / bbl		90
Put Options Sold | Gas | Contract period October 1, 2016 to December 31, 2016 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Gas Production Being Hedged (in MMBtu) | MMBTU		460,000
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 (in MMBtu) | MMBTU		1,825,000
Weighted average price (in dollars per unit) | $ / MMBTU		3.50
Put Options Sold | Oil | Contract period October 1, 2016 to December 31, 2016 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged (in Bbls) | bbl		36,800
Weighted average price (in dollars per unit) | $ / bbl		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 (in Bbls) | bbl		73,000
Weighted average price (in dollars per unit) | $ / bbl		75
Range Bonus Accumulators | Oil | Contract period October 1, 2016 to December 31, 2016 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Derivative, Nonmonetary Notional Amount, Volume | bbl		46,000
Bonus (in dollars per unit) | $ / bbl		4
Ceiling (in dollars per unit) | $ / bbl		100
Floor (in dollars per unit) | $ / bbl		75
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 (in MMBtu) | MMBTU		450,000
Ceiling (in dollars per unit) | $ / MMBTU		3.45
Floor (in dollars per unit) | $ / MMBTU		3.10
Collars | Oil | Contract period October 1, 2016 to December 31, 2016 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged (in Bbls) | bbl		138,000
Ceiling (in dollars per unit) | $ / bbl		55
Floor (in dollars per unit) | $ / bbl		45
Puts | Oil | Contract period October 1, 2016 to December 31, 2016 [Member]
Commodity derivative contracts covering our anticipated future production [Abstract]
Portion of Future Oil and liquids Production Being Hedged (in Bbls) | bbl		92,000
Put Price ($/Bbl) | $ / bbl		60
Interest Rate Swaps
Interest rate derivative contracts [Abstract]
Notional amount | $		$ 505,000
Interest Rate Swaps | Contract period October 1, 2016 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, 2016 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, 2016 to August 5, 2018 [Member]
Interest rate derivative contracts [Abstract]
Notional amount | $		$ 30,000
Fixed Libor Rates (in hundredths)		2.25%
Interest Rate Swaps | Contract period October 1, 2016 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, 2016 to December 31, 2019 [Member]
Interest rate derivative contracts [Abstract]
Notional amount | $		$ 175,000
Fixed Libor Rates (in hundredths)		2.3195%
Interest Rate Swaps | Contract period October 1, 2016 to February 16, 2017 Swap A [Member]
Interest rate derivative contracts [Abstract]
Notional amount | $		$ 75,000
Fixed Libor Rates (in hundredths)		1.7275%
Interest Rate Swaps | Contract period October 1, 2016 to June 16, 2017 [Member]
Interest rate derivative contracts [Abstract]
Notional amount | $		$ 70,000
Fixed Libor Rates (in hundredths)		1.4275%
Interest Rate Swaps | Contract period October 1, 2016 to February 16, 2017 Swap B [Member]
Interest rate derivative contracts [Abstract]
Notional amount | $		$ 75,000
Fixed Libor Rates (in hundredths)		1.725%
Subsequent Event [Member]
Derivative [Line Items]
Value of hedges monetized | $	$ 42,300

Price and Interest Rate Risk 41

Price and Interest Rate Risk Management Activities - Balance Sheet Presentation (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Offsetting Derivative Assets:
Gross amounts of recognized assets	$ 129,235	$ 349,281
Gross amounts offset in the consolidated balance sheets	(25,947)	(32,234)
Net Amounts Presented in the Consolidated Balance Sheets	103,288	317,047
Offsetting Derivative Liabilities:
Gross amounts of recognized liabilities	(27,650)	(32,590)
Gross amounts offset in the consolidated balance sheets	25,946	32,234
Net Amounts Presented in the Consolidated Balance Sheets	(1,704)	(356)
Commodity Contract
Offsetting Derivative Assets:
Gross amounts of recognized assets	129,235	349,281
Gross amounts offset in the consolidated balance sheets	(17,419)	(21,834)
Net Amounts Presented in the Consolidated Balance Sheets	111,816	327,447
Offsetting Derivative Liabilities:
Gross amounts of recognized liabilities	(17,703)	(21,934)
Gross amounts offset in the consolidated balance sheets	17,418	21,834
Net Amounts Presented in the Consolidated Balance Sheets	(285)	(100)
Interest Rate Contract
Offsetting Derivative Assets:
Gross amounts of recognized assets	0	0
Gross amounts offset in the consolidated balance sheets	(8,528)	(10,400)
Net Amounts Presented in the Consolidated Balance Sheets	(8,528)	(10,400)
Offsetting Derivative Liabilities:
Gross amounts of recognized liabilities	(9,947)	(10,656)
Gross amounts offset in the consolidated balance sheets	8,528	10,400
Net Amounts Presented in the Consolidated Balance Sheets	$ (1,419)	$ (256)

Price and Interest Rate Risk 42

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, 2016	Sep. 30, 2015	Dec. 31, 2015
Fair Value, Net Derivative Asset (Liability), Reconciliation [Roll Forward]
Derivative asset at beginning of period, net	$ 316,691	$ 220,734	$ 220,734
Fair value of derivatives acquired	0		195,273
Net premiums and fees (received) paid or deferred for derivative contracts	(1,960)		7,126
Net gains (losses) on commodity and interest rate derivative contracts	(21,813)	100,270	169,569
Cash settlement received on matured commodity derivative contracts	(198,104)	(125,988)	(211,723)
Cash settlements paid on matured interest rate derivative contracts	6,770	$ 2,968	5,227
Termination of derivative contracts	0		(69,515)
Derivative asset at end of period, net	$ 101,584		$ 316,691

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Discount rate used in determining limitation of capitalized costs			10.00%
Impairment of goodwill	$ 252,676	$ 0	$ 252,676	$ 0
Liabilities:
Asset retirement obligations incurred and recorded			502		$ 2,699
Change in estimate			$ (4,368)		22,329
Asset retirement obligations incurred and assumed from business combinations					90,900
Average inflation rate (in hundredths)			1.97%
Fair Value Measured on a Recurring Basis
Assets:
Commodity price derivative contracts	111,816		$ 111,816		327,447
Interest Rate Derivative Assets, at Fair Value	(8,528)		(8,528)		(10,400)
Total derivative instruments	103,288		103,288		317,047
Liabilities:
Commodity price derivative contracts	(285)		(285)		(99)
Interest rate derivative contracts	(1,419)		(1,419)		(257)
Total derivative instruments	(1,704)		(1,704)		(356)
Fair Value Measured on a Recurring Basis | Fair Value Measurements Using Level 1
Assets:
Commodity price derivative contracts	0		0		0
Interest Rate Derivative Assets, at Fair Value	0		0		0
Total derivative instruments	0		0		0
Liabilities:
Commodity price derivative contracts	0		0		0
Interest rate derivative contracts	0		0		0
Total derivative instruments	0		0		0
Fair Value Measured on a Recurring Basis | Fair Value Measurements Using Level 2
Assets:
Commodity price derivative contracts	112,976		112,976		333,380
Interest Rate Derivative Assets, at Fair Value	(8,528)		(8,528)		(10,400)
Total derivative instruments	104,448		104,448		322,980
Liabilities:
Commodity price derivative contracts	(285)		(285)		(99)
Interest rate derivative contracts	(1,419)		(1,419)		(257)
Total derivative instruments	(1,704)		(1,704)		(356)
Fair Value Measured on a Recurring Basis | Fair Value Measurements Using Level 3
Assets:
Commodity price derivative contracts	(1,160)		(1,160)		(5,933)
Interest Rate Derivative Assets, at Fair Value	0		0		0
Total derivative instruments	(1,160)		(1,160)		(5,933)
Liabilities:
Commodity price derivative contracts	0		0		0
Interest rate derivative contracts	0		0		0
Total derivative instruments	0		$ 0		$ 0
Minimum
Liabilities:
Credit-adjusted risk-free interest rate (in hundredths)			4.60%
Maximum
Liabilities:
Credit-adjusted risk-free interest rate (in hundredths)			5.50%
Senior Notes due 2019 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt, fair value	24,100		$ 24,100
Senior Notes due 2020 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt, fair value	189,100		189,100
Subordinated Debt due 2023
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt, fair value	$ 37,500		$ 37,500

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, 2016	Sep. 30, 2015
Unobservable inputs reconciliation
Unobservable inputs, beginning of period	$ (5,933)	$ (6,470)
Total gains	9,381	3,525
Settlements	(4,608)	(3,124)
Unobservable inputs, end of period	(1,160)	(6,069)
Change in fair value included in earnings related to derivatives still held as of September 30,	$ 223	$ (2,254)

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Changes in asset retirement obligations [Abstract]
Asset retirement obligations, beginning of period	$ 271,456	$ 149,062
Liabilities added during the current period	502	2,699
Liabilities added from the LRE Merger and the Eagle Rock Merger	0	88,228
Accretion expense	9,142	10,238
Retirements	(1,492)	(838)
Liabilities related to assets divested	(9,342)	(262)
Change in estimate	(4,368)	22,329
Asset retirement obligation, end of period	265,898	271,456
Less: current obligations	(7,592)	(9,024)
Long-term asset retirement obligation, end of period	$ 258,306	$ 262,432

Commitments and Contingencies -

Commitments and Contingencies - Transportation Demand Charges (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2016USD ($)
Gross future minimum transportation demand
October 1, 2016 - December 31, 2016	$ 3,317
Due 2,017	12,538
Due 2,018	11,678
Due 2,019	9,661
Due 2,020	410
Total	$ 37,604
Minimum
Oil and Gas Delivery Commitments and Contracts
Oil and Gas Delivery Commitments and Contracts, Length of Contract	1 month
Maximum
Oil and Gas Delivery Commitments and Contracts
Oil and Gas Delivery Commitments and Contracts, Length of Contract	4 years

Members_ Deficit and Net Loss47

Members’ Deficit and Net Loss per Common and Class B Unit - Preferred Units Outstanding (Details) - USD ($) $ / shares in Units, $ in Thousands	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
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
Preferred Stock, Amount of Preferred Dividends in Arrears	$ 3,000
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
Preferred Stock, Amount of Preferred Dividends in Arrears	$ 7,800
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
Preferred Stock, Amount of Preferred Dividends in Arrears	$ 4,900

Members_ Deficit and Net Loss48

Members’ Deficit and Net Loss per Common and Class B Unit - Common and Class B Units Rollforward (Details) - shares shares in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Common Units
Increase (Decrease) in Members' Equity [Roll Forward]
Beginning of period (shares)	130,477	83,452
Issuance of Common units for cash (shares)	0	2,430
Repurchase of units under the Common unit buyback program (shares)	0	(157)
Unit-based compensation (shares)	563	1,418
End of period (shares)	131,040	130,477
EROC Merger [Member]
Increase (Decrease) in Members' Equity [Roll Forward]
Partners' Capital Account, Units, Acquisitions	0	27,886
LRE Merger [Member]
Increase (Decrease) in Members' Equity [Roll Forward]
Partners' Capital Account, Units, Acquisitions	0	15,448

Members_ Deficit and Net Loss49

Members’ Deficit and Net Loss per Common and Class B Unit - Net Income per Unit (Details) - shares	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Equity [Abstract]
Antidilutive securities excluded from computation (shares)	2,632,083	47,626	2,632,083	166,331

Members_ Deficit and Net Loss50

Members’ Deficit and Net Loss per Common and Class B Unit - Distributions Declared (Details) - $ / shares

1 Months Ended

9 Months Ended

Jan. 31, 2016

Dec. 31, 2015

Nov. 30, 2015

Oct. 31, 2015

Sep. 30, 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

Sep. 30, 2016

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)

$ 0.03

$ 0.03

$ 0.03

$ 0.1175

$ 0.1175

$ 0.1175

$ 0.1175

$ 0.1175

$ 0.1175

$ 0.1175

$ 0.1175

$ 0.1175

$ 0.1175

$ 0.21

Cash distribution, declaration date

Feb. 18, 2016

Jan. 20, 2016

Dec. 18, 2015

Nov. 20, 2015

Oct. 19, 2015

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

Cash Distributions Record Date

Mar. 1, 2016

Feb. 1, 2016

Jan. 4, 2016

Dec. 1, 2015

Nov. 2, 2015

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

Cash Distributions Payment Date

Mar. 15, 2016

Feb. 12, 2016

Jan. 14, 2016

Dec. 15, 2015

Nov. 13, 2015

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

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, 2016shares	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)officershares	Sep. 30, 2015USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Accrued liability | $		$ 0.6	$ 1.1	$ 0.6	$ 1.1
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage				33.33%
Restricted Stock Units (RSUs) | Employee [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted (in units) | shares				7,500
Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage				33.33%
Phantom Share Units (PSUs) | Executive Officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted (in units) | shares	2,255,033
Phantom Share Units (PSUs) | Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted (in units) | shares				125,838
Vesting period				1 year
Selling, General and Administrative Expenses | Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense | $		1.5	3.4	$ 4.1	10.4
Selling, General and Administrative Expenses | Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense | $		1.3	0.4	$ 3.6	1.3
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]
Vesting period				3 years
Amended Agreements | Selling, General and Administrative Expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense | $		$ 0.6	$ 0.4	$ 1.8	$ 1.1
VNR LTIP | Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted (in units) | shares				1,331,579
Vesting period				3 years

Unit-Based Compensation - Summa

Unit-Based Compensation - Summary of Non-Vested Restricted Units (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$ 8.2		$ 8.2
Unrecognized compensation cost recognition period (in years)			1 year 4 months
Number of Non-vested Units
Non-vested units at beginning of period (in units)			203,221
Granted (in units)			3,712,450
Forfeited (in units)			(30,124)
Vested (in units)			(122,523)
Non-vested units at end of period (in units)	3,763,024		3,763,024
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per unit)			$ 20.99
Granted (in dollars per unit)			2.56
Forfeited (in dollars per unit)			1.97
Vested (in dollars per unit)			22.23
Non-vested units at end of period (in dollars per unit)	$ 2.92		$ 2.92
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$ 6.1		$ 6.1
Unrecognized compensation cost recognition period (in years)			1 year 3 months
Number of Non-vested Units
Non-vested units at beginning of period (in units)			976,348
Granted (in units)			7,500
Forfeited (in units)			(29,891)
Vested (in units)			(259,047)
Non-vested units at end of period (in units)	694,910		694,910
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per unit)			$ 18.29
Granted (in dollars per unit)			3.11
Forfeited (in dollars per unit)			13.34
Vested (in dollars per unit)			17.09
Non-vested units at end of period (in dollars per unit)	$ 18.84		$ 18.84
Selling, General and Administrative Expenses | Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash compensation	$ 1.3	$ 0.4	$ 3.6	$ 1.3
Selling, General and Administrative Expenses | Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash compensation	$ 1.5	$ 3.4	$ 4.1	$ 10.4

Unit-Based Compensation - Sum53

Unit-Based Compensation - Summary of Non-Vested Phantom Units (Details) - Phantom Share Units (PSUs) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$ 8.2		$ 8.2
Unrecognized compensation cost recognition period (in years)			1 year 4 months
Number of Non-vested Units
Non-vested units at beginning of period (in units)			203,221
Granted (in units)			3,712,450
Forfeited (in units)			(30,124)
Non-vested units at end of period (in units)	3,763,024		3,763,024
Weighted Average Grant Date Fair Value
Non-vested units at beginning of period (in dollars per unit)			$ 20.99
Granted (in dollars per unit)			2.56
Forfeited (in dollars per unit)			1.97
Non-vested units at end of period (in dollars per unit)	$ 2.92		$ 2.92
Selling, General and Administrative Expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash compensation	$ 1.3	$ 0.4	$ 3.6	$ 1.3

Shelf Registration Statements54

Shelf Registration Statements (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016USD ($)
Registration Payment Arrangement, Maximum Potential Consideration	$ 500
Common Units | Distribution Agreement 2013 [Member]
Maximum offering under equity distribution agreement	400
Series A Preferred Units | Distribution Agreement 2013 [Member]
Maximum offering under equity distribution agreement	50
Series B Preferred Unit | Distribution Agreement 2013 [Member]
Maximum offering under equity distribution agreement	100
Series C Preferred Units | Distribution Agreement 2013 [Member]
Maximum offering under equity distribution agreement	$ 75

Subsequent Events (Details)

Subsequent Events (Details) - USD ($) $ in Thousands	Nov. 03, 2016	Oct. 26, 2016	Sep. 30, 2016	Sep. 30, 2015	Dec. 01, 2016	Oct. 03, 2016	May 26, 2016	Dec. 31, 2015
Subsequent Event [Line Items]
Debt amount outstanding			$ 1,883,894					$ 2,313,788
Interest Paid			60,575	$ 47,718
Subsequent Event [Member]
Subsequent Event [Line Items]
Interest Payable						$ 15,000
Long-term Line of Credit, Deficiency	$ 187,500
Percentage of proceeds to be paid to First Lien Lenders		100.00%
Senior Notes due 2020 [Member]
Subsequent Event [Line Items]
Debt amount outstanding			381,830					550,000
Senior Notes due 2020 [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Interest Payable						$ 15,000
Interest Paid		$ 15,100
Senior Notes due 2019 [Member]
Subsequent Event [Line Items]
Debt amount outstanding			51,120					51,120
Senior Notes due 2019 [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Interest Payable					$ 2,100
Senior Secured Reserve-Based Credit Facility
Subsequent Event [Line Items]
Line of Credit, Liquidity Amount			50,000
Debt amount outstanding			1,354,000					$ 1,688,000
Line of Credit Facility, Current Borrowing Capacity			1,325,000				$ 1,780,000
Line of Credit Facility, Periodic Payment			$ 17,500
Long-term Line of Credit, Deficiency							$ 103,500
Senior Secured Reserve-Based Credit Facility | Subsequent Event [Member]
Subsequent Event [Line Items]
Line of Credit Facility, Current Borrowing Capacity	1,100,000
Line of Credit Facility, Periodic Payment	$ 37,500
May 2016 Redetermination [Member] | Senior Secured Reserve-Based Credit Facility | Subsequent Event [Member]
Subsequent Event [Line Items]
Line of Credit Facility, Periodic Payment		29,300
November 2016 Redetermination [Member] | Senior Secured Reserve-Based Credit Facility | Subsequent Event [Member]
Subsequent Event [Line Items]
Line of Credit Facility, Periodic Payment		$ 37,500