Legacy Reserves 10-Q 3 Aug 16 2016 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Aug. 01, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	LEGACY RESERVES LP
Entity Central Index Key	1,358,831
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		72,411,046

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Current assets:
Cash	$ 1,140	$ 2,006
Accounts receivable, net:
Oil and natural gas	35,578	33,944
Joint interest owners	13,752	25,378
Other	2	86
Fair value of derivatives	23,188	63,711
Prepaid expenses and other current assets (Note 1)	7,724	4,334
Total current assets	81,384	129,459
Oil and natural gas properties using the successful efforts method, at cost:
Proved properties	3,307,925	3,485,634
Unproved properties	13,653	13,424
Accumulated depletion, depreciation, amortization and impairment	(2,048,928)	(2,090,102)
Oil and natural gas properties using the successful efforts method, at cost	1,272,650	1,408,956
Other property and equipment, net of accumulated depreciation and amortization of $9,754 and $8,915, respectively	4,048	4,575
Operating rights, net of amortization of $5,161 and $4,953, respectively	1,856	2,064
Fair value of derivatives	30,254	56,373
Other assets	10,109	11,047
Investments in equity method investees	633	646
Total assets	1,400,934	1,613,120
Current liabilities:
Accounts payable	3,722	13,581
Accrued oil and natural gas liabilities	55,086	50,573
Fair value of derivatives	3,047	2,019
Asset retirement obligation	3,496	3,496
Other	7,594	11,424
Total current liabilities	72,945	81,093
Long-term debt	1,173,009	1,427,614
Asset retirement obligation	266,427	282,909
Fair value of derivatives	3,469	0
Other long-term liabilities	1,195	1,181
Total liabilities	1,517,045	1,792,797
Commitments and contingencies
Partners' equity
Limited partners' deficit - 72,055,697 and 68,949,961 units issued and outstanding at June 30, 2016 and December 31, 2015, respectively	(376,260)	(439,811)
General partner's deficit (approximately 0.03%)	(118)	(133)
Total partners' deficit	(116,111)	(179,677)
Total liabilities and partners' deficit	1,400,934	1,613,120
Incentive distribution equity - 100,000 units issued and outstanding at June 30, 2016 and December 31, 2015
Partners' equity
Incentive distribution equity - 100,000 units issued and outstanding at June 30, 2016 and December 31, 2015	30,814	30,814
Series A Preferred equity - 2,300,000 units issued and outstanding at June 30, 2016 and December 31, 2015
Partners' equity
Preferred equity	55,192	55,192
Series B Preferred equity - 7,200,000 units issued and outstanding at June 30, 2016 and December 31, 2015
Partners' equity
Preferred equity	$ 174,261	$ 174,261

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Other property and equipment, accumulated depreciation and amortization	$ 9,754	$ 8,915
Operating rights, amortization	$ 5,161	$ 4,953
Limited partners' equity, units issued (in shares)	72,055,697	68,949,961
Limited partners' equity, units outstanding (in shares)	72,055,697	68,949,961
General partner's equity, percent	0.03%	0.03%
Incentive Distribution Equity
Incentive distribution equity, units issued (in shares)	100,000	100,000
Incentive distribution equity, units outstanding (in shares)	100,000	100,000
Preferred Unit Series A
Preferred equity, units issued (in shares)	2,300,000	2,300,000
Preferred equity, units outstanding (in shares)	2,300,000	2,300,000
Preferred Unit Series B
Preferred equity, units issued (in shares)	7,200,000	7,200,000
Preferred equity, units outstanding (in shares)	7,200,000	7,200,000

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Revenues:
Oil sales	$ 41,272	$ 59,113	$ 71,592	$ 109,409
Natural gas liquids (NGL) sales	3,922	5,729	6,375	9,921
Natural gas sales	28,173	22,959	61,259	50,010
Total revenues	73,367	87,801	139,226	169,340
Expenses:
Oil and natural gas production	44,561	45,220	94,584	94,440
Production and other taxes	3,390	3,986	5,963	8,204
General and administrative	10,993	10,390	20,427	19,259
Depletion, depreciation, amortization and accretion	37,668	36,197	74,627	77,265
Impairment of long-lived assets	0	0	15,447	209,402
(Gain) loss on disposal of assets	(9,141)	(934)	(40,842)	1,007
Total expenses	87,471	94,859	170,206	409,577
Operating loss	(14,104)	(7,058)	(30,980)	(240,237)
Other income (expense):
Interest income	16	176	54	382
Interest expense	(20,302)	(17,760)	(45,478)	(35,552)
Gain on extinguishment of debt	19,998	0	150,802	0
Equity in income (loss) of equity method investees	(9)	24	(14)	103
Net gains (losses) on commodity derivatives	(37,675)	(13,497)	(20,637)	6,983
Other	(98)	97	(192)	702
Income (loss) before income taxes	(52,174)	(38,018)	53,555	(267,619)
Income tax (expense) benefit	(87)	(456)	(487)	291
Net income (loss)	(52,261)	(38,474)	53,068	(267,328)
Distributions to preferred unitholders	(4,750)	(4,750)	(8,708)	(9,500)
Net income (loss) attributable to unitholders	$ (57,011)	$ (43,224)	$ 44,360	$ (276,828)
Income (loss) per unit - basic & diluted (in dollars per share)	$ (0.81)	$ (0.63)	$ 0.64	$ (4.02)
Weighted average number of units used in computing net income (loss) per unit -
Basic and diluted (in shares)	70,071	68,897	69,518	68,909

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Partners' Equity (Unaudited) - 6 months ended Jun. 30, 2016 - USD ($) shares in Thousands, $ in Thousands	Total	Preferred EquitySeries A Preferred Equity	Preferred EquitySeries B Preferred Equity	Incentive Distribution Equity	Unitholders' EquityLimited Partner	Unitholders' EquityGeneral Partner
Unitholders equity, beginning balance (in units) at Dec. 31, 2015		2,300	7,200	100	68,950
Unitholders equity, beginning balance at Dec. 31, 2015	$ (179,677)	$ 55,192	$ 174,261	$ 30,814	$ (439,811)	$ (133)
Increase (Decrease) in Partners' Capital [Roll Forward]
Units issued to Legacy Board of Directors for services	614				$ 614
Units issued to Legacy Board of Directors for services (in units)					237
Unit-based compensation	3,275				$ 3,275
Vesting of restricted and phantom units (in units)					150
Units issued in exchange for retirement of debt (in units)					2,719
Units issued in exchange for Senior Notes	6,609				$ 6,609
Net income	53,068				$ 53,053	15
Unitholders equity, ending balance (in units) at Jun. 30, 2016		2,300	7,200	100	72,056
Unitholders equity, ending balance at Jun. 30, 2016	$ (116,111)	$ 55,192	$ 174,261	$ 30,814	$ (376,260)	$ (118)

Condensed Consolidated Stateme6

Condensed Consolidated Statement of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash flows from operating activities:
Net income (loss)	$ 53,068	$ (267,328)
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
Depletion, depreciation, amortization and accretion	74,627	77,265
Amortization of debt discount and issuance costs	6,975	2,680
Gain on extinguishment of debt	(150,802)	0
Impairment of long-lived assets	15,447	209,402
(Gain) loss on derivatives	26,269	(8,078)
Equity in (income) loss of equity method investees	14	(103)
Distribution from equity method investee	0	191
Unit-based compensation	4,003	3,174
(Gain) loss on disposal of assets	(40,842)	1,007
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, oil and natural gas	(1,634)	8,155
Decrease in accounts receivable, joint interest owners	11,626	3,811
(Increase) decrease in accounts receivable, other	84	(17)
Increase in other assets	(2,452)	(241)
Decrease in accounts payable	(9,859)	(1,368)
Increase (decrease) in accrued oil and natural gas liabilities	4,513	(23,948)
Decrease in other liabilities	(5,663)	(4,396)
Total adjustments	(67,694)	267,534
Net cash provided by (used in) operating activities	(14,626)	206
Cash flows from investing activities:
Investment in oil and natural gas properties	(14,103)	(23,704)
Proceeds from sale of assets	87,475	740
Investment in other equipment	(312)	(181)
Net cash settlements received on commodity derivatives	44,871	77,526
Net cash provided by investing activities	117,931	54,381
Cash flows from financing activities:
Proceeds from long-term debt	81,000	155,000
Payments of long-term debt	(181,402)	(129,000)
Payments of debt issuance costs	(3,769)	(1,475)
Proceeds from the issuance of units, net	0	(71)
Distributions to unitholders	0	(76,105)
Net cash used in financing activities	(104,171)	(51,651)
Net increase (decrease) in cash and cash equivalents	(866)	2,936
Cash, beginning of period	2,006	725
Cash, end of period	1,140	3,661
Non-cash investing and financing activities:
Asset retirement obligations associated with properties sold	(21,664)	(4,553)
Asset retirement obligations associated with property acquisitions	0	18,756
Units acquired in exchange for equity method investee interest	0	1,349
Units issued in exchange for outstanding Senior Notes	$ (6,607)	$ 0

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies (a) Organization, Basis of Presentation and Description of Business Legacy Reserves LP ("LRLP," "Legacy" or the "Partnership") and, unless the context indicates otherwise, its affiliated entities, are referred to as Legacy in these financial statements. The accompanying condensed consolidated financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred. These condensed consolidated financial statements as of June 30, 2016 and for the three and six months ended June 30, 2016 and 2015 are unaudited. In the opinion of management, such financial statements include the adjustments and accruals, all of which are of a normal recurring nature, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year. Certain information and footnote disclosures normally included in the financial statements prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). These condensed consolidated financial statements should be read in connection with the consolidated financial statements and notes thereto included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015 . LRLP, a Delaware limited partnership, was formed by its general partner, Legacy Reserves GP, LLC (“LRGPLLC”), on October 26, 2005 to own and operate oil and natural gas properties. LRGPLLC is a Delaware limited liability company formed on October 26, 2005, and owns an approximate 0.03% general partner interest in LRLP. Significant information regarding rights of unitholders includes the following: • Right to receive, within 45 days after the end of each quarter, distributions of available cash, if distributions are declared. • No limited partner shall have any management power over LRLP’s business and affairs; the general partner shall conduct, direct and manage LRLP’s activities. • The general partner may be removed if such removal is approved by the unitholders holding at least 66 2/3 percent of the outstanding units, including units held by LRGPLLC and its affiliates, provided that a unit majority has elected a successor general partner. • Right to receive information reasonably required for tax reporting purposes within 90 days after the close of the calendar year. In the event of liquidation, after making required payments to Legacy's preferred unitholders, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and LRGPLLC in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of Legacy’s assets in liquidation. Legacy owns and operates oil and natural gas producing properties located primarily in the Permian Basin (West Texas and Southeast New Mexico), East Texas, Rocky Mountain and Mid-Continent regions of the United States. (b) Accrued Oil and Natural Gas Liabilities Below are the components of accrued oil and natural gas liabilities as of June 30, 2016 and December 31, 2015 : June 30, December 31, (In thousands) Revenue payable to joint interest owners $ 23,493 $ 15,253 Accrued lease operating expense 15,070 19,007 Accrued capital expenditures 2,180 2,881 Accrued ad valorem tax 9,137 8,723 Other 5,206 4,709 $ 55,086 $ 50,573 (c) Restricted Cash Restricted cash on our Balance Sheet as of June 30, 2016 is recorded as $2.9 million in the "Prepaid expenses and other current assets" line. The restricted cash amounts represent various deposits to secure the performance of contracts, surety bonds and other obligations incurred in the ordinary course of business. There was no restricted cash recorded at December 31, 2015. (d) Recent Accounting Pronouncements In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2016-02, "Leases" ("ASU 2016-02"). ASU 2016-02 establishes a right-of-use (ROU) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. We are currently evaluating the impact of our pending adoption of ASU 2016-02 on our consolidated financial statements. In August 2014, the FASB issued Accounting Standards Update No. 2014-15, "Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern" (“ASU 2014-15”). ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU 2014-15 and do not anticipate any impact on our consolidated financial statements. In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers" ("ASU 2014-09"), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing U.S. GAAP. In August 2015, the FASB issued ASU No. 2015-14, "Revenue from Contracts with Customers" ("ASU 2015-14"), which approved a one-year delay of the standard's effective date. In accordance with ASU 2015-14, the standard is now effective for annual periods beginning after December 15, 2017, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are currently evaluating the impact of our pending adoption of ASU 2014-09 on our consolidated financial statements and do not anticipate the standard will have a material impact on our consolidated financial statements. (e) 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 2—Long-Term Debt for further discussion regarding this reclassification.

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt consists of the following as of June 30, 2016 and December 31, 2015 : June 30, December 31, 2016 2015 (In thousands) Credit Facility due 2019 $ 533,000 $ 608,000 8% Senior Notes due 2020 232,989 300,000 6.625% Senior Notes due 2021 432,656 550,000 1,198,645 1,458,000 Unamortized discount on Senior Notes (12,916 ) (17,604 ) Unamortized debt issuance costs (a) (12,720 ) (12,782 ) Total Long-Term Debt $ 1,173,009 $ 1,427,614 _______________ (a) In order to comply with Accounting Standards Update No. 2015-03, unamortized debt issuance costs are now recorded as a direct deduction from the carrying amount of debt. As such, 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 retained earnings. Credit Facility On April 1, 2014, Legacy entered into a five -year $1.5 billion secured revolving credit facility with Wells Fargo Bank, National Association, as administrative agent, Compass Bank, as syndication agent, UBS Securities LLC and U.S. Bank National Association, as co-documentation agents and the lenders party thereto (the “Current Credit Agreement”). Borrowings under the Current Credit Agreement mature on April 1, 2019. Legacy's obligations under the Current Credit Agreement are secured by mortgages on over 90% of the total value of its oil and natural gas properties as well as a pledge of all of its ownership interests in its operating subsidiaries. The amount available for borrowing at any one time is limited to the borrowing base and contains a $2 million sub-limit for letters of credit. The borrowing base is currently set at $630 million . The borrowing base is subject to semi-annual redeterminations on or about April 1 and October 1 of each year with the next redetermination scheduled for October 2016. Additionally, either Legacy or the lenders may, once during each calendar year, elect to redetermine the borrowing base between scheduled redeterminations. Legacy also has the right, once during each calendar year, to request the redetermination of the borrowing base upon the proposed acquisition of certain oil and natural gas properties where the purchase price is greater than 10% of the borrowing base then in effect. Any increase in the borrowing base requires the consent of all the lenders and any decrease in or maintenance of the borrowing base must be approved by the lenders holding at least 66-2/3% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the Current Credit Agreement. If the requisite lenders do not agree on an increase or decrease, then the borrowing base will be the highest borrowing base acceptable to the lenders holding 66-2/3% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the Current Credit Agreement so long as it does not increase the borrowing base then in effect. Our Current Credit Agreement also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows: • first lien debt to EBITDA for the four fiscal quarters ending on last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available to be less than: (i) 3.50 to 1.00, at any time during the period from and including February 19, 2016 through December 31, 2016, (ii) 3.25 to 1.00, at any time during the fiscal quarter ending March 31, 2017, (iii) 3.00 to 1.00, at any time during the fiscal quarter ending June 30, 2017 and (iv) 2.50 to 1.00, at any time on or after July 1, 2017; • as of the last day of the most recent quarter, total EBITDA over the last four quarters to total Interest Expense over the last four quarters to be greater than (i) 2.50 to 1.00 for the fiscal quarters ending December 31, 2015 and March 31, 2016, (ii) 2.00 to 1.00 for the fiscal quarters ending June 30, 2016, September 30, 2016, December 31, 2016, March 31, 2017 and June 30, 2017 and (iii) 2.50 to 1.00 for each fiscal quarter ending on or after September 30, 2017; and • consolidated current assets, as of the last day of the most recent quarter and including the unused amount of the total commitments, to consolidated current liabilities as of the last day of the most recent quarter of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under ASC 815, which includes the current portion of oil, natural gas and interest rate derivatives. As of June 30, 2016 , Legacy was in compliance with all financial and other covenants of the Current Credit Agreement. Depending on oil and natural gas prices in 2016, Legacy could breach certain financial covenants under its revolving credit facility, which would constitute a default under its revolving credit facility. Such default, if not remedied, would require a waiver from Legacy's lenders in order for it to avoid an event of default and subsequent acceleration of all amounts outstanding under its revolving credit facility and potential foreclosure on its oil and natural gas properties. If the lenders under Legacy's revolving credit facility were to accelerate the indebtedness under its revolving credit facility as a result of a default, such acceleration could cause a cross-default of all of its other outstanding indebtedness, including its 8% Senior Notes due 2020 (the "2020 Senior Notes") and its 6.625% Senior Notes due 2021 (the "2021 Senior Notes" and, together with the 2020 Senior Notes, the “Senior Notes”), and permit the holders of such indebtedness to accelerate the maturities of such indebtedness. While no assurances can be made that, in the event of a covenant breach, such a waiver will be granted, Legacy believes the long-term global outlook for commodity prices and its efforts to date, which include the suspension of distributions to its unitholders and holders of both its 8% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the "Series A Preferred Units") and its 8.00% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the "Series B Preferred Units" and, together with the Series A Preferred Units, the “Preferred Units”), as well as asset sales completed as of the date of this filing, will be viewed positively by its lenders. As of June 30, 2016 , Legacy had approximately $533.0 million drawn under the Current Credit Agreement at a weighted-average interest rate of 3.22% , leaving approximately $95.6 million of availability under the Current Credit Agreement. For the six -month period ended June 30, 2016 , Legacy paid in cash $9.3 million of interest expense on the Current Credit Agreement. 8% Senior Notes Due 2020 On December 4, 2012, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of $300 million of its 2020 Senior Notes, which were subsequently registered through a public exchange offer that closed on January 8, 2014. The 2020 Senior Notes were issued at 97.848% of par. Legacy will have the option to redeem the 2020 Senior Notes, in whole or in part, at any time on or after December 1, 2016, at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption if redeemed during the twelve-month period beginning on December 1 of the years indicated below. Year Percentage 2016 104.000 % 2017 102.000 % 2018 and thereafter 100.000 % Prior to December 1, 2016, Legacy may redeem all or any part of the 2020 Senior Notes at the “make-whole” redemption price as defined in the indenture. Legacy may be required to offer to repurchase the 2020 Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. Legacy's and Legacy Reserves Finance Corporation's obligations under the 2020 Senior Notes are guaranteed by its 100% owned subsidiaries Legacy Reserves Operating GP LLC, Legacy Reserves Operating LP and Legacy Reserves Services, Inc., Legacy Reserves Energy Services LLC, Dew Gathering LLC and Pinnacle Gas Treating LLC, which constitute all of Legacy's wholly-owned subsidiaries other than Legacy Reserves Finance Corporation. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the properties of the guarantor; (ii) in connection with any sale or other disposition of sufficient capital stock of the guarantor so that it no longer qualifies as our Restricted Subsidiary (as defined in the indenture); (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of the guarantor provided no default or event of default has occurred or is occurring; (vi) at such time the guarantor does not have outstanding guarantees of its, or any other guarantor's, other, debt; or (vii) upon merging into, or transferring all of its properties to Legacy or another guarantor and ceasing to exist. Refer to Note 11 - Subsidiary Guarantors for further details on Legacy's guarantors. The indenture governing the 2020 Senior Notes limits Legacy's ability and the ability of certain of its subsidiaries to (i) sell assets; (ii) pay distributions on, repurchase or redeem equity interests or purchase or redeem Legacy's subordinated debt, provided that such subsidiaries may pay dividends to the holders of their equity interests (including Legacy) and Legacy may pay distributions to the holders of its equity interests subject to the absence of certain defaults, the satisfaction of a fixed charge coverage ratio test and so long as the amount of such distributions does not exceed the sum of available cash (as defined in the partnership agreement) at Legacy, net proceeds from the sales of certain securities and return of or reductions to capital from restricted investments; (iii) make certain investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from certain of its subsidiaries to Legacy; (vii) consolidate, merge or transfer all or substantially all of Legacy's assets; (viii) engage in certain transactions with affiliates; (ix) create unrestricted subsidiaries; and (x) engage in certain business activities. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 2020 Senior Notes are rated investment grade by each of Moody's Investors Service, Inc. and Standard & Poor's Ratings Services and no Default (as defined in the indenture) has occurred and is continuing, many of such covenants will terminate and Legacy and its subsidiaries will cease to be subject to such covenants. The indenture also includes customary events of default. The Partnership is in compliance with all financial and other covenants of the 2020 Senior Notes. However, if the lenders under Legacy's Current Credit Agreement were to accelerate the indebtedness under Legacy's Current Credit Agreement as a result of a default, such acceleration could cause a cross-default of all of the 2020 Senior Notes and permit the holders of such notes to accelerate the maturities of such indebtedness. Interest is payable on June 1 and December 1 of each year. During the six months ended June 30, 2016 , Legacy repurchased a face amount of $52.0 million of its 2020 Senior Notes on the open market. Legacy treated these repurchases as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2020 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the repurchase price. On June 1, 2016, Legacy exchanged 2,719,124 units representing limited partner interests in the Partnership for $15.0 million of face amount of its outstanding 2020 Senior Notes. Legacy treated this exchange as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2020 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the fair value of the units issued in the exchange based on the closing price on June 1, 2016. 6.625% Senior Notes Due 2021 On May 28, 2013, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of $250 million of its 2021 Senior Notes, which were subsequently registered through a public exchange offer that closed on March 18, 2014. The 2021 Senior Notes were issued at 98.405% of par. On May 13, 2014, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of an additional $300 million of the 6.625% 2021 Senior Notes, which were subsequently registered through a public exchange offer that closed on February 10, 2015. These 2021 Senior Notes were issued at 99.0% of par. The terms of the 2021 Senior Notes, including details related to our guarantors, are substantially identical to the terms of the 2020 Senior Notes with the exception of the interest rate and redemption provisions noted below. Legacy will have the option to redeem the 2021 Senior Notes, in whole or in part, at any time on or after June 1, 2017, at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption if redeemed during the twelve-month period beginning on June 1 of the years indicated below. Year Percentage 2017 103.313 % 2018 101.656 % 2019 and thereafter 100.000 % Prior to June 1, 2017, Legacy may redeem all or any part of the 2021 Senior Notes at the “make-whole” redemption price as defined in the indenture. In addition, prior to June 1, 2016, Legacy may at its option, redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes at the redemption price of 106.625% with the net proceeds of a public or private equity offering. Legacy may be required to offer to repurchase the 2021 Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. The Partnership is in compliance with all financial and other covenants of the 2021 Senior Notes. However, if the lenders under Legacy's Current Credit Agreement were to accelerate the indebtedness under Legacy's Current Credit Agreement as a result of a default, such acceleration could cause a cross-default of all of the 2021 Senior Notes and permit the holders of such notes to accelerate the maturities of such indebtedness. Interest is payable on June 1 and December 1 of each year. During the six months ended June 30, 2016 , Legacy repurchased a face amount of $117.3 million of its 2021 Senior Notes on the open market. Legacy treated these repurchases as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2021 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the repurchase price.

Acquisitions

Acquisitions	6 Months Ended
	Jun. 30, 2016
Business Combinations [Abstract]
Acquisitions	Acquisitions On July 31, 2015, Legacy purchased (1) 100% of the issued and outstanding limited liability company membership interests in Dew Gathering LLC, which owns directly and indirectly natural gas gathering and processing assets in Anderson, Freestone, Houston, Leon, Limestone and Robertson Counties, Texas (the "WGR Acquisition") from WGR Operating LP ("WGR") for a net purchase price of $96.7 million , and (2) various oil and natural gas properties and associated exploration and production assets (the "Anadarko E&P Acquisition," together with the WGR Acquisition, the "Anadarko Acquisitions") from Anadarko E&P Onshore LLC ("Anadarko") for a net purchase price of $337.2 million . The Anadarko Acquisitions were accounted for as a business combination. The allocation of the Anadarko Acquisitions purchase price to the fair value of the acquired assets and liabilities assumed was as follows (in thousands): Proved oil and natural gas properties including related equipment $ 461,306 Future abandonment costs (27,351 ) Fair value of net assets acquired $ 433,955 Pro Forma Operating Results The following table reflects the unaudited pro forma results of operations as though the Anadarko Acquisitions had occurred on January 1, 2014. The pro forma amounts are not necessarily indicative of the results that may be reported in the future and do not include any adjustments for acquisition related expenses. Three Months Ended June 30, Six Months Ended June 30, 2015 2015 Revenues $ 119,416 $ 233,877 Net loss attributable to unitholders $ (29,151 ) $ (247,638 ) Loss per unit — basic and diluted $ (0.42 ) $ (3.59 ) Units used in computing loss per unit: Basic and diluted 68,897 68,909 The amounts of revenues and revenues in excess of direct operating expenses included in our consolidated statements of operations for the Anadarko Acquisitions are shown in the table that follows. Direct operating expenses include lease operating expenses and production and other taxes. Three Months Ended June 30, Six Months Ended June 30, 2016 2016 (In thousands) Anadarko Acquisitions Revenues $ 10,387 $ 21,865 Excess of revenues over direct operating expenses $ 4,362 $ 8,518

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Blue Quail Energy Services, LLC (“Blue Quail”), a company specializing in water transfer services, is an affiliate of Moriah Energy Services LLC, an entity which Cary D. Brown and Dale A. Brown, both directors of Legacy, are principals. Legacy has contracted with Blue Quail to provide water transfer services and paid $82,587 and $93,193 in the six month periods ended June 30, 2016 and June 30, 2015 , respectively, to Blue Quail for such services. Blue Quail charged Legacy prices consistent with that of other vendors for services rendered.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies From time to time Legacy is a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, Legacy is not currently a party to any proceeding that it believes could have a potential material adverse effect on its financial condition, results of operations or cash flows. Legacy is party to a contractual agreement, extending through 2022, to purchase CO 2 volumes from a third party. The contract requires Legacy to purchase minimum annual volumes, the pricing of which is calculated as a percentage of NYMEX-WTI oil prices, with a floor of $57.14 . Based upon the minimum required volumes and the NYMEX-WTI strip prices as of June 30, 2016 , we estimate the value of our total future obligation through the term of the agreement to be approximately $50.5 million . Legacy is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of Legacy could be adversely affected. Legacy has employment agreements with its officers that specify that if the officer is terminated by Legacy for other than cause or following a change in control, the officer shall receive severance pay ranging from 24 to 36 months salary plus bonus and COBRA benefits, respectively.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements Fair value is defined as the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories: Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Legacy considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that Legacy values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity price swaps and collars and interest rate swaps as well as long-term incentive plan liabilities calculated using the Black-Scholes model to estimate the fair value as of the measurement date. Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). Legacy’s valuation models are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 instruments currently are limited to Midland-Cushing crude oil differential swaps. Although Legacy utilizes third party broker quotes to assess the reasonableness of its prices and valuation techniques, Legacy does not have sufficient corroborating evidence to support classifying these assets and liabilities as Level 2. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Legacy’s 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. Fair Value on a Recurring Basis The following table sets forth by level within the fair value hierarchy Legacy’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2016 : Fair Value Measurements at June 30, 2016 Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Total Carrying Value as of Description (Level 1) (Level 2) (Level 3) June 30, 2016 (In thousands) LTIP liability (a) $ — $ (113 ) $ — $ (113 ) Oil and natural gas derivatives — 54,210 (1,290 ) 52,920 Interest rate swaps — (5,994 ) — (5,994 ) Total $ — $ 48,103 $ (1,290 ) $ 46,813 (a) See Note 10 for further discussion on unit-based compensation expenses and the related Long-Term Incentive Plan ("LTIP") liability for certain grants accounted for under the liability method. Legacy estimates the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate for those commodities for which published forward pricing is readily available. For those commodity derivatives for which forward commodity price curves are not readily available, Legacy estimates, with the assistance of third-party pricing experts, the forward curves as of the date of the estimate. Legacy validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming, where applicable, that those securities trade in active markets. Legacy estimates the option value of puts and calls combined into hedges, including three-way collars and enhanced swaps, using an option pricing model which takes into account market volatility, market prices, contract parameters and discount rates based on published London interbank offered rates ("LIBOR") and interest rate swaps. Due to the lack of an active market for periods beyond one-month from the balance sheet date for its oil price differential swaps, Legacy has reviewed historical differential prices and known economic influences to estimate a reasonable forward curve of future pricing scenarios based upon these factors. In order to estimate the fair value of our interest rate swaps, Legacy uses a yield curve based on money market rates and interest rate swaps, extrapolates a forecast of future interest rates, estimates each future cash flow, derives discount factors to value the fixed and floating rate cash flows of each swap, and then discounts to present value all known (fixed) and forecasted (floating) swap cash flows. Curve building and discounting techniques used to establish the theoretical market value of interest bearing securities are based on readily available money market rates and interest swap market data. The determination of the fair values above incorporates various factors including the impact of our non-performance risk and the credit standing of the counterparties involved in the Partnership’s derivative contracts. The risk of nonperformance by the Partnership’s counterparties is mitigated by the fact that most of our current counterparties (or their affiliates) are also current or former bank lenders under the Partnership’s revolving credit facility. In addition, Legacy routinely monitors the creditworthiness of its counterparties. As the factors described above are based on significant assumptions made by management, these assumptions are the most sensitive to change. The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy: Significant Unobservable Inputs (Level 3) Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (In thousands) Beginning balance $ (2,828 ) $ (2,485 ) $ (4,493 ) $ 555 Total gains (losses) 888 (3,275 ) 899 (6,632 ) Settlements, net 650 949 2,304 1,266 Ending balance $ (1,290 ) $ (4,811 ) $ (1,290 ) $ (4,811 ) Gains (losses) included in earnings relating to derivatives still held as of June 30, 2016 and 2015 $ 581 $ (3,492 ) $ 978 $ (4,811 ) During periods of market disruption, including periods of volatile oil and natural gas prices, rapid credit contraction or illiquidity, it may be difficult to value certain of the Partnership's derivative instruments if trading becomes less frequent and/or market data becomes less observable. There may be certain asset classes that were previously in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments may fall to Level 3 and thus require more subjectivity and management judgment. As such, valuations may include inputs and assumptions that are less observable or require greater estimation as well as valuation methods which are more sophisticated or require greater estimation thereby resulting in valuations with less certainty. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within Legacy's consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on Legacy's results of operations or financial condition Fair Value on a Non-Recurring Basis Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; measurements of oil and natural gas property impairments; and the initial recognition of asset retirement obligations ("ARO") for which fair value is used. These ARO estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, Legacy has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of Legacy’s asset retirement obligation is presented in Note 8. Nonrecurring fair value measurements of proved oil and natural gas properties during the six -month period ended June 30, 2016 consist of: Fair Value Measurements During the Six Months Ended June 30, 2016 Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description (Level 1) (Level 2) (Level 3) (In thousands) Assets: Impairment (a) $ — $ — $ 19,783 (a) Legacy periodically reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. During the six -month period ended June 30, 2016 , Legacy incurred impairment charges of $15.4 million as oil and natural gas properties with a net cost basis of $35.2 million were written down to their fair value of $19.8 million . In order to determine whether the carrying value of an asset is recoverable, Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If the net capitalized cost exceeds the undiscounted future net cash flows, Legacy writes the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets. The carrying amount of the revolving long-term debt of $533 million as of June 30, 2016 approximates fair value because Legacy's current borrowing rate does not materially differ from market rates for similar bank borrowings. Legacy has classified the revolving long-term debt as a Level 2 item within the fair value hierarchy. As of June 30, 2016 , the fair values of the 2020 Senior Notes and the 2021 Senior Notes were $111.6 million and $182.8 million , respectively. As these valuations are based on unadjusted quoted prices in an active market, the fair values are classified as Level 1 items within the fair value hierarchy.

Derivative Financial Instrument

Derivative Financial Instruments	6 Months Ended
	Jun. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	Derivative Financial Instruments Commodity derivative transactions Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps, enhanced swaps or collars) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from increases in the prices of oil and natural gas, it also reduces Legacy’s potential exposure to adverse price movements. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas prices and limit Legacy’s potential gains from future increases in prices. None of these instruments are used for trading or speculative purposes and required no upfront or deferred cash premium paid or payable to our counterparty. All of these price risk management transactions are considered derivative instruments . These derivative instruments are intended to reduce Legacy’s price risk and may be considered hedges for economic purposes, but Legacy has chosen not to designate them as cash flow hedges for accounting purposes. Therefore, all derivative instruments are recorded on the balance sheet at fair value with changes in fair value being recorded in current period earnings. By using derivative instruments to mitigate exposures to changes in commodity prices, Legacy exposes itself 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 Legacy, which creates credit risk. Legacy minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties, all of whom are current or former members of Legacy's lending group. The following table sets forth a reconciliation of the changes in fair value of Legacy's commodity derivatives for the three and six months ended June 30, 2016 and 2015 : Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (In thousands) Beginning fair value of commodity derivatives $ 112,688 $ 133,242 $ 118,427 $ 153,099 Total gain (loss) - oil derivatives (5,411 ) (12,649 ) (2,892 ) 945 Total gain (loss) - natural gas derivatives (32,264 ) (848 ) (17,745 ) 6,038 Crude oil derivative cash settlements received (9,760 ) (27,364 ) (22,345 ) (59,564 ) Natural gas derivative cash settlements received (12,333 ) (9,825 ) (22,525 ) (17,962 ) Ending fair value of commodity derivatives $ 52,920 $ 82,556 $ 52,920 $ 82,556 Certain of our commodity derivatives and interest rate derivatives are presented on a net basis on the Consolidated Balance Sheets. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets as of the dates indicated below (in thousands): June 30, 2016 Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Offsetting Derivative Assets: (In thousands) Commodity derivatives $ 85,562 $ (32,120 ) $ 53,442 Total derivative assets $ 85,562 $ (32,120 ) $ 53,442 Offsetting Derivative Liabilities: Commodity derivatives $ (32,642 ) $ 32,120 $ (522 ) Interest rate derivatives (5,994 ) — (5,994 ) Total derivative liabilities $ (38,636 ) $ 32,120 $ (6,516 ) December 31, 2015 Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Offsetting Derivative Assets: (In thousands) Commodity derivatives $ 177,082 $ (58,655 ) $ 118,427 Interest rate derivatives 1,982 (325 ) 1,657 Total derivative assets $ 179,064 $ (58,980 ) $ 120,084 Offsetting Derivative Liabilities: Commodity derivatives $ (58,655 ) $ 58,655 $ — Interest rate derivatives (2,344 ) 325 (2,019 ) Total derivative liabilities $ (60,999 ) $ 58,980 $ (2,019 ) As of June 30, 2016 , Legacy had the following NYMEX West Texas Intermediate ("WTI") crude oil swaps paying floating prices and receiving fixed prices for a portion of its future oil production as indicated below: Average Price Time Period Volumes (Bbls) Price per Bbl Range per Bbl July-December 2016 1,002,800 $55.24 $50.15 - $91.00 2017 182,500 $84.75 $84.75 As of June 30, 2016 , Legacy had the following Midland-to-Cushing crude oil differential swaps paying a floating differential and receiving a fixed differential for a portion of its future oil production as indicated below: Average Price Time Period Volumes (Bbls) Price per Bbl Range per Bbl July-December 2016 1,472,000 $(1.60) $(1.50) - $(1.75) 2017 2,190,000 $(0.30) $(0.05) - $(0.75) As of June 30, 2016 , Legacy had the following NYMEX WTI crude oil derivative three-way collar contracts that combine a long and short put with a short call as indicated below: Average Short Average Long Average Short Time Period Volumes (Bbls) Put Price per Bbl Put Price per Bbl Call Price per Bbl July-December 2016 230,000 $60.00 $85.00 $102.46 2017 72,400 $60.00 $85.00 $104.20 As of June 30, 2016 , Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put and long put with a fixed-price swap as indicated below: Average Long Average Short Average Time Period Volumes (Bbls) Put Price per Bbl Put Price per Bbl Swap Price per Bbl July-December 2016 92,000 $57.00 $82.00 $91.70 2017 182,500 $57.00 $82.00 $90.85 2018 127,750 $57.00 $82.00 $90.50 As of June 30, 2016 , Legacy had the following NYMEX Henry Hub and West Texas Waha natural gas swaps paying floating natural gas prices and receiving fixed prices for a portion of its future natural gas production as indicated below: Average Price Time Period Volumes (MMBtu) Price per MMBtu Range per MMBtu July-December 2016 24,973,600 $3.01 $2.42 - $5.30 2017 27,600,000 $3.36 $3.29 - $3.39 2018 27,600,000 $3.36 $3.29 - $3.39 2019 25,800,000 $3.36 $3.29 - $3.39 As of June 30, 2016 , Legacy had the following NYMEX Henry Hub natural gas derivative three-way collar contracts that combine a long put, a short put and a short call as indicated below: Average Short Put Average Long Put Average Short Call Time Period Volumes (MMBtu) Price per MMBtu Price per MMBtu Price per MMBtu July-December 2016 2,790,000 $3.75 $4.25 $5.08 2017 5,040,000 $3.75 $4.25 $5.53 As of June 30, 2016 , Legacy had the following Henry Hub NYMEX to Northwest Pipeline, California SoCal NGI and San Juan Basin natural gas differential swaps paying a floating differential and receiving a fixed differential for a portion of its future natural gas production as indicated below: July-December 2016 2017 Average Average Volumes (MMBtu) Price per MMBtu Volumes (MMBtu) Price per MMBtu NWPL 7,529,832 $(0.19) 7,300,000 $(0.16) SoCal — $— 2,500,250 $0.11 San Juan 1,256,720 $(0.16) 2,500,250 $(0.10) Interest rate derivative transactions Due to the volatility of interest rates, Legacy periodically enters into interest rate risk management transactions in the form of interest rate swaps for a portion of its outstanding debt balance. These transactions allow Legacy to reduce exposure to interest rate fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from decreases in interest rates, it also reduces Legacy’s potential exposure to increases in interest rates. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its outstanding debt balance, provide only partial protection against interest rate increases and limit Legacy’s potential savings from future interest rate declines. It is never management’s intention to hold or issue derivative instruments for speculative trading purposes. Conditions sometimes arise where actual borrowings are less than notional amounts hedged, which has, and could result in overhedged amounts. Legacy accounts for these interest rate swaps at fair value and included in the consolidated balance sheet as assets or liabilities. Legacy does not designate these derivatives as cash flow hedges, even though they reduce its exposure to changes in interest rates. Therefore, the mark-to-market of these instruments is recorded in current earnings as a component of interest expense. The total impact on interest expense from the mark-to-market and settlements was as follows: Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (In thousands) Beginning fair value of interest rate swaps $ (4,695 ) $ (1,540 ) $ (362 ) $ (2,080 ) Total loss on interest rate swaps (1,977 ) (143 ) (7,049 ) (291 ) Cash settlements paid 678 698 1,417 1,386 Ending fair value of interest rate swaps $ (5,994 ) $ (985 ) $ (5,994 ) $ (985 ) The table below summarizes the interest rate swap position as of June 30, 2016 : Weighted Average Estimated Fair Value at Notional Amount Fixed Rate Effective Date Maturity Date June 30, 2016 (Dollars in thousands) $ 115,000 0.850 % 9/1/2015 9/1/2017 $ (1,588 ) $ 235,000 1.363 % 9/1/2015 9/1/2019 (4,406 ) Total fair value of interest rate derivatives $ (5,994 )

Asset Retirement Obligation

Asset Retirement Obligation	6 Months Ended
	Jun. 30, 2016
Asset Retirement Obligation [Abstract]
Asset Retirement Obligation	Asset Retirement Obligation AROs associated with the retirement of a tangible long-lived asset are recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at Legacy’s credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset. The following table reflects the changes in the ARO during the six months ended June 30, 2016 and year ended December 31, 2015 : June 30, December 31, (In thousands) Asset retirement obligation - beginning of period $ 286,405 $ 226,525 Liabilities incurred with properties acquired — 60,526 Liabilities incurred with properties drilled — 92 Liabilities settled during the period (1,172 ) (2,615 ) Liabilities associated with properties sold (21,664 ) (9,386 ) Current period accretion 6,354 11,263 Asset retirement obligation - end of period $ 269,923 $ 286,405

Partners' Equity

Partners' Equity	6 Months Ended
	Jun. 30, 2016
Equity [Abstract]
Partners' Equity	Partners' Equity Preferred Units On April 17, 2014, Legacy issued 2,000,000 of its Series A Preferred Units in a public offering at a price of $25.00 per unit. On May 12, 2014 Legacy issued an additional 300,000 Series A Preferred Units pursuant to the underwriters’ option to purchase additional Series A Preferred Units. On June 17, 2014, Legacy issued 7,000,000 of its Series B Preferred Units in a public offering at a price of $25.00 per unit. On July 1, 2014, the underwriters exercised their over-allotment option to purchase an additional 200,000 Series B Preferred Units. Distributions on the Preferred Units are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of the Partnership's general partner. Distributions on the Series A Preferred Units will be payable from, and including, the date of the original issuance to, but not including April 15, 2024 at an initial rate of 8.00% per annum of the stated liquidation preference. Distributions on the Series B Preferred Units will be payable from, and including, the date of the original issuance to, but not including June 15, 2024 at an initial rate of 8.00% per annum of the stated liquidation preference. Distributions accruing on and after April 15, 2024 for the Series A Preferred Units and June 15, 2024 for the Series B Preferred Units will accrue at an annual rate equal to the sum of (a) three-month LIBOR as calculated on each applicable date of determination and (b) 5.24% for Series A and 5.26% for Series B, based on the $25.00 liquidation preference per preferred unit. At any time on or after April 15, 2019 or June 15, 2019, Legacy may redeem the Series A Preferred Units or Series B Preferred Units, respectively, in whole or in part at a redemption price of $25.00 per Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon through and including the date of redemption, whether or not declared. Legacy may also redeem the Preferred Units in the event of a Change of Control. The Series A Preferred Units and the Series B Preferred Units trade on NASDAQ under the symbols "LGCYP" and "LGCYO,” respectively. On January 21, 2016, Legacy announced that its general partner suspended monthly cash distributions for both its Series A Preferred Units and its Series B Preferred Units. As of June 30, 2016 , $0.92 of distributions per unit were in arrears, representing a total cumulative arrearage of approximately $8.7 million . Incentive Distribution Units On June 4, 2014, Legacy issued 300,000 Incentive Distribution Units representing limited partner interests in the Partnership (the "Incentive Distribution Units") to WPX Energy Rocky Mountain, LLC (“WPX”) as part of Legacy’s purchase of a non-operated interest in oil and natural gas properties located in the Piceance Basin in Garfield County, Colorado from WPX on June 4, 2014 (the “WPX Acquisition”). The Incentive Distribution Units issued to WPX include 100,000 Incentive Distribution Units that immediately vested along with the ability to vest in up to an additional 200,000 Incentive Distribution Units (the “Unvested IDUs”) in connection with any future asset sales or transactions completed with Legacy. Incentive Distribution Units that are not issued to WPX or other parties will remain in Legacy's treasury for the benefit of all limited partners until such time as Legacy may make future issuances of Incentive Distribution Units. Effective January 1, 2016, WPX assigned its vested and unvested IDUs to WPX Energy Holdings, LLC ("WPX Holdings"), a controlled affiliate of WPX Energy, Inc. The Incentive Distribution Units represent a right to incremental cash distributions from Legacy after certain target levels of distributions are paid to unitholders, which targets are set above the current levels of Legacy's distributions to unitholders. The Unvested IDUs do not participate in cash distributions from Legacy until vested. The Unvested IDUs will automatically be forfeited on each of the first two anniversaries of the closing date of the WPX Acquisition in an amount per forfeiture equal to 66,666 Incentive Distribution Units and on the third anniversary of the closing date of the WPX Acquisition in an amount equal to 66,668 Incentive Distribution Units. Unvested IDUs that have not been forfeited will vest ratably at a rate of 10,000 Incentive Distribution Units per $35.5 million of additional cash consideration that is paid by Legacy to WPX or to a third party (along with the fair market value of any non-cash consideration) in connection with the consummation of any transaction by which Legacy acquires oil and natural gas properties (or rights therein or other assets related thereto) from WPX or jointly with WPX. 66,666 Unvested IDUs were forfeited on each of June 4, 2015 and June 4, 2016. In addition, the vested and outstanding Incentive Distribution Units held by WPX Holdings may be converted by Legacy, subject to applicable conversion factors, into units on a one-for-one basis at any time when Legacy has made a distribution in respect of its units for each of the four full fiscal quarters prior to the delivery of its conversion notice, and the amount of the distribution in respect of the units for the full quarter immediately preceding delivery of its conversion notice was equal to at least $0.90 per unit; and the amount of all distributions during each quarter within the four-quarter period immediately preceding delivery of its conversion notice did not exceed the adjusted operating surplus for such quarter. Further, WPX Holdings also has the ability to similarly convert any of its vested Incentive Distribution Units beginning three years after June 4, 2014. WPX Holdings may not transfer any of the Incentive Distribution Units it holds to any person that is not a controlled affiliate of WPX Energy, Inc. Income (loss) per unit The following table sets forth the computation of basic and diluted loss per unit: Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (In thousands) Net income (loss) $ (52,261 ) $ (38,474 ) $ 53,068 $ (267,328 ) Distributions to preferred unitholders (4,750 ) (4,750 ) (8,708 ) (9,500 ) Net loss available to unitholders (57,011 ) (43,224 ) 44,360 (276,828 ) Weighted average number of units outstanding 70,071 68,897 69,518 68,909 Effect of dilutive securities: Restricted and phantom units — — — — Weighted average units and potential units outstanding 70,071 68,897 69,518 68,909 Basic and diluted income (loss) per unit $ (0.81 ) $ (0.63 ) $ 0.64 $ (4.02 ) For the three and six months ended June 30, 2016 , 431,691 restricted units and 1,212,692 phantom units were excluded from the calculation of diluted income per unit due to their anti-dilutive effect. For the three and six months ended June 30, 2015 , 508,830 restricted units and 862,064 phantom units were excluded from the calculation of diluted income per unit due to their anti-dilutive effect.

Unit-Based Compensation

Unit-Based Compensation	6 Months Ended
	Jun. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Unit-Based Compensation	Unit-Based Compensation Long-Term Incentive Plan On March 15, 2006, the LTIP for Legacy was implemented for its employees, consultants and directors, its affiliates and its general partner. On June 12, 2015, the unitholders of Legacy approved an amendment to the LTIP to provide for an increase in the number of units available for issuance from 2,000,000 to 5,000,000 . The awards under the LTIP may include unit grants, restricted units, phantom units, unit options and unit appreciation rights ("UARs"). As of June 30, 2016 , grants of awards net of forfeitures and, in the case of phantom units, historical exercises covering 2,797,391 units had been made, comprised of 266,014 unit option awards, 885,001 restricted unit awards, 1,212,692 phantom unit awards and 433,684 unit awards. The UAR awards and certain phantom unit awards granted under the LTIP may only be settled in cash, and therefore are not included in the aggregate number of units granted under the LTIP. The LTIP is administered by the compensation committee (the “Compensation Committee”) of the board of directors of LRGPLLC. The cost of employee services in exchange for an award of equity instruments is measured based on a grant-date fair value of the award (with limited exceptions), and that cost must generally be recognized over the vesting period of the award. However, if an entity that nominally has the choice of settling awards by issuing stock predominately settles in cash, or if an entity usually settles in cash whenever an employee asks for cash settlement, the entity is settling a substantive liability rather than repurchasing an equity instrument. Because the UARs are settled in cash, Legacy accounts for them by utilizing the liability method. The liability method requires companies to measure the cost of the employee services in exchange for a cash award based on the fair value of the underlying security at the end of each reporting period. Compensation cost is recognized based on the change in the liability between periods. Unit Appreciation Rights A UAR is a notional unit that entitles the holder, upon vesting, to receive cash valued at the difference between the closing price of units on the exercise date and the exercise price, as determined on the date of grant. Because these awards are settled in cash, Legacy is accounting for the UARs by utilizing the liability method. During the year ended December 31, 2015 , Legacy issued 204,500 UARs to employees which vest ratably over a three -year period and 96,520 UARs to employees which vest at the end of a three -year period. Legacy did not issue UARs to employees during the six -month period ended June 30, 2016 . All UARs granted in 2015 expire seven years from the grant date and are exercisable when they vest. For the six -month periods ended June 30, 2016 and 2015 , Legacy recorded $112,100 and $16,359 , respectively, of compensation expense due to the change in liability from December 31, 2015 and 2014 , respectively, based on its use of the Black-Scholes model to estimate the June 30, 2016 and 2015 fair value of these UARs (see Note 6). As of June 30, 2016 , there was a total of approximately $104,048 of unrecognized compensation costs related to the unexercised and non-vested portion of these UARs. At June 30, 2016 , this cost was expected to be recognized over a weighted-average period of approximately 2.07 years. Compensation expense is based upon the fair value as of June 30, 2016 and is recognized as a percentage of the service period satisfied. Based on historical data, Legacy has assumed a volatility factor of approximately 81% and employed the Black-Scholes model to estimate the June 30, 2016 fair value to be realized as compensation cost based on the percentage of service period satisfied. Based on historical data, Legacy has assumed an estimated forfeiture rate of 5.3% . Legacy will adjust the estimated forfeiture rate based upon actual experience. Legacy has assumed no annual distribution. A summary of UAR activity for the six months ended June 30, 2016 is as follows: Units Weighted-Average Exercise Price Weighted-Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1, 2016 936,116 $ 20.61 4.91 $ — Forfeited (20,667 ) 20.71 Outstanding at June 30, 2016 915,449 $ 20.61 4.40 $ — UARs and unit options exercisable at June 30, 2016 450,456 $ 25.84 2.55 $ — The following table summarizes the status of Legacy’s non-vested UARs since January 1, 2016 : Non-Vested UARs Number of Units Weighted-Average Exercise Price Non-vested at January 1, 2016 566,067 $ 16.80 Vested (80,407 ) 23.07 Forfeited (20,667 ) 20.71 Non-vested at March 31, 2016 464,993 $ 15.54 Legacy has used a weighted-average risk-free interest rate of 0.9% in its Black-Scholes calculation of fair value, which approximates the U.S. Treasury interest rates at June 30, 2016 whose terms are consistent with the expected life of the UARs. Expected life represents the period of time that UARs are expected to be outstanding and is based on Legacy’s best estimate. The following table represents the weighted-average assumptions used for the Black-Scholes option-pricing model. Six Months Ended June 30, Expected life (years) 4.40 Risk free interest rate 0.9 % Annual distribution rate per unit $0.00 Volatility 81.4 % Phantom Units Legacy has also issued phantom units under the LTIP to executive officers. A phantom unit is a notional unit that entitles the holder, upon vesting, to receive either one Partnership unit for each phantom unit or the cash equivalent of a Partnership unit, as stipulated by the form of the grant. Legacy is accounting for the phantom units settled in Partnership units by utilizing the equity method. Legacy is accounting for the phantom units settled in cash by utilizing the liability method. On September 21, 2009, the board of directors of LRGPLLC, upon the recommendation of the Compensation Committee, implemented an equity-based incentive compensation policy applicable to the executive officers of Legacy. In addition to cash bonus awards, under the compensation plan, the executives are eligible for both subjective and objective grants of phantom units. The subjective, or service-based, grants may be awarded up to a maximum percentage of annual salary as determined by the Compensation Committee. Once granted, these phantom units vest ratably over a three -year period. The objective, or performance-based, grants may be awarded up to a maximum percentage of annual salary as determined by the Compensation Committee. However, the amount to vest each year for the three -year vesting period will be determined on each vesting date based on a three-step process, with the first two steps each comprising 50% of the total vesting amount while the third step is the sum of the first two steps. The first step in the process will be a function of Total Unitholder Return (“TUR”) for the Partnership and the percentage rank of the Legacy TUR among a peer group of upstream master limited partnerships, as determined by the Compensation Committee at the beginning of each year. In the second step, the Legacy TUR will be compared to the TUR of a group of master limited partnerships included in the Alerian MLP Index. The third step is the addition of the above two steps to determine the total performance-based awards to vest. On March 7, 2013, the board of directors of LRGPLLC, upon the recommendation of the Compensation Committee, approved a revised compensation policy (the “Revised Policy”). This Revised Policy applies to incentive awards granted after the fiscal year ended 2013. While the Revised Policy measures TUR against both the peer group and Alerian MLP Index, the measurement periods were increased to a three -year cumulative measurement period with a corresponding increase in vesting from a ratable three -year vesting to three -year cliff vesting. Performance based phantom units subject to vesting which do not vest in a given year will be forfeited. With respect to both the subjective and objective units awarded under both compensation policies, distribution equivalent rights ("DERs") will accumulate and accrue based on the total number of actual amounts vested and will be payable at the date of vesting. However, due to the aforementioned revision for executive employees, accrued DERs paid at the date of vesting will be treated as distributions in the period paid rather than being recognized as compensation expense over the life of the award. On February 24, 2015 , the Compensation Committee approved the award of 341,251 subjective, or service-based, phantom units and 259,998 objective, or performance based, phantom units to Legacy’s executive officers. On June 22, 2016 , the Compensation Committee approved with respect to Paul Horne, and the board of directors of LRGPLLC approved the recommendation of the Compensation Committee with respect to the other executive officers the award of a maximum of 391,674 subjective, or service-based, phantom units that, upon vesting, settle in Partnership units, a maximum of 1,286,930 subjective phantom units that, upon vesting, settle in cash and a maximum of 2,238,138 objective, or performance-based, phantom units that, upon vesting, settle in cash to our executive officers. Compensation expense related to the phantom units was $1.8 million and $1.4 million for the six months ended June 30, 2016 and 2015 , respectively. Restricted Units During the year ended December 31, 2015 , Legacy issued an aggregate of 381,860 restricted units to both non-executive employees and an executive employee. The restricted units awarded to non-executive employees vest ratably over a three -year period beginning at the date of grant. The restricted units granted to the executive employee vest ratably over a three -year period for a portion of the restricted units, with the remainder vesting in full at the end of a five -year period. During the six -month period ended June 30, 2016 , Legacy did not issue restricted units to any employees. Compensation expense related to restricted units was $1.6 million and $1.2 million for the six months ended June 30, 2016 and 2015 , respectively. As of June 30, 2016 , there was a total of $3.2 million of unrecognized compensation expense related to the unvested portion of these restricted units. At June 30, 2016 , this cost was expected to be recognized over a weighted-average period of 2.0 years. Pursuant to the provisions of ASC 718, Legacy’s issued units, as reflected in the accompanying consolidated balance sheet at June 30, 2016 , do not include 431,691 units related to unvested restricted unit awards. Board Units On June 15, 2015, Legacy granted and issued 11,025 units to each of its six non-employee directors. The value of each unit was $9.13 at the time of issuance. On May 10, 2016, Legacy granted and issued 39,526 units to each of its six non-employee directors. The value of each unit was $2.59 at the time of issuance.

Subsidiary Guarantors

Subsidiary Guarantors	6 Months Ended
	Jun. 30, 2016
Guarantees [Abstract]
Subsidiary Guarantors	Subsidiary Guarantors On April 2, 2014, Legacy filed a registration statement on Form S-3 with the Securities and Exchange Commission ("SEC") to register the issuance and sale of, among other securities, Legacy's debt securities, which may be co-issued by Legacy Reserves Finance Corporation. The registration statement also registered guarantees of debt securities by Legacy Reserves Operating GP LLC, Legacy Reserves Operating LP and Legacy Reserves Services, Inc. The Partnership's 2020 Senior Notes were issued in a private offering on December 4, 2012 and were subsequently registered through a public exchange offer that closed on January 8, 2014. The Partnership's 2021 Senior Notes were issued in two separate private offerings on May 28, 2013 and May 8, 2014. $250 million aggregate principal amount of our 2021 Senior Notes were subsequently registered through a public exchange offer that closed on March 18, 2014. The remaining $300 million of aggregate principal amount of Legacy's 2021 Senior Notes were subsequently registered through a public exchange offer that closed on February 10, 2015. The 2020 Senior Notes and the 2021 Senior Notes are guaranteed by Legacy's 100% owned subsidiaries Legacy Reserves Operating GP LLC, Legacy Reserves Operating LP, Legacy Reserves Services, Inc., Legacy Reserves Energy Services LLC, Dew Gathering LLC and Pinnacle Gas Treating LLC, which constitute all of Legacy's wholly-owned subsidiaries other than Legacy Reserves Finance Corporation, and certain other future subsidiaries (the “Guarantors”, together with any future 100% owned subsidiaries that guarantee the Partnership's 2020 Senior Notes and 2021 Senior Notes, the “Subsidiaries”). The Subsidiaries are 100% owned, directly or indirectly, by the Partnership and the guarantees by the Subsidiaries are full and unconditional, except for customary release provisions described in Note 2 - Long-Term Debt . The Partnership has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Partnership. The guarantees constitute joint and several obligations of the Guarantors.

Summary of Significant Accoun18

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Accounting	The accompanying condensed consolidated financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred. These condensed consolidated financial statements as of June 30, 2016 and for the three and six months ended June 30, 2016 and 2015 are unaudited. In the opinion of management, such financial statements include the adjustments and accruals, all of which are of a normal recurring nature, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year. Certain information and footnote disclosures normally included in the financial statements prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). These condensed consolidated financial statements should be read in connection with the consolidated financial statements and notes thereto included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015 .
Recent Accounting Pronouncements	Recent Accounting Pronouncements In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2016-02, "Leases" ("ASU 2016-02"). ASU 2016-02 establishes a right-of-use (ROU) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. We are currently evaluating the impact of our pending adoption of ASU 2016-02 on our consolidated financial statements. In August 2014, the FASB issued Accounting Standards Update No. 2014-15, "Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern" (“ASU 2014-15”). ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU 2014-15 and do not anticipate any impact on our consolidated financial statements. In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers" ("ASU 2014-09"), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing U.S. GAAP. In August 2015, the FASB issued ASU No. 2015-14, "Revenue from Contracts with Customers" ("ASU 2015-14"), which approved a one-year delay of the standard's effective date. In accordance with ASU 2015-14, the standard is now effective for annual periods beginning after December 15, 2017, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are currently evaluating the impact of our pending adoption of ASU 2014-09 on our consolidated financial statements and do not anticipate the standard will have a material impact on our consolidated financial statements.

Summary of Significant Accoun19

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of components of accrued oil and natural gas liabilities	Below are the components of accrued oil and natural gas liabilities as of June 30, 2016 and December 31, 2015 : June 30, December 31, (In thousands) Revenue payable to joint interest owners $ 23,493 $ 15,253 Accrued lease operating expense 15,070 19,007 Accrued capital expenditures 2,180 2,881 Accrued ad valorem tax 9,137 8,723 Other 5,206 4,709 $ 55,086 $ 50,573

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Schedule of long-term debt	Long-term debt consists of the following as of June 30, 2016 and December 31, 2015 : June 30, December 31, 2016 2015 (In thousands) Credit Facility due 2019 $ 533,000 $ 608,000 8% Senior Notes due 2020 232,989 300,000 6.625% Senior Notes due 2021 432,656 550,000 1,198,645 1,458,000 Unamortized discount on Senior Notes (12,916 ) (17,604 ) Unamortized debt issuance costs (a) (12,720 ) (12,782 ) Total Long-Term Debt $ 1,173,009 $ 1,427,614 _______________ (a) In order to comply with Accounting Standards Update No. 2015-03, unamortized debt issuance costs are now recorded as a direct deduction from the carrying amount of debt. As such, 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 retained earnings.
Schedule of debt redemption	Legacy will have the option to redeem the 2020 Senior Notes, in whole or in part, at any time on or after December 1, 2016, at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption if redeemed during the twelve-month period beginning on December 1 of the years indicated below. Year Percentage 2016 104.000 % 2017 102.000 % 2018 and thereafter 100.000 % The terms of the 2021 Senior Notes, including details related to our guarantors, are substantially identical to the terms of the 2020 Senior Notes with the exception of the interest rate and redemption provisions noted below. Legacy will have the option to redeem the 2021 Senior Notes, in whole or in part, at any time on or after June 1, 2017, at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption if redeemed during the twelve-month period beginning on June 1 of the years indicated below. Year Percentage 2017 103.313 % 2018 101.656 % 2019 and thereafter 100.000 %

Acquisitions (Tables)

Acquisitions (Tables)	6 Months Ended
	Jun. 30, 2016
Business Combinations [Abstract]
Schedule of allocation of the purchase price to the fair value of the acquired assets and liabilities assumed	The allocation of the Anadarko Acquisitions purchase price to the fair value of the acquired assets and liabilities assumed was as follows (in thousands): Proved oil and natural gas properties including related equipment $ 461,306 Future abandonment costs (27,351 ) Fair value of net assets acquired $ 433,955
Schedule of unaudited pro forma results of operations	The following table reflects the unaudited pro forma results of operations as though the Anadarko Acquisitions had occurred on January 1, 2014. The pro forma amounts are not necessarily indicative of the results that may be reported in the future and do not include any adjustments for acquisition related expenses. Three Months Ended June 30, Six Months Ended June 30, 2015 2015 Revenues $ 119,416 $ 233,877 Net loss attributable to unitholders $ (29,151 ) $ (247,638 ) Loss per unit — basic and diluted $ (0.42 ) $ (3.59 ) Units used in computing loss per unit: Basic and diluted 68,897 68,909
Schedule of revenues and revenues in excess of direct operating expenses	The amounts of revenues and revenues in excess of direct operating expenses included in our consolidated statements of operations for the Anadarko Acquisitions are shown in the table that follows. Direct operating expenses include lease operating expenses and production and other taxes. Three Months Ended June 30, Six Months Ended June 30, 2016 2016 (In thousands) Anadarko Acquisitions Revenues $ 10,387 $ 21,865 Excess of revenues over direct operating expenses $ 4,362 $ 8,518

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis	The following table sets forth by level within the fair value hierarchy Legacy’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2016 : Fair Value Measurements at June 30, 2016 Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Total Carrying Value as of Description (Level 1) (Level 2) (Level 3) June 30, 2016 (In thousands) LTIP liability (a) $ — $ (113 ) $ — $ (113 ) Oil and natural gas derivatives — 54,210 (1,290 ) 52,920 Interest rate swaps — (5,994 ) — (5,994 ) Total $ — $ 48,103 $ (1,290 ) $ 46,813 (a) See Note 10 for further discussion on unit-based compensation expenses and the related Long-Term Incentive Plan ("LTIP") liability for certain grants accounted for under the liability method.
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3	The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy: Significant Unobservable Inputs (Level 3) Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (In thousands) Beginning balance $ (2,828 ) $ (2,485 ) $ (4,493 ) $ 555 Total gains (losses) 888 (3,275 ) 899 (6,632 ) Settlements, net 650 949 2,304 1,266 Ending balance $ (1,290 ) $ (4,811 ) $ (1,290 ) $ (4,811 ) Gains (losses) included in earnings relating to derivatives still held as of June 30, 2016 and 2015 $ 581 $ (3,492 ) $ 978 $ (4,811 )
Schedule of fair value measurements of proved oil and natural gas properties	six -month period ended June 30, 2016 consist of: Fair Value Measurements During the Six Months Ended June 30, 2016 Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description (Level 1) (Level 2) (Level 3) (In thousands) Assets: Impairment (a) $ — $ — $ 19,783 (a) Legacy periodically reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. During the six -month period ended June 30, 2016 , Legacy incurred impairment charges of $15.4 million as oil and natural gas properties with a net cost basis of $35.2 million were written down to their fair value of $19.8 million . In order to determine whether the carrying value of an asset is recoverable, Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If the net capitalized cost exceeds the undiscounted future net cash flows, Legacy writes the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

Derivative Financial Instrume23

Derivative Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of reconciliation of the changes in fair value of Legacy's commodity derivatives	The following table sets forth a reconciliation of the changes in fair value of Legacy's commodity derivatives for the three and six months ended June 30, 2016 and 2015 : Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (In thousands) Beginning fair value of commodity derivatives $ 112,688 $ 133,242 $ 118,427 $ 153,099 Total gain (loss) - oil derivatives (5,411 ) (12,649 ) (2,892 ) 945 Total gain (loss) - natural gas derivatives (32,264 ) (848 ) (17,745 ) 6,038 Crude oil derivative cash settlements received (9,760 ) (27,364 ) (22,345 ) (59,564 ) Natural gas derivative cash settlements received (12,333 ) (9,825 ) (22,525 ) (17,962 ) Ending fair value of commodity derivatives $ 52,920 $ 82,556 $ 52,920 $ 82,556
Schedule of gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities	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 as of the dates indicated below (in thousands): June 30, 2016 Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Offsetting Derivative Assets: (In thousands) Commodity derivatives $ 85,562 $ (32,120 ) $ 53,442 Total derivative assets $ 85,562 $ (32,120 ) $ 53,442 Offsetting Derivative Liabilities: Commodity derivatives $ (32,642 ) $ 32,120 $ (522 ) Interest rate derivatives (5,994 ) — (5,994 ) Total derivative liabilities $ (38,636 ) $ 32,120 $ (6,516 ) December 31, 2015 Gross Amounts of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Offsetting Derivative Assets: (In thousands) Commodity derivatives $ 177,082 $ (58,655 ) $ 118,427 Interest rate derivatives 1,982 (325 ) 1,657 Total derivative assets $ 179,064 $ (58,980 ) $ 120,084 Offsetting Derivative Liabilities: Commodity derivatives $ (58,655 ) $ 58,655 $ — Interest rate derivatives (2,344 ) 325 (2,019 ) Total derivative liabilities $ (60,999 ) $ 58,980 $ (2,019 )
Schedule of notional amounts of outstanding derivative positions	As of June 30, 2016 , Legacy had the following NYMEX West Texas Intermediate ("WTI") crude oil swaps paying floating prices and receiving fixed prices for a portion of its future oil production as indicated below: Average Price Time Period Volumes (Bbls) Price per Bbl Range per Bbl July-December 2016 1,002,800 $55.24 $50.15 - $91.00 2017 182,500 $84.75 $84.75 As of June 30, 2016 , Legacy had the following Midland-to-Cushing crude oil differential swaps paying a floating differential and receiving a fixed differential for a portion of its future oil production as indicated below: Average Price Time Period Volumes (Bbls) Price per Bbl Range per Bbl July-December 2016 1,472,000 $(1.60) $(1.50) - $(1.75) 2017 2,190,000 $(0.30) $(0.05) - $(0.75) As of June 30, 2016 , Legacy had the following NYMEX WTI crude oil derivative three-way collar contracts that combine a long and short put with a short call as indicated below: Average Short Average Long Average Short Time Period Volumes (Bbls) Put Price per Bbl Put Price per Bbl Call Price per Bbl July-December 2016 230,000 $60.00 $85.00 $102.46 2017 72,400 $60.00 $85.00 $104.20 As of June 30, 2016 , Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put and long put with a fixed-price swap as indicated below: Average Long Average Short Average Time Period Volumes (Bbls) Put Price per Bbl Put Price per Bbl Swap Price per Bbl July-December 2016 92,000 $57.00 $82.00 $91.70 2017 182,500 $57.00 $82.00 $90.85 2018 127,750 $57.00 $82.00 $90.50 As of June 30, 2016 , Legacy had the following NYMEX Henry Hub and West Texas Waha natural gas swaps paying floating natural gas prices and receiving fixed prices for a portion of its future natural gas production as indicated below: Average Price Time Period Volumes (MMBtu) Price per MMBtu Range per MMBtu July-December 2016 24,973,600 $3.01 $2.42 - $5.30 2017 27,600,000 $3.36 $3.29 - $3.39 2018 27,600,000 $3.36 $3.29 - $3.39 2019 25,800,000 $3.36 $3.29 - $3.39 As of June 30, 2016 , Legacy had the following NYMEX Henry Hub natural gas derivative three-way collar contracts that combine a long put, a short put and a short call as indicated below: Average Short Put Average Long Put Average Short Call Time Period Volumes (MMBtu) Price per MMBtu Price per MMBtu Price per MMBtu July-December 2016 2,790,000 $3.75 $4.25 $5.08 2017 5,040,000 $3.75 $4.25 $5.53 As of June 30, 2016 , Legacy had the following Henry Hub NYMEX to Northwest Pipeline, California SoCal NGI and San Juan Basin natural gas differential swaps paying a floating differential and receiving a fixed differential for a portion of its future natural gas production as indicated below: July-December 2016 2017 Average Average Volumes (MMBtu) Price per MMBtu Volumes (MMBtu) Price per MMBtu NWPL 7,529,832 $(0.19) 7,300,000 $(0.16) SoCal — $— 2,500,250 $0.11 San Juan 1,256,720 $(0.16) 2,500,250 $(0.10)
Schedule of total impact on interest expense from the mark-to-market and settlements	The total impact on interest expense from the mark-to-market and settlements was as follows: Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (In thousands) Beginning fair value of interest rate swaps $ (4,695 ) $ (1,540 ) $ (362 ) $ (2,080 ) Total loss on interest rate swaps (1,977 ) (143 ) (7,049 ) (291 ) Cash settlements paid 678 698 1,417 1,386 Ending fair value of interest rate swaps $ (5,994 ) $ (985 ) $ (5,994 ) $ (985 )
Schedule of interest rate swap liabilities	The table below summarizes the interest rate swap position as of June 30, 2016 : Weighted Average Estimated Fair Value at Notional Amount Fixed Rate Effective Date Maturity Date June 30, 2016 (Dollars in thousands) $ 115,000 0.850 % 9/1/2015 9/1/2017 $ (1,588 ) $ 235,000 1.363 % 9/1/2015 9/1/2019 (4,406 ) Total fair value of interest rate derivatives $ (5,994 )

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	6 Months Ended
	Jun. 30, 2016
Asset Retirement Obligation [Abstract]
Schedule of changes in asset retirement obligations	The following table reflects the changes in the ARO during the six months ended June 30, 2016 and year ended December 31, 2015 : June 30, December 31, (In thousands) Asset retirement obligation - beginning of period $ 286,405 $ 226,525 Liabilities incurred with properties acquired — 60,526 Liabilities incurred with properties drilled — 92 Liabilities settled during the period (1,172 ) (2,615 ) Liabilities associated with properties sold (21,664 ) (9,386 ) Current period accretion 6,354 11,263 Asset retirement obligation - end of period $ 269,923 $ 286,405

Partners' Equity (Tables)

Partners' Equity (Tables)	6 Months Ended
	Jun. 30, 2016
Equity [Abstract]
Schedule of computation of basic and diluted income (loss) per unit	The following table sets forth the computation of basic and diluted loss per unit: Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (In thousands) Net income (loss) $ (52,261 ) $ (38,474 ) $ 53,068 $ (267,328 ) Distributions to preferred unitholders (4,750 ) (4,750 ) (8,708 ) (9,500 ) Net loss available to unitholders (57,011 ) (43,224 ) 44,360 (276,828 ) Weighted average number of units outstanding 70,071 68,897 69,518 68,909 Effect of dilutive securities: Restricted and phantom units — — — — Weighted average units and potential units outstanding 70,071 68,897 69,518 68,909 Basic and diluted income (loss) per unit $ (0.81 ) $ (0.63 ) $ 0.64 $ (4.02 )

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of option and UAR activity	A summary of UAR activity for the six months ended June 30, 2016 is as follows: Units Weighted-Average Exercise Price Weighted-Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1, 2016 936,116 $ 20.61 4.91 $ — Forfeited (20,667 ) 20.71 Outstanding at June 30, 2016 915,449 $ 20.61 4.40 $ — UARs and unit options exercisable at June 30, 2016 450,456 $ 25.84 2.55 $ —
Schedule of status of the Partnership’s non-vested UARs	The following table summarizes the status of Legacy’s non-vested UARs since January 1, 2016 : Non-Vested UARs Number of Units Weighted-Average Exercise Price Non-vested at January 1, 2016 566,067 $ 16.80 Vested (80,407 ) 23.07 Forfeited (20,667 ) 20.71 Non-vested at March 31, 2016 464,993 $ 15.54
Schedule of weighted average assumptions used for the Black-Scholes option-pricing model	The following table represents the weighted-average assumptions used for the Black-Scholes option-pricing model. Six Months Ended June 30, Expected life (years) 4.40 Risk free interest rate 0.9 % Annual distribution rate per unit $0.00 Volatility 81.4 %

Summary of Significant Accoun27

Summary of Significant Accounting Policies - Other Narrative (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General partner's equity, percent	0.03%	0.03%
Term of right to receive distributions of available cash after quarter end	45 days
Minimum percentage of unitholder approval to remove general partner	66.67%
Term of right to receive information reasonably required for tax reporting purposes after close of year	90 days

Summary of Significant Accoun28

Summary of Significant Accounting Policies - Accrued Oil and Natural Gas Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Revenue payable to joint interest owners	$ 23,493	$ 15,253
Accrued lease operating expense	15,070	19,007
Accrued capital expenditures	2,180	2,881
Accrued ad valorem tax	9,137	8,723
Other	5,206	4,709
Accrued oil and natural gas liabilities	$ 55,086	$ 50,573

Summary of Significant Accoun29

Summary of Significant Accounting Policies Summary of SIgnificant Accounting Policies - Restricted Cash (Details) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Restricted Cash	$ 2,900,000	$ 0

Long-Term Debt - Schedule of Lo

Long-Term Debt - Schedule of Long-term Debt (Details) - USD ($)	Jun. 30, 2016	Dec. 31, 2015	May 13, 2014
Debt Instrument [Line Items]
Long-term debt, gross	$ 1,198,645,000	$ 1,458,000,000
Unamortized discount on Senior Notes	(12,916,000)	(17,604,000)
Unamortized debt issuance costs	(12,720,000)	(12,782,000)
Total Long-Term Debt	$ 1,173,009,000	1,427,614,000
Senior notes | 8% Senior Notes due 2020
Debt Instrument [Line Items]
Stated interest rate	8.00%
Long-term debt, gross	$ 232,989,000	300,000,000
Senior notes | 6.625% Senior Notes due 2021
Debt Instrument [Line Items]
Stated interest rate	6.625%		6.625%
Long-term debt, gross	$ 432,656,000	550,000,000	$ 300,000,000
Credit facility due 2019
Debt Instrument [Line Items]
Long-term debt, gross	$ 533,000,000	$ 608,000,000

Long-Term Debt - Credit Facilit

Long-Term Debt - Credit Facility (Details)	Apr. 01, 2014USD ($)	Jun. 30, 2016USD ($)	Dec. 31, 2015USD ($)	May 13, 2014USD ($)	Mar. 18, 2014USD ($)	May 28, 2013USD ($)	Dec. 04, 2012USD ($)
Line of Credit Facility [Line Items]
Long-term debt, gross		$ 1,198,645,000	$ 1,458,000,000
Credit facility due 2019
Line of Credit Facility [Line Items]
Expiration period	5 years
Maximum borrowing capacity	$ 1,500,000,000	$ 630,000,000
Minimum Percent of Total Property Value Securing Credit Agreement	90.00%
Purchase price of properties as a percentage of borrowing base required for potential re-determination of borrowing base, minimum	10.00%
Ratio of consolidated current assets to consolidated current liabilities, minimum		1
Aggregate principal amount		$ 533,000,000
Minimum percent of outstanding principal amount required for changes to credit agreement	66.67%
Long-term debt, gross		$ 533,000,000	608,000,000
Interest rate at period end		3.22%
Remaining borrowing capacity		$ 95,600,000
Interest Paid		$ 9,300,000
Letter of Credit
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 2,000,000
Debt Covenant, Period One | Credit facility due 2019
Line of Credit Facility [Line Items]
Ratio of indebtedness to earnings before interest, taxes, depreciation and amortization, maximum		3.5
Ratio of EBITDA to interest expense, minimum		2.5
Debt Covenant, Period Two | Credit facility due 2019
Line of Credit Facility [Line Items]
Ratio of indebtedness to earnings before interest, taxes, depreciation and amortization, maximum		3.25
Ratio of EBITDA to interest expense, minimum		2
Debt Covenant, Period Three | Credit facility due 2019
Line of Credit Facility [Line Items]
Ratio of indebtedness to earnings before interest, taxes, depreciation and amortization, maximum		3
Ratio of EBITDA to interest expense, minimum		2.5
Debt Covenant, Period Four | Credit facility due 2019
Line of Credit Facility [Line Items]
Ratio of indebtedness to earnings before interest, taxes, depreciation and amortization, maximum		2.5
Senior notes
Line of Credit Facility [Line Items]
Aggregate principal amount					$ 250,000,000
Senior notes | 8% Senior Notes due 2020
Line of Credit Facility [Line Items]
Stated interest rate		8.00%
Aggregate principal amount							$ 300,000,000
Long-term debt, gross		$ 232,989,000	300,000,000
Senior notes | 6.625% Senior Notes due 2021
Line of Credit Facility [Line Items]
Stated interest rate		6.625%		6.625%
Aggregate principal amount				$ 300,000,000		$ 250,000,000
Long-term debt, gross		$ 432,656,000	$ 550,000,000	$ 300,000,000
Series A Preferred Equity
Line of Credit Facility [Line Items]
Dividend rate		8.00%
Series B Preferred Equity
Line of Credit Facility [Line Items]
Dividend rate		8.00%

Long-Term Debt - Senior Notes (

Long-Term Debt - Senior Notes (Details) - USD ($)	Jun. 01, 2016	May 13, 2014	May 28, 2013	Dec. 04, 2012	Jun. 30, 2016	Dec. 31, 2013	Mar. 18, 2014
Senior notes
Debt Instrument [Line Items]
Aggregate principal amount							$ 250,000,000
Senior notes | 8% Senior Notes due 2020
Debt Instrument [Line Items]
Stated interest rate					8.00%
Aggregate principal amount				$ 300,000,000
Face amount repurchased					$ 52,000,000
Issuance percent of par				97.848%
Senior notes | 8% Senior Notes due 2020 | Change in Control
Debt Instrument [Line Items]
Redemption price percentage						101.00%
Senior notes | 8% Senior Notes due 2020 | 2016
Debt Instrument [Line Items]
Redemption price percentage					104.00%
Senior notes | 8% Senior Notes due 2020 | 2017
Debt Instrument [Line Items]
Redemption price percentage					102.00%
Senior notes | 8% Senior Notes due 2020 | 2018 and thereafter
Debt Instrument [Line Items]
Redemption price percentage					100.00%
Senior notes | 6.625% Senior Notes due 2021
Debt Instrument [Line Items]
Stated interest rate		6.625%			6.625%
Aggregate principal amount		$ 300,000,000	$ 250,000,000
Face amount repurchased					$ 117,300,000
Debt extinguished	$ 15,000,000
Issuance percent of par		99.00%	98.405%
Senior notes | 6.625% Senior Notes due 2021 | Company Option
Debt Instrument [Line Items]
Redemption price percentage					106.625%
Percent of notes eligible of early redemption					35.00%
Senior notes | 6.625% Senior Notes due 2021 | Change in Control
Debt Instrument [Line Items]
Redemption price percentage					101.00%
Senior notes | 6.625% Senior Notes due 2021 | 2017
Debt Instrument [Line Items]
Redemption price percentage					103.313%
Senior notes | 6.625% Senior Notes due 2021 | 2018
Debt Instrument [Line Items]
Redemption price percentage					101.656%
Senior notes | 6.625% Senior Notes due 2021 | 2019 and thereafter
Debt Instrument [Line Items]
Redemption price percentage					100.00%
Legacy Reserves Finance Corporation
Debt Instrument [Line Items]
Ownership interest		100.00%	100.00%	100.00%	100.00%
Unitholders' Equity | Limited Partner
Debt Instrument [Line Items]
Units issued in exchange for retirement of debt (in units)	2,719,124				2,719,000

Acquisitions (Details)

Acquisitions (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	Jul. 31, 2015	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Units used in computing loss per unit:
Revenues		$ 73,367	$ 87,801	$ 139,226	$ 169,340
Excess of revenues over direct operating expenses		(14,104)	(7,058)	(30,980)	(240,237)
WGR acquisition
Business Acquisition [Line Items]
Membership interests acquired	100.00%
Acquisition purchase price	$ 96,700
Anadarko acquisitions
Business Acquisition [Line Items]
Acquisition purchase price	337,200
Schedule of allocation of the purchase price to the fair value of the acquired assets and liabilities assumed
Proved oil and natural gas properties including related equipment	461,306
Future abandonment costs	(27,351)
Fair value of net assets acquired	$ 433,955
Pro Forma Operating Results
Revenues			119,416		233,877
Net loss attributable to unitholders			$ (29,151)		$ (247,638)
Loss per unit - basic (in dollars per share)			$ (0.42)		$ (3.59)
Loss per unit - diluted (in dollars per share)			$ (0.42)		$ (3.59)
Units used in computing loss per unit:
Basic and diluted (in shares)			68,897		68,909
Revenues		10,387		21,865
Excess of revenues over direct operating expenses		$ 4,362		$ 8,518

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($)	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Water Transfer Services | Blue Quail Energy Services, LLC | Board of Directors Chairman and Director
Related Party Transaction [Line Items]
Amount paid for service	$ 82,587	$ 93,193

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016USD ($)$ / MMBTU
Loss Contingencies [Line Items]
Purchase obligation calculated floor price | $ / MMBTU	57.14
Estimated total future purchase obligation | $	$ 50.5
Officer
Loss Contingencies [Line Items]
Employment agreements with officers, severance pay consideration period, minimum	24 months
Employment agreements with officers, severance pay consideration period, maximum	36 months

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015	May 13, 2014
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Impairment	$ 1,272,650,000		$ 1,272,650,000		$ 1,408,956,000
Impairment of long-lived assets			15,400,000
Long-term debt, gross	1,198,645,000		1,198,645,000		1,458,000,000
Credit facility due 2019
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Long-term debt, gross	533,000,000		533,000,000		608,000,000
Senior notes | 8% Senior Notes due 2020
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Long-term debt, gross	232,989,000		232,989,000		300,000,000
Senior notes | 6.625% Senior Notes due 2021
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Long-term debt, gross	432,656,000		432,656,000		$ 550,000,000	$ 300,000,000
Quoted Prices in Active Markets for Identical Assets (Level 1) | Senior notes | 8% Senior Notes due 2020
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Fair value of notes payable	111,600,000		111,600,000
Quoted Prices in Active Markets for Identical Assets (Level 1) | Senior notes | 6.625% Senior Notes due 2021
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Fair value of notes payable	182,800,000		182,800,000
Recurring
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
LTIP liability	(113,000)		(113,000)
Total	46,813,000		46,813,000
Recurring | Commodity derivatives | Oil and natural gas
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Oil and natural gas derivatives	52,920,000		52,920,000
Recurring | Interest rate swaps
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Oil and natural gas derivatives	(5,994,000)		(5,994,000)
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
LTIP liability	0		0
Total	0		0
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity derivatives | Oil and natural gas
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Oil and natural gas derivatives	0		0
Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest rate swaps
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Oil and natural gas derivatives	0		0
Recurring | Significant Other Observable Inputs (Level 2)
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
LTIP liability	(113,000)		(113,000)
Total	48,103,000		48,103,000
Recurring | Significant Other Observable Inputs (Level 2) | Commodity derivatives | Oil and natural gas
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Oil and natural gas derivatives	54,210,000		54,210,000
Recurring | Significant Other Observable Inputs (Level 2) | Interest rate swaps
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Oil and natural gas derivatives	(5,994,000)		(5,994,000)
Recurring | Significant Unobservable Inputs (Level 3)
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
LTIP liability	0		0
Total	(1,290,000)		(1,290,000)
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3
Beginning balance	(2,828,000)	$ (2,485,000)	(4,493,000)	$ 555,000
Total gains (losses)	888,000	(3,275,000)	899,000	(6,632,000)
Settlements, net	650,000	949,000	2,304,000	1,266,000
Ending balance	(1,290,000)	(4,811,000)	(1,290,000)	(4,811,000)
Recurring | Significant Unobservable Inputs (Level 3) | Derivative assets
Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3
Gains (losses) included in earnings relating to derivatives still held as of June 30, 2016 and 2015	581,000	$ (3,492,000)	978,000	$ (4,811,000)
Recurring | Significant Unobservable Inputs (Level 3) | Commodity derivatives | Oil and natural gas
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Oil and natural gas derivatives	(1,290,000)		(1,290,000)
Recurring | Significant Unobservable Inputs (Level 3) | Interest rate swaps
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis
Oil and natural gas derivatives	0		0
Nonrecurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Impairment	0		0
Nonrecurring | Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Impairment	0		0
Nonrecurring | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Abstract]
Impairment	19,783,000		19,783,000
Oil and gas properties, gross	$ 35,200,000		$ 35,200,000

Derivative Financial Instrume37

Derivative Financial Instruments - Commodity Derivatives (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total gain (loss) on derivatives			$ (26,269)	$ 8,078
Derivative cash settlements paid (received)			(44,871)	(77,526)
Not designated as hedging instrument | Commodity contract
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Beginning fair value of interest rate swaps	$ 112,688	$ 133,242	118,427	153,099
Ending fair value of interest rate swaps	52,920	82,556	52,920	82,556
Not designated as hedging instrument | Commodity contract | Oil
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total gain (loss) on derivatives	(5,411)	(12,649)	(2,892)	945
Derivative cash settlements paid (received)	(9,760)	(27,364)	(22,345)	(59,564)
Not designated as hedging instrument | Commodity contract | Natural gas
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward]
Total gain (loss) on derivatives	(32,264)	(848)	(17,745)	6,038
Derivative cash settlements paid (received)	$ (12,333)	$ (9,825)	$ (22,525)	$ (17,962)

Derivative Financial Instrume38

Derivative Financial Instruments - Offsetting Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Offsetting Derivative Assets:
Gross Amounts of Recognized Assets	$ 85,562	$ 179,064
Gross Amounts Offset in the Consolidated Balance Sheets	(32,120)	(58,980)
Net Amounts Presented in the Consolidated Balance Sheets	53,442	120,084
Offsetting Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(38,636)	(60,999)
Gross Amounts Offset in the Consolidated Balance Sheets	32,120	58,980
Net Amounts Presented in the Consolidated Balance Sheets	6,516	2,019
Commodity contract
Offsetting Derivative Assets:
Gross Amounts of Recognized Assets	85,562	177,082
Gross Amounts Offset in the Consolidated Balance Sheets	(32,120)	(58,655)
Net Amounts Presented in the Consolidated Balance Sheets	53,442	118,427
Offsetting Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(32,642)	(58,655)
Gross Amounts Offset in the Consolidated Balance Sheets	32,120	58,655
Net Amounts Presented in the Consolidated Balance Sheets	522	0
Interest rate contract
Offsetting Derivative Assets:
Gross Amounts of Recognized Assets		1,982
Gross Amounts Offset in the Consolidated Balance Sheets		(325)
Net Amounts Presented in the Consolidated Balance Sheets		1,657
Offsetting Derivative Liabilities:
Gross Amounts of Recognized Liabilities	(5,994)	(2,344)
Gross Amounts Offset in the Consolidated Balance Sheets	0	325
Net Amounts Presented in the Consolidated Balance Sheets	$ 5,994	$ 2,019

Derivative Financial Instrume39

Derivative Financial Instruments - Schedule of Derivatives, Notional Amounts Outstanding (Details)	Jun. 30, 2016USD ($)MMBTUbbl$ / bbl$ / MMBTU	Jun. 30, 2015MMBTU$ / MMBTU
NYMEX WTI Swaps | Crude Oil | July-December 2016
Derivative [Line Items]
Volumes | bbl	1,002,800
Average Price	55.24
NYMEX WTI Swaps | Crude Oil | July-December 2016 | Minimum
Derivative [Line Items]
Price Range	(50.15)
NYMEX WTI Swaps | Crude Oil | July-December 2016 | Maximum
Derivative [Line Items]
Price Range	(91)
NYMEX WTI Swaps | Crude Oil | 2017
Derivative [Line Items]
Volumes | bbl	182,500
Average Price	84.75
Price Range	(84.75)
Midland-to-Cushing Differential Swaps | Crude Oil | July-December 2016
Derivative [Line Items]
Volumes | bbl	1,472,000
Average Price	1.60
Midland-to-Cushing Differential Swaps | Crude Oil | July-December 2016 | Minimum
Derivative [Line Items]
Price Range	(1.50)
Midland-to-Cushing Differential Swaps | Crude Oil | July-December 2016 | Maximum
Derivative [Line Items]
Price Range	(1.75)
Midland-to-Cushing Differential Swaps | Crude Oil | 2017
Derivative [Line Items]
Volumes | bbl	2,190,000
Average Price	0.30
Midland-to-Cushing Differential Swaps | Crude Oil | 2017 | Minimum
Derivative [Line Items]
Price Range	(0.05)
Midland-to-Cushing Differential Swaps | Crude Oil | 2017 | Maximum
Derivative [Line Items]
Price Range	(0.75)
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | July-December 2016
Derivative [Line Items]
Volumes | bbl	230,000
NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017
Derivative [Line Items]
Volumes | bbl	72,400
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2017
Derivative [Line Items]
Volumes | bbl	92,000
Average Price	91.70
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2017 | Short
Derivative [Line Items]
Average Strike Price	82
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2017 | Long
Derivative [Line Items]
Average Strike Price	57
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2018
Derivative [Line Items]
Volumes | bbl	182,500
Average Price	90.85
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2018 | Short
Derivative [Line Items]
Average Strike Price	82
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2018 | Long
Derivative [Line Items]
Average Strike Price	57
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2019
Derivative [Line Items]
Volumes | bbl	127,750
Average Price	90.50
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2019 | Short
Derivative [Line Items]
Average Strike Price	82
NYMEX WTI Enhanced Swap Contracts 1 | Crude Oil | 2019 | Long
Derivative [Line Items]
Average Strike Price	57
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | July-December 2016
Derivative [Line Items]
Volumes | MMBTU	24,973,600
Average Price | $ / MMBTU	3.01
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | July-December 2016 | Minimum
Derivative [Line Items]
Price Range | $ / MMBTU	(2.42)
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | July-December 2016 | Maximum
Derivative [Line Items]
Price Range | $ / MMBTU	(5.30)
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2017
Derivative [Line Items]
Volumes | MMBTU	27,600,000
Average Price | $ / MMBTU	3.36
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2017 | Minimum
Derivative [Line Items]
Price Range | $ / MMBTU	(3.29)
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2017 | Maximum
Derivative [Line Items]
Price Range | $ / MMBTU	(3.39)
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2018
Derivative [Line Items]
Volumes | MMBTU	27,600,000
Average Price | $ / MMBTU	3.36
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2018 | Minimum
Derivative [Line Items]
Price Range | $ / MMBTU	(3.29)
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2018 | Maximum
Derivative [Line Items]
Price Range | $ / MMBTU	(3.39)
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2019
Derivative [Line Items]
Volumes | MMBTU	25,800,000
Average Price | $ / MMBTU	3.36
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2019 | Minimum
Derivative [Line Items]
Price Range | $ / MMBTU	(3.29)
NYMEX Henry Hub, Waha, ANR-OK and CIG-Rockies Swaps | Natural gas | 2019 | Maximum
Derivative [Line Items]
Price Range | $ / MMBTU	(3.39)
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | July-December 2016
Derivative [Line Items]
Volumes | MMBTU	2,790,000
NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017
Derivative [Line Items]
Volumes | MMBTU	5,040,000
Henry Hub NYMEX to Northwest Pipeline Natural Gas Differential Swaps | Natural gas | July-December 2016
Derivative [Line Items]
Volumes | MMBTU		7,529,832
Average Price | $ / MMBTU		0.19
Henry Hub NYMEX to Northwest Pipeline Natural Gas Differential Swaps | Natural gas | 2017
Derivative [Line Items]
Volumes | MMBTU		7,300,000
Average Price | $ / MMBTU		0.16
Henry Hub NYMEX to California SoCal NGI Natural Gas Differential Swaps | Natural gas | July-December 2016
Derivative [Line Items]
Volumes | MMBTU		0
Average Price | $ / MMBTU		0
Henry Hub NYMEX to California SoCal NGI Natural Gas Differential Swaps | Natural gas | 2017
Derivative [Line Items]
Volumes | MMBTU		2,500,250
Average Price | $ / MMBTU		0.11
Henry Hub NYMEX to San Juan Basin Natural Gas Differential Swaps | Natural gas | July-December 2016
Derivative [Line Items]
Volumes | MMBTU		1,256,720
Average Price | $ / MMBTU		0.16
Henry Hub NYMEX to San Juan Basin Natural Gas Differential Swaps | Natural gas | 2017
Derivative [Line Items]
Volumes | MMBTU		2,500,250
Average Price | $ / MMBTU		0.10
Put Option | NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | July-December 2016 | Short
Derivative [Line Items]
Average Strike Price	60
Put Option | NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | July-December 2016 | Long
Derivative [Line Items]
Average Strike Price	85
Put Option | NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017 | Short
Derivative [Line Items]
Average Strike Price	60
Put Option | NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017 | Long
Derivative [Line Items]
Average Strike Price	85
Put Option | NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | July-December 2016 | Short
Derivative [Line Items]
Average Strike Price | $ / MMBTU	3.75
Put Option | NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | July-December 2016 | Long
Derivative [Line Items]
Average Strike Price | $ / MMBTU	4.25
Put Option | NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017 | Short
Derivative [Line Items]
Average Strike Price | $ / MMBTU	3.75
Put Option | NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017 | Long
Derivative [Line Items]
Average Strike Price | $ / MMBTU	4.25
Call Option | NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | July-December 2016 | Short
Derivative [Line Items]
Average Strike Price	102.46
Call Option | NYMEX WTI Derivative Three-Way Collar Contracts | Crude Oil | 2017 | Short
Derivative [Line Items]
Average Strike Price	104.20
Call Option | NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | July-December 2016 | Short
Derivative [Line Items]
Average Strike Price | $ / MMBTU	5.08
Call Option | NYMEX Henry Hub Derivative Three-Way Collar Contracts | Natural gas | 2017 | Short
Derivative [Line Items]
Average Strike Price | $ / MMBTU	5.53
Not designated as hedging instrument | Interest Rate Swap Due Sept 2017
Derivative [Line Items]
Notional Amount | $	$ 115,000,000
Fixed Rate	0.85%
Estimated Fair Market Value | $	$ (1,588,000)
Not designated as hedging instrument | Interest Rate Swap Due Sept 2019
Derivative [Line Items]
Notional Amount | $	$ 235,000,000
Fixed Rate	1.363%
Estimated Fair Market Value | $	$ (4,406,000)
Not designated as hedging instrument | Interest rate swaps
Derivative [Line Items]
Estimated Fair Market Value | $	$ (5,994,000)

Derivative Financial Instrume40

Derivative Financial Instruments - Schedule of Derivatives, Gain (Loss) on Derivative Activity (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Cash settlements paid			$ 44,871	$ 77,526
Interest rate swaps | Not designated as hedging instrument
Derivative Instruments, Gain (Loss) [Line Items]
Beginning fair value of interest rate swaps	$ (4,695)	$ (1,540)	(362)	(2,080)
Cash settlements paid	678	698	1,417	1,386
Ending fair value of interest rate swaps	(5,994)	(985)	(5,994)	(985)
Interest rate swaps | Not designated as hedging instrument | Interest expense
Derivative Instruments, Gain (Loss) [Line Items]
Total loss on interest rate swaps	$ (1,977)	$ (143)	$ (7,049)	$ (291)

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Changes in the ARO
Asset retirement obligation - beginning of period	$ 286,405	$ 226,525
Liabilities incurred with properties acquired	0	60,526
Liabilities incurred with properties drilled	0	92
Liabilities settled during the period	(1,172)	(2,615)
Liabilities associated with properties sold	(21,664)	(9,386)
Current period accretion	6,354	11,263
Asset retirement obligation - end of period	$ 269,923	$ 286,405

Partners' Equity - Preferred Un

Partners' Equity - Preferred Units (Details) - USD ($) $ / shares in Units, $ in Millions	Jun. 30, 2016	Jul. 01, 2014	Jun. 17, 2014	May 12, 2014	Apr. 17, 2014	Jun. 30, 2016
Class of Stock [Line Items]
Liquidation preference (in dollars per share)	$ 25					$ 25
Distributions in arrears (in dollars per share)	$ 0.92
Distributions in arrears	$ 8.7
Series A Preferred Equity
Class of Stock [Line Items]
Stock issuance (in shares)					2,000,000
Share price (per share)					$ 25
Additional shares of underwriter purchase option (in shares)				300,000
Dividend rate						8.00%
Series A Preferred Equity | three-month LIBOR
Class of Stock [Line Items]
Variable dividend rate						5.24%
Series B Preferred Equity
Class of Stock [Line Items]
Stock issuance (in shares)			7,000,000
Share price (per share)			$ 25
Dividend rate						8.00%
Series B Preferred Equity | three-month LIBOR
Class of Stock [Line Items]
Variable dividend rate						5.256%
Series B Preferred Equity | Over-Allotment Option
Class of Stock [Line Items]
Stock issuance (in shares)		200,000

Partners' Equity - Incentive Di

Partners' Equity - Incentive Distribution Units (Details) - WPX acquisition - USD ($) $ / shares in Units, $ in Millions	Jun. 04, 2016	Jun. 04, 2015	Jun. 04, 2014
Class of Stock [Line Items]
Equity interests issuable (in shares)			300,000
Conversion terms, minimum distribution per share (in dollars per share)			$ 0.90
Unvested IDUs
Class of Stock [Line Items]
Equity interests issuable (in shares)			200,000
Equity interests forfeiture (in shares)	66,666	66,666
Immediate vesting
Class of Stock [Line Items]
Equity interests issuable (in shares)			100,000
Forfeiture, first two anniversaries
Class of Stock [Line Items]
Equity interests forfeiture (in shares)			66,666
Forfeiture, third anniversary
Class of Stock [Line Items]
Equity interests forfeiture (in shares)			66,668
Ratable vesting
Class of Stock [Line Items]
Equity interests issuable (in shares)			10,000
Additional cash consideration			$ 35.5

Partners' Equity - Income (loss

Partners' Equity - Income (loss) per unit (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Equity [Abstract]
Net income (loss)	$ (52,261)	$ (38,474)	$ 53,068	$ (267,328)
Distributions to preferred unitholders	(4,750)	(4,750)	(8,708)	(9,500)
Net income (loss) attributable to unitholders	$ (57,011)	$ (43,224)	$ 44,360	$ (276,828)
Weighted average number of units outstanding (in shares)	70,071,000	68,897,000	69,518,000	68,909,000
Effect of dilutive securities:
Restricted and phantom units (in shares)	0	0	0	0
Weighted average units and potential common units outstanding (in shares)	70,071,000	68,897,000	69,518,000	68,909,000
Income (loss) per unit - basic & diluted (in dollars per share)	$ (0.81)	$ (0.63)	$ 0.64	$ (4.02)
Phantom share units (PSUs)
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive restricted units excluded from computation of EPS (in shares)	1,212,692	862,064	821,018	862,064
Restricted stock units (RSUs)
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive restricted units excluded from computation of EPS (in shares)	431,691	508,830	539,646	278,383

Unit-Based Compensation - LTIP,

Unit-Based Compensation - LTIP, Unit Appreciation Rights and Unit Options (Details) - USD ($)	6 Months Ended		12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015	Jun. 12, 2015	Jun. 11, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Annual interest rate	0.90%
Unit appreciation rights (UARs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit award expiration period			7 years
Share-based compensation expense	$ 112,100	$ 16,359
Unrecognized compensation costs	$ 104,048
Unrecognized compensation costs, weighted-average remaining period for recognition	2 years 25 days
Volatility	81.00%
Share based compensation, forfeiture rate	5.30%
Annual distribution	$ 0
Annual interest rate	0.90%
Unit appreciation rights (UARs) | Ratable vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued as compensation, gross (in units)	0		204,500
Award vesting period			3 years
Unit appreciation rights (UARs) | Cliff vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued as compensation, gross (in units)			96,520
Award vesting period			3 years
Restricted stock units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 1,600,000	1,200,000
Unrecognized compensation costs	$ 3,200,000
Unrecognized compensation costs, weighted-average remaining period for recognition	2 years 6 days
Phantom share units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 1,800,000	$ 1,400,000
Long Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units authorized for issuance (in shares)				5,000,000	2,000,000
Units issued as compensation (in shares)	2,797,391
Long Term Incentive Plan | Unit option awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued as compensation (in shares)	266,014
Long Term Incentive Plan | Restricted stock units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued as compensation (in shares)	885,001
Long Term Incentive Plan | Phantom share units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued as compensation (in shares)	1,212,692
Long Term Incentive Plan | Unrestricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units issued as compensation (in shares)	433,684

Unit-Based Compensation - Optio

Unit-Based Compensation - Option and UAR Activity (Details) - Unit appreciation rights (UARs) - USD ($)	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Units (in shares)
Outstanding (in units)	936,116
Forfeited (in units)	(20,667)
Outstanding (in units)	915,449	936,116
Options and UARs exercisable (in units)	450,456
Weighted-Average Exercise Price (in dollars per share)
Outstanding (in dollars per unit)	$ 20.61
Forfeited (in dollars per unit)	20.71
Outstanding (in dollars per unit)	20.61	$ 20.61
Options and UARs exercisable (in dollars per unit)	$ 25.84
Weighted-Average Remaining Contractual Term
Outstanding	4 years 4 months 23 days	4 years 10 months 28 days
Options and UARs exercisable	2 years 6 months 20 days
Aggregate Intrinsic Value
Outstanding	$ 0	$ 0
Options and UARs exercisable	$ 0

Unit-Based Compensation - Statu

Unit-Based Compensation - Status of the Partnership's non-vested UARs (Details) - Unit appreciation rights (UARs)	6 Months Ended
	Jun. 30, 2016$ / sharesshares
Number of Units
Non-vested at January 1, 2016 | shares	566,067
Vested (in units) | shares	(80,407)
Forfeited (in units) | shares	(20,667)
Non-vested at March 31, 2016 | shares	464,993
Weighted- Average Exercise Price
Non-vested at January 1, 2016 | $ / shares	$ 16.80
Vested (in dollars per unit) | $ / shares	23.07
Forfeited (in dollars per unit) | $ / shares	20.71
Non-vested at March 31, 2016 | $ / shares	$ 15.54

Unit-Based Compensation - Weigh

Unit-Based Compensation - Weighted Average Assumptions (Details) - $ / shares	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Annual interest rate	0.90%
Stock Appreciation Rights (SARs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected life (years)	4 years 4 months 23 days	4 years 10 months 28 days
Annual interest rate	0.90%
Annual distribution rate per unit (in dollars per share)	$ 0
Volatility	81.00%

Unit-Based Compensation - Phant

Unit-Based Compensation - Phantom, Board and Restricted Units (Details)	Jun. 22, 2016shares	May 10, 2016director$ / sharesshares	Jun. 15, 2015director$ / sharesshares	Feb. 24, 2015shares	Mar. 07, 2013	Sep. 21, 2009	Jun. 30, 2016USD ($)shares	Jun. 30, 2015USD ($)	Dec. 31, 2015shares
Stock Appreciation Rights (SARs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested units not included in consolidated balance sheet (in shares)							464,993		566,067
Share-based compensation expense | $							$ 112,100	$ 16,359
Unrecognized compensation costs | $							$ 104,048
Unrecognized compensation costs, period of recognition							2 years 25 days
Stock Appreciation Rights (SARs) [Member] | Ratable vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period									3 years
Stock Appreciation Rights (SARs) [Member] | Cliff vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period									3 years
Subjective phantom share units (PSUs) | Executive officers | Ratable vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period						3 years
Subjective or service based phantom units | Executive officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)				341,251
Objective phantom share units (PSUs) | Executive officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award measurement period					3 years
Granted (in shares)				259,998
Objective phantom share units (PSUs) | Executive officers | Ratable vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period					3 years
Objective phantom share units (PSUs) | Executive officers | Three-step process vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period						3 years
Objective phantom share units (PSUs) | Executive officers | Three-step process vesting, each of first two steps
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting percentage						50.00%
Objective phantom share units (PSUs) | Executive officers | Cliff vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period					3 years
Phantom share units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Partnership unit conversion ratio							1
Share-based compensation expense | $							$ 1,800,000	1,400,000
Restricted stock units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested units not included in consolidated balance sheet (in shares)							431,691
Share-based compensation expense | $							$ 1,600,000	$ 1,200,000
Unrecognized compensation costs | $							$ 3,200,000
Unrecognized compensation costs, period of recognition							2 years 6 days
Restricted stock units (RSUs) | Non-executive employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)									381,860
Restricted stock units (RSUs) | Non-executive employees | Ratable vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period									3 years
Restricted stock units (RSUs) | Executive employee | Ratable vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period									3 years
Restricted stock units (RSUs) | Executive employee | Cliff vesting
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period									5 years
Unrestricted units | Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		39,526	11,025
Individuals eligible for plan | director		6	6
Value of each unit at issuance (in dollars per share) | $ / shares		$ 2.59	$ 9.13
Maximum | Subjective phantom share units (PSUs) | Executive officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	1,286,930
Maximum | Subjective or service based phantom units | Executive officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	391,674
Maximum | Objective phantom share units (PSUs) | Executive officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	2,238,138

Subsidiary Guarantors (Details)

Subsidiary Guarantors (Details)	11 Months Ended
	May 08, 2014offering	Jun. 30, 2016USD ($)	Dec. 31, 2015USD ($)	May 13, 2014USD ($)	Mar. 18, 2014USD ($)	May 28, 2013USD ($)
Debt Instrument [Line Items]
Long-term debt, gross		$ 1,198,645,000	$ 1,458,000,000
Senior notes
Debt Instrument [Line Items]
Number of private offerings | offering	2
Aggregate principal amount					$ 250,000,000
Percent of subsidiaries owned		100.00%
Senior notes | 6.625% Senior Notes due 2021
Debt Instrument [Line Items]
Aggregate principal amount				$ 300,000,000		$ 250,000,000
Long-term debt, gross		$ 432,656,000	$ 550,000,000	$ 300,000,000